- -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K
TABLE OF CONTENTS
We meet the conditions specified in General Instruction I(1)(a) and (b) to Form 10-K and are thereby permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies specified therein. Accordingly, we have omitted from this report the information called for by Item 4 (Submission of Matters to a Vote of Security Holders), Item 10 (Directors and Executive Officers of the Registrant), Item 11 (Executive Compensation), Item 12 (Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters) and Item 13 (Certain Relationships and Related Party Transactions) of Form 10-K. In lieu of the information called for by Item 6 (Selected Financial Data) and Item 7 (Management's Discussion and Analysis of Financial Condition and Results of Operations) of Form 10-K, we have included under Item 7 a Management's Narrative Analysis of the Results of Operations to explain material changes in the amount of revenue and expense items between 2000, 2001 and 2002. CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those expressed or implied by these statements. You can generally identify our forward-looking statements by the words "anticipate," "believe," "continue," "could," "estimate," "expect," "intend," "may," "plan," "potential," "predict," "should," "will," "forecast," "goal," "objective," "projection," or other similar words. We have based our forward-looking statements on our management's beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements. Some of the factors that could cause actual results to differ from those expressed or implied by our forward-looking statements are described under "Risk Factors" beginning on page 8 of this report. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements. ii
PART I ITEM 1. BUSINESS OUR BUSINESS GENERAL We own gas distribution systems that together form one of the United States' largest natural gas distribution operations in terms of the number of customers served. Through wholly owned subsidiaries, we own two interstate natural gas pipelines and gathering systems and provide pipeline services. We are a Delaware corporation, incorporated in 1996, formerly named Reliant Energy Resources Corp. (RERC Corp.). In this report, we refer to CenterPoint Energy Resources Corp. as "CERC Corp." and to CERC Corp. and its subsidiaries as "CERC", "we", "our," or "us," unless the context clearly indicates otherwise. We are an indirect wholly owned subsidiary of CenterPoint Energy, Inc., a public utility holding company, created on August 31, 2002 as part of the corporate restructuring of Reliant Energy, Incorporated (Reliant Energy). In this report, we refer to CenterPoint Energy, Inc. as "CenterPoint Energy," unless the context clearly indicates otherwise. Our executive offices are located at 1111 Louisiana, Houston, TX 77002 (telephone number 713-207-1111). We conduct our operations primarily in the natural gas industry. We conduct our operations through our Natural Gas Distribution, Pipelines and Gathering and Other Operations business segments. THE RESTRUCTURING Reliant Energy completed the separation of the generation, transmission and distribution, and retail sales functions of its Texas electric operations pursuant to the following steps, which occurred on August 31, 2002 (the Restructuring): - CenterPoint Energy became the holding company for the Reliant Energy group of companies; - Reliant Energy and its subsidiaries, including us, became subsidiaries of CenterPoint Energy; and - each share of Reliant Energy common stock was converted into one share of CenterPoint Energy common stock. After the Restructuring, CenterPoint Energy distributed to its shareholders the shares of common stock of Reliant Resources, Inc. (Reliant Resources) that it owned (the Distribution) in a tax-free transaction. Contemporaneous with the Restructuring, CenterPoint Energy registered and became subject, with its subsidiaries, to regulation as a registered holding company system under the Public Utility Holding Company Act of 1935 (1935 Act). The 1935 Act directs the Securities and Exchange Commission (SEC) to regulate, among other things, transactions among affiliates, sales or acquisitions of assets, issuances of securities, distributions and permitted lines of business. In 2002, we obtained authority from each state in which such authority was required to restructure in a manner that would allow CenterPoint Energy to claim an exemption from registration under the 1935 Act. CenterPoint Energy has concluded that a restructuring would not be beneficial and has elected to remain a registered holding company under the 1935 Act. For additional information regarding the Restructuring and the Distribution, please read Note 2 to our consolidated financial statements. NATURAL GAS DISTRIBUTION Our Natural Gas Distribution business segment engages in intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas and some non-rate regulated retail gas marketing operations. We currently 1
conduct intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers through three unincorporated divisions: CenterPoint Energy Arkla (Arkla), CenterPoint Energy Entex (Entex) and CenterPoint Energy Minnegasco (Minnegasco). These operations are regulated as natural gas utility operations in the jurisdictions served by these divisions. - Arkla. Arkla provides natural gas distribution services in over 245 communities in Arkansas, Louisiana, Oklahoma and Texas. The largest metropolitan areas served by Arkla are Little Rock, Arkansas and Shreveport, Louisiana. In 2002, approximately 65% of Arkla's total throughput was attributable to retail sales of natural gas and approximately 35% was attributable to transportation services. - Entex. Entex provides natural gas distribution services in over 500 communities in Louisiana, Mississippi and Texas. The largest metropolitan area served by Entex is Houston. In 2002, approximately 95% of Entex's total throughput was attributable to retail sales of natural gas and approximately 5% was attributable to transportation services. - Minnegasco. Minnegasco provides natural gas distribution services in over 240 communities in Minnesota. The largest metropolitan area served by Minnegasco is Minneapolis. In 2002, approximately 93% of Minnegasco's total throughput was attributable to retail sales of natural gas and approximately 7% was attributable to transportation services. Additionally, Minnegasco provides heating, ventilating and air conditioning (HVAC) equipment and appliance repair services, HVAC and hearth equipment sales and home security monitoring which are unregulated services. The demand for intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers is seasonal. In 2002, approximately 60% of the total throughput of our natural gas distribution business occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during those periods. COMMERCIAL AND INDUSTRIAL SALES Our commercial and industrial sales group (C&I group) provides comprehensive natural gas products and services to commercial and industrial customers in the Gulf Coast and Midwestern regions of the United States. Most services provided by the C&I group are not subject to rate regulation. Subsidiaries making up the C&I group typically enter into fixed-volume forward sales commitments with customers with contract lengths typically ranging from one day to three years. Such sales are generally made on a monthly index price basis, but are also made on daily index and fixed price bases. In the case of fixed price commitments for delivery in future periods, the C&I group is exposed to risks resulting from changes in market prices of natural gas during the term of the contract. The C&I group engages in hedging activities with unaffiliated third parties in order to mitigate this risk. In 2002, approximately 94% of the C&I group's total throughput was attributable to natural gas sales; the remainder was attributable to transportation services that the C&I group provides for affiliates and third parties. For more information on the C&I group's derivative instruments and hedging activities, please read "Quantitative and Qualitative Disclosures About Market Risk -- Commodity Price Risk From Non-Trading Activities" in Item 7A of this report and Note 5 to our consolidated financial statements. SUPPLY AND TRANSPORTATION Arkla. In 2002, Arkla purchased approximately 56% of its natural gas supply pursuant to third-party term contracts with terms ranging from three months to one year, 29% of its natural gas supply from Reliant Energy Services, Inc. (Reliant Energy Services), a subsidiary of Reliant Resources and our former affiliate, under a contract expiring in March 2003 and 15% on the spot market. Arkla's major third-party natural gas suppliers in 2002 included Oneok Gas Marketing Company, BP Energy Company, Aquila Energy Marketing and Cross Timbers Energy Services. Arkla transports substantially all of its natural gas supplies under contracts with our pipeline subsidiaries. Entex. In 2002, Entex purchased virtually all of its natural gas supply pursuant to term contracts, with terms varying from one to five years. Entex's major third-party natural gas suppliers in 2002 included AEP 2
Gas Marketing, Kinder Morgan Texas Pipeline, L.P., Gulf Energy Marketing, Island Fuel Trading and Entergy Koch Trading. Entex transports its natural gas supplies on both interstate and intrastate pipelines under long-term contracts with terms varying from one to five years. Minnegasco. In 2002, Minnegasco purchased approximately 74% of its natural gas supply pursuant to term contracts, with terms varying from five months to ten years, with more than 20 different suppliers. Minnegasco purchased the remaining 26% on the daily or spot market. Most of the natural gas volumes under long-term contracts are committed under terms providing for delivery during the winter heating season, which extends from November through March. Minnegasco purchased approximately 60% of its natural gas requirements from three third-party suppliers in 2002: Tenaska Marketing Ventures, BP Canada Energy Marketing and Mirant Americas Energy Marketing. Purchases from Reliant Energy Services represented 10% of Minnegasco's total natural gas purchases in 2002. Minnegasco transports its natural gas supplies through various interstate pipelines under long-term contracts with terms varying from one to five years. Generally, the regulations of the states in which our natural gas distribution business operates allow us to pass through changes in the costs of natural gas to our customers through purchased gas adjustment provisions in our tariffs. There is, however, a timing difference between our purchases of natural gas and the ultimate recovery of these costs. Consequently, we may incur carrying costs as a result of this timing difference that are not recoverable from our customers. Arkla and Minnegasco use various leased or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather. Minnegasco also supplements contracted supplies and storage from time to time with stored liquefied natural gas and propane-air plant production. Minnegasco owns and operates an underground storage facility with a capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of 2.1 Bcf available for use during a normal heating season and a maximum daily withdrawal rate of 50 million cubic feet (MMcf). Minnegasco also owns nine propane-air plants with a total capacity of 204 MMcf per day and on-site storage facilities for 12 million gallons of propane (1.0 Bcf gas equivalent). Minnegasco owns a liquefied natural gas facility with a 12 million-gallon liquefied natural gas storage tank (1.0 Bcf gas equivalent) and a send-out capability of 72 MMcf per day. Although available natural gas supplies have exceeded demand for several years, currently supply and demand appear to be more balanced. We have sufficient supplies and pipeline capacity under contract to meet our firm customer requirements. However, from time to time, it is possible for limited service disruptions to occur due to weather conditions, transportation constraints and other events. As a result of these factors, supplies of natural gas may become unavailable from time to time or prices may increase rapidly in response to temporary supply constraints or other factors. ASSETS As of December 31, 2002, we owned approximately 61,000 linear miles of gas distribution mains, varying in size from one-half inch to 24 inches in diameter. Generally, in each of the cities, towns and rural areas served by us, we own the underground gas mains and service lines, metering and regulating equipment located on customers' premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which we receive gas are owned, operated and maintained by others, and our distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on the land owned by suppliers. COMPETITION We compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly for gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass our facilities and markets and sell and/or transport natural gas directly to commercial and industrial customers. 3
PIPELINES AND GATHERING Our Pipelines and Gathering business segment operates two interstate natural gas pipelines as well as gas gathering facilities and also provides pipeline services. Our pipeline operations are primarily conducted by two wholly owned interstate pipeline subsidiaries which provide gas transportation and storage services primarily to industrial customers and local distribution companies. Our gathering and pipeline services operations are conducted by a wholly owned gas gathering subsidiary and a wholly owned pipeline services subsidiary. Through our gas gathering subsidiary, we provide natural gas gathering and related services, including related liquids extraction and other well operating services. Through our pipeline services subsidiary, we provide pipeline project management and facility operation services to affiliates and third parties. In 2002, approximately 27% of our total operating revenues from pipelines and gathering was attributable to services provided to Arkla, and approximately 11% was attributable to services to Laclede Gas Company (Laclede), an unaffiliated distribution company that provides natural gas utility service to the greater St. Louis metropolitan area in Illinois and Missouri. An additional 8% of our operating revenues from pipelines and gathering was attributable to the transportation of gas marketed by Reliant Energy Services. Services to Arkla and Laclede are provided under several long-term firm storage and transportation agreements. Contracts for firm transportation in Arkla's major service areas are currently scheduled to expire in 2005. An agreement to extend the existing service relationship with Laclede for a five-year period was entered into in February 2002. Our pipelines and gathering business operations may be affected by changes in the demand for natural gas, the available supply and relative price of natural gas in the Midcontinent and Gulf Coast natural gas supply regions and general economic conditions. ASSETS We own and operate approximately 8,200 miles of gas transmission lines primarily located in Missouri, Illinois, Arkansas, Louisiana, Oklahoma and Texas. We also own and operate six natural gas storage fields with a combined daily deliverability of approximately 1.2 Bcf and a combined working gas capacity of approximately 64.3 Bcf. We also own a 10% interest, with Gulf South Pipeline Company, LP, in the Bistineau storage facility with 73.8 Bcf of working gas capacity and approximately 1.1 Bcf per day of deliverability. Our storage capacity in the Bistineau facility is 8 Bcf of working gas with 100 MMcf per day of deliverability. Most of our storage operations are in north Louisiana and Oklahoma. We also own and operate approximately 4,300 miles of gathering pipelines that collect gas from more than 300 separate systems located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas. COMPETITION Our pipelines and gathering business competes with other interstate and intrastate pipelines and gathering companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, and flexibility and reliability of service. Our pipelines and gathering business competes indirectly with other forms of energy available to its customers, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability of energy and pipeline capacity, the level of business activity, conservation and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in areas we serve and the level of competition for transportation and storage services. In addition, competition for our gathering operations is impacted by commodity pricing levels because of their influence on the level of drilling activity. 4
OTHER OPERATIONS In 2002, Other Operations included unallocated corporate costs and inter-segment eliminations. REGULATION We are subject to regulation by various federal, state, local and foreign governmental agencies, including the regulations described below. PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 As a subsidiary of a registered public utility holding company, we are subject to a comprehensive regulatory scheme imposed by the SEC in order to protect customers, investors and the public interest. Although the SEC does not regulate rates and charges under the 1935 Act, it does regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies. In order to obtain financing, acquire additional public utility assets or stock, or engage in other significant transactions, we are generally required to obtain approval from the SEC under the 1935 Act. Prior to the Restructuring, CenterPoint Energy and Reliant Energy obtained an order from the SEC that authorized the Restructuring transactions, including the Distribution, and granted CenterPoint Energy certain authority with respect to system financing, dividends and other matters. The financing authority granted by that order will expire on June 30, 2003, and CenterPoint Energy must obtain a further order from the SEC under the 1935 Act, related, among other things, to the financing activities of CenterPoint Energy and its subsidiaries, including us, subsequent to June 30, 2003. In a July 2002 order, the SEC limited the aggregate amount of our external borrowings to $2.7 billion. Our ability to pay dividends is restricted by the SEC's requirement that common equity as a percentage of total capitalization must be at least 30% after the payment of any dividend. In addition, the order restricts our ability to pay dividends out of capital accounts to the extent current or retained earnings are insufficient for those dividends. Under these restrictions, we are permitted to pay dividends in excess of our current or retained earnings in an amount up to $100 million. In 2002, we obtained authority from each state in which such authority was required to restructure in a manner that would allow CenterPoint Energy to claim an exemption from registration under the 1935 Act. CenterPoint Energy has concluded that a restructuring would not be beneficial and has elected to remain a registered holding company under the 1935 Act. FEDERAL ENERGY REGULATORY COMMISSION The transportation and sale or resale of natural gas in interstate commerce is subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act and the Natural Gas Policy Act of 1978, as amended. The FERC has jurisdiction over, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The rates charged by interstate pipelines for interstate transportation and storage services are also regulated by the FERC. Our natural gas pipeline subsidiaries may periodically file applications with the FERC for changes in their generally available maximum rates and charges designed to allow them to recover their costs of providing service to customers (to the extent allowed by prevailing market conditions), including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period and, in some cases, are subject to refund under applicable law until such time as the FERC issues an order on the allowable level of rates. In February 2000, the FERC issued Order No. 637, which introduced several measures to increase competition for interstate pipeline transportation services. Order No. 637 authorizes interstate pipelines to propose term-differentiated and peak/off-peak rates, and requires pipelines to make tariff filings to expand pipeline service options for customers. Both of our natural gas pipeline subsidiaries made two Order No. 637 5
compliance filings in 2000, and both obtained uncontested settlements filed with the FERC in 2001. In 2002, the FERC issued orders accepting both settlements, subject to certain modifications. The FERC has denied requests for rehearing and clarification of the orders and has accepted, with modification, the compliance tariff filed under one of the orders and ordered additional revised tariff sheets to be filed under the other order. STATE AND LOCAL REGULATION In almost all communities in which we provide natural gas distribution services, we operate under franchises, certificates or licenses obtained from state and local authorities. The terms of the franchises, with various expiration dates, typically range from 10 to 30 years. None of our material franchises expires before 2005. We expect to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive. Substantially all of our retail natural gas sales are subject to traditional cost-of-service regulation at rates regulated by the relevant state public service commissions and, in Texas, by the Railroad Commission of Texas (Railroad Commission) and municipalities we serve. Arkansas Rate Case. In November 2001, Arkla filed a rate request in Arkansas seeking rates to yield approximately $47 million in additional annual gross revenue. In August 2002, a settlement was approved by the Arkansas Public Service Commission (APSC) which is expected to result in an increase in base rates of approximately $32 million annually. In addition, the APSC approved a gas main replacement surcharge which is expected to provide $2 million of additional gross revenue in 2003 and additional amounts in subsequent years. The new rates included in the final settlement were effective with all bills rendered on and after September 21, 2002. Oklahoma Rate Case. In May 2002, Arkla filed a request in Oklahoma to increase its base rates by $13.7 million annually. In December 2002, a settlement was approved by the Oklahoma Corporation Commission which is expected to result in an increase in base rates of approximately $7.3 million annually. The new rates included in the final settlement were effective with all bills rendered on and after December 29, 2002. City of Tyler, Texas, Gas Costs Review. By letter to Entex dated July 31, 2002, the City of Tyler, Texas, forwarded various computations of what it believes to be excessive costs ranging from $2.8 million to $39.2 million for gas purchases by Entex for resale to residential and small commercial customers in that city under supply agreements in effect since 1992. Entex's gas costs for its Tyler system are recovered from customers pursuant to tariffs approved by the city and filed with both the city and the Railroad Commission. Pursuant to an agreement, on January 29, 2003, Entex and the city filed a Joint Petition for Review of Charges for Gas Sales (Joint Petition) with the Railroad Commission. The Joint Petition requests that the Railroad Commission determine whether Entex has properly and lawfully charged and collected for gas service to its residential and commercial customers in its Tyler distribution system for the period beginning November 1, 1992, and ending October 31, 2002. We believe that all costs for Entex's Tyler distribution system have been properly included and recovered from customers pursuant to Entex's filed tariffs and that the city has no legal or factual support for the statements made in its letter. DEPARTMENT OF TRANSPORTATION In December 2002, Congress enacted the Pipeline Safety Improvement Act of 2002. This legislation applies to our interstate pipelines as well as our intra-state pipelines and local distribution companies. The legislation imposes several requirements related to ensuring pipeline safety and integrity. It requires companies to assess the integrity of their pipeline transmission and distribution facilities in areas of high population concentration and further requires companies to perform remediation activities in accordance with the requirements of the legislation over a 10-year period. In January 2003, the U.S. Department of Transportation published a notice of proposed rulemaking to implement provisions of the legislation. The Department of Transportation is expected to issue final rules by the end of 2003. 6
While we anticipate that increased capital and operating expenses will be required to comply with the legislation, we will not be able to quantify the level of spending required until the Department of Transportation's final rules are issued. ENVIRONMENTAL MATTERS GENERAL ENVIRONMENTAL ISSUES We are subject to numerous federal, state and local requirements relating to the protection of the environment and the safety and health of personnel and the public. These requirements relate to a broad range of our activities, including: the discharge of pollutants into water and soil; the proper handling of solid, hazardous, and toxic materials; and waste, noise, and safety and health standards applicable to the workplace. In order to comply with these requirements, we will spend substantial amounts from time to time to construct, modify and retrofit equipment, and to clean up or decommission disposal or fuel storage areas and other locations as necessary. Our facilities are subject to state and federal laws and regulations governing the discharge of pollutants into the air and waterways. In many cases we must obtain permits or other governmental authorizations that prescribe the parameters for discharges from our facilities. There are ongoing efforts to modify standards relating to both the discharge of pollutants into streams and waterways and to air quality. These efforts may result in more restrictive regulations and permit terms applicable to our facilities in the future. We anticipate no significant capital and other special project expenditures between 2002 and 2006 for environmental compliance. If we do not comply with environmental requirements that apply to our operations, regulatory agencies could seek to impose on us civil, administrative and/or criminal liabilities as well as seek to curtail our operations. Under some statutes, private parties could also seek to impose civil fines or liabilities for property damage, personal injury and possibly other costs. Under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, owners and operators of facilities from which there has been a release or threatened release of hazardous substances, together with those who have transported or arranged for the disposal of those substances, are liable for: - the costs of responding to that release or threatened release; and - the restoration of natural resources damaged by any such release. We are not aware of any liabilities under CERCLA that would have a material adverse effect on us, our financial position, results of operations or cash flows. LIABILITY FOR PREEXISTING CONDITIONS AND REMEDIATION Manufactured Gas Plant Sites. We and our predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, remediation has been completed on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in our Minnesota service territory, two of which we believe were neither owned nor operated by us, and for which we believe we have no liability. At December 31, 2002, we had accrued $19 million for remediation of the Minnesota sites. At December 31, 2002, the estimated range of possible remediation costs was $8 million to $44 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. We have an environmental expense tracker mechanism in our rates in Minnesota. We have collected $12 million at December 31, 2002 to be used for future environmental remediation. 7
We have received notices from the United States Environmental Protection Agency and others regarding our status as a PRP for sites in other states. Based on current information, we have not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Hydrocarbon Contamination. In August 2001, a number of Louisiana residents who live near the Wilcox Aquifer filed suit in the 1st Judicial District Court, Caddo Parish, Louisiana against us and others. The suit alleges that we and the other defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by the defendants and is the sole or primary drinking water aquifer in the area. The monetary damages sought are unspecified. In April 2002, a separate suit with identical allegations against the same parties was filed in the same court. Additionally in January 2003, a third suit with similar allegations was filed against the same parties in the 26th Judicial Court, Bossier Parish, Louisiana. Mercury Contamination. Like similar companies, our pipeline and natural gas distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area around the meters with elemental mercury. We have found this type of contamination in the past, and we have conducted remediation at sites found to be contaminated. Although we are not aware of additional specific sites, it is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on our experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, we believe that the cost of any remediation of these sites will not be material to our financial position, results of operations or cash flows. EMPLOYEES As of December 31, 2002, we had 5,428 full-time employees. The following table sets forth the number of our employees by business segment as of December 31, 2002:
burdensome than those of our current indebtedness. These terms may negatively impact our ability to operate our business. The success of our future financing efforts may depend, at least in part, on: - general economic and capital market conditions; - credit availability from financial institutions and other lenders; - investor confidence in us and the market in which we operate; - maintenance of acceptable credit ratings by us and CenterPoint Energy; - market expectations regarding our future earnings and probable cash flows; - market perceptions of our ability to access capital markets on reasonable terms; - our exposure to Reliant Resources in connection with its indemnification obligations arising in connection with its separation from CenterPoint Energy; - provisions of relevant tax and securities laws; and - our ability to obtain approval of specific financing transactions under the 1935 Act. Our current credit ratings are discussed in "Management's Narrative Analysis of Results of Operations -- Liquidity -- Impact on Liquidity of a Downgrade in Credit Ratings" in Item 7 of this report. We cannot assure you that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms. THE FINANCIAL CONDITION AND LIQUIDITY OF OUR PARENT COMPANY COULD AFFECT OUR ACCESS TO CAPITAL, OUR CREDIT STANDING AND OUR FINANCIAL CONDITION. Our ratings and credit may be impacted by CenterPoint Energy's credit standing. CenterPoint Energy and its subsidiaries other than us have approximately $293 million of debt, including capital leases, required to be paid in 2003. We cannot assure you that CenterPoint Energy and its other subsidiaries will be able to pay or refinance these amounts. If CenterPoint Energy were to experience a deterioration in its credit standing or liquidity difficulties, our access to credit and our ratings could be adversely affected. WE ARE A WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY. CENTERPOINT ENERGY CAN EXERCISE SUBSTANTIAL CONTROL OVER OUR DIVIDEND POLICY AND BUSINESS AND OPERATIONS AND COULD DO SO IN A MANNER THAT IS ADVERSE TO OUR INTERESTS. We are managed by officers and employees of CenterPoint Energy. Our management will make determinations with respect to the following: - our payment of dividends; - decisions on our financings and our capital raising activities; - mergers or other business combinations; and - our acquisition or disposition of assets. There are no contractual restrictions on our ability to pay dividends to CenterPoint Energy. Our management could decide to increase our dividends to CenterPoint Energy to support its cash needs. This could adversely affect our liquidity. Under the 1935 Act, our ability to pay dividends is restricted by the SEC's requirement that common equity as a percentage of total capitalization must be at least 30% after the payment of any dividend. In addition, the order restricts our ability to pay dividends out of capital accounts to the extent current or retained earnings are insufficient for those dividends. Under these restrictions, we are permitted to pay dividends in excess of the respective current or retained earnings in an amount up to $100 million. 9
IF CENTERPOINT ENERGY IS UNABLE TO OBTAIN AN EXTENSION OF ITS FINANCING ORDER UNDER THE 1935 ACT, WE WILL NOT BE ABLE TO ENGAGE IN FINANCING TRANSACTIONS AFTER JUNE 30, 2003. In connection with CenterPoint Energy's registration as a public utility holding company under the 1935 Act, the SEC issued a financing order which authorizes us to enter into a wide range of financing transactions. This financing order expires on June 30, 2003. If CenterPoint Energy is unable to obtain an extension of the financing order, we would generally be unable to engage in any financing transactions, including the refinancing of existing obligations after June 30, 2003. RISK FACTORS AFFECTING THE RESULTS OF OUR BUSINESSES OUR NATURAL GAS DISTRIBUTION BUSINESS MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES. We compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly with us for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass our facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by us as a result of competition may have an adverse impact on our results of operations, financial condition and cash flows. OUR NATURAL GAS DISTRIBUTION BUSINESS IS SUBJECT TO FLUCTUATIONS IN NATURAL GAS PRICING LEVELS. We are subject to risk associated with upward price movements of natural gas. High natural gas prices might affect our ability to collect balances due from our customers and could create the potential for uncollectible accounts expense to exceed the recoverable levels built into our tariff rates. In addition, a sustained period of high natural gas prices could apply downward demand pressure on natural gas consumers in our service territory. WE MAY INCUR CARRYING COSTS ASSOCIATED WITH PASSING THROUGH CHANGES IN THE COSTS OF NATURAL GAS. Generally, the regulations of the states in which we operate allow us to pass through changes in the costs of natural gas to our customers through purchased gas adjustment provisions in the applicable tariffs. There is, however, a timing difference between our purchases of natural gas and the ultimate recovery of these costs. Consequently, we may incur carrying costs as a result of this timing difference that are not recoverable from our customers. The failure to recover those additional carrying costs may have an adverse effect on our results of operations, financial condition and cash flows. OUR PIPELINES AND GATHERING BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE TRANSPORTATION AND STORAGE OF NATURAL GAS AND INDIRECTLY WITH ALTERNATIVE FORMS OF ENERGY. Our two interstate pipelines and our gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. They also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price. The actions of our competitors could lead to lower prices, which may have an adverse impact on our results of operations, financial condition and cash flows. IF WE FAIL TO EXTEND CONTRACTS WITH TWO OF OUR SIGNIFICANT INTERSTATE PIPELINES' CUSTOMERS, IT COULD HAVE AN ADVERSE IMPACT ON OUR OPERATIONS. Contracts with two of our interstate pipelines' significant customers, Arkla and Laclede, are currently scheduled to expire in 2005 and 2007, respectively. To the extent the pipelines are unable to extend these contracts or the contracts are renegotiated at rates substantially different than the rates provided in the current contracts, it could have an adverse effect on our results of operations, financial condition and cash flows. 10
OUR INTERSTATE PIPELINES ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS. Our interstate pipelines largely rely on gas sourced in the various supply basins located in the Midcontinent region of the United States. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on our results of operations, financial condition and cash flows. OUR REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL. A portion of our revenues are derived from natural gas sales and transportation. Thus, our revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months. OUR INSURANCE COVERAGE MAY NOT BE SUFFICIENT. INSUFFICIENT INSURANCE COVERAGE AND INCREASED INSURANCE COSTS COULD ADVERSELY IMPACT OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. We have insurance covering certain of our facilities, including property damage insurance and public liability insurance in amounts that we consider appropriate. Where we have such insurance policies in place, they are subject to certain limits and deductibles and do not include business interruption coverage. We cannot assure you that insurance coverage will be available in the future on commercially reasonable terms or that the insurance proceeds received for any loss of or any damage to any of our facilities will be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows. The costs of our insurance coverage have increased significantly in recent months and may continue to increase in the future. OUR REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO RISKS THAT ARE BEYOND OUR CONTROL, INCLUDING BUT NOT LIMITED TO FUTURE TERRORIST ATTACKS OR RELATED ACTS OF WAR. The cost of repairing damage to our facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events, in excess of reserves established for such repairs, may adversely impact our results of operations, financial condition and cash flows. The occurrence or risk of occurrence of future terrorist activity may impact our results of operations and financial condition in unpredictable ways. These actions could also result in adverse changes in the insurance markets and disruptions of power and fuel markets. In addition, our natural gas distribution and pipelines and gathering facilities could be directly or indirectly harmed by future terrorist activity. The occurrence or risk of occurrence of future terrorist attacks or related acts of war could also adversely affect the United States economy. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and margins and limit our future growth prospects. Also, these risks could cause instability in the financial markets and adversely affect our ability to access capital. ITEM 2. PROPERTIES CHARACTER OF OWNERSHIP We own our principal properties in fee. Also, most gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others. NATURAL GAS DISTRIBUTION For information regarding the properties of our Natural Gas Distribution business segment, please read "Our Business -- Natural Gas Distribution" in Item 1 of this report, which information is incorporated herein by reference. PIPELINES AND GATHERING For information regarding the properties of our Pipelines and Gathering business segment, please read "Our Business -- Pipelines and Gathering" in Item 1 of this report, which information is incorporated herein by reference. 11
ITEM 3. LEGAL PROCEEDINGS For a brief descriptions of certain legal and regulatory proceedings affecting us, see "Regulation" and "Environmental Matters" in Item 1 of this report and Notes 10(c) and 10(d) to our consolidated financial statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The information called for by Item 4 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries). PART II ITEM 5. MARKET FOR COMMON STOCK AND RELATED STOCKHOLDER MATTERS All of the 1,000 outstanding shares of CERC Corp.'s common stock are held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy, Inc. Our ability to pay dividends is restricted by the SEC's requirement that common equity as a percentage of total capitalization must be at least 30% after the payment of any dividend. In addition, the order restricts our ability to pay dividends out of capital accounts to the extent current or retained earnings are insufficient for those dividends. Under these restrictions, we are permitted to pay dividends in excess of the respective current or retained earnings in an amount up to $100 million. ITEM 6. SELECTED FINANCIAL DATA The information called for by Item 6 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries). ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF CENTERPOINT ENERGY RESOURCES CORP. AND ITS CONSOLIDATED SUBSIDIARIES The following narrative analysis should be read in combination with our consolidated financial statements and notes contained in Item 8 of this report. Because we are an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), our determination of reportable segments considers the strategic operating units under which CenterPoint Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. We have identified the following reportable business segments: Natural Gas Distribution, Pipelines and Gathering and Other Operations. Prior to 2001, we also conducted business in the Wholesale Energy and European Energy business segments. Wholesale Energy included wholesale energy trading, marketing, power origination and risk management services in North America but excluded the operations of Reliant Energy Power Generation, Inc., a wholly owned subsidiary of Reliant Resources, Inc. (Reliant Resources) and formerly an indirect wholly owned subsidiary of CenterPoint Energy's predecessor, Reliant Energy, Incorporated (Reliant Energy). European Energy included the energy trading and marketing operations initiated in the fourth quarter of 1999 in the Netherlands and other countries in Europe but excluded Reliant Energy Power Generation Benelux N.V., a Dutch power company. Reliant Energy completed the separation of the generation, transmission and distribution, and retail sales functions of its Texas electric operations pursuant to the following steps, which occurred on August 31, 2002 (the Restructuring): - CenterPoint Energy became the holding company for the Reliant Energy group of companies; - Reliant Energy and its subsidiaries, including us, became subsidiaries of CenterPoint Energy; and 12
- each share of Reliant Energy common stock was converted into one share of CenterPoint Energy common stock. After the Restructuring, CenterPoint Energy distributed to its shareholders the shares of common stock of Reliant Resources that it owned (the Distribution) in a tax-free transaction. Contemporaneous with the Restructuring, CenterPoint Energy registered and became subject, with its subsidiaries, to regulation as a registered holding company system under the Public Utility Holding Company Act of 1935 (1935 Act). The 1935 Act directs the Securities and Exchange Commission (SEC) to regulate, among other things, transactions among affiliates, sales or acquisitions of assets, issuances of securities, distributions and permitted lines of business. In 2002, we obtained authority from each state in which such authority was required to restructure in a manner that would allow CenterPoint Energy to claim an exemption from registration under the 1935 Act. CenterPoint Energy has concluded that a restructuring would not be beneficial and has elected to remain a registered holding company under the 1935 Act. On December 31, 2000, CERC Corp. transferred all of the outstanding capital stock (collectively, Stock Transfer) of Reliant Energy Services International, Inc. (RESI), Arkla Finance Corporation (Arkla Finance) and Reliant Energy Europe Trading & Marketing, Inc. (RE Europe Trading), all of which were wholly owned subsidiaries of CERC Corp., to Reliant Resources. Both CERC Corp. and Reliant Resources were wholly owned subsidiaries of Reliant Energy at that time. As a result of the Stock Transfer, RESI, Arkla Finance and RE Europe Trading each became a wholly owned subsidiary of Reliant Resources. Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources merged with and into Reliant Energy Services, a wholly owned subsidiary of CERC Corp., with Reliant Energy Services as the surviving corporation (Merger). As a result of the Merger, Reliant Energy Services became a wholly owned subsidiary of Reliant Resources. As consideration for the Stock Transfer and the Merger, Reliant Resources paid $94 million to CERC Corp. Reliant Energy Services, together with RESI and RE Europe Trading, conducted the Wholesale Energy business segment's trading, marketing, power origination and risk management business and operations of Reliant Energy prior to the formation of CenterPoint Energy. Arkla Finance is a company that holds an investment in marketable equity securities. The Stock Transfer and the Merger were part of the Restructuring. We are reporting the results of RE Europe Trading as discontinued operations for all periods presented in our consolidated financial statements in accordance with Accounting Principles Board (APB) Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" (APB Opinion No. 30). The transfer of the operations of Reliant Energy Services, RESI and Arkla Finance did not result in the disposal of a segment of business as defined under APB NO. 30. For additional information regarding the operating results of the entities transferred to Reliant Resources, please read Note 14 to our consolidated financial statements. 13
CONSOLIDATED RESULTS OF OPERATIONS Our results of operations are affected by seasonal fluctuations in the demand for natural gas and price movements of energy commodities. Our results of operations are also affected by, among other things, the actions of various federal and state governmental authorities having jurisdiction over rates we charge, competition in our various business operations, debt service costs and income tax expense. The following table sets forth selected financial data for the years ended December 31, 2000, 2001 and 2002, followed by a discussion of our consolidated results of operations based on earnings from continuing operations before interest expense, distribution on trust preferred securities and income taxes (EBIT). EBIT, as defined, is shown because it is a financial measure we use to evaluate the performance of our business segments and we believe it is a measure of financial performance that may be used as a means to analyze and compare companies on the basis of operating performance. We expect that some analysts and investors will want to review EBIT when evaluating our company. EBIT is not defined under accounting principles generally accepted in the United States (GAAP), should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP and is not indicative of operating income from operations as determined under GAAP. Additionally, our computation of EBIT may not be comparable to other similarly titled measures computed by other companies, because all companies do not calculate it in the same fashion. We consider operating income to be a comparable measure under GAAP. We believe the difference between operating income and EBIT on both a consolidated and business segment basis is not material. We have provided a reconciliation of consolidated operating income to EBIT and EBIT to net income below. SELECTED FINANCIAL RESULTS
2002 Compared to 2001. We reported EBIT for 2002 of $361 million compared to $280 million in 2001. The $81 million increase was primarily due to: - a $31 million increase in EBIT primarily as a result of improved operating margins (revenues less fuel costs) from rate increases in 2002, a 5% increase in throughput and changes in estimates of unbilled revenues and deferred gas costs, which reduced operating margins in 2001; and - a $49 million increase in EBIT as a result the discontinuance of goodwill amortization in accordance with Statement of Financial Accounting Standards (SFAS) SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142) in 2002. Operation and maintenance expenses increased $10 million in 2002 as compared to 2001 primarily due to project work consisting of construction management, material acquisition, engineering, project planning and other services as well as increased benefit costs and higher general and administrative expenses. These increases were partially offset by a reduction in bad debt expense in 2002 as a result of improved collections and lower gas prices. Depreciation and amortization expense decreased $40 million in 2002 as compared to 2001 primarily as a result of the discontinuance of goodwill amortization in accordance with SFAS No. 142 as further discussed in Note 3(d) to our consolidated financial statements. Goodwill amortization was $49 million for the year ended December 31, 2001. This was partially offset by an increase in depreciation expense due to an increase in the asset base. Taxes other than income taxes decreased $13 million in 2002 as compared to 2001 due primarily to reduced franchise fees as a result of decreased revenues. Other income decreased $6 million in 2002 as compared to 2001 primarily due to decreased interest income from affiliated parties. Our effective tax rates for 2002 and 2001 were 42.2% and 46.4%, respectively. The decrease in the effective rate for 2002 compared to 2001 was primarily the result of the discontinuance of goodwill amortization in accordance with SFAS No. 142, offset by an increase in state income taxes. 2001 Compared to 2000. We reported EBIT for 2001 of $280 million compared to $334 million in 2000. The $54 million decrease was primarily due to: - a $106 million decrease in EBIT resulting from the transfer of Reliant Energy Services to Reliant Resources pursuant to the Merger discussed above; - a $24 million increase in EBIT primarily resulting from increased operating margins (revenues less fuel costs) due to increased volumes in the first quarter of 2001 due to the effect of colder weather, partially offset by changes in estimates of unbilled revenues and recoverability of deferred gas accounts and other items; and - a $33 million increase in EBIT primarily resulting from a $27 million impairment loss on marketable equity securities classified as "available for sale" in 2000. Operation and maintenance expenses decreased $102 million in 2001 as compared to 2000 primarily due to the transfer of Reliant Energy Services to Reliant Resources pursuant to the Merger discussed above. This decrease was partially offset by increased customer growth and usage and reduced operating expenses due to exiting certain non-rate regulated retail gas markets outside of our established market areas during 2000 in our Natural Gas Distribution segment. Depreciation and amortization expense decreased $7 million in 2001 as compared to 2000 primarily as a result of the transfer of Reliant Energy Services to Reliant Resources, offset by an increase in depreciation expense due to an increase in the asset base. Taxes other than income taxes increased $20 million in 2001 as compared to 2000 due primarily to increased franchise fees, state franchise taxes and state gross receipts taxes. 15
Other income increased $12 million in 2001 as compared to 2000 primarily due to a $27 million impairment loss on marketable equity securities classified as "available for sale" in 2000, partially offset by a $17 million reduction in interest income in 2001. Interest expense increased $12 million in 2001 as compared to 2000 primarily due to increased long-term borrowings. Our effective tax rates for 2001 and 2000 were 46.4% and 48.7%, respectively. The decrease in the effective tax rate for 2001 compared to 2000 was primarily due to a decrease in state income taxes. Loss from discontinued operations includes the results of RE Europe Trading for all periods presented in our consolidated financial statements in accordance with APB Opinion No. 30. For additional information, please read Note 14 to our consolidated financial statements. FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS For information regarding our exposure to risk as a result of fluctuations in commodity prices and derivative instruments, please read "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this report. CERTAIN FACTORS AFFECTING FUTURE EARNINGS Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on numerous factors including: - state and federal legislative and regulatory actions or developments, constraints placed on our activities or business by the 1935 Act, changes in or application of laws or regulations applicable to other aspects of our business and actions; - timely rate increases including recovery of costs; - the successful and timely completion of our capital projects; - industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns; - our pursuit of potential business strategies, including acquisitions or dispositions of assets; - changes in business strategy or development plans; - the timing and extent of changes in commodity prices, particularly natural gas; - changes in interest rates or rates of inflation; - unanticipated changes in operating expenses and capital expenditures; - weather variations and other natural phenomena; - the timing and extent of changes in the supply of natural gas; - commercial bank and financial market conditions, our access to capital, the costs of such capital and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets; - actions by rating agencies; - legal and administrative proceedings and settlements; - changes in tax laws; - inability of various counterparties to meet their obligations with respect to our financial instruments; 16
- any lack of effectiveness of our disclosure controls and procedures; - changes in technology; - significant changes in our relationship with our employees, including the availability of qualified personnel and the potential adverse effects if labor disputes or grievances were to occur; - significant changes in critical accounting policies; - acts of terrorism or war, including any direct or indirect effect on our business resulting from terrorist attacks such as occurred on September 11, 2001 or any similar incidents or responses to those incidents; - the availability and price of insurance; - political, legal, regulatory and economic conditions and developments in the United States; and - other factors discussed in Item 1 of this report under "Risk Factors." LIQUIDITY Long-Term Debt and Trust Preferred Securities. Of the $1.96 billion of debt outstanding at December 31, 2002, approximately $1.8 billion principal amount is senior and unsecured and, approximately $79.4 million principal amount with a final maturity of 2012 is subordinated. In addition, the debentures relating to $0.4 million of trust preferred securities issued by our statutory business-trust subsidiary are subordinated. The issuance of secured debt by us is limited under an indenture relating to approximately $145 million principal amount of debt maturing in 2006 which provides for equal and ratable security for such debt in the event debt secured by "principal property" (as defined in the indenture) is issued. Other than this indenture, agreements relating to the issuance of long-term debt do not restrict the issuance of secured debt. Additionally, our $350 million credit agreement expiring in March 2003 prohibits the issuance of debt secured by "principal property". The definition is similar to that contained in the indenture described above. Finally, our ability to issue secured debt may be limited under the terms of agreements entered into by CenterPoint Energy. The assets that may be pledged as security for our debt may be limited by the SEC because our parent is a registered holding company. On February 28, 2003, CenterPoint Energy reached agreement with a syndicate of banks on a second amendment to its existing $3.85 billion bank facility. The amendment provides that proceeds from capital stock or indebtedness issued or incurred by us must be applied (subject to a $200 million basket for us and another $250 million basket for borrowings by CenterPoint Energy and other limited exceptions) to repay bank loans and reduce the bank facility. Cash proceeds from issuances of indebtedness to refinance indebtedness existing on October 10, 2002 are not subject to this limitation. Short-Term Debt and Receivables Facility. During 2003, our bank and receivables facilities are scheduled to terminate on the dates indicated below.
available for repaying borrowings under our existing $350 million revolving credit facility that expires on March 31, 2003 in the event sufficient proceeds are not raised in the capital markets to repay such borrowings on or before March 31, 2003. Final terms for the bridge facility have not been established, but it is anticipated that the rates for borrowings under the facility will be LIBOR plus 450 basis points. We paid a commitment fee of 25 basis points on the committed amount and will be required to pay a facility fee of 75 basis points of the amount funded and an additional 100 basis points on the amount funded and outstanding for more than two months. In connection with this facility, we expect to provide the lender with collateral in the form of a security interest in the stock we own in our interstate natural gas pipeline subsidiaries. On December 31, 2002, we had received proceeds from the sale of receivables of approximately $107 million under the $150 million receivables facility and our $350 million bank facility was fully drawn or utilized in the form of letters of credit. Advances under the $150 million receivables facility are not recorded as a financing because the facility provides for the sale of receivables to third parties as discussed in Note 3(i) to the consolidated financial statements. On December 31, 2002, we had $74 million borrowed from affiliates. We participate in a "money pool" through which we and certain of our affiliates can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The money pool's net funding requirements are generally met by borrowings of CenterPoint Energy. The terms of the money pool are in accordance with requirements applicable to registered public utility holding companies under the 1935 Act. The money pool may not provide sufficient funds to meet our cash needs. Capital Requirements. We anticipate investing up to an aggregate $1.3 billion in capital expenditures in the years 2003 through 2007, including approximately $264 million and $279 million in 2003 and 2004, respectively. Cash Requirements in 2003. Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, and working capital needs. Our principal cash requirements during 2003 include the following: - approximately $264 million of capital expenditures; - the refinancing of borrowings under our $350 million bank facility; and - remarketing or refinancing of $500 million of debt, plus the possible payment of option termination costs (currently estimated to be $61 million) as discussed in "Quantitative and Qualitative Disclosures About Market Risk -- Interest Rate Risk" in Item 7A of this report. We expect to meet our capital requirements with cash flows from operations, short-term borrowings and proceeds from debt offerings. We believe that our current liquidity, along with anticipated cash flows from operations and proceeds from short-term borrowings, including the renewal, extension or replacement of existing bank facilities, and anticipated sales of securities in the capital markets will be sufficient to meet our cash needs. However, disruptions in our ability to access the capital markets on a timely basis could adversely affect our liquidity. In addition, the cost of our debt issuances may be high. Please read "Risk Factors -- Risks Related to Our Corporate and Financial Structure -- If we are unable to arrange future financings on reasonable terms, our ability to fund future capital expenditures and refinance existing indebtedness could be limited" in Item 1 of this report. Prior to the Restructuring, Reliant Energy obtained an order from the SEC that granted Reliant Energy certain authority with respect to financing, dividends and other matters. The financing authority granted by that order will expire on June 30, 2003, and CenterPoint Energy must obtain a further order from the SEC under the 1935 Act in order for it and its subsidiaries, including us, to engage in financing activities subsequent to that date. We have registered $50 million principal amount of debt securities with the SEC for future issuance. These debt securities may be sold in a public offering. The amount of any debt issuance, whether registered or unregistered, is expected to be affected by the market's perception of our creditworthiness, general market 18
conditions and factors affecting our industry. Proceeds from the sales of securities are expected to be used primarily to refinance existing long-term and short-term debt. The following table sets forth estimates of our contractual obligations to make future payments for 2003 through 2007 and thereafter (in millions):
territories served by our pipelines and distribution subsidiaries. In order to hedge its exposure to natural gas prices, CenterPoint Energy Gas Resources Corp. has agreements with provisions standard for the industry that establish credit thresholds and then require a party to provide additional collateral on two business days' notice when that party's rating or the rating of a credit support provider for that party (CERC Corp. in this case) falls below those levels. As of March 4, 2003, the senior unsecured debt of CERC Corp. was rated BBB by S&P and Ba1 by Moody's. Based on these ratings, we estimate that unsecured credit limits extended to CenterPoint Energy Gas Resources Corp. by counterparties could aggregate $25 million; however, utilized credit capacity is significantly lower. Cross Defaults. Our debentures and borrowings generally provide that a default on obligations by CenterPoint Energy does not cause a default under our debentures, revolving credit facility or receivables facility. A payment default at CERC Corp. exceeding $50 million will cause a default under CenterPoint Energy's $3.85 billion bank facility. Other Factors that Could Affect Cash Requirements. In addition to the above factors, our liquidity and capital resources could be affected by: - the potential need to provide cash collateral in connection with certain contracts; - acceleration of payment dates on certain gas supply contracts under certain circumstances; and - various regulatory actions. Capitalization. Factors affecting our capitalization include: - covenants in our bank facilities and other borrowing agreements; and - limitations imposed on us because our parent is a registered holding company. In connection with our parent company's registration as a public utility holding company under the 1935 Act, the SEC has limited the aggregate amount of our external borrowings to $2.7 billion. Our ability to pay dividends is restricted by the SEC's requirement that common equity as a percentage of total capitalization must be at least 30% after the payment of any dividend. In addition, the order restricts our ability to pay dividends out of capital accounts to the extent current or retained earnings are insufficient for those dividends. Under these restrictions, we are permitted to pay dividends in excess of the respective current or retained earnings in an amount up to $100 million. Relationship with CenterPoint Energy. We are an indirect wholly owned subsidiary of CenterPoint Energy. As a result of this relationship, the financial condition and liquidity of our parent company could affect our access to capital, our credit standing and our financial condition. Pension Plan. As discussed in Note 8(a) to the consolidated financial statements, we participate in CenterPoint Energy's qualified non-contributory pension plan covering substantially all employees. Pension expense for 2003 is estimated to be $36 million based on an expected return on plan assets of 9.0% and a discount rate of 6.75% as of December 31, 2002. Pension expense for the year ended December 31, 2002 was $13 million. Future changes in plan asset returns, assumed discount rates and various other factors related to the pension will impact our future pension expense and liabilities. We cannot predict with certainty what these factors will be in the future. OFF BALANCE SHEET FINANCING In connection with the November 2002 amendment and extension of our $150 million receivables facility, we formed a bankruptcy remote subsidiary for the sole purpose of buying and selling receivables created by us. This transaction described above is accounted for as a sale of receivables under the provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities", and, as a result, the related receivables are excluded from our Consolidated Balance Sheets. For additional information regarding this transaction, please read Note 3(i) to our consolidated financial statements. 20
CRITICAL ACCOUNTING POLICIES A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We believe the following accounting policies involve the application of critical accounting estimates. IMPAIRMENT OF LONG-LIVED ASSETS Long-lived assets recorded in our Consolidated Balance Sheets primarily consist of property, plant and equipment (PP&E). Net PP&E comprises $3.2 billion or 54% of our total assets as of December 31, 2002. We make judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and useful lives. We evaluate our PP&E for impairment whenever indicators of impairment exist. During 2002, no such indicators of impairment existed. Accounting standards require that if the sum of the undiscounted expected future cash flows from a company's asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. The amount of impairment recognized is calculated by subtracting the fair value of the asset from the carrying value of the asset. IMPAIRMENT OF GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS We evaluate our goodwill and other indefinite-lived intangible assets for impairment at least annually and more frequently when indicators of impairment exist. Accounting standards require that if the fair value of a reporting unit is less than its carrying value, including goodwill, a charge for impairment of goodwill must be recognized. To measure the amount of the impairment loss, we compare the implied fair value of the reporting unit's goodwill with its carrying value. We recorded goodwill associated with the acquisition of our Natural Gas Distribution and Pipelines and Gathering operations in 1997. We reviewed our goodwill for impairment as of January 1, 2002. We computed the fair value of the Natural Gas Distribution and the Pipelines and Gathering operations as the sum of the discounted estimated net future cash flows applicable to each of these operations. We determined that the fair value for each of the Natural Gas Distribution operations and the Pipelines and Gathering operations exceeded their corresponding carrying value, including unallocated goodwill. We also concluded that no interim impairment indicators existed subsequent to this initial evaluation. As of December 31, 2002 we had recorded $1.7 billion of goodwill. Future evaluations of the carrying value of goodwill could be significantly impacted by our estimates of cash flows associated with our Natural Gas Distribution and Pipelines and Gathering operations, regulatory matters, and estimated operating costs. 21
UNBILLED REVENUES Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of natural gas delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. Accrued unbilled revenues recorded in the Consolidated Balance Sheet as of December 31, 2001 and 2002 were $269 million and $284 million, respectively, related to our Natural Gas Distribution business segment. NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations" (SFAS No. 141). SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting and broadens the criteria for recording intangible assets separate from goodwill. Recorded goodwill and intangibles will be evaluated against these new criteria and may result in certain intangibles being transferred to goodwill, or alternatively, amounts initially recorded as goodwill may be separately identified and recognized apart from goodwill. We adopted the provisions of the statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 on January 1, 2002. The adoption of SFAS No. 141 did not have any impact on our historical results of operations or financial position. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of an asset retirement obligation to be recognized as a liability is incurred and capitalized as part of the cost of the related tangible long-lived assets. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. SFAS No. 143 requires entities to record a cumulative effect of change in accounting principle in the income statement in the period of adoption. We adopted SFAS No. 143 on January 1, 2003. We have completed an assessment of the applicability and implications of SFAS No. 143 and have identified no asset retirement obligations. Our rate-regulated businesses have previously recognized removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2002, these previously recognized removal costs of $378 million do not represent SFAS No. 143 asset retirement obligations, but rather embedded regulatory liabilities. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," (SFAS No. 144). SFAS No. 144 provides new guidance on the recognition of impairment losses on long-lived assets to be held and used or to be disposed of and also broadens the definition of what constitutes a discontinued operation and how the results of a discontinued operation are to be measured and presented. SFAS No. 144 supercedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and APB Opinion No. 30, while retaining many of the requirements of these two statements. Under SFAS No. 144, assets held for sale that are a component of an entity will be included in discontinued operations if the operations and cash flows will be or have been eliminated from the ongoing operations of the entity and the entity will not have any significant continuing involvement in the operations prospectively. SFAS No. 144 was effective for fiscal years beginning after December 15, 2001, with early adoption encouraged. SFAS No. 144 did not materially change the methods we use to measure impairment losses on long-lived assets, but may result in additional future dispositions being reported as discontinued operations than was previously permitted. We adopted SFAS No. 144 on January 1, 2002. 22
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent. SFAS No. 145 also requires that capital leases that are modified so that the resulting lease agreement is classified as an operating lease be accounted for as a sale-leaseback transaction. The changes related to debt extinguishment are effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting are effective for transactions occurring after May 15, 2002. We have applied this guidance prospectively. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)" (EITF No. 94-3). The principal difference between SFAS No. 146 and EITF No. 94-3 relates to the requirements for recognition of a liability for costs associated with an exit or disposal activity. SFAS No. 146 requires that a liability be recognized for a cost associated with an exit or disposal activity when it is incurred. A liability is incurred when a transaction or event occurs that leaves an entity little or no discretion to avoid the future transfer or use of assets to settle the liability. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. In addition, SFAS No. 146 also requires that a liability for a cost associated with an exit or disposal activity be recognized at its fair value when it is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002 with early application encouraged. We will apply the provisions of SFAS No. 146 to all exit or disposal activities initiated after December 31, 2002. In June 2002, the Emerging Issues Task Force ("EITF") reached a consensus that all mark-to-market gains and losses on energy trading contracts should be shown net in the statement of consolidated income whether or not settled physically. In October 2002, the EITF issued a consensus that superceded the June 2002 consensus. The October 2002 consensus required, among other things, that energy derivatives held for trading purposes be shown net in the statement of consolidated income. This new consensus, EITF 02-3 "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," is effective for fiscal periods beginning after December 15, 2002. Our former subsidiaries, RESI, RE Europe Trading and Reliant Energy Services entered into energy derivatives held for trading purposes. On December 31, 2000, these subsidiaries were either sold or transferred to Reliant Resources, an unconsolidated related party. See Note 2 to our consolidated financial statements. For financial periods beginning subsequent to December 31, 2002, we will retroactively restate the financial statement presentation of these energy trading activities. For the year ended December 31, 2000, RESI, RE Europe Trading, and Reliant Energy Services reported combined revenues and natural gas and purchased power expenses of $17.6 billion and $17.4 billion, respectively. We are currently evaluating the effects on our Statements of Consolidated Income of the net presentation of these trading activities for the year ended December 31, 2000. Such presentation will not affect previously reported operating income or net income. In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of certain guarantees. In addition, FIN 45 requires disclosures about the guarantees that an entity has issued. The provision for initial recognition and measurement of the liability will be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure provisions of FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. The adoption of FIN 45 is not expected to materially affect our consolidated financial statements. We have adopted the additional disclosure provisions of FIN 45 in our consolidated financial statements as of December 31, 2002. In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51" (FIN 46). FIN 46 requires certain variable interest entities to be 23
consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. We do not expect the adoption of FIN 46 to have a material impact on our results of operations and financial condition. Please read Note 5 to our consolidated financial statements for a discussion of our adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133) on January 1, 2001 and adoption of subsequent cleared guidance. Please read Note 3(d) to our consolidated financial statements for a discussion of our adoption of SFAS No. 142. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. IMPACT OF CHANGES IN INTEREST RATES AND ENERGY COMMODITY PRICES We are exposed to various market risks. These risks arise from transactions entered into in the normal course of business and are inherent in our consolidated financial statements. Most of the revenues and income from our business activities are impacted by market risks. Categories of market risk include exposure to commodity prices through non-trading activities, interest rates and equity prices. A description of each market risk is set forth below: - Commodity price risk results from exposures to changes in spot prices, forward prices and price volatilities of commodities, such as natural gas and other energy commodities risk. - Interest rate risk primarily results from exposures to changes in the level of borrowings and changes in interest rates. - Equity price risk results from exposures to changes in prices of individual equity securities. Management has established comprehensive risk management policies to monitor and manage these market risks. We seek to manage these risk exposures through the implementation of our risk management policies and framework. We seek to manage our exposures through the use of derivative financial instruments and derivative commodity instrument contracts. During the normal course of business, we review our hedging strategies and determine the hedging approach we deem appropriate based upon the circumstances of each situation. Derivative instruments such as futures, forward contracts, swaps and options derive their value from underlying assets, indices, reference rates or a combination of these factors. These derivative instruments include negotiated contracts, which are referred to as over-the-counter derivatives, and instruments that are listed and traded on an exchange. Derivative transactions are entered into in our non-trading operations to manage and hedge certain exposures, such as exposure to changes in gas prices. We believe that the associated market risk of these instruments can best be understood relative to the underlying assets or risk being hedged. INTEREST RATE RISK We have outstanding long-term debt, mandatorily redeemable preferred securities of subsidiary trusts holding solely our junior subordinated debentures (trust preferred securities), bank facilities, and some lease obligations which subject us to the risk of loss associated with movements in market interest rates. Our floating-rate obligations aggregated $0.3 billion in each of the years ended December 31, 2001 and 2002, (please read Note 6 to our consolidated financial statements), inclusive of (a) amounts borrowed under our short-term credit facilities, (b) amounts obtained under a receivables facility and (c) borrowings from affiliates. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rates were to increase by 10% from their levels at 24
December 31, 2002, our combined interest expense would increase by an immaterial amount each month in which such increase continued. At December 31, 2001 and 2002, we had outstanding fixed-rate debt and trust preferred securities aggregating $1.9 billion and $2.0 billion, respectively, in principal amount and having a fair value of $1.9 billion and $2.1 billion, respectively. These instruments are fixed-rate and, therefore, do not expose us to the risk of loss in earnings due to changes in market interest rates (please read Notes 6 and 7 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $44 million if interest rates were to decline by 10% from their levels at December 31, 2002. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity. As discussed in Note 6(b) to our consolidated financial statements, our $500 million aggregate principal amount of 6 3/8% Term Enhanced Remarketable Securities (TERM Notes) include an embedded option to remarket the securities. The option is expected to be exercised in the event that the ten-year Treasury rate in 2003 is below 5.66%. At December 31, 2002, we could terminate the option at a cost of $61 million. A decrease of 10% in the December 31, 2002 level of interest rates would increase the cost of terminating the option by approximately $17 million. COMMODITY PRICE RISK FROM NON-TRADING ACTIVITIES To reduce our commodity price risk from market fluctuations in the revenues derived from the sale of natural gas and related transportation, we enter into forward contracts, swaps and options (Non-Trading Energy Derivatives) in order to hedge some expected purchases of natural gas and sales of natural gas (a portion of which are firm commitments at the inception of the hedge). Non-Trading Energy Derivatives are also utilized to fix the price of compressor fuel or other future operational gas requirements and to protect natural gas distribution earnings against unseasonably warm weather during peak gas heating months, although usage to date for this purpose has not been material. We use derivative instruments as economic hedges to offset the commodity exposure inherent in our businesses. The stand-alone commodity risk created by these instruments, without regard to the offsetting effect of the underlying exposure these instruments are intended to hedge, is described below. We measure the commodity risk of our Non-Trading Energy Derivatives using a sensitivity analysis. The sensitivity analysis performed on our Non-Trading Energy Derivatives measures the potential loss in earnings based on a hypothetical 10% movement in energy prices. An increase of 10% in the market prices of energy commodities from their December 31, 2001 levels would have decreased the fair value of our Non-Trading Energy Derivatives by $14 million. A decrease of 10% in the market prices of energy commodities from their December 31, 2002 levels would have decreased the fair value of our Non-Trading Energy Derivatives by $12 million. The above analysis of the Non-Trading Energy Derivatives utilized for hedging purposes does not include the favorable impact that the same hypothetical price movement would have on our physical purchases and sales of natural gas to which the hedges relate. Furthermore, the Non-Trading Energy Derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of Non-Trading Energy Derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions, assuming: - the Non-Trading Energy Derivatives are not closed out in advance of their expected term; - the Non-Trading Energy Derivatives continue to function effectively as hedges of the underlying risk; and - as applicable, anticipated underlying transactions settle as expected. If any of the above-mentioned assumptions ceases to be true, a loss on the derivative instruments may occur, or the options might be worthless as determined by the prevailing market value on their termination or 25
maturity date, whichever comes first. Non-Trading Energy Derivatives designated and effective as hedges, may still have some percentage which is not effective. The change in value of the Non-Trading Energy Derivatives that represents the ineffective component of the hedges is recorded in our results of operations. During 2002, we recognized a $0.9 million loss as a result of the discontinuance of a cash flow hedge because it was no longer probable that the forecasted transaction would occur. CenterPoint Energy has established a Risk Oversight Committee, comprised of corporate and business segment officers, that oversees all commodity price and credit risk activities, including CenterPoint Energy's trading, marketing, risk management services and hedging activities. The committee's duties are to establish CenterPoint Energy's commodity risk policies, allocate risk capital, approve trading of new products and commodities, monitor risk positions and ensure compliance with the risk management policies and procedures and trading limits established by CenterPoint Energy's board of directors. CenterPoint Energy's policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument. 26
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) STATEMENTS OF CONSOLIDATED INCOME
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) CONSOLIDATED BALANCE SHEETS
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) STATEMENTS OF CONSOLIDATED CASH FLOWS
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) STATEMENTS OF CONSOLIDATED STOCKHOLDER'S EQUITY
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BACKGROUND AND BASIS OF PRESENTATION CenterPoint Energy Resources Corp. (CERC Corp.) formerly named Reliant Energy Resources Corp. (RERC Corp.), together with its subsidiaries (collectively, CERC), distributes natural gas, transports natural gas through its interstate pipelines and provides natural gas gathering and pipeline services. Prior to 2001, CERC provided energy services including wholesale energy trading, marketing, power origination and risk management services in North America and Western Europe. CERC Corp. is a Delaware corporation and an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy). CERC's natural gas distribution operations (Natural Gas Distribution) are conducted by three unincorporated divisions CenterPoint Energy Entex (Entex), CenterPoint Energy Minnegasco (Minnegasco) and CenterPoint Energy Arkla (Arkla) and other non-rate regulated retail gas marketing operations. CERC's pipelines and gathering operations (Pipelines and Gathering) are primarily conducted by two wholly owned pipeline subsidiaries, CenterPoint Energy Gas Transmission Company (CEGT) and CenterPoint Energy-Mississippi River Transmission Corporation (MRT), and a wholly owned gas gathering subsidiary, CenterPoint Energy Field Services, Inc. (CEFS). CERC's principal operations are located in Arkansas, Louisiana, Minnesota, Mississippi, Missouri, Oklahoma and Texas. Wholesale energy trading, marketing, power origination and risk management activities in North America were conducted primarily by Reliant Energy Services, Inc. (Reliant Energy Services), a wholly owned subsidiary of CERC prior to January 1, 2001. European energy trading and marketing activities were conducted by Reliant Energy Europe Trading & Marketing, Inc. (RE Europe Trading), an indirect wholly owned subsidiary of CERC Corp. prior to January 1, 2001. See Note 2 regarding the Restructuring. 2. THE RESTRUCTURING Reliant Energy, Incorporated (Reliant Energy) completed the separation of the generation, transmission and distribution, and retail sales functions of Reliant Energy's Texas electric operations pursuant to the following steps, which occurred on August 31, 2002 (the Restructuring): - CenterPoint Energy became the holding company for the Reliant Energy group of companies; - Reliant Energy and its subsidiaries, including CERC, became subsidiaries of CenterPoint Energy; and - each share of Reliant Energy common stock was converted into one share of CenterPoint Energy common stock. After the Restructuring, CenterPoint Energy distributed to its shareholders the shares of common stock of Reliant Resources, Inc. (Reliant Resources) that it owned (the Distribution) in a tax-free transaction. Contemporaneous with the Restructuring, CenterPoint Energy registered and became subject, with its subsidiaries, to regulation as a registered holding company system under the Public Utility Holding Company Act of 1935 (1935 Act). The 1935 Act directs the Securities and Exchange Commission (SEC) to regulate, among other things, transactions among affiliates, sales or acquisitions of assets, issuances of securities, distributions and permitted lines of business. Prior to the Restructuring, CenterPoint Energy and Reliant Energy obtained an order from the SEC that authorized the Restructuring transactions, including the Distribution, and granted CenterPoint Energy certain authority with respect to system financing, dividends and other matters. The financing authority granted by that order will expire on June 30, 2003, and CenterPoint Energy must obtain a further order from the SEC under the 1935 Act, related, among other things, to the financing activities of CenterPoint Energy and its subsidiaries subsequent to June 30, 2003. 32
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In connection with CenterPoint Energy's registration as a public utility holding company under the 1935 Act, the SEC has limited the aggregate amount of CERC's external borrowings to $2.7 billion. CERC's ability to pay dividends is restricted by the SEC's requirement that common equity as a percentage of total capitalization must be at least 30% after the payment of any dividend. In addition, the order restricts CERC's ability to pay dividends out of capital accounts to the extent current or retained earnings are insufficient for those dividends. Under these restrictions, CERC is permitted to pay dividends in excess of the respective current or retained earnings in an amount up to $100 million. In 2002, CERC obtained authority from each state in which such authority was required to restructure in a manner that would allow CenterPoint Energy to claim an exemption from registration under the 1935 Act. CenterPoint Energy has concluded that a restructuring would not be beneficial and has elected to remain a registered holding company under the 1935 Act. On December 31, 2000, CERC Corp. transferred all of the outstanding capital stock (collectively, the Stock Transfer) of Reliant Energy Services International, Inc. (RESI), Arkla Finance Corporation (Arkla Finance) and RE Europe Trading, all wholly owned subsidiaries of CERC Corp., to Reliant Resources. Both CERC Corp. and Reliant Resources were wholly owned subsidiaries of Reliant Energy at that time. As a result of the Stock Transfer, RESI, Arkla Finance and RE Europe Trading each became a wholly owned subsidiary of Reliant Resources. Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources merged with and into Reliant Energy Services, a wholly owned subsidiary of CERC Corp., with Reliant Energy Services as the surviving corporation (Merger). As a result of the Merger, Reliant Energy Services became a wholly owned subsidiary of Reliant Resources. As consideration for the Merger, Reliant Resources paid $94 million to CERC Corp. Prior to January 1, 2001, Reliant Energy Services, RESI and RE Europe Trading conducted the trading, marketing, power origination and risk management business and operations of CERC Corp. Arkla Finance is a company that holds an investment in marketable equity securities. The Stock Transfer and the Merger were part of the Restructuring. CERC accounted for the Stock Transfer and the Merger as the sale of a business operation. Accordingly, the CERC consolidated financial statements include the financial position and results of operations for the subsidiaries included in these transactions for all periods prior to December 31, 2000. CERC is reporting the results of RE Europe Trading as discontinued operations for all periods presented in CERC's consolidated financial statements in accordance with Accounting Principles Board (APB) Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" (APB Opinion No. 30). 3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) RECLASSIFICATIONS AND USE OF ESTIMATES Some amounts from the previous years have been reclassified to conform to the 2002 presentation of financial statements. These reclassifications do not affect net income. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, 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. Actual results could differ from those estimates. 33
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (b) PRINCIPLES OF CONSOLIDATION The accounts of CERC Corp. and its wholly owned and majority owned subsidiaries are included in CERC's consolidated financial statements. All significant intercompany transactions and balances are eliminated. Other investments, excluding marketable securities, are carried at cost. (c) REVENUES CERC records natural gas sales and services under the accrual method and these revenues are generally recognized upon delivery. Natural gas sales and services not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. Pipelines and Gathering records revenues as transportation services are provided. In 2000, Reliant Energy Services' energy trading and marketing operations were accounted for under mark-to-market accounting, as discussed in Note 5. (d) LONG-LIVED ASSETS AND INTANGIBLES CERC records property, plant and equipment at historical cost. CERC expenses all repair and maintenance costs as incurred. The cost of utility plant and equipment retirements is charged to accumulated depreciation. Property, plant and equipment includes the following:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The components of CERC's other intangible assets consist of the following:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) provide $2 million of additional gross revenue in 2003 and additional amounts in subsequent years. The new rates included in the final settlement were effective with all bills rendered on and after September 21, 2002. Oklahoma Rate Case In May 2002, Arkla filed a request in Oklahoma to increase its base rates by $13.7 million annually. In December 2002, a settlement was approved by the Oklahoma Corporation Commission that is expected to result in an increase in base rates of approximately $7.3 million annually. The new rates included in the final settlement were effective with all bills rendered on and after December 29, 2002. (f) DEPRECIATION AND AMORTIZATION EXPENSE Depreciation is computed using the straight-line method based on economic lives or a regulatory mandated recovery period. Other amortization expense includes amortization of regulatory assets and other intangibles. The following table presents depreciation, goodwill amortization and other amortization expense for 2000, 2001 and 2002:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In the first quarter of 2002, CERC reduced its trade receivables facility from $350 million to $150 million. During 2001 and 2002, CERC sold its customer accounts receivable and utilized $346 million of its $350 million receivables facility at December 31, 2001 and $107 million of its $150 million receivables facility at December 31, 2002. The amount of receivables sold will fluctuate based on the amount of receivables created by CERC Corp. In connection with CERC's November 2002 amendment and extension of its receivables facility, CERC Corp. formed a bankruptcy remote subsidiary for the sole purpose of buying and selling receivables created by CERC. This transaction is accounted for as a sale of receivables under the provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities", and, as a result, the related receivables are excluded from the Consolidated Balance Sheets. (j) INVENTORY Inventory consists principally of materials and supplies and natural gas and is valued at the lower of average cost or market. Inventory includes the following components:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (n) CHANGES IN ACCOUNTING PRINCIPLES AND NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS No. 141). SFAS No. 141 requires business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting and broadens the criteria for recording intangible assets separate from goodwill. Recorded goodwill and intangibles will be evaluated against these new criteria and may result in certain intangibles being transferred to goodwill, or alternatively, amounts initially recorded as goodwill may be separately identified and recognized apart from goodwill. CERC adopted the provisions of the statement which apply to goodwill and intangible assets acquired prior to June 30, 2001 on January 1, 2002. The adoption of SFAS No. 141 did not have any impact on CERC's historical results of operations or financial position. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of an asset retirement obligation to be recognized as a liability is incurred and capitalized as part of the cost of the related tangible long-lived assets. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. SFAS No. 143 requires entities to record a cumulative effect of change in accounting principle in the income statement in the period of adoption. CERC adopted SFAS No. 143 on January 1, 2003. CERC has completed an assessment of the applicability and implications of SFAS No. 143 and has identified no asset retirement obligations. CERC's rate-regulated businesses have previously recognized removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2002, these previously recognized removal costs of $378 million do not represent SFAS No. 143 asset retirement obligations, but rather embedded regulatory liabilities. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," (SFAS No. 144). SFAS No. 144 provides new guidance on the recognition of impairment losses on long-lived assets to be held and used or to be disposed of and also broadens the definition of what constitutes a discontinued operation and how the results of a discontinued operation are to be measured and presented. SFAS No. 144 supercedes SFAS No. 121 and APB Opinion No. 30, while retaining many of the requirements of these two statements. Under SFAS No. 144, assets held for sale that are a component of an entity will be included in discontinued operations if the operations and cash flows will be or have been eliminated from the ongoing operations of the entity and the entity will not have any significant continuing involvement in the operations prospectively. SFAS No. 144 did not materially change the methods used by CERC to measure impairment losses on long-lived assets but may result in more future dispositions being reported as discontinued operations than would previously have been permitted. CERC adopted SFAS No. 144 on January 1, 2002. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent. SFAS No. 145 also requires that capital leases that are modified so that the resulting lease agreement is classified as an operating lease be accounted for as a sale-leaseback transaction. The changes related to debt extinguishment are effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting are effective for transactions occurring after May 15, 2002. CERC has applied this guidance prospectively. 38
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 nullifies EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)" (EITF No. 94-3). The principal difference between SFAS No. 146 and EITF No. 94-3 relates to the requirements for recognition of a liability for costs associated with an exit or disposal activity. SFAS No. 146 requires that a liability be recognized for a cost associated with an exit or disposal activity when it is incurred. A liability is incurred when a transaction or event occurs that leaves an entity little or no discretion to avoid the future transfer or use of assets to settle the liability. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. In addition, SFAS No. 146 also requires that a liability for a cost associated with an exit or disposal activity be recognized at its fair value when it is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002 with early application encouraged. CERC will apply the provisions of SFAS No. 146 to all exit or disposal activities initiated after December 31, 2002. In June 2002, the Emerging Issues Task Force ("EITF") reached a consensus that all mark-to-market gains and losses on energy trading contracts should be shown net in the statement of consolidated income whether or not settled physically. In October 2002, the EITF issued a consensus that superceded the June 2002 consensus. The October 2002 consensus required, among other things, that energy derivatives held for trading purposes be shown net in the statement of consolidated income. This new consensus, EITF 02-3 "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," is effective for fiscal periods beginning after December 15, 2002. CERC's former subsidiaries, RESI, RE Europe Trading and Reliant Energy Services entered into energy derivatives held for trading purposes. On December 31, 2000, these subsidiaries were either sold or transferred to Reliant Resources, an unconsolidated related party (see Note 2). For financial periods beginning subsequent to December 31, 2002, CERC will retroactively restate the financial statement presentation of these energy trading activities. For the year ended December 31, 2000, RESI, RE Europe Trading, and Reliant Energy Services reported combined revenues and natural gas and purchased power expenses of $17.6 billion and $17.4 billion, respectively. CERC is currently evaluating the effects on its Statements of Consolidated Income of the net presentation of these trading activities for the year ended December 31, 2000. Such presentation will not affect previously reported operating income or net income. In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 requires that a liability be recorded in the guarantor's balance sheet upon issuance of certain guarantees. In addition, FIN 45 requires disclosures about the guarantees that an entity has issued. The provision for initial recognition and measurement of the liability will be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure provisions of FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. The adoption of FIN 45 is not expected to materially affect CERC's consolidated financial statements. CERC has adopted the additional disclosure provisions of FIN 45 in its consolidated financial statements as of December 31, 2002. In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51" (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual 39
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) period beginning after June 15, 2003. CERC does not expect the adoption of FIN 46 to have a material impact on its results of operations and financial condition. See Note 5 for a discussion of CERC's adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), on January 1, 2001 and adoption of subsequent cleared guidance. See Note 3(d) for a discussion of CERC's adoption of SFAS No. 142 on January 1, 2002. 4. RELATED PARTY TRANSACTIONS From time to time, CERC has advanced money to, or borrowed money from, CenterPoint Energy or its subsidiaries. As of December 31, 2001, CERC had net short-term receivables, included in accounts and notes receivable-affiliated companies, of $132 million, partially offset by net accounts payable of $93 million. As of December 31, 2002, CERC had net short-term borrowings, included in accounts and notes payable-affiliated companies, of $74 million and net accounts payable of $27 million. As of December 31, 2001, CERC had net long-term receivables, included in notes receivable-affiliated companies, totaling $3 million. As of December 31, 2002, CERC had net long-term receivables, included in notes receivable-affiliated companies, of $39 million. In February 2001, CERC Corp. paid a dividend to CenterPoint Energy from the proceeds of a debt offering as discussed in Note 6(b). In May 2001, CenterPoint Energy made a $236 million capital contribution to CERC Corp., and CERC Corp. subsequently invested the $236 million with an affiliate. In August 2002, CERC paid a dividend of $350 million to CenterPoint Energy in the form of an intercompany note payable. In October 2002, CERC paid the intercompany note payable. Substantially all of the funds for repayment were obtained from borrowings under CERC Corp.'s revolving credit facility. For the years ended December 31, 2000 and 2001, CERC had net interest income related to affiliate borrowings of $3 million and $5 million, respectively. For the year ended December 31, 2002, CERC had net interest expense related to affiliate borrowings of $2 million. In 2000, Reliant Energy Services supplied natural gas to, purchased electricity for resale from, and provided marketing and risk management services to, unregulated power plants in deregulated markets acquired or operated by Reliant Energy Power Generation, Inc., an indirect wholly owned subsidiary of Reliant Energy, or its subsidiaries. In 2001 and 2002, CERC supplied natural gas to Reliant Energy Services, a subsidiary of Reliant Resources. During 2000, 2001 and 2002, the sales and services by CERC to Reliant Resources and its subsidiaries totaled $816 million, $181 million and $42 million, respectively. During 2002, the sales and services by CERC to CenterPoint Energy and its affiliates totaled $28 million. Purchases of natural gas by CERC from Reliant Resources and its subsidiaries were $391 million, $639 million and $204 million in 2000, 2001 and 2002, respectively. CenterPoint Energy provides some corporate services to CERC. The costs of services have been directly charged to CERC using methods that management believes to be reasonable. These methods include negotiated usage rates, dedicated asset assignment, and proportionate corporate formulas based on assets, operating expenses and employees. These charges are not necessarily indicative of what would have been incurred had CERC not been an affiliate. Amounts charged to CERC for these services were $71 million, $72 million and $107 million for 2000, 2001 and 2002, respectively, and are included primarily in operation and maintenance expenses. The 1935 Act generally prohibits borrowings by CenterPoint Energy from its subsidiaries, including CERC. 40
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. DERIVATIVE INSTRUMENTS Effective January 1, 2001, CERC adopted SFAS No. 133, which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement requires that derivatives be recognized at fair value in the balance sheet and that changes in fair value be recognized either currently in earnings or deferred as a component of other comprehensive income, depending on the intended use of the derivative instrument as hedging (a) the exposure to changes in the fair value of an asset or liability (Fair Value Hedge), (b) the exposure to variability in expected future cash flows (Cash Flow Hedge), or (c) the foreign currency exposure of a net investment in a foreign operation. For a derivative not designated as a hedging instrument, the gain or loss is recognized in earnings in the period it occurs. Adoption of SFAS No. 133 on January 1, 2001 resulted in a cumulative after-tax increase in accumulated other comprehensive income of $38 million. The adoption also increased current assets, long-term assets, current liabilities and long-term liabilities by approximately $88 million, $5 million, $53 million and $2 million, respectively, in CERC's Consolidated Balance Sheet. CERC is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CERC utilizes derivative financial instruments such as physical forward contracts, swaps and options (Energy Derivatives) to mitigate the impact of changes and cash flows of its natural gas businesses on its operating results and cash flows. (a) Non-Trading Activities Cash Flow Hedges. To reduce the risk from market fluctuations associated with purchased gas costs, CERC enters into energy derivatives in order to hedge certain expected purchases and sales of natural gas. CERC applies hedge accounting for its non-trading energy derivatives utilized in non-trading activities only if there is a high correlation between price movements in the derivative and the item designated as being hedged. CERC analyzes its physical transaction portfolio to determine its net exposure by delivery location and delivery period. Because CERC's physical transactions with similar delivery locations and periods are highly correlated and share similar risk exposures, CERC facilitates hedging for customers by aggregating physical transactions and subsequently entering into non-trading energy derivatives to mitigate exposures created by the physical positions. During 2002, no hedge ineffectiveness was recognized in earnings from derivatives that are designated and qualify as Cash Flow Hedges. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, CERC realizes in net income the deferred gains and losses recognized in accumulated other comprehensive income. During the year ended December 31, 2002, there was a $0.9 million deferred loss recognized in earnings as a result of the discontinuance of cash flow hedges because it was no longer probable that the forecasted transaction would occur. Once the anticipated transaction occurs, the accumulated deferred gain or loss recognized in accumulated other comprehensive income is reclassified and included in CERC's Statements of Consolidated Income under the caption "Natural Gas and Purchased Power." Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of December 31, 2002, CERC expects $17 million in accumulated other comprehensive income to be reclassified into net income during the next twelve months. The maximum length of time CERC is hedging its exposure to the variability in future cash flows for forecasted transactions on existing financial instruments is primarily two years with a limited amount of exposure up to three years. CERC's policy is not to exceed five years in hedging its exposure. 41
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (b) CREDIT RISKS In addition to the risk associated with price movements, credit risk is also inherent in CERC's non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of the non-trading derivative assets of CERC as of December 31, 2001 and 2002:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 6. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The money pool's net funding requirements are generally met with short-term borrowings of CenterPoint Energy. The terms of the money pool are in accordance with requirements applicable to registered public utility holding companies under the 1935 Act. The weighted average interest rate on external short-term borrowings as of December 31, 2001 and 2002 was 2.0% and 1.7%, respectively. (b) LONG-TERM DEBT Consolidated maturities of long-term debt and sinking fund requirements for CERC are $518 million in 2003 (of which $500 million may be remarketed by an option holder to a maturity of 2013), $1 million in 2004, $368 million in 2005, $152 million in 2006 and $7 million in 2007. The 2003 and 2004 amounts are net of accumulated sinking fund payments that can be satisfied with bonds that had been acquired and retired as of December 31, 2002. At December 31, 2001 and 2002, CERC Corp. had issued and outstanding $86 million and $79 million, respectively, aggregate principal amount ($82 million and $76 million, respectively, carrying amount) of its 6% Convertible Subordinated Debentures due 2012 (Subordinated Debentures). The holders of the Subordinated Debentures receive interest quarterly and, prior to the Restructuring, had the right at any time on or before the maturity date thereof to convert each $50 Subordinated Debenture into 0.65 shares of Reliant Energy common stock and $14.24 in cash. After the Restructuring, but prior to the Distribution, each $50 Subordinated Debenture was convertible into 0.65 shares of CenterPoint Energy common stock and $14.24 in cash. The Distribution and the Texas Genco stock distribution changed the conversion rights for each Subordinated Debenture as follows:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) investment bank prior to remarketing. If the TERM Notes are remarketed, the final maturity date of the TERM Notes will be November 1, 2013, subject to adjustment, and the effective interest rate on the remarketed TERM Notes will be 5.66% plus CERC Corp.'s applicable credit spread at the time of such remarketing. In February 2001, CERC Corp. issued $550 million of unsecured notes that bear interest at 7.75% per year and mature in February 2011. Net proceeds to CERC Corp. were $545 million. CERC Corp. used the net proceeds from the sale of the notes to pay a $400 million dividend to CenterPoint Energy and for general corporate purposes. CenterPoint Energy used the $400 million proceeds from the dividend for general corporate purposes, including the repayment of short-term borrowings. A subsidiary of CERC Corp. had an agreement (ANR Agreement) with ANR Pipeline Company (ANR) that contemplated that this subsidiary would transfer to ANR an interest in some of CERC Corp.'s pipeline and related assets. In 2001, this subsidiary was transferred to Reliant Resources as a result of CenterPoint Energy's planned divestiture of certain unregulated business operations. However, CERC retained the pipelines covered by the ANR Agreement. Therefore, the subsequent divestiture of Reliant Resources by CenterPoint Energy on September 30, 2002, resulted in a conversion of CERC's obligation to ANR into an obligation to Reliant Resources. As of December 31, 2001, CERC had recorded $41 million in long-term debt and as of December 31, 2002, CERC had recorded $5 million and $36 million in current portion of long-term debt and long-term debt, respectively, in CERC's Consolidated Balance Sheets to reflect this obligation for the use of 130 million cubic feet (Mmcf)/day of capacity in some of CERC's transportation facilities. The volume of transportation will decline to 100 Mmcf/day in the year 2003 with a refund by CERC of $5 million to Reliant Resources. The ANR Agreement will terminate in 2005 with a refund of $36 million to Reliant Resources. (c) RESTRICTIONS ON DEBT CERC Corp.'s credit facilities contain various business and financial covenants requiring CERC Corp. to, among other things, maintain leverage (as defined in the credit facilities), below specified ratios. These covenants are not anticipated to materially restrict CERC Corp. from borrowing funds or obtaining letters of credit under these facilities. As of December 31, 2002, CERC Corp. was in compliance with these debt covenants. 7. TRUST PREFERRED SECURITIES In June 1996, a Delaware statutory business trust created by CERC Corp. (CERC Trust) issued $173 million aggregate amount of convertible preferred securities to the public. CERC Corp. accounts for CERC Trust as a wholly owned consolidated subsidiary. CERC Trust used the proceeds of the offering to purchase convertible junior subordinated debentures issued by CERC Corp. having an interest rate and maturity date that correspond to the distribution rate and mandatory redemption date of the convertible preferred securities. The convertible junior subordinated debentures represent CERC Trust's sole asset and its entire operations. CERC Corp. considers its obligation under the Amended and Restated Declaration of Trust, Indenture and Guaranty Agreement relating to the convertible preferred securities, taken together, to constitute a full and unconditional guarantee by CERC Corp. of CERC Trust's obligations with respect to the convertible preferred securities. The convertible preferred securities are mandatorily redeemable upon the repayment of the convertible junior subordinated debentures at their stated maturity or earlier redemption. Effective January 7, 2003, the convertible preferred securities are convertible at the option of the holder into $33.62 of cash and 2.34 shares of CenterPoint Energy common stock for each $50 of liquidation value. As of December 31, 2001 and 2002, $0.4 million liquidation amount of convertible preferred securities were outstanding. The securities, and their 45
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) underlying convertible junior subordinated debentures, bear interest at 6.25% and mature in June 2026. Subject to some limitations, CERC Corp. has the option of deferring payments of interest on the convertible junior subordinated debentures. During any deferral or event of default, CERC Corp. may not pay dividends on its common stock to CenterPoint Energy. As of December 31, 2002, no interest payments on the convertible junior subordinated debentures had been deferred. 8. EMPLOYEE BENEFIT PLANS (a) PENSION PLANS Substantially all of CERC's employees participate in CenterPoint Energy's qualified non-contributory pension plan. Under the cash balance formula, participants accumulate a retirement benefit based upon 4% of eligible earnings and accrued interest. Prior to 1999, the pension plan accrued benefits based on years of service, final average pay and covered compensation. As a result, certain employees participating in the plan as of December 31, 1998 are eligible to receive the greater of the accrued benefit calculated under the prior plan through 2008 or the cash balance formula. CenterPoint Energy's funding policy is to review amounts annually in accordance with applicable regulations in order to achieve adequate funding of projected benefit obligations. Pension expense is allocated to CERC based on covered employees. This calculation is intended to allocate pension costs in the same manner as a separate employer plan. Assets of the plan are not segregated or restricted by CenterPoint Energy's participating subsidiaries. Pension benefit was $21 million for the year ended December 31, 2000. CERC recognized pension expense of $1 million and $13 million for the years ended December 31, 2001 and 2002, respectively. In addition to the Plan, CERC participates in CenterPoint Energy's non-qualified pension plan, which allows participants to retain the benefits to which they would have been entitled under the qualified pension plan except for federally mandated limits on these benefits or on the level of salary on which these benefits may be calculated. The expense associated with the non-qualified pension plan was $13 million, $5 million and $2 million for the years ended December 31, 2000, 2001 and 2002, respectively. As of December 31, 2001, CenterPoint Energy allocated $94 million of pension assets, $40 million of non-qualified pension liabilities and $2 million minimum pension liabilities to CERC. As of December 31, 2002, CenterPoint Energy has not allocated such pension assets or liabilities to CERC. This change in method of allocation had no impact on pension expense recorded for the year ended December 31, 2002. (B) SAVINGS PLAN CERC participates in CenterPoint Energy's qualified savings plan, which includes a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code of 1986, as amended. Under the plan, participating employees may contribute a portion of their compensation, on a pre-tax or after-tax basis, generally up to a maximum of 16% of compensation. CenterPoint Energy matches 75% of the first 6% of each employee's compensation contributed. CenterPoint Energy may contribute an additional discretionary match of up to 50% of the first 6% of each employee's compensation contributed. These matching contributions are fully vested at all times. A substantial portion of the matching contribution is initially invested in CenterPoint Energy common stock. CenterPoint Energy allocates to CERC the savings plan benefit expense related to CERC's employees. Savings plan benefit expense was $18 million, $12 million and $17 million for the years ended December 31, 2000, 2001 and 2002, respectively. 46
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (c) POSTRETIREMENT BENEFITS CERC employees participate in CenterPoint Energy's plans which provide certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees become eligible for these benefits if they have met certain age and service requirements at retirement, as defined in the plans. Under plan amendments effective in early 1999, health care benefits for future retirees were changed to limit employer contributions for medical coverage. Such benefit costs are accrued over the active service period of employees. CERC is required to fund a portion of its obligations in accordance with rate orders. All other obligations are funded on a pay-as-you-go basis. The net postretirement benefit cost includes the following components:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Following are reconciliations of CERC's beginning and ending balances of its postretirement benefit plans benefit obligation, plan assets and funded status for 2001 and 2002.
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (e) OTHER NON-QUALIFIED PLANS CERC participates in CenterPoint Energy's deferred compensation plans which permit eligible participants to elect each year to defer a percentage of that year's salary and up to 100% of that year's annual bonus. Employees may elect to receive an early distribution of their deferral plus interest after at least four years or any year, up to and including, their age 65 retirement year. In general, employees who attain the age of 60 during employment and participate in CenterPoint Energy's deferred compensation plans may elect to have their deferred compensation amounts repaid in (a) fifteen equal annual installments commencing at the later of age 65 or termination of employment or (b) a lump-sum distribution following termination of employment. Interest generally accrues on deferrals at a rate equal to the average Moody's Long-Term Corporate Bond Index plus 2%, determined annually until termination when the rate is fixed at the rate in effect for the plan year immediately prior to which a participant attains age 65. CERC recorded interest expense related to its deferred compensation obligation of $1 million each year for the years ended December 31, 2000, 2001 and 2002. The discounted deferred compensation obligation recorded by CERC was $14 million and $13 million as of December 31, 2001 and 2002, respectively. (e) OTHER EMPLOYEE MATTERS As of December 31, 2002, CERC employed 5,428 people. Of these employees, 1,552 are covered by collective bargaining agreements. 9. INCOME TAXES The components of income from continuing operations before taxes are as follows:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Following are CERC's tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The valuation allowance reflects a net decrease of $33 million in 2001 and a net increase of $68 million in 2002. These net changes resulted from a reassessment of CERC's future ability to use federal capital loss carryforwards and state tax net operating loss carryforwards. Tax Refund Case. In December 2000, CERC received a refund from the IRS of $32 million in taxes and interest following an audit of its tax returns and refund claims for the 1979 through 1993 tax years. Interest of $26 million related to the period prior to the acquisition of CERC by CenterPoint Energy was recorded as a reduction of goodwill. The income statement effect of $4 million (after-tax) was recorded in CERC's Statements of Consolidated Income in 2000. All of CERC Corp.'s consolidated federal income tax returns for tax years ending on or prior to the date of CenterPoint Energy's acquisition of RERC have been audited and settled. 10. COMMITMENTS AND CONTINGENCIES (a) ENVIRONMENTAL CAPITAL COMMITMENTS CERC has various commitments for capital and environmental expenditures. CERC anticipates no significant capital and other special project expenditures between 2003 and 2007 for environmental compliance. (b) Lease Commitments The following table sets forth information concerning CERC's obligations under non-cancelable long-term operating leases, principally consisting of rental agreements for building space, data processing equipment and vehicles, including major work equipment (in millions):
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility." This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. This site was originally leased and operated by predecessors of REGT in the late 1940s and was operated until Arkansas Louisiana Gas Company ceased operations of the plant in the late 1970s. Beginning about 1985, the predecessors of certain Reliant Energy defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they own or lease. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The quantity of monetary damages sought is unspecified. As of December 31, 2002, CERC is unable to estimate the monetary damages, if any, that the plaintiffs may be awarded in these matters. Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, remediation has been completed on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in our Minnesota service territory, two of which CERC believes were neither owned nor operated by CERC, and for which CERC believes it has no liability. At December 31, 2001 and 2002, CERC had accrued $23 million and $19 million, respectively, for remediation of the Minnesota sites. At December 31, 2002, the estimated range of possible remediation costs was $8 million to $44 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has an environmental expense tracker mechanism in its rates in Minnesota. CERC has collected $12 million at December 31, 2002 to be used for future environmental remediation. CERC has received notices from the United States Environmental Protection Agency and others regarding its status as a PRP for sites in other states. Based on current information, CERC has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Mercury Contamination. CERC's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by CERC at some sites in the past, and CERC has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by CERC and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, CERC believes that the costs of any remediation of these sites will not be material to CERC's financial condition, results of operations or cash flows. 53
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Other Environmental. From time to time CERC has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Considering the information currently known about such sites and the involvement of CERC in activities at these sites, CERC does not believe that these matters will have a material adverse effect on CERC's financial position, results of operations or cash flows. Department of Transportation In December 2002, Congress enacted the Pipeline Safety Improvement Act of 2002. This legislation applies to CERC's interstate pipelines as well as its intra-state pipelines and local distribution companies. The legislation imposes several requirements related to ensuring pipeline safety and integrity. It requires companies to assess the integrity of their pipeline transmission and distribution facilities in areas of high population concentration and further requires companies to perform remediation activities, in accordance with the requirements of the legislation, over a 10-year period. In January 2003, the U.S. Department of Transportation published a notice of proposed rulemaking to implement provisions of the legislation. The Department of Transportation is expected to issue final rules by the end of 2003. While CERC anticipates that increased capital and operating expenses will be required to comply with the requirements of the legislation, it will not be able to quantify the level of spending required until the Department of Transportation's final rules are issued. (d) OTHER LEGAL MATTERS Natural Gas Measurement Lawsuits. In 1997, a suit was filed under the Federal False Claims Act against RERC Corp. (now CERC Corp.) and certain of its subsidiaries alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs, and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming. In addition, CERC Corp., CenterPoint Energy Gas Transmission Company, CenterPoint Energy Field Services, Inc. and CenterPoint Energy-Mississippi River Transmission Corporation are defendants in a class action filed in May 1999 against approximately 245 pipeline companies and their affiliates. The plaintiffs in the case purport to represent a class of natural gas producers and fee royalty owners who allege that they have been subject to systematic gas mismeasurement by the defendants for more than 25 years. The plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. The action is currently pending in state court in Stevens County, Kansas. Motions to dismiss and class certification issues have been briefed and argued. City of Tyler, Texas, Gas Costs Review. By letter to Entex dated July 31, 2002, the City of Tyler, Texas, forwarded various computations of what it believes to be excessive costs ranging from $2.8 million to $39.2 million for gas purchased by Entex for resale to residential and small commercial customers in that city under supply agreements in effect since 1992. Entex's gas costs for its Tyler system are recovered from customers pursuant to tariffs approved by the city and filed with both the city and the Railroad Commission of Texas (the Railroad Commission). Pursuant to an agreement, on January 29, 2003, Entex and the city filed a Joint Petition for Review of Charges for Gas Sales (Joint Petition) with the Railroad Commission. The Joint 54
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Petition requests that the Railroad Commission determine whether Entex has properly and lawfully charged and collected for gas service to its residential and commercial customers in its Tyler distribution system for the period beginning November 1, 1992, and ending October 31, 2002. The Company believes that all costs for Entex's Tyler distribution system have been properly included and recovered from customers pursuant to Entex's filed tariffs and that the city has no legal or factual support for the statements made in its letter. Gas Recovery Suits. In October 2002, a suit was filed in state district court in Wharton County, Texas, against CenterPoint Energy, CERC, Entex Gas Marketing Company, and others alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utility Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act. The plaintiffs seek class certification, but no class has been certified. The plaintiffs allege that defendants inflated the prices charged to residential and small commercial consumers of natural gas. In February 2003, a similar suit was filed against CERC in state court in Caddo Parish, Louisiana purportedly on behalf of a class of residential or business customers in Louisiana who allegedly have been overcharged for gas or gas service provided by CERC. The plaintiffs in both cases seek restitution for alleged overcharges, exemplary damages and penalties. CERC denies that it has overcharged any of its customers for natural gas and believes that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities. Other Proceedings. CERC is involved in other proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Management currently believes that the disposition of these matters will not have a material adverse effect on CERC's financial position, results of operations or cash flows. 11. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS The fair values of cash and cash equivalents, investments in debt and equity securities classified as "available-for-sale" and "trading" in accordance with SFAS No. 115, and short-term borrowings are estimated to be equivalent to carrying amounts and have been excluded from the table below. The fair values of non-trading derivative assets and liabilities are recognized in the Consolidated Balance Sheets at December 31, 2001 and 2002 (see Note 5). Therefore, these financial instruments are stated at fair value and are excluded from the table below:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 12. UNAUDITED QUARTERLY INFORMATION Summarized quarterly financial data is as follows:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) RERC Corp., to Reliant Resources. Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources merged with and into Reliant Energy Services, a wholly owned subsidiary of RERC Corp., with Reliant Energy Services as the surviving corporation. As a result of the Merger, Reliant Energy Services became a wholly owned subsidiary of Reliant Resources. Reportable segments from previous years have been restated to conform to the 2002 presentation. All of CERC's long-lived assets are in the United States. Financial data for business segments and products and services are as follows:
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 15. GUARANTOR DISCLOSURES CenterPoint Energy Gas Resources Corp., CenterPoint Energy Gas Marketing Company and other wholly owned subsidiaries of CERC Corp. provide comprehensive natural gas sales and services to industrial and commercial customers who are primarily located within or near the territories served by the Company's pipelines and distribution subsidiaries. In order to hedge their exposure to natural gas prices, these CERC Corp. subsidiaries have entered standard purchase and sale agreements with various counterparties. CenterPoint Energy and CERC Corp. have guaranteed the payment obligations of these subsidiaries under certain of these agreements, typically for one-year terms. As of December 31, 2002, CenterPoint Energy had delivered 14 such guarantees with an aggregate maximum potential exposure of $133.5 million and an aggregate carrying amount of $12.1 million. As of December 31, 2002, CERC Corp. had delivered 43 such guarantees with an aggregate maximum potential exposure of $410 million and an aggregate carrying amount of $53.7 million. CenterPoint Energy has delivered a guarantee in favor of the Tennessee Board for Licensing Contractors to support the contracting activities of CenterPoint Energy Pipeline Services, Inc. in Tennessee. The term of this guarantee runs with the two-year license granted by the Tennessee Board and provides for a maximum potential exposure of $15 million. 59
INDEPENDENT AUDITORS' REPORT To the Stockholder of CenterPoint Energy Resources Corp.: We have audited the accompanying consolidated balance sheets of CenterPoint Energy Resources Corp., formerly Reliant Energy Resources Corp., and its subsidiaries (CERC) as of December 31, 2001 and 2002, and the related consolidated statements of income, comprehensive income, stockholder's equity and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2). These financial statements and the financial statement schedule are the responsibility of CERC's management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of CERC at December 31, 2001 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As discussed in Note 3(d) to the consolidated financial statements, on January 1, 2002, CERC changed its method of accounting for goodwill and certain intangible assets to conform to Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." DELOITTE & TOUCHE LLP Houston, Texas February 28, 2003 60
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS. The information called for by Item 10 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries). ITEM 11. EXECUTIVE COMPENSATION. The information called for by Item 11 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries). ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERS MATTERS. The information called for by Item 12 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries). ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. The information called for by Item 13 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries). PART IV ITEM 14. CONTROLS AND PROCEDURES. Within the 90 days prior to the date of this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-14 of the Securities Exchange Act of 1934. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to us (including our consolidated subsidiaries) required to be included in our periodic SEC filings. Subsequent to the date of their evaluation, there were no significant changes in our internal controls or in other factors that could significantly affect the internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses. 61
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) SCHEDULE II -- RESERVES FOR THE THREE YEARS ENDED DECEMBER 31, 2002
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, the State of Texas, on the 11th day of March, 2003. CENTERPOINT ENERGY RESOURCES CORP. (Registrant) By: /s/ DAVID M. MCCLANAHAN ------------------------------------ David M. McClanahan President and Chief Executive Officer 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 on March 11, 2003.
CERTIFICATIONS I, David M. McClanahan, certify that: 1. I have reviewed this annual report on Form 10-K of CenterPoint Energy Resources Corp.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 11, 2003 By: /s/ DAVID M. MCCLANAHAN -------------------------------------------------------- David M. McClanahan President and Chief Executive Officer 65
CERTIFICATIONS I, Gary L. Whitlock, certify that: 1. I have reviewed this annual report on Form 10-K of CenterPoint Energy Resources Corp.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 11, 2003 By: /s/ GARY L. WHITLOCK -------------------------------------------------------- Gary L. Whitlock Executive Vice President and Chief Financial Officer 66
CENTERPOINT ENERGY RESOURCES CORP. EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2002 INDEX OF EXHIBITS Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
EXHIBIT 12 CENTERPOINT ENERGY RESOURCES CORP. (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (THOUSANDS OF DOLLARS) YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------ 1998 1999 2000 2001 2002 -------- -------- -------- -------- -------- Income from continuing operations................ $ 93,824 $103,871 $ 98,228 $ 67,244 $120,060 Income taxes for continuing operations........... 111,830 88,781 93,272 58,287 87,643 -------- -------- -------- -------- -------- 205,654 192,652 191,500 125,531 207,703 -------- -------- -------- -------- -------- Fixed charges, as defined: Interest expense.............................. 111,337 119,500 142,861 154,965 153,688 Distribution on trust preferred securities.... 632 357 29 28 25 Interest component of rentals charged to operating expense............................. 8,485 10,975 10,934 10,369 8,651 -------- -------- -------- -------- -------- Total fixed charges........................... 120,454 130,832 153,824 165,362 162,364 -------- -------- -------- -------- -------- Earnings, as defined............................. $326,108 $323,484 $345,324 $290,893 $370,067 ======== ======== ======== ======== ======== Ratio of earnings to fixed charges............... 2.71 2.47 2.24 1.76 2.28 ======== ======== ======== ======== ========
EXHIBIT 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-54256 of CenterPoint Energy Resources, Corp. on Form S-3 of our report dated February 28, 2003 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the change in method of accounting for goodwill and certain intangible assets) appearing in this Annual Report on Form 10-K of CenterPoint Energy Resources, Corp. for the year ended December 31, 2002. DELOITTE & TOUCHE LLP Houston, Texas March 7, 2003