10-K 1 h03755e10vk.txt CENTERPOINT ENERGY, INC. - DATED 12/31/2002 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------------- FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER 1-31447 --------------------- CENTERPOINT ENERGY, INC. (Exact name of registrant as specified in its charter) TEXAS 74-0694415 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1111 LOUISIANA (713) 207-1111 HOUSTON, TEXAS 77002 (Registrant's telephone number, including area (Address and zip code of principal executive code) offices) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------- ----------------------------------------- Common Stock, $0.01 par value and associated New York Stock Exchange rights to purchase preference stock Chicago Stock Exchange HL&P Capital Trust I 8.125% Trust Preferred New York Stock Exchange Securities, Series A REI Trust I 7.20% Trust Originated Preferred New York Stock Exchange Securities, Series C

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of each of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] The aggregate market value of the voting stock held by non-affiliates of CenterPoint Energy, Inc. (Company) was $5,027,126,669 as of June 28, 2002, using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to the Securities Exchange Act of 1934 and excluding shares held by directors and executive officers. As of February 25, 2003, the Company had 305,204,724 shares of Common Stock outstanding, including 4,452,404 ESOP shares not deemed outstanding for financial statement purposes. Excluded from the number of shares of Common Stock outstanding are 166 shares held by the Company as treasury stock. Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Act). Yes [X] No [ ] Portions of the definitive proxy statement relating to the 2003 Annual Meeting of Shareholders of the Company, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2002, are incorporated by reference in Item 10, Item 11, Item 12 and Item 13 of Part III of this Form 10-K. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- TABLE OF CONTENTS

PAGE ---- PART I Item 1. Business.................................................... 1 Item 2. Properties.................................................. 41 Item 3. Legal Proceedings........................................... 41 Item 4. Submission of Matters to a Vote of Security Holders......... 41 PART II Item 5. Market for Common Stock and Related Stockholder Matters..... 41 Item 6. Selected Financial Data..................................... 43 Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 45 Item 7A Quantitative and Qualitative Disclosures About Market Risk........................................................ 74 Item 8. Financial Statements and Supplementary Data of the Company..................................................... 77 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................... 143 PART III Item 10. Directors and Executive Officers............................ 143 Item 11. Executive Compensation...................................... 143 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.................. 143 Item 13. Certain Relationships and Related Transactions.............. 143 PART IV Item 14. Controls and Procedures..................................... 143 Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K......................................................... 144

i 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," "forecast," "goal," "intend," "may," "objective," "plan," "potential," "predict," "projection," "should," "will," 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 26 in Item 1 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 COMMONLY USED TERMS Below is a list of terms commonly used in this Form 10-K, along with their definitions or descriptions. Some of the definitions or descriptions below are summaries, and you should refer to the corresponding discussion within this Form 10-K for a complete definition or description. 1935 Act...................... Public Utility Holding Company Act of 1935 AOL TW........................ AOL Time Warner Inc. AOL TW Common................. AOL TW common stock Arkla......................... CenterPoint Energy Arkla, a division of CERC Corp. Bcf........................... Billion cubic feet Business separation plan...... Reliant Energy's amended business separation plan providing for the separation of its generation, transmission and distribution, and retail operations into three different companies and for the separation of its regulated and unregulated businesses into two publicly traded companies, as filed with the Texas Utility Commission CenterPoint Energy............ CenterPoint Energy, Inc. CenterPoint Houston........... CenterPoint Energy Houston Electric, LLC, the transmission and distribution business of CenterPoint Energy after the Restructuring CERC.......................... CenterPoint Energy Resources Corp. and subsidiaries CERC Corp..................... CenterPoint Energy Resources Corp. ECOM.......................... The Texas Utility Commission's Excess Cost Over Market computer model used to estimate stranded costs related to generation plant assets ECOM true-up.................. A reconciliation, to be part of the 2004 true-up proceeding to be conducted by the Texas Utility Commission, of any difference between the actual market power prices received in state mandated generation capacity auctions and the Texas Utility Commission's earlier estimates of those market prices during the period from January 1, 2002 through December 31, 2003 Entex......................... CenterPoint Energy Entex, a division of CERC Corp. EPA........................... Environmental Protection Agency ERCOT......................... Electric Reliability Council of Texas, Inc. ERCOT ISO..................... The ERCOT independent system operator ERCOT market.................. The State of Texas, other than a portion of the panhandle, a portion of the eastern part of the state bordering on Louisiana and the area in and around El Paso FASB.......................... Financial Accounting Standards Board FERC.......................... Federal Energy Regulatory Commission General Mortgage.............. The General Mortgage dated October 10, 2002, as supplemented, between CenterPoint Houston and JPMorgan Chase Bank, as trustee, which creates a lien which is junior to the lien of the Mortgage GWh........................... Gigawatt hour, a million kwh iii ISO........................... Independent System Operator Kyoto Protocol................ United Nations Framework Convention on Climate Change Laclede....................... Laclede Gas Company MACT.......................... Maximum achievable control technology Minnegasco.................... CenterPoint Energy Minnegasco, a division of CERC Corp. MMcf.......................... Million cubic feet Mortgage...................... The Mortgage and Deed of Trust dated November 1, 1944, as supplemented, between our predecessor in interest, Houston Lighting & Power Company, and JPMorgan Chase Bank (successor to South Texas Commercial National Bank of Houston), as trustee MW............................ Megawatt Non-bypassable................ An element of a transmission and distribution utility's rates that must be paid by essentially all customers and that cannot, except in limited circumstances, be avoided by switching to self-generation NOx........................... Oxides of nitrogen NRC........................... United States Nuclear Regulatory Commission October 3, 2001 Order......... Order from the Texas Utility Commission dated October 3, 2001 that established the transmission and distribution rates that became effective January 1, 2002 price to beat................. The price, as set by the Texas Utility Commission, that retail electric providers affiliated with a former integrated utility charge residential and small commercial customers within their affiliated electric utility's service area Railroad Commission........... The Railroad Commission of Texas REGT.......................... Reliant Energy Gas Transmission Company Reliant Energy................ Reliant Energy, Incorporated Reliant Energy HL&P........... An unincorporated division of Reliant Energy, formerly an integrated electric utility Reliant Energy Services....... Reliant Energy Services, Inc., a subsidiary of Reliant Resources Reliant Resources............. Reliant Resources, Inc. Reliant Resources Distribution.................. The distribution of CenterPoint Energy's remaining equity interest in the common stock of Reliant Resources, Inc. to our shareholders that occurred on September 30, 2002 Reliant Resources Offering.... The May 2001 initial public offering of approximately 20% of the common stock of Reliant Resources REPG.......................... Reliant Energy Power Generation, Inc. REPS.......................... Reliant Energy Pipeline Services, Inc. iv Restructuring................. The transactions through which CenterPoint Energy became the holding company for Reliant Energy and its subsidiaries, Reliant Energy and its subsidiaries became subsidiaries of CenterPoint Energy, each share of Reliant Energy common stock was converted into one share of CenterPoint Energy common stock and Reliant Energy's electric generation assets were transferred to Texas Genco SEC........................... Securities and Exchange Commission Separation.................... The transactions that include the transfers of substantially all of our unregulated businesses to Reliant Resources, the Reliant Resources Offering, the Restructuring and the Reliant Resources Distribution SFAS.......................... Statement of Financial Accounting Standards South Texas Project........... South Texas Project Electric Generating Station TCR........................... Transmission Congestion Rights Texas electric restructuring law........................... Texas Electric Choice Plan, Texas Utility Code sec. 39.001, et seq. Texas Genco................... Texas Genco Holdings, Inc. and the intermediate subsidiaries through which interests in Texas Genco, LP are held Texas Genco Option............ Option granted to Reliant Resources to purchase all of the shares of capital stock of Texas Genco owned by CenterPoint Energy Texas generation business..... The generating facilities and operations transferred to Texas Genco in the Restructuring Texas Utility Commission...... Public Utility Commission of Texas TMDL.......................... Total Maximum Daily Load program of the Clean Water Act We, us, our or similar terms......................... Reliant Energy and its subsidiaries prior to the Restructuring and CenterPoint Energy and its Subsidiaries after the Restructuring, unless the context states or implies otherwise v PART I ITEM 1. BUSINESS OUR BUSINESS OVERVIEW We are a public utility holding company that became the parent of Reliant Energy, Incorporated (Reliant Energy) and its subsidiaries on August 31, 2002 as part of a corporate restructuring of Reliant Energy (the Restructuring). Prior to the Restructuring, Reliant Energy was an operating integrated electric utility, a utility holding company for local gas distribution companies and the parent company of a group of companies providing energy and energy services on a non-utility basis primarily in North America and Western Europe. Reliant Energy's non-utility wholesale and retail energy operations were conducted principally through Reliant Resources, Inc. (Reliant Resources) and its subsidiaries. On September 30, 2002, we distributed to our shareholders the approximately 83% ownership interest we held in our subsidiary, Reliant Resources, effectively divesting our ownership of our unregulated businesses (Reliant Resources Distribution). The Restructuring implemented certain requirements of the Texas electric restructuring law described below. We are the successor to Reliant Energy for financial reporting purposes under the Securities Exchange Act of 1934. Our indirect wholly owned operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities and natural gas pipelines. Our publicly traded subsidiary, Texas Genco Holdings, Inc. (Texas Genco), operates electric generation plants. Our indirect wholly owned subsidiaries include: - CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in Reliant Energy's former electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes Houston; and - CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns 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, CERC also owns two interstate natural gas pipelines and gas gathering systems and provides various ancillary services. We also have an approximately 81% ownership interest in Texas Genco, which owns and operates the Texas generating plants that were formerly part of the integrated electric utility that was part of Reliant Energy. We distributed approximately 19% of the outstanding common stock of Texas Genco to our shareholders on January 6, 2003. We are a registered holding company, subject to regulation, with our subsidiaries, under the Public Utility Holding Company Act of 1935 (1935 Act). The 1935 Act directs the SEC to regulate, among other things, transactions among affiliates, sales or acquisitions of assets, issuance of securities, distributions and permitted lines of business. The executive offices of CenterPoint Energy are located at 1111 Louisiana, Houston, Texas 77002 (telephone number 713-207-1111). We make available free of charge on our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the SEC. Our web site address is http://www.centerpointenergy.com. In June 1999, the Texas legislature enacted a law that substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition. We refer to this legislation as the "Texas electric restructuring law." Under this law, integrated electric utilities were required to restructure their businesses to separate their generation, transmission and distribution and retail functions into separate units, and sales by power generators such as Texas Genco and retail sales of electricity (which are now 1 conducted by subsidiaries of Reliant Resources and not by us) ceased to be subject to traditional cost-based regulation as of January 1, 2002. Also under this law, our transmission and distribution subsidiary, CenterPoint Houston, remains subject to cost-based rate regulation and recovers the cost of its service through an energy delivery charge approved by the Public Utility Commission of Texas (Texas Utility Commission) and not as a component of the prior bundled rate. Texas Genco sells its available generation capacity, energy and ancillary services at prices determined by the market. None of our businesses sell electricity and related services to end users of electricity. Accordingly, we no longer operate under the bundled regulated rates in effect prior to 2002, so there are no meaningful comparisons for these business segments against prior periods. RECENT DEVELOPMENT On February 28, 2003, we reached agreement with a syndicate of banks on a second amendment to our existing $3.85 billion bank facility. Under the second amendment, the maturity date of the bank facility was extended from October 2003 to June 30, 2005, and the $1.2 billion in mandatory prepayments that would have been required this year (including $600 million due on February 28, 2003) were eliminated. As part of the consideration for the extension, we agreed to grant the banks (i) a security interest in our 81% stock ownership of Texas Genco and (ii) warrants to purchase up to 10%, on a fully diluted basis, of our common stock, both of which require SEC approval under the 1935 Act. If we are not able to obtain SEC approval by May 28, 2003, in the case of the Texas Genco stock pledge, the interest rate under the facility will increase by 25 basis points and, in the case of the warrants, we will become obligated to provide the banks equivalent cash compensation. If issued, the exercise price of the warrants will be the greater of $6.56 per share or 110% of the closing price on the New York Stock Exchange on the date of issuance, they will become exercisable one year following that date and they will expire four years after becoming exercisable. We have the right to cause some or all of the warrants (or the related rights to equivalent cash compensation) to be extinguished by making certain prepayments under the facility during 2003. Also as part of the consideration for the extension, we agreed to restrictions on the level of cash dividends on our common stock until specified repayment milestones are met. These restrictions limit our quarterly dividend to the lesser of 10 cents per share, or beginning in 2004, 50% of earnings under certain circumstances. For additional information, please read "Market for Common Stock and Related Stockholder Matters" in Item 5 of this report and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- "Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Long-Term Debt" in Item 7 of this report. THE TEXAS ELECTRIC RESTRUCTURING LAW The Texas electric restructuring law substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition for all customers. Retail pilot projects, allowing competition for up to 5% of each utility's energy demand, or "load," in all customer classes, began in August 2001 and retail electric competition for all other customers began in January 2002. Under the Texas electric restructuring law: - integrated electric utilities in Texas have restructured their businesses in order to separate power generation, transmission and distribution and retail electric provider activities into separate business units; - since January 2002, most Texas retail customers that, prior to that date, were customers of investor-owned electric utilities in Texas have been entitled to purchase their electricity from any of several "retail electric providers" that have been certified by the Texas Utility Commission; - retail electric providers, who may not themselves own any generation assets, obtain their electricity from power generation companies such as Texas Genco, exempt wholesale generators and other generating entities and provide services at generally unregulated rates; - the transmission and distribution of power are performed by transmission and distribution utilities, such as CenterPoint Houston, at rates that continue to be regulated by the Texas Utility Commission; and 2 - transmission and distribution utilities in Texas whose generation assets were "unbundled" pursuant to the Texas electric restructuring law, may recover, following a regulatory proceeding to be held in 2004: (i) "regulatory assets," which consist of the Texas jurisdictional amount reported by the previously vertically integrated electric utilities as regulatory assets and liabilities (offset and adjusted by specified amounts) in their audited financial statements for 1998; (ii) "stranded costs," which consist of the positive excess of the net regulatory book value of generation assets over the market value of the assets, taking specified factors into account; and (iii) the ECOM True-Up, Fuel Over/Under Recovery and Price to Beat Clawback components as further discussed in " -- Electric Transmission & Distribution -- Stranded Costs and Regulatory Assets Recovery" below. The Texas electric restructuring law permits transmission and distribution utilities to recover regulatory assets and stranded costs through non-bypassable charges authorized by the Texas Utility Commission to the extent that such assets and costs are established in certain regulatory proceedings. The law also authorizes the Texas Utility Commission to permit these utilities to issue securitization bonds based on the securitization of the revenue associated with that charge. For more information, please read "Our Business -- Electric Transmission & Distribution -- Stranded Costs and Regulatory Assets Recovery" below. For additional information regarding the Texas electric restructuring law, retail competition in Texas and its application to our operations and structure, please read "Regulation -- State and Local Regulation -- Electric Operations -- The Texas Electric Restructuring Law" below. ERCOT MARKET FRAMEWORK CenterPoint Houston is a member of the Electric Reliability Council of Texas, Inc. (ERCOT), an intrastate network of retail customers, investor and municipally owned electric utilities, rural electric co-operatives, river authorities, independent generators, power marketers and retail electric providers, which serves as the regional reliability coordinating council for member electric power systems in Texas. Texas Genco sells electric generation capacity, energy and ancillary services in the ERCOT market. The ERCOT market consists of the State of Texas, other than a portion of the panhandle, a portion of the eastern part of the state bordering on Louisiana and the area in and around El Paso. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation's largest power markets. The ERCOT market includes an aggregate net generating capacity of approximately 70,000 megawatts (MW), approximately 14,000 MW of which are owned by Texas Genco. There are only limited direct current interconnections between the ERCOT market and other power markets in the United States. The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council. The Texas Utility Commission has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state's main interconnected power transmission grid. The ERCOT independent system operator (ERCOT ISO) is responsible for maintaining reliable operations of the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike independent system operators in other regions of the country, the ERCOT market is not a centrally dispatched power pool, and the ERCOT ISO does not procure energy on behalf of its members other than to maintain the reliable operations of the transmission system. Members are responsible for contracting sales and purchases of power bilaterally. The ERCOT ISO also serves as agent for procuring ancillary services for those who elect not to provide their own ancillary services. CenterPoint Houston's electric transmission business supports the operation of the ERCOT ISO and all ERCOT members. The transmission business has planning, design, construction, operation and maintenance responsibility for the transmission grid and for the load serving substations. The transmission business is participating with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing limitations on the ERCOT transmission grid. 3 ELECTRIC TRANSMISSION & DISTRIBUTION SERVICE AREA CenterPoint Houston's service area consists of a 5,000-square-mile area located along the Texas Gulf Coast, with a population of approximately 4.7 million people. Electric transmission and distribution service is provided to approximately 1.8 million metered customers in this area, which includes the City of Houston and surrounding cities such as Galveston, Pasadena, Baytown, Bellaire, Freeport, Humble, Katy and Sugar Land. With the exception of Texas City, CenterPoint Houston serves nearly all of the Houston/Galveston metropolitan area. Effective January 2002, all former electricity customers of Reliant Energy HL&P whose service was regulated became free to choose to purchase their electricity from retail electric providers who compete for their business. The competing retail electric providers are now CenterPoint Houston's primary customers. See "-- Customers" below. ELECTRIC TRANSMISSION CenterPoint Houston transports electricity from power plants to substations and from one substation to another and to retail customers taking power above 69 kilovolts (kV). Transmission services are provided under tariffs approved by the Texas Utility Commission. Transmission service offers the use of the transmission system for delivery of power over facilities operating at 69 kV and above. ELECTRIC DISTRIBUTION CenterPoint Houston distributes electricity for retail electric providers in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer. CenterPoint Houston's distribution network consists of primary distribution lines, transformers, secondary distribution lines and service wires. Operations include construction and maintenance of facilities, metering services, outage response services and other call center operations. As part of the Texas electric restructuring law, metering service was to be provided on a competitive basis for commercial and industrial customers beginning January 1, 2004 and for residential customers in each service area on the later of September 1, 2005, or the date when 40% of the residential retail electric customers in that service area are taking service from unaffiliated or not formerly affiliated retail electric providers. However, the Texas Utility Commission has determined that the market is not yet ready for all metering services to be made competitive and has begun a rulemaking proceeding to decide when and what type of metering services will be opened to competition. CenterPoint Houston's distribution network receives electricity from the transmission grid through power distribution substations and distributes electricity to end users through CenterPoint Houston's distribution feeders. Distribution services are provided under tariffs approved by the Texas Utility Commission. New Texas Utility Commission rules and market protocols govern the commercial retail operations of distribution companies and other market participants. STRANDED COSTS AND REGULATORY ASSETS RECOVERY The Texas electric restructuring law provides us an opportunity to recover our "regulatory assets" and "stranded costs." "Stranded costs" include the positive excess of the regulatory net book value of generation assets over the market value of the generation assets. The Texas electric restructuring law allows alternative methods of third party valuation of the market value of generation assets, including outright sale, full and partial stock valuation and asset exchanges. Reliant Energy agreed in the business separation plan approved by the Texas Utility Commission that the market value of Texas Genco's generating assets would be determined using the partial stock valuation method. Accordingly, on January 6, 2003, we distributed to our shareholders approximately 19% of the outstanding common stock of Texas Genco. As the surviving regulated utility following the Restructuring, CenterPoint Houston will be allowed to recover these stranded costs in 2004 following the determination by the Texas Utility Commission of the amount of such costs. The market prices of the publicly traded common stock will be used to determine the market value of Texas Genco. For more 4 information regarding the market value determination, please read "-- Final True-Up -- Stranded Cost Component" below. The Texas electric restructuring law also provides specific regulatory remedies to reduce or mitigate a utility's stranded cost exposure. For example, during a base rate freeze period from 1999 through 2001, earnings above the utility's authorized rate of return formula were required to be applied in a manner to accelerate depreciation of generation-related plant assets for regulatory purposes if the utility was expected to have stranded costs. In addition, depreciation expense for transmission and distribution related assets could be redirected to generation assets for regulatory purposes during that period if the utility was expected to have stranded costs. Reliant Energy undertook both of these remedies provided in the Texas electric restructuring law. Under the Texas electric restructuring law, "regulatory assets" consist of the Texas jurisdictional amount reported by an electric utility as regulatory assets and liabilities (offset and adjusted by specified amounts) in its audited financial statements for 1998. The Texas electric restructuring law permits utilities to recover regulatory assets through non-bypassable transition charges on retail electric customers' bills, to the extent that such assets and costs are established in regulatory proceedings as discussed below. CenterPoint Energy recovered a portion of its regulatory assets in 2001 through the issuance of transition bonds. The Texas electric restructuring law also permits CenterPoint Houston to issue securitization bonds for the recovery of generation-related regulatory assets and stranded costs. Please read "-- Securitization Financing" below for a more complete discussion of the issuance of securitization bonds. Any stranded costs not recovered through the sale of securitization bonds may be recovered through a separate non-bypassable transition charge to transmission and distribution customers. Mitigation. In October 2001, the Texas Utility Commission ruled that Reliant Energy had overmitigated its stranded costs by redirecting transmission and distribution depreciation and by accelerating depreciation of generation assets as provided under its transition plan and the Texas electric restructuring law. In December 2001, Reliant Energy recorded a regulatory liability of $1.1 billion to reflect the prospective refund of accelerated depreciation, removed its previously recorded embedded regulatory asset of $841 million that had resulted from redirected depreciation and recorded a regulatory asset of $2.0 billion based upon then current projections of the market value of Reliant Energy's Texas generation assets to be recovered by the 2004 true-up proceeding described below. These regulatory assets and liabilities are recorded by CenterPoint Houston. Reliant Energy began refunding the excess mitigation credits in January 2002, and CenterPoint Houston will continue to do so over a seven-year period. If events occur that make the recovery of all or a portion of the regulatory assets no longer probable, we will write off the corresponding balance of these assets as a charge against earnings. We appealed the Texas Utility Commission's true-up rule on the basis that there are no negative stranded costs, that we should be allowed to collect interest on stranded costs, and that the premium on the partial stock valuation applies to only the equity of Texas Genco, not equity plus debt. The Texas court of appeals issued a decision on February 6, 2003 upholding the rule in part and reversing in part. The court ruled that there are no negative stranded costs and that the premium on the partial stock valuation applies only to equity. The court upheld the Texas Utility Commission's rule that interest on stranded costs begins upon the date of the final true-up order. On February 21, 2003, we filed a motion for rehearing on the issue that interest on amounts determined in the true-up proceeding should accrue from an earlier date. We have not accrued interest in our consolidated financial statements, but estimate that interest could be material. If the court of appeals denies our motion, then we will have 45 days to appeal to the Texas Supreme Court. We have not decided what action, if any, we will take if the motion for rehearing is denied. Final True-Up. Beginning in January 2004, the Texas Utility Commission will conduct true-up proceedings for each investor-owned utility. The purpose of the true-up proceeding is to quantify and reconcile the amount of stranded costs, the difference in the price of power obtained through capacity auctions conducted by Texas Genco and the power costs used in the Excess Cost Over Market (ECOM) model, any fuel costs over- or under-recovery, the "price to beat" clawback and other regulatory assets associated with the generating assets that were not previously securitized as described below under "-- Securitization Financing." 5 The true-up proceeding will result in either additional charges being assessed on, or credits being issued to, retail electric customers taking delivery from CenterPoint Houston. Stranded Cost Component. The regulatory net book value of generating assets will be compared to the market value of those assets using the partial stock valuation method. The resulting difference, if positive, represents stranded costs that will be recovered through a transition charge, which is a non-bypassable charge assessed to customers taking delivery service from CenterPoint Houston. Stranded costs may be securitized. Please read "-- Securitization Financing" below for a more complete discussion of the securitization. The publicly traded common stock of Texas Genco will be used to determine the market value of the generating assets of Texas Genco pursuant to the partial stock valuation method for determining stranded costs. The market value will be equal to the average daily closing price on The New York Stock Exchange for publicly held shares of Texas Genco common stock for the 30 consecutive trading days chosen by the Texas Utility Commission out of the last 120 trading days immediately preceding the true-up filing, plus a control premium, up to a maximum of 10%, to the extent included in the valuation determination made by the Texas Utility Commission. The regulatory net book value of generating plant assets is the balance as of December 31, 2001 plus certain costs incurred for reductions in emissions of oxides of nitrogen (NOx) and any above-market purchased power contracts. ECOM True-Up Component. The Texas Utility Commission used a computer model or projection, called an ECOM model, to estimate stranded costs related to generation plant assets. Accordingly, the Texas Utility Commission estimated the market power prices that would be received in the generation capacity auctions mandated by the Texas electric restructuring law during the period from January 1, 2002 through December 31, 2003. Any difference between the actual market power prices received in those auctions and the Texas Utility Commission's earlier estimates of those market prices will be a component of the 2004 true-up proceeding. Fuel Over/Under Recovery Component. CenterPoint Houston and Texas Genco filed their joint application to reconcile fuel revenues and expenses with the Texas Utility Commission on July 1, 2002. This final fuel reconciliation filing covers reconcilable fuel revenue, fuel expense and interest of approximately $8.5 billion incurred from August 1, 1997 through January 30, 2002. Also included in this amount is an under-recovery of $94 million, which was the balance at July 31, 1997 as approved in CenterPoint Houston's last fuel reconciliation. On January 28, 2003, a settlement agreement was reached under which it was agreed that certain items totaling $24 million were written off during the fourth quarter of 2002 and items totaling $203 million will be carried forward for resolution by the Texas Utility Commission in late 2003 or early 2004. "Price to Beat" Clawback Component. In connection with the implementation of the Texas electric restructuring law, the Texas Utility Commission has set a "price to beat" that retail electric providers affiliated or formerly affiliated with a former integrated utility must charge residential and small commercial customers within their affiliated electric utility's service area. The true-up provides for a clawback of "price to beat" in excess of the market price of electricity if 40% of the "price to beat" load is not served by a non-affiliated retail electric provider by January 1, 2004. Pursuant to the Texas electric restructuring law and the master separation agreement between Reliant Energy and Reliant Resources, Reliant Resources is obligated to pay CenterPoint Houston for the clawback component of the true-up. The clawback may not exceed $150 times the number of customers served by the affiliated retail electric provider in the transmission and distribution utility's service territory, less the number of customers served by the affiliated retail electric provider outside the transmission and distribution utility's service territory, on January 1, 2004. We expect the clawback, if any, will reduce any stranded cost recovery to which CenterPoint Houston is entitled or, if no stranded costs are recoverable, will be refunded to retail electric customers. Securitization Financing. The Texas electric restructuring law provides for the use of special purpose entities to issue securitization bonds for the economic value of generation-related regulatory assets and stranded costs. These securitization bonds will be amortized over a period not to exceed 15 years through non-bypassable transition charges to customers taking delivery service from CenterPoint Houston. Any stranded costs not recovered through the securitization bonds will be recovered through a non-bypassable competition transition charge assessed to customers taking delivery service from CenterPoint Houston. 6 In October 2001, one of our subsidiaries issued $749 million of transition bonds to securitize generation-related regulatory assets. These transition bonds have a final maturity date of September 15, 2015 and are non-recourse to us or our subsidiaries other than to the special purpose issuer. Payments on the transition bonds are made out of funds from non-bypassable transition charges assessed to customers taking delivery service from CenterPoint Houston. We expect that CenterPoint Houston will seek to securitize the true-up balance upon completion of the 2004 true-up proceeding. The securitization bonds may have a maximum maturity of 15 years. Payments on these securitization bonds would also be made out of funds from non-bypassable transition charges assessed to customers taking delivery service from CenterPoint Houston. PROPERTIES All of CenterPoint Houston's properties are located in the State of Texas. CenterPoint Houston's transmission system carries electricity from power plants to substations and from one substation to another. These substations serve to connect power plants, the high voltage transmission lines and the lower voltage distribution lines. Unlike the transmission system, which carries high voltage electricity over long distances, distribution lines carry lower voltage power from the substation to the retail electric customers. The distribution system consists primarily of distribution lines, transformers, secondary distribution lines and service wires. Most of CenterPoint Houston's transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets as permitted by law. All real and tangible properties of CenterPoint Houston, subject to certain exclusions, are currently subject to: - the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1, 1944, as supplemented, between our predecessor in interest, Houston Lighting & Power Company, and JPMorgan Chase Bank (successor to South Texas Commercial National Bank of Houston), as trustee; and - the lien of a General Mortgage (the General Mortgage) dated October 10, 2002, as supplemented, between CenterPoint Houston and JPMorgan Chase Bank, as trustee, which is junior to the lien of the Mortgage. CenterPoint Houston has issued approximately $1.2 billion aggregate principal amount of first mortgage bonds under the Mortgage, including approximately $547 million to secure certain medium-term notes and pollution control bonds for which CenterPoint Energy is obligated. Additionally, under the General Mortgage, CenterPoint Houston has issued approximately $527 million aggregate principal amount of general mortgage bonds to secure certain additional pollution control bonds for which CenterPoint Energy is obligated and approximately $1.3 billion aggregate principal amount of general mortgage bonds to secure the borrowings under a collateralized term loan due in 2005. For more information, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations -- "Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Long-Term Debt" in Item 7 of this report. Electric Lines -- Overhead. As of December 31, 2002, CenterPoint Houston owned 26,346 pole miles of overhead distribution lines and 3,599 circuit miles of overhead transmission lines, including 444 circuit miles operated at 69,000 volts, 2,078 circuit miles operated at 138,000 volts and 1,077 circuit miles operated at 345,000 volts. Electric Lines -- Underground. As of December 31, 2002, CenterPoint Houston owned 13,364 circuit miles of underground distribution lines and 16.6 circuit miles of underground transmission lines, including 4.5 circuit miles operated at 69,000 volts and 12.1 circuit miles operated at 138,000 volts. Substations. As of December 31, 2002, CenterPoint Houston owned 224 major substation sites having total installed rated transformer capacity of 44,163 megavolt amperes. Service Centers. CenterPoint Houston operates 20 regional service centers located on a total of 405 acres of land. These service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity. 7 Franchises. CenterPoint Houston has franchise contracts with 89 of the 90 cities in its service area. The remaining city has enacted an ordinance that governs the placement of utility facilities in its streets. These franchises and this ordinance give CenterPoint Houston the right to construct, operate and maintain its electrical transmission and distribution systems within city streets, alleys and rights-of-ways in exchange for payment of a fee. Fiber Optic System. CenterPoint Houston owns a fiber optic system to provide communications among its service center facilities and office operations. CenterPoint Houston owns approximately 284 miles of single-mode fiber in Harris, Fort Bend and Galveston counties located in Texas. This fiber is buried in transmission line rights-of-way or strung on overhead electrical distribution or transmission facilities. CUSTOMERS CenterPoint Houston's customers consist of municipalities, electric cooperatives, other distribution companies and approximately 31 retail electric providers in its certificated service area. Each retail electric provider is licensed by the Texas Utility Commission and must meet creditworthiness criteria established by the Texas Utility Commission. Two of these retail electric providers are subsidiaries of Reliant Resources. CenterPoint Houston's receivables balance from retail electric providers as of December 31, 2002, was $85 million. Approximately 72% of this amount was owed by subsidiaries of Reliant Resources. Sales to Reliant Resources represented approximately 83% of CenterPoint Houston's transmission and distribution revenues since deregulation began in 2002. CenterPoint Houston provides services under tariffs approved by the Texas Utility Commission. It does not have long-term contracts with any of its customers. CenterPoint Houston operates on a continuous billing cycle, with meter readings being conducted and invoices being distributed to retail electric providers each business day. COMPETITION There are no other transmission and distribution utilities in CenterPoint Houston's service area. In order for another provider of transmission and distribution services to provide such services in CenterPoint Houston's territory, it would be required to obtain a certificate of convenience and necessity in proceedings before the Texas Utility Commission and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. We know of no other party intending to enter this business in CenterPoint Houston's service area at this time. ELECTRIC GENERATION Texas Genco acquired Reliant Energy's portfolio of electric generation facilities located in Texas and related business effective August 31, 2002 through a transfer of assets between entities under common control. From January 1, 2002 until August 31, 2002, however, the electric generation assets were operated as a separate division within Reliant Energy. For convenience, we describe Texas Genco's business in this Form 10-K as if Texas Genco had owned and operated its generation assets prior to the date those assets were actually conveyed to Texas Genco. Texas Genco is one of the largest wholesale electric power generating companies in the United States. Texas Genco owns and operates 60 generating units at 11 power generation facilities. Texas Genco also owns a 30.8% interest in the South Texas Project Electric Generating Station (South Texas Project), a nuclear generating station with two 1,250 MW nuclear generating units. As of December 31, 2002, the aggregate net generating capacity of Texas Genco's combined portfolio of generating assets was 14,175 MW. Texas Genco sells electric generation capacity, energy and ancillary services in the ERCOT market, which is the largest power market in the State of Texas. Collectively, Texas Genco's facilities provide approximately 20% of the aggregate net generating capacity serving the ERCOT market. Under the Texas electric restructuring law, Texas Genco and other power generators in Texas ceased to be subject to traditional cost-based regulation. Since January 1, 2002, Texas Genco has been selling generation capacity, energy and ancillary services to wholesale purchasers at prices determined by the market. 8 Because of this change, historical financial information and operating data for periods prior to January 1, 2002, including demand and fuel data, is not indicative of how this business may be expected to perform in subsequent periods. As a result of requirements under the Texas electric restructuring law, as well as an agreement between Reliant Resources and us, Texas Genco is obligated to sell substantially all of its available capacity and related ancillary services through 2003 pursuant to capacity auctions, subject to permitted operating reserves. In these auctions, Texas Genco sells firm entitlements to capacity and ancillary services on a forward basis dispatched within specified operational constraints. For more information regarding these auctions, please read "-- Operations and Capacity Auctions" below. FACILITIES Texas Genco's generation facilities as of December 31, 2002 are described in the table below.

NET GENERATING NUMBER CAPACITY OF GENERATION FACILITIES (IN MW)(1) UNITS DISPATCH TYPE FUEL --------------------- ---------- ------ ------------------------ -------- W. A. Parish......................... 3,661 9 Base-load, Intermediate, Coal/Gas Cyclic, Peaking Limestone............................ 1,612 2 Base-load Lignite South Texas Project(2)............... 770 2 Base-load Nuclear Cedar Bayou.......................... 2,260 3 Intermediate Gas/Oil P. H. Robinson(3).................... 2,213 4 Intermediate Gas San Jacinto.......................... 162 2 Intermediate Gas T. H. Wharton(3)..................... 1,254 18 Cyclic, Peaking Gas/Oil S. R. Bertron........................ 844 6 Cyclic, Peaking Gas/Oil Greens Bayou(3)...................... 760 7 Cyclic, Peaking Gas/Oil Webster(3)........................... 387 2 Cyclic, Peaking Gas Deepwater(3)......................... 174 1 Cyclic Gas H. O. Clarke......................... 78 6 Peaking Gas ------ -- Total.............................. 14,175 62 ====== ==

--------------- (1) Net generating capacity equals gross maximum summer generating capability less the electric energy consumed at the facility. (2) Represents our 30.8% interest in the South Texas Project. (3) In October 2002, Texas Genco announced its plan to mothball all 2,213 MW of capacity at its P.H. Robinson facility, 229 MW of capacity at its T.H. Wharton facility, 406 MW of capacity at its Greens Bayou facility, 374 MW of capacity at its Webster facility and all 174 MW of capacity at its Deepwater facility through at least May 2003. Beginning in September 2002, an outage was commenced for one of the generating units at the South Texas Project to replace its steam generators with a model that is less susceptible to tube cracking. We expect this change will restore the design life of the unit and increase the potential for an extension of the South Texas Project's license. This unit was briefly returned to service in December 2002. However, as a result of certain non-safety-related mechanical failures, the unit was removed from service in December 2002 and is expected to return to service in the first quarter of 2003. The steam generators in the other generating unit at the plant were replaced in the spring of 2000. 9 MARKET FRAMEWORK Since January 1, 2002, any wholesale producer of electricity that qualifies as a "power generation company" under the Texas electric restructuring law and that can access the ERCOT electric grid is allowed to sell power in the ERCOT market at unregulated rates. Transmission capacity, which may be limited, is needed to effect power sales. In the ERCOT market, buyers and sellers enter into bilateral wholesale capacity, energy and ancillary services contracts or may participate in the centralized ancillary services market that ERCOT administers. OPERATIONS AND CAPACITY AUCTIONS Since January 1, 2002, Texas Genco has operated its generation business solely in the wholesale market. It is required by the Texas electric restructuring law to auction 15% of its available generation capacity (state mandated auctions) and will sell 85% of its available generation capacity in the auctions mandated by an agreement with Reliant Resources (contractually mandated auctions). Texas Genco's auction products are only entitlements to capacity dispatched to specific zonal delivery points from base, intermediate, cyclic or peaking units and do not convey a right to receive power from a particular unit. This enables Texas Genco to dispatch its commitments in the most cost-effective manner, but also exposes it to the risk that, depending upon the availability of its units, it could be required to supply energy from a higher cost unit, such as an intermediate unit, to meet an obligation for lower cost generation, such as base-load generation, or to obtain the energy on the open market at a market price higher than its contracted price. Additionally, Texas Genco, like other power generating companies within ERCOT, is required to purchase power from qualifying facilities under the Public Utility Regulatory Policies Act of 1978 at avoided cost. Revenues from capacity auctions come from two sources: capacity payments and energy payments. Capacity payments are based on the final clearing prices, in dollars per kilowatt-month, determined during the auctions. Texas Genco bills and collects for these capacity payments on a monthly basis just prior to the month of the entitlement. Energy payments consist of a variety of charges related to the fuel and ancillary services scheduled through the auctioned capacity entitlements. Energy payments for base-load products are tied to fixed prices specified in the auction products while gas payments are recovered through heat rates specified for gas auction products times an index based on the Houston Ship Channel Gas price. Texas Genco invoices for these energy payments on a monthly basis in arrears. STATE MANDATED CAPACITY AUCTIONS The obligation to conduct state mandated auctions of 15% of Texas Genco's available generation capacity will continue until January 1, 2007, unless before that date the Texas Utility Commission determines that an amount equal to at least 40% of the electric power consumed before the onset of competition by residential and small commercial customers in CenterPoint Houston's service area is being served by retail electric providers not affiliated or formerly affiliated with us. Reliant Resources is deemed to be our affiliate for purposes of this test. Reliant Resources currently is not permitted under the Texas electric restructuring law to purchase capacity sold by Texas Genco in the state mandated auctions. CONTRACTUALLY MANDATED CAPACITY AUCTIONS Texas Genco is contractually obligated to auction entitlements to substantially all of its available capacity and related ancillary services available after the state-mandated auctions until the date on which the Texas Genco Option, described below, either is exercised or expires. Texas Genco is permitted to reduce the amount of capacity sold in the contractually mandated auctions by the amount of operating reserves required to back up its obligations under its capacity auctions. Since Texas Genco sells the majority of its available capacity as firm entitlements, it typically reserves 1,250 MW of its capacity as operating reserves, which can be sold as interruptible power on a system-contingent basis. Through 2003, Reliant Resources has the contractual right, but not the obligation, to purchase 50% (but not less than 50%) of each type of capacity entitlement Texas Genco auctions in the contractually mandated auctions at the prices established in the auctions. To exercise this right, Reliant Resources is required to notify 10 Texas Genco whether it elects to purchase 50% of the capacity auctioned no later than three business days prior to the date of the auction. Texas Genco excludes the amount of capacity specified in Reliant Resources' notice from the auction. Texas Genco auctions any portion of the capacity that Reliant Resources does not reserve through its notice in the contractually mandated auctions. Upon determination of the prices for the capacity entitlements Texas Genco auctions, Reliant Resources is obligated to purchase the capacity it elected to reserve from the auction process at the prices set during the auction for that entitlement. If Texas Genco auctions capacity and ancillary services separately, Reliant Resources is entitled to participate in 50% of the offered capacity of each. In addition to its reservation of capacity, and whether or not it has reserved capacity in the auction, Reliant Resources is entitled to participate in each contractually mandated auction. If Reliant Resources exercises its option to purchase the shares of Texas Genco common stock owned by us in January 2004 (Texas Genco Option), Texas Genco will not conduct any capacity auctions, other than as required by Texas Utility Commission's rules, between the option exercise date and the option closing date without obtaining Reliant Resources' consent, which it may not unreasonably withhold. If Reliant Resources does not exercise the Texas Genco Option, Texas Genco will no longer be required to conduct contractually mandated auctions following the expiration of that option. Auction Results. Texas Genco conducted its initial state mandated auctions and contractually mandated auctions from September 2001 through January 2003. Thirty-one companies, including Reliant Resources, registered and qualified to participate in these auctions. As a result, Texas Genco sold 91% of its available capacity for 2002 and has sold 74% of its available capacity for 2003. Texas Genco's available capacity equals its total net generating capacity less capacity withheld as operating reserves and capacity that is subject to planned outages. The 3,400 MW of capacity that we have "mothballed" as described below under "-- Competition" is included in our available capacity only for the months of June through September 2003. Reliant Resources purchased 63% of Texas Genco's available 2002 capacity and, through January 2003, has purchased 58% of Texas Genco's available 2003 capacity. Texas Genco intends to hold auctions to sell its remaining available capacity for 2003 in March and July 2003. To date, the market-based prices established in Texas Genco's capacity auctions have provided returns on its facilities substantially below historical regulated returns. Higher gas prices in the latter part of 2002 and early 2003 have positively influenced the prices established in its recent capacity auctions. Generally, higher gas prices increase the capacity prices for its base-load entitlements since prospective purchasers face higher-cost and more volatile-priced gas-fired generation alternatives. TEXAS GENCO OPTION Reliant Resources has an option that may be exercised between January 10, 2004 and January 24, 2004 to purchase all of the approximately 81% of the outstanding shares of Texas Genco common stock that we currently own. The per share exercise price under the Texas Genco Option will equal the average daily closing price of Texas Genco common stock on The New York Stock Exchange over the 30 consecutive trading days out of the last 120 trading days ending January 9, 2004 which result in the highest average closing price. In addition, a control premium, up to a maximum of 10%, will be added to the price to the extent a control premium is included in the valuation determination made by the Texas Utility Commission relating to the market value of Texas Genco. If the option closing has not occurred within sixteen months of the option exercise, rights under the option agreement will terminate. The exercise price formula is based upon the generation asset valuation methodology in the Texas electric restructuring law that we will use to calculate the market value of Texas Genco. This market value will be used to determine the amount CenterPoint Houston will be allowed to recover as generation related "stranded costs" under the Texas electric restructuring law. The exercise price is also subject to adjustment based on the difference between the per share dividends Texas Genco pays to us during the period through the option closing date and Texas Genco's actual per share earnings during that period. To the extent Texas Genco's per share dividends are less than its actual per share earnings during that period, the per share option price will be increased. To the extent its per share dividends exceed its actual per share earnings, the per share option price will be reduced. 11 Reliant Resources has agreed that if it exercises its option, it will purchase from us all notes and other payables owed by Texas Genco to us as of the option closing date, at their principal amount plus accrued interest. Similarly, if there are notes or payables owed to Texas Genco by us as of the option closing date, Reliant Resources will assume those obligations in exchange for a payment from us of an amount equal to the principal plus accrued interest. In the event Reliant Resources exercises its option, Reliant Resources and CenterPoint Energy have agreed to make an election under Section 338(h)(10) of the Internal Revenue Code with respect to the purchase. As a result of the Section 338(h)(10) election, CenterPoint Energy will recognize no gain or loss from the sale of the Texas Genco stock for income tax purposes. Instead, at the closing of the sale, Texas Genco would be deemed, for income tax purposes, to have sold all of its assets for an amount generally equal to the value of the equity of Texas Genco, based upon the purchase price, plus the principal amount of Texas Genco's indebtedness at the time of the purchase. Under an agreement with Reliant Resources, we have agreed to maintain ownership of our approximate 81% interest in Texas Genco following the distribution until exercise or expiration of the Texas Genco Option. In addition, Texas Genco has agreed with us that it will not issue additional equity securities. We have agreed to lend funds to Texas Genco for operating needs upon request from time to time following the distribution. Texas Genco may also obtain third-party financing if it so desires. CenterPoint Energy's separation agreement with Texas Genco, as amended, contains covenants restricting Texas Genco's ability to: - merge or consolidate with another entity; - sell assets; - enter into long-term agreements and commitments for the purchase of fuel or the purchase or sale of power outside the ordinary course of business; - engage in other businesses; - construct or acquire new generation plants or capacity; - engage in hedging transactions; - encumber its assets; - issue additional equity securities; - pay special dividends; and - make certain loans, investments or advances to, or engage in certain transactions with, its affiliates. Exercise of the option will be subject to various regulatory approvals, including Hart-Scott-Rodino antitrust clearance and United States Nuclear Regulatory Commission (NRC) license transfer approval. In certain circumstances involving a change in control of us, the time at which the Texas Genco Option may be exercised and the period over which the exercise price is determined are accelerated, with corresponding changes to the time and manner of payment of the exercise price. FUEL SUPPLIES Texas Genco relies primarily on natural gas, coal, lignite and uranium to fuel its generation facilities. The fuel mix of Texas Genco's generating portfolio, based on actual fuel usage during 2002, was approximately 60% coal and lignite, 28% natural gas and 12% nuclear. As of December 31, 2002, the fuel mix of its generating portfolio based on the capacity of its facilities was approximately 66% natural gas, 29% coal and lignite and 5% nuclear. Based on Texas Genco's current assumptions regarding the cost and availability of fuel, plant operation schedules, load growth, load management and the impact of environmental regulations, it does not expect the mix of fuel used by its generating portfolio will vary materially during 2003 from prior levels. As a result of new air emissions standards imposed by federal and state law, Texas Genco anticipates having higher levels of plant maintenance in 2003 and subsequent years associated with the installation of environmental equipment. These factors could affect the mix of its future fuel usage. 12 As a result of the Texas electric restructuring law, most of Texas Genco's capacity and energy sales are now based on the generation capacity entitlement auctions described above. Successful bidders in these auctions are able to dispatch energy from their entitlements within specified operational constraints. Under the terms of the capacity auctions, successful bidders are required to make energy payments to cover a variety of charges related to the fuel and ancillary services scheduled through the auctioned entitlements. Natural Gas. Texas Genco has long-term natural gas supply contracts with several suppliers. Substantially all of its long-term natural gas supply contracts contain pricing provisions based on fluctuating spot market prices. In 2002, 60% of Texas Genco's natural gas requirements were purchased under these long-term contracts. Texas Genco purchased the remaining 40% of its natural gas requirements in 2002 on the spot market. Based on current market conditions, Texas Genco believes it will be able to replace the supplies of natural gas covered under its long-term contracts when they expire with gas purchased on the spot market or under new long-term or short-term contracts. Texas Genco's natural gas requirements are generally more volatile than its other fuel requirements because it uses natural gas to fuel intermediate, cyclic and peaking facilities and other more economical fuels to fuel base-load facilities. Since its intermediate and peaking facilities are dispatched to meet the variations of demand for electricity, its gas requirements are highly variable, on both an hour-to-hour and day-to-day basis. Although natural gas supplies have been sufficient in recent years, available supplies are subject to potential disruption 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. Although its long-term supply contracts provide some of the flexibility needed to accommodate variations in demands for natural gas, Texas Genco relies on its 6.3 billion cubic feet of leased gas storage facilities, of which 4.2 billion cubic feet is working capacity, to provide additional flexibility. Coal and Lignite. In 2002, Texas Genco purchased approximately 80% of the fuel requirements for its four coal-fired generating units at its W.A. Parish facility under two fixed-quantity, long-term supply contracts scheduled to expire in 2010 and 2011. The price for coal was fixed under the first contract through the end of 2002, after which the price is tied to spot market prices. The price for coal under the second contract was approximately three times greater than the spot market prices for coal as of December 31, 2002. The second contract does not contemplate future prices being tied to spot market prices. The terms of this contract result from the market conditions in effect during the 1970's when the contract was entered into, including shortages of natural gas supplies, increased demand for low sulfur coal as a result of new environmental regulations and uncertainty regarding the future availability of long-term sources of coal supply. The energy payments Texas Genco collects for capacity entitlements with underlying coal-fired capacity are based on a pre-established price based on the Texas Utility Commission's forecasted fuel costs, which incorporate Texas Genco's expected fuel costs under these long-term coal supply contracts. Texas Genco purchases its remaining coal requirements for the W.A. Parish facility under short-term contracts. It has long-term rail transportation contracts with Burlington Northern Santa Fe Railroad and the Union Pacific Railroad Company to transport coal to the W.A. Parish facility. Texas Genco obtains the lignite used to fuel the two generating units of the Limestone facility from a surface mine adjacent to the facility. It owns the mining equipment and facilities and a portion of the lignite reserves located at the mine. Mining operations are conducted by the owner of the remaining lignite reserves. In the past, Texas Genco has obtained its lignite requirements under a long-term contract on a cost-plus basis. Since July 2002, Texas Genco has obtained its lignite requirements under an amended long-term contract with the owner/operator of the mine at a fixed price determined annually that is expected to result in a cost of generation at the Limestone facility equivalent to the cost of generating with low-sulphur Western coal. Texas Genco expects the lignite reserves will be sufficient to provide all of the lignite requirements of this facility through 2015. The energy payments Texas Genco collects for capacity entitlements with underlying lignite-fired capacity are based on a pre-established price based on the Texas Utility Commission's forecasted fuel costs, which incorporate Texas Genco's expected costs under its lignite supply contract. 13 During 2002, Texas Genco conducted a successful test burn of Wyoming coal at the Limestone facility. Texas Genco anticipates using a blend of lignite and Wyoming coal to fuel its Limestone facility beginning in 2003 as a component of its NOx control strategy. A fuel unloading and handling system was installed at the Limestone facility to accommodate the delivery of Wyoming coal. Texas Genco expects that it will obtain Wyoming coal through spot and long-term market priced contracts. Texas Genco's Limestone facility is connected with the Burlington Northern Santa Fe Railroad. Nuclear. The South Texas Project satisfies its fuel supply requirements by acquiring uranium concentrates, converting uranium concentrates into uranium hexafluoride, enriching uranium hexafluoride and fabricating nuclear fuel assemblies. Texas Genco is a party to a number of contracts covering a portion of the fuel requirements of the South Texas Project for uranium, conversion services, enrichment services and fuel fabrication. Other than a fuel fabrication agreement that extends for the life of the South Texas Project, these contracts have varying expiration dates, and most are short to medium term (less than seven years). Management believes that sufficient capacity for nuclear fuel supplies and processing exists to permit normal operations of the South Texas Project nuclear generating units. The energy payments Texas Genco collects for capacity entitlements with underlying nuclear capacity are based on a pre-established price based on the Texas Utility Commission's forecasted costs, which incorporate Texas Genco's expected costs under these contracts. Fuel Pipeline. Texas Genco owns an 87-mile fuel pipeline that can transport either fuel oil or gas. As part of its system, it owns over five million barrels of oil storage capacity that can supply fuel oil to its Cedar Bayou, Greens Bayou, S.R. Bertron and T.H. Wharton plants. For natural gas supply, its pipeline is connected to six of its generation facilities and is interconnected with several of its suppliers. Texas Genco's pipeline provides it with added flexibility in managing the fuel supply requirements of its generation facilities. CUSTOMERS Since January 1, 2002, Texas Genco has sold power to wholesale purchasers, including retail electric providers, at unregulated rates through its capacity auctions. In addition to retail electric providers, Texas Genco's customers in the ERCOT market include municipal utilities, electric co-operatives, power trading organizations and other power generating companies. Texas Genco is also a significant provider to the ancillary services market operated by the ERCOT ISO. Texas Genco expects its mix of customers and the mix of participants will change significantly as the ERCOT market evolves from one dominated by vertically integrated electric utilities to one with utility-affiliated retail electric providers, new-entrant retail electric providers, greater participation by unregulated energy merchants, and more generation capacity from independent generation companies. Sales to Reliant Resources represented approximately 66% of Texas Genco's total revenues in 2002. COMPETITION The ERCOT market is highly competitive. Texas Genco has approximately 80 competitors, which include generation companies affiliated with Texas-based utilities, independent power producers, municipal or co-operative generators and wholesale power marketers. These competitors will compete with Texas Genco and each other by buying and selling wholesale power in the ERCOT market, entering into bilateral contracts and/or selling to aggregated retail customers. At December 31, 2002, Texas Genco's facilities provided approximately 20% of the aggregate net generating capacity serving the ERCOT market. Texas Genco's competition is based primarily on price but it also may compete based on product flexibility. A number of Texas Genco's competitors are building efficient, combined cycle power plants that are generally not able to provide the operational flexibility, ancillary services and fuel risk mitigation that Texas Genco's large diversified portfolio of generating facilities can provide. Texas Genco believes that there may be significant excess generating capacity constructed in the ERCOT market over the next several years. This overbuilding could result in lower prices for wholesale power in the ERCOT market. There is currently a surplus of generating capacity in the ERCOT market, and we expect the market for wholesale power to be highly competitive. For more information on competition in the ERCOT market, please read "Risk Factors -- Risk Factors Affecting the Results of Our Electric Generation Business" below. 14 In October 2002, Texas Genco announced its plan to remove temporarily from service, or mothball, approximately 3,400 MW of its gas-fired generating units through at least May 2003. Texas Genco decided to mothball these units because of unfavorable market conditions within the ERCOT market, including a surplus of generating capacity and a lack of bids for the output of these units in its previous capacity auctions. The ERCOT ISO has determined that the mothballed units are not required to remain in service for reliability reasons through May 2003. Based upon the results of Texas Genco's recent capacity auctions, we will return some or all of the mothballed facilities to service during the summer of 2003. NATURAL GAS DISTRIBUTION Through CERC, we engage 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. CERC currently conducts 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 CERC's 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 CERC's 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 15 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 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 CERC's natural gas distribution business operates allow it to pass through changes in the costs of natural gas to its customers through purchased gas adjustment provisions in its tariffs. There is, however, a timing difference between CERC's purchases of natural gas and the ultimate recovery of these costs. Consequently, CERC may incur carrying costs as a result of this timing difference that are not recoverable from its 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. CERC has sufficient supplies and pipeline capacity under contract to meet its 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. 16 ASSETS As of December 31, 2002, CERC 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 CERC, it owns 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 CERC receives gas are owned, operated and maintained by others, and its 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 CERC competes 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 CERC's facilities and markets and sell and/or transport natural gas directly to commercial and industrial customers. 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 per day 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. 17 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. OTHER OPERATIONS Our Other Operations business segment includes our Latin America operations, office buildings and other real estate used in our business operations, district cooling in the central business district in downtown Houston, energy management services and other corporate operations which support all of our business operations. In February 2003, we sold our interest in Argener, a cogeneration facility in Argentina, for $23.1 million. The carrying value of this investment was approximately $11 million as of December 31, 2002. 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 We are a registered public utility holding company under the 1935 Act. Prior to the Restructuring, Reliant Energy was a public utility holding company that was exempt from registration under the 1935 Act. After the Restructuring, an exemption was no longer available for the resulting corporate structure. As a registered public utility holding company, we and our subsidiaries 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, we and Reliant Energy obtained an order from the SEC that authorized the Restructuring transactions, including the Reliant Resources Distribution, and granted us 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 we must obtain a further order from the SEC under the 1935 Act, related, among other things, to the financing activities of us and our subsidiaries subsequent to June 30, 2003. In a July 2002 order, the SEC limited the aggregate amount of external borrowings of Texas Genco, CenterPoint Houston and CERC to $500 million, $3.55 billion and $2.7 billion, respectively. The ability of each of Texas Genco, CenterPoint Houston and CERC 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, Texas Genco, CenterPoint Houston and CERC are permitted to pay dividends in excess of the respective current or retained earnings in an amount up to $200 million, $100 million, $200 million and $100 million, respectively. 18 In 2002 CERC obtained authority from each state in which such authority was required to restructure CERC in a manner that would allow us to claim an exemption from registration under the 1935 Act. We have concluded that restructuring CERC would not be beneficial to us and have elected to remain a registered holding company under the 1935 Act. Based on that conclusion, we believe we will be required to form a service company to provide centralized services to our various operating subsidiaries, and we must obtain SEC approval for the formation of that company. Service companies typically are required for registered public utility holding companies, but the SEC granted us a temporary exemption from that requirement in its July 2002 order. 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 natural gas pipeline subsidiaries made two Order No. 637 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. CenterPoint Houston is not a "public utility" under the Federal Power Act and therefore is not generally regulated by the FERC, except in limited circumstances. Texas Genco is not a "public utility" under the Federal Power Act and its sales are all within ERCOT; Texas Genco therefore is not regulated by the FERC. STATE AND LOCAL REGULATION Electric Operations -- The Texas Electric Restructuring Law. In June 1999, the Texas legislature adopted the Texas electric restructuring law, which substantially amended the regulatory structure governing electric utilities in Texas in order to allow and encourage retail competition. Retail pilot projects allowing competition for up to 5% of each utility's load in all customer classes began in August 2001, and retail electric competition for all other customers began in January 2002. CenterPoint Houston conducts its operations pursuant to a certificate of convenience and necessity issued by the Texas Utility Commission that covers its present service area and facilities. In addition, CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. These franchises give CenterPoint Houston the right to operate its transmission and distribution system within the streets and public ways of these municipalities for the purpose of delivering electric service to the municipality, its residents and businesses. None of these franchises expires before 2007. Historically, Reliant Energy paid the incorporated municipalities in its service territory a franchise fee based on a formula that was usually a percentage of gross receipts received from electricity sales for consumption within each municipality. CenterPoint Houston has become responsible for Reliant Energy's 19 obligations under these franchise arrangements although the method for calculating such fees was changed by the Texas electric restructuring law effective January 1, 2002. We expect the franchise fees payable to remain consistent with the historical fees paid by Reliant Energy. For additional information regarding the Texas electric restructuring law, retail competition in Texas and its application to our operations and structure, please read "Our Business -- Overview -- The Texas Electric Restructuring Law" and "Our Business -- Electric Generation" above. Transmission and Distribution Rates. All retail electric providers in CenterPoint Houston's service area pay the same rates and other charges for transmission and distribution services. CenterPoint Houston's distribution rates charged to retail electric providers are generally based on amounts of energy delivered. Transmission rates charged to other distribution companies are based on amounts of energy transmitted under "postage stamp" rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay CenterPoint Houston the same rates and other charges for transmission services. The current transmission and distribution rates for CenterPoint Houston have been in effect since January 1, 2002, when electric competition began. This regulated delivery charge includes the transmission and distribution rate (which includes costs for nuclear decommissioning and municipal franchise fees), a system benefit fund fee imposed by the Texas electric restructuring law, a transition charge associated with securitization of regulatory assets and an excess mitigation credit imposed by the Texas Utility Commission. Natural Gas Distribution. In almost all communities in which CERC provides natural gas distribution services, it operates 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 CERC's 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 CERC's 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 CERC serves. 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 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. 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. The Company believes that all costs for Entex's Tyler distribution system 20 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. NUCLEAR REGULATORY COMMISSION Texas Genco is subject to regulation by the NRC with respect to the operation of the South Texas Project. This regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstrations to the NRC that plant operations meet applicable requirements are also required. The NRC has the ultimate authority to determine whether any nuclear powered generating unit may operate. Texas Genco and the other owners of the South Texas Project are required by NRC regulations to estimate from time to time the amounts required to decommission that nuclear generating facility and are required to maintain funds to satisfy that obligation when the plant ultimately is decommissioned. CenterPoint Houston currently collects through its electric rates amounts calculated to provide sufficient funds at the time of decommissioning to discharge these obligations. Funds collected are deposited into a nuclear decommissioning trust. The beneficial ownership in the nuclear decommissioning trust is held by Texas Genco, as the licensee of the facility. While current funding levels exceed NRC minimum requirements, no assurance can be given that the amounts held in trust will be adequate to cover the actual decommissioning costs of the South Texas Project. Such costs may vary because of changes in the assumed date of decommissioning and changes in regulatory requirements, technology and costs of labor, materials and waste burial. In the event that funds from the trust are inadequate to decommission the facilities, CenterPoint Houston will be required to collect through rates or other authorized charges all additional amounts required to fund Texas Genco's obligations relating to the decommissioning of the South Texas Project. We are contractually obligated to indemnify Texas Genco from and against any obligations relating to the decommissioning not otherwise satisfied through collections by CenterPoint Houston. 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. 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 air, 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, acquire air emission allowances for operation of our facilities, and to clean up or decommission disposal or fuel storage areas and other locations as necessary. 21 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 upon us 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. AIR EMISSIONS As part of the 1990 amendments to the Federal Clean Air Act, requirements and schedules for compliance were developed for attainment of health-based standards. As part of this process, standards for NOx emissions, a product of the combustion process associated with power generation and natural gas compression, are being developed or have been finalized. The Texas Commission on Environmental Quality standards require reduction of emissions from Texas Genco's power generating units and some of our natural gas compression facilities. As of December 31, 2002, Texas Genco had invested $551 million for NOx emission controls, and it is planning to make expenditures of at least $131 million in the years 2003 through 2005, with possible additional expenditures after 2005. NOx control estimates for 2006 and 2007 have not been finalized. The Texas Utility Commission has initially approved Texas Genco's NOx emission reduction plan in the amount of $699 million as the most cost-effective alternative in achieving compliance with applicable air quality standards for these generation facilities. Texas Genco is required to fund NOx reduction projects for pipelines in East Texas at a cost of $16.2 million, which is included in the amounts described above. The Environmental Protection Agency (EPA) has announced its determination to regulate hazardous air pollutants, including mercury, from coal-fired and oil-fired steam electric generating units under Section 112 of the Clean Air Act. The EPA plans to develop Maximum Achievable Control Technology (MACT) standards for these types of units as well as for turbines, engines and industrial boilers. The rulemaking for coal and oil-fired steam electric generating units must be completed by December 2004. Compliance with the rules will be required within three years thereafter. The MACT standards that will be applicable to the Texas Genco units cannot be predicted at this time and may adversely impact Texas Genco's operations. The rulemaking for turbines is expected to be complete in August 2003, and for engines and industrial boilers in early February 2004. Based on the rules currently proposed, management does not anticipate a materially adverse impact in interstate pipeline operations or Texas Genco's operations. In 1998, the United States became a signatory to the United Nations Framework Convention on Climate Change (Kyoto Protocol). The Kyoto Protocol calls for developed nations to reduce their emissions of greenhouse gases. Carbon dioxide, which is a major byproduct of the combustion of fossil fuel, is considered to be a greenhouse gas. In 2002, President Bush withdrew the United States' support for the Kyoto Protocol. Since this withdrawal, Congress has explored a number of other alternatives for regulating domestic greenhouse gas emissions. If the country re-enters and the United States Senate ultimately ratifies the Kyoto Protocol and/or if the United States Congress adopts other measures for the control of greenhouse gases, any resulting limitations on power plant carbon dioxide emissions could have a material adverse impact on all fossil fuel-fired electric generating facilities, including those belonging to Texas Genco. The EPA is conducting a nationwide investigation regarding the historical compliance of coal-fueled electric generating stations with various permitting requirements of the Clean Air Act. Specifically, the EPA and the United States Department of Justice have initiated formal enforcement actions and litigation against 22 several other utility companies that operate these stations, alleging that these companies modified their facilities without proper pre-construction permit authority. To date, Texas Genco has not received requests for information related to work activities conducted at its facilities. The EPA has not filed an enforcement action or initiated litigation in connection with Texas Genco facilities. Nevertheless, any litigation, if pursued successfully by the EPA, could accelerate the timing of emission reductions currently contemplated for the facilities and result in the imposition of penalties. In February 2001, the United States Supreme Court upheld previously adopted EPA ambient air quality standards for fine particulate matter and ozone. While attaining these new standards may ultimately require expenditures for air quality control system upgrades for our facilities, regulations establishing required controls are not expected until after 2005. Consequently, it is not possible to determine the impact on our operations at this time. In July 2002, the White House sent to Congress a bill proposing the Clear Skies Act of 2002. The Act is designed to achieve long-term reductions of multiple pollutants produced from fossil fuel-fired power plants. The Act targets reductions averaging 70% for sulfur dioxide, NOx and mercury emissions. If approved by the United States Congress, the Act would create a gradually imposed market-based compliance program that would come into effect initially in 2008 with full compliance required by 2018. Fossil fuel-fired power plants owned by companies like Texas Genco would be affected by the adoption of this program, or other legislation currently pending in the United States Congress addressing similar issues. To comply with such programs, Texas Genco and other regulated entities could pursue a variety of strategies including the installation of pollution controls, the purchase of emission allowances or the curtailment of operations. WATER ISSUES In July 2000, the EPA issued final rules for the implementation of the total maximum daily load (TMDL) program. The goal of the TMDL program is to restore waters designated as impaired by identifying and restricting the loading of pollutants contributing to the impairment. While we are not aware of any of our facilities being directly affected by the current TMDL developments, there is the potential that the establishment of TMDLs may eventually result in more stringent discharge limits in our plant discharge permits. Such limits could require our facilities to install additional water treatment facilities or equipment, modify operational practices or implement other water quality improvement measures. In October 2001, the EPA signed a final rule delaying the effective date of the TMDL rule until April 30, 2003. In December 2002, the EPA published a proposed rulemaking that would withdraw the July 2000 rule. In April 2002, the EPA proposed rules under Section 316(b) of the Clean Water Act relating to the design and operation of cooling water intake structures. This proposal is the second of three current phases of rulemaking dealing with Section 316(b) and generally would affect existing facilities that use significant quantities of cooling water. Under the amended court deadline, the EPA is to issue final rules for these Phase II facilities by February 2004. While the requirements of the final rule cannot be predicted at this time, significant capital expenditures by Texas Genco could be required. We anticipate that substantial comments and, if necessary, litigation will be filed by affected parties to attempt to achieve an acceptable final regulation. The EPA and the State of Texas periodically update water quality standards in response to new toxicological data and the development of enhanced analytical techniques that allow lower detection levels. The lowering of water quality criteria for parameters such as arsenic, mercury and selenium could affect generating facility discharge limitations and require our facilities to install additional treatment equipment. LIABILITY FOR PREEXISTING CONDITIONS AND REMEDIATION Asbestos and Other. As a result of their age, many of our facilities contain significant amounts of asbestos insulation, other asbestos-containing materials and lead-based paint. Existing state and federal rules require the proper management and disposal of these potentially toxic materials. We have developed a management plan that includes proper maintenance of existing non-friable asbestos installations, and removal and abatement of asbestos containing materials where necessary because of maintenance, repairs, replacement 23 or damage to the asbestos itself. We have planned for the proper management, abatement and disposal of asbestos and lead-based paint at our facilities. We have been named, along with numerous others, as a defendant in a number of lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast. Most of these claimants have been third party workers who participated in construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by us. We anticipate that additional claims like those received may be asserted in the future, and we intend to continue our practice of vigorously contesting claims that we do not consider to have merit. Although their ultimate outcome cannot be predicted at this time, we do not believe, based on our experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flows. 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 CERC's Minnesota service territory, two of which CERC believes it neither owned or operated, and for which CERC believes it has no liability. At December 31, 2002, CERC 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. 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 other sites. Based on current information, the Company has 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 CERC and others. The suit alleges that CERC 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 District 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. 24 EMPLOYEES As of December 31, 2002, we had 12,019 full-time employees. The following table sets forth the number of our employees by business segment:

BUSINESS SEGMENT NUMBER ---------------- ------ Electric Transmission & Distribution........................ 3,286 Electric Generation......................................... 1,639 Natural Gas Distribution.................................... 4,797 Pipelines and Gathering..................................... 631 Other Operations............................................ 1,666 ------ Total..................................................... 12,019 ======

The number of our employees who were represented by unions or other collective bargaining groups as of December 31, 2002 include (i) Electric Transmission & Distribution, 1,549; (ii) Electric Generation, 1,102; (iii) Natural Gas Distribution, 1,552; and (iv) Other Operations, 314. Collective bargaining agreements covering the Electric Transmission & Distribution, Electric Generation and some Natural Gas Distribution employees expire in 2003. EXECUTIVE OFFICERS (AS OF MARCH 1, 2003)

NAME AGE TITLE ---- --- ----- David M. McClanahan....................... 53 Director, President and Chief Executive Officer Scott E. Rozzell.......................... 53 Executive Vice President, General Counsel and Corporate Secretary Stephen C. Schaeffer...................... 55 Executive Vice President and Group President, Gas Distribution and Sales Gary L. Whitlock.......................... 53 Executive Vice President and Chief Financial Officer James S. Brian............................ 55 Senior Vice President and Chief Accounting Officer Thomas R. Standish........................ 53 President and Chief Operating Officer, CenterPoint Houston David G. Tees............................. 58 President and Chief Executive Officer, Texas Genco

DAVID M. MCCLANAHAN has been President and Chief Executive Officer and a director of CenterPoint Energy since September 2002. He served as Vice Chairman of Reliant Energy from October 2000 to September 2002 and as President and Chief Operating Office of Reliant Energy's Delivery Group from April 1999 until October 2000. He also served as the President and Chief Operating Officer of Reliant Energy HL&P, the electric utility division of Reliant Energy, from 1997 to 1999. He has served in various executive capacities with Reliant Energy since 1986. He previously served as Chairman of the Board of Directors of ERCOT and Chairman of the Board of the University of St. Thomas. He currently serves on the boards of the Edison Electric Institute, American Gas Association and Interstate Natural Gas Association of America. SCOTT E. ROZZELL has served as Executive Vice President, General Counsel and Corporate Secretary of CenterPoint Energy since September 2002. He served as Executive Vice President and General Counsel of the Delivery Group of Reliant Energy from March 2001 to September 2002. Before joining Reliant Energy in 2001, Mr. Rozzell was a senior partner in the law firm of Baker Botts L.L.P. STEPHEN C. SCHAEFFER has served as Executive Vice President and Group President, Gas Distribution Sales and Service, since December 2002. From September 2002 to December 2002, he served as Executive 25 Vice President-Government and Regulatory Affairs of CenterPoint Energy. Prior to this position, Mr. Schaeffer served as Senior Vice President-Regulatory of Reliant Energy beginning in 1999. From 1997 to 1998, he served as Executive Vice President-Retail Energy Regulation of Reliant Energy's Retail Energy Group. He has served in various executive capacities with Reliant Energy since 1989. GARY L. WHITLOCK has served as Executive Vice President and Chief Financial Officer of CenterPoint Energy since September 2002. He served as Executive Vice President and Chief Financial Officer of the Delivery Group of Reliant Energy from July 2001 to September 2002. Mr. Whitlock served as the Vice President, Finance and Chief Financial Officer of Dow AgroSciences, a subsidiary of The Dow Chemical Company, from 1998 to 2001. JAMES S. BRIAN has served as Senior Vice President and Chief Accounting Officer of CenterPoint Energy since August 2002. He served as Senior Vice President, Finance and Administration of the Delivery Group of Reliant Energy from 1999 to August 2002, and as Vice President and Chief Financial Officer of Reliant Energy HL&P from 1997 to 1999. Mr. Brian has served in various executive capacities with Reliant Energy since 1983. THOMAS R. STANDISH has served as President and Chief Operating Officer of CenterPoint Houston since August 2002. He served as President and Chief Operating Officer for both electricity and natural gas for Reliant Energy's Houston area from 1999 until August 2002, and as Senior Vice President of Distribution Customer Service for Reliant Energy HL&P from 1997 to 1999. Mr. Standish has served in various executive capacities with Reliant Energy since 1993. DAVID G. TEES has served as President and Chief Executive Officer of Texas Genco since August 2002. He served as Senior Vice President, Generation Operations of Reliant Energy from 1998 through August 2002. He also served as Vice President of Energy Production of Reliant Energy HL&P from 1986 to 1998. Mr. Tees has also served on the executive committee of the Edison Electric Institute Energy Supply Subcommittee and presently represents CenterPoint Energy as a Research Advisory Committee Member of the Electric Power Research Institute and is a director of the South Texas Project Nuclear Operating Company. RISK FACTORS RISK FACTORS ASSOCIATED WITH FINANCIAL CONDITION AND OTHER RISKS IF WE ARE UNABLE TO ARRANGE FUTURE FINANCINGS ON ACCEPTABLE TERMS, OUR ABILITY TO FUND FUTURE CAPITAL EXPENDITURES AND REFINANCE EXISTING INDEBTEDNESS COULD BE LIMITED. As a result of several events occurring in 2001 and 2002, including the September 11, 2001 terrorist attacks, the bankruptcy of Enron Corp., the downgrading of our credit ratings and the credit ratings of several energy companies, the general downturn in the utility industry and the unusual volatility in the U.S. financial markets, the availability and cost of capital for our business have been adversely affected. If we are unable to obtain external financing to meet our future capital requirements on terms that are acceptable to us, our financial condition and future results of operations could be materially adversely affected. As of December 31, 2002, we had $11.1 billion of outstanding indebtedness and trust preferred securities, including $1.0 billion of debt that must be refinanced in 2003, after giving effect to the amendment and extension of our $3.85 billion credit facility in February 2003. In addition, the capital constraints currently impacting our businesses may require our future indebtedness to include terms that are more restrictive or burdensome than those of our current indebtedness. These terms may negatively impact our ability to operate our business or severely restrict or prohibit distributions from our subsidiaries. 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; 26 - maintenance of acceptable credit ratings; - 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 us; - provisions of relevant tax and securities laws; and - our ability to obtain approval of specific financing transactions under the 1935 Act. As of December 31, 2002, our CenterPoint Houston subsidiary had $1.8 billion of general mortgage bonds outstanding. It may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Although approximately $900 million of additional general mortgage bonds could be issued on the basis of property additions as of December 31, 2002, CenterPoint Houston has agreed contractually to limit incremental secured debt to $300 million. In addition, we are contractually prohibited, subject to certain exceptions, from issuing additional first mortgage bonds. Our current credit ratings are discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Impact on Liquidity of a Downgrade in Credit Ratings" in Item 7 of this report. We cannot assure you that these credit 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. AS A HOLDING COMPANY WITH NO OPERATIONS OF OUR OWN, WE WILL DEPEND ON DISTRIBUTIONS FROM OUR SUBSIDIARIES TO MAKE PAYMENTS ON ANY OF OUR DEBT SECURITIES, AND PROVISIONS OF APPLICABLE LAW OR CONTRACTUAL RESTRICTIONS COULD LIMIT THE AMOUNT OF THOSE DISTRIBUTIONS. We derive substantially all our operating income from, and hold substantially all our assets through, our subsidiaries. As a result, we will depend on distributions from our subsidiaries in order to meet our payment obligations under any debt securities and our other obligations. In general, these subsidiaries are separate and distinct legal entities and will have no obligation to pay any amounts due on our debt securities or to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In the case of medium-term notes, which are in the aggregate principal amount of $150 million and mature in April 2003, if we were to become the subject of a voluntary or involuntary bankruptcy proceeding, the trustee for the medium-term notes could seek the payment of an amount equal to the principal amount of the medium-term notes from CenterPoint Houston under the first mortgage bonds that CenterPoint Houston issued as collateral for the medium-term notes. In addition, provisions of applicable law, such as those limiting the legal sources of dividends and those under the 1935 Act, limit their ability to make payments or other distributions to us, and they could agree to contractual restrictions on their ability to make distributions. For a discussion of restrictions under the 1935 Act, please read "Regulation -- Public Utility Holding Company Act of 1935" below. Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary's creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us. 27 THE ISSUANCE OF WARRANTS PURSUANT TO THE TERMS OF OUR AMENDED BANK FACILITY COULD RESULT IN SUBSTANTIAL DILUTION TO OUR SHAREHOLDERS. Subject to SEC approval under the 1935 Act, we have agreed to provide the bank syndicate for our $3.85 billion bank credit facility warrants to purchase up to 10% of our common stock. The exercise price of these warrants will be the greater of $6.56 per share or 110% of the closing price on the New York Stock Exchange on the date the warrants are issued. The exercise of these warrants could cause substantial dilution to our shareholders. The warrants would not be exercisable for a year after issuance but would remain outstanding for four years. We have the right to cause some or all of the warrants to be extinguished by making certain prepayments under the bank facility during 2003. To the extent that we reduce the bank facility by up to $400 million on or before May 28, 2003, up to half of the warrants will be extinguished on a basis proportionate to the reduction in the credit facility. To the extent such warrants are not extinguished on or before May 28, 2003, they will vest and become exercisable in accordance with their terms. Whether or not we are able to extinguish warrants on or before May 28, 2003, the remaining 50% of the warrants will be extinguished, again on a proportionate basis, if we reduce the bank facility by up to $400 million by the end of 2003. Because of current financial market conditions and uncertainties regarding such conditions over the balance of the year, there can be no assurance that we will be able to fund the $800 million prepayments in 2003 in order to extinguish the warrants or to do so on favorable terms. If SEC approval of our issuance of the warrants is not obtained by May 28, 2003, we will become obligated to provide the banks with equivalent cash compensation over the term that the warrants would have been exercisable to the extent they are not otherwise extinguished. For more information, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations -- "Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Long-Term Debt" in Item 7 of this report. OUR AMENDED BANK FACILITY IMPOSES RESTRICTIONS ON OUR ABILITY TO PAY DIVIDENDS. Under the terms of our bank facility as amended in February 2003, we agreed that our quarterly common stock dividend will not exceed $0.10 per share. If we have not reduced the bank facility by a total of at least $400 million by the end of 2003, of which at least $200 million has come from the issuance of capital stock or securities linked to capital stock (such as convertible debt), the maximum dividend payable during 2004 and for the balance of the term of the facility is subject to an additional test. Under that test the maximum permitted quarterly dividend will be the lesser of (i) $0.10 per share or (ii) 12.5% of our net income per share for the 12 months ended on the last day of the previous quarter. There can be no assurance that we will be able to fund the $400 million in 2003 in order avoid the further limitation on our common stock dividends. For more information, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations -- "Liquidity and Capital Resources -- Future Sources and Uses of Cash -- Long-Term Debt" in Item 7 of this report. IF WE ARE UNABLE TO OBTAIN AN EXTENSION OF OUR FINANCING ORDER UNDER THE 1935 ACT, WE WILL NOT BE ABLE TO ENGAGE IN FINANCING TRANSACTIONS AFTER JUNE 30, 2003. In connection with our 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 we are 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. WE COULD INCUR LIABILITIES ASSOCIATED WITH BUSINESSES AND ASSETS OF RELIANT RESOURCES. In connection with the organization and capitalization of Reliant Resources, Reliant Resources and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. Reliant Resources also agreed to indemnify and cause the applicable transferee subsidiaries to indemnify CenterPoint Energy and its subsidiaries, including CenterPoint Houston and CERC, with respect to liabilities associated with the transferred assets and businesses. The indemnity provisions were intended to place sole financial responsibility on Reliant Resources and its subsidiaries for all liabilities associated with the 28 current and historical business and operations of Reliant Resources, regardless of the time those liabilities arose. If Reliant Resources is unable to satisfy a liability that has been so assumed and in circumstances in which we were not released from the liability in connection with the transfer, we could be responsible for satisfying the liability. Reliant Resources has reported that it is facing large maturities of debt over the next several months, and its securities ratings are now below investment grade. If Reliant Resources is unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event Reliant Resources might not honor its indemnification obligations, and claims by Reliant Resources' creditors might be made against us as its former owner. As described in Note 13(c) to our consolidated financial statements, Reliant Energy and Reliant Resources are named as defendants in a number of lawsuits arising out of power sales in California and other West Coast markets and financial reporting matters. Although these matters relate to the business and operations of Reliant Resources, claims against Reliant Energy have been made on grounds that include the effect of Reliant Resources' financial results on Reliant Energy's historical financial statements and Reliant Energy's liability as a controlling shareholder of Reliant Resources. We could incur liability if claims in one or more of these lawsuits were successfully asserted against us and indemnification from Reliant Resources were determined to be unavailable or if Reliant Resources were unable to satisfy indemnification obligations owed to us with respect to those claims. OUR HISTORICAL FINANCIAL RESULTS ARE NOT NECESSARILY REPRESENTATIVE OF OUR EXPECTED FUTURE RESULTS. We have limited experience operating in a deregulated electricity market in which our transmission and distribution business is subject to rate regulation while our generation business is not. The financial information we have included in this report does not necessarily reflect what our financial position, results of operations and cash flows would have been prior to 2002 had we conducted those businesses separately rather than as an integrated electric utility during the periods presented. 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. Texas Genco and the other owners of the South Texas Project maintain nuclear property and nuclear liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. The owners of the South Texas Project currently maintain $2.75 billion in property damage insurance coverage, which is above the legally required minimum, but is less than the total amount of insurance currently available for such losses. Under the federal Price Anderson Act, the maximum liability to the public of owners of nuclear power plants was $9.3 billion as of December 31, 2002. Owners are required under the Price Anderson Act to insure their liability for nuclear incidents and protective evacuations. Texas Genco and the other owners of the South Texas Project currently maintain the required nuclear liability insurance and participate in the industry retrospective rating plan. In addition, the security procedures at this facility have recently been enhanced to provide additional protection against terrorist attacks. All potential losses or liabilities associated with the South Texas Project may not be insurable, and the amount of insurance may not be sufficient to cover them. In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system because CenterPoint Houston 29 believes it to be cost prohibitive. If CenterPoint Houston were to sustain any loss of or damage to its transmission and distribution properties, it would be entitled to seek to recover such loss or damage through a change in its regulated rates, although there is no assurance that CenterPoint Houston ultimately would obtain any such rate recovery or that any such rate recovery would be timely granted. Therefore, we cannot assure you that CenterPoint Houston will be able to restore any loss of or damage to its transmission and distribution properties without negative impact on our results of operations, financial condition and cash flows. AN INCREASE IN SHORT-TERM INTEREST RATES COULD ADVERSELY AFFECT OUR CASH FLOWS. As of December 31, 2002, we had $5.6 billion of outstanding floating-rate debt. Because of capital constraints impacting our business at the time some of this floating-rate debt was entered into, the interest rates are substantially above our historical borrowing rates. In addition, any floating-rate debt issued by us in the future could be at interest rates substantially above our historical borrowing rates. While we may seek to use interest rate swaps in order to hedge portions of our floating-rate debt, we may not be successful in obtaining hedges on acceptable terms. Any increase in short-term interest rates would result in higher interest costs and could adversely affect our results of operations, financial condition and cash flows. 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 operating subsidiaries' 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, financial condition and cash flows 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 electric transmission and distribution, electric generation, natural gas distribution and pipeline 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. RISK FACTORS AFFECTING THE RESULTS OF OUR ELECTRIC TRANSMISSION & DISTRIBUTION BUSINESS CENTERPOINT HOUSTON MAY NOT BE SUCCESSFUL IN RECOVERING THE FULL VALUE OF ITS STRANDED COSTS AND REGULATORY ASSETS RELATED TO GENERATION. CenterPoint Houston is entitled to recover its stranded costs (the excess of regulatory net book value of generation assets, as defined by the Texas electric restructuring law, over the market value of those assets) and its regulatory assets related to generation. CenterPoint Houston expects to make a filing in January 2004 in a true-up proceeding provided for by the Texas electric restructuring law. The purpose of this proceeding will be to quantify and reconcile: - the amount of stranded costs; - differences in the prices achieved in the state mandated auctions of Texas Genco's generation capacity and Texas Utility Commission estimates; - fuel over- or under-recovery; - the "price to beat" clawback; and - other regulatory assets associated with our generation business that were not previously recovered through the issuance of securitization bonds by a subsidiary. CenterPoint Houston will be required to establish and support the amounts of these costs in order to recover them. CenterPoint Houston expects these costs to be substantial. We cannot assure you that 30 CenterPoint Houston will be able to successfully establish and support its estimates of the value of these costs. For more information about the true-up proceeding, please read "Our Business -- Electric Transmission & Distribution -- Stranded Costs and Regulatory Assets Recovery" above and Note 4(a) to our consolidated financial statements. In addition, CenterPoint Houston's $1.3 billion collateralized term loan matures on November 11, 2005 and is expected to be repaid or refinanced with the proceeds from the recovery of these costs. To the extent CenterPoint Houston has not received the proceeds by November 11, 2005, CenterPoint Houston's ability to repay or refinance its $1.3 billion term loan will be adversely affected. CENTERPOINT HOUSTON'S RECEIVABLES ARE CONCENTRATED IN A SMALL NUMBER OF RETAIL ELECTRIC PROVIDERS. CenterPoint Houston's receivables from the distribution of electricity are collected from retail electric providers that supply the electricity CenterPoint Houston distributes to their customers. Currently, CenterPoint Houston does business with approximately 31 retail electric providers. Adverse economic conditions, structural problems in the new ERCOT market or financial difficulties of one or more retail electric providers could impair the ability of these retail providers to pay for CenterPoint Houston's services or could cause them to delay such payments. CenterPoint Houston depends on these retail electric providers to remit payments timely to it. Any delay or default in payment could adversely affect CenterPoint Houston's cash flows, financial condition and results of operations. CenterPoint Houston's receivables balance from retail electric providers at December 31, 2002 was $85 million. Approximately 72% of CenterPoint Houston's receivables from retail electric providers at December 31, 2002 was owed by subsidiaries of Reliant Resources. Our financial condition may be adversely affected if Reliant Resources is unable to meet its obligations to CenterPoint Houston. Reliant Resources, through its subsidiaries, is CenterPoint Houston's largest customer. Pursuant to the Texas electric restructuring law, Reliant Resources may be obligated to make a large "price to beat" clawback payment to CenterPoint Houston in 2004. CenterPoint Houston expects the clawback, if any, to be applied against any stranded cost recovery to which CenterPoint Houston is entitled or, if no stranded costs are recoverable, to be refunded to retail electric providers. Also, as discussed in "Risk Factors Associated with Financial Condition and Other Risks," Reliant Resources is obligated to indemnify CenterPoint Houston for other potential liabilities. Reliant Resources has reported that it is facing large maturities of its debt over the next year and thus its ability to satisfy its obligations to CenterPoint Houston cannot be assured. RATE REGULATION OF CENTERPOINT HOUSTON'S BUSINESS MAY DELAY OR DENY CENTERPOINT HOUSTON'S FULL RECOVERY OF ITS COSTS. CenterPoint Houston's rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses incurred in a test year. Thus, the rates CenterPoint Houston is allowed to charge may not match its expenses at any given time. While rate regulation in Texas is premised on providing a reasonable opportunity to recover reasonable and necessary operating expenses and to earn a reasonable return on its invested capital, there can be no assurance that the Texas Utility Commission will judge all of CenterPoint Houston's costs to be reasonable or necessary or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of CenterPoint Houston's costs. CENTERPOINT HOUSTON IS OPERATING IN A RELATIVELY NEW MARKET ENVIRONMENT IN WHICH IT AND OTHERS HAVE LITTLE OPERATING EXPERIENCE. The competitive electric market in Texas became fully operational in January 2002. Neither CenterPoint Houston nor any of the Texas Utility Commission, ERCOT or other market participants has any significant operating history under the market framework created by the Texas electric restructuring law. Some operational difficulties were encountered in the pilot program conducted in 2001 and continue to be experienced now. These difficulties include delays in the switching of some customers from one retail electric provider to another. These difficulties create uncertainty as to the amount of transmission and distribution 31 charges owed by each retail electric provider, which may cause payment of those amounts to be delayed. While to date these difficulties have not been material, these operating difficulties could become material or structural changes adopted to address these difficulties could materially adversely affect its results of operations, financial condition and cash flows. DISRUPTIONS AT POWER GENERATION FACILITIES OWNED BY THIRD PARTIES COULD INTERRUPT CENTERPOINT HOUSTON'S SALES OF TRANSMISSION AND DISTRIBUTION SERVICES. CenterPoint Houston depends on power generation facilities owned by third parties to provide retail electric providers with electric power which it transmits and distributes to their customers. CenterPoint Houston does not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, CenterPoint Houston's transmission and distribution services may be interrupted, and its results of operations, financial condition and cash flows may be adversely affected. CENTERPOINT HOUSTON'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL. A portion of CenterPoint Houston's revenues is derived from rates that it collects from each retail electric provider based on the amount of electricity it distributes on behalf of each retail electric provider. Thus, CenterPoint Houston's revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months. TECHNOLOGICAL CHANGE MAY MAKE ALTERNATIVE ENERGY SOURCES MORE ATTRACTIVE AND MAY ADVERSELY AFFECT CENTERPOINT HOUSTON'S REVENUES AND RESULTS OF OPERATIONS. The continuous process of technological development may result in the introduction to retail customers of economically attractive alternatives to purchasing electricity through CenterPoint Houston's distribution facilities. Manufacturers of self-generation facilities continue to develop smaller-scale, more-fuel-efficient generating units that can be cost-effective options for some retail customers with smaller electric energy requirements. Any reduction in the amount of electric energy CenterPoint Houston distributes as a result of these technologies may have an adverse impact on its results of operations, financial condition and cash flows in the future. RISK FACTORS AFFECTING THE RESULTS OF OUR ELECTRIC GENERATION BUSINESS TEXAS GENCO'S REVENUES AND RESULTS OF OPERATIONS ARE IMPACTED BY MARKET RISKS THAT ARE BEYOND ITS CONTROL. Texas Genco sells electric generation capacity, energy and ancillary services in the ERCOT market. The ERCOT market consists of the majority of the population centers in the State of Texas and represents approximately 85% of the demand for power in the state. Under the Texas electric restructuring law, Texas Genco and other power generators in Texas are not subject to traditional cost-based regulation and, therefore, may sell electric generation capacity, energy and ancillary services to wholesale purchasers at prices determined by the market. As a result, Texas Genco is not guaranteed any rate of return on its capital investments through mandated rates, and its revenues and results of operations depend, in large part, upon prevailing market prices for electricity in the ERCOT market. Market prices for electricity, generation capacity, energy and ancillary services may fluctuate substantially. Texas Genco's gross margins are primarily derived from the sale of capacity entitlements associated with its large, solid fuel base-load generating units, including its Limestone and W. A. Parish facilities and its interest in the South Texas Project. The gross margins generated from payments associated with the capacity of these units are directly impacted by natural gas prices. Since the fuel costs for Texas Genco's base-load units are largely fixed under long-term contracts, they are generally not subject to significant daily and monthly fluctuations. However, the market price for power in the ERCOT market is directly affected by the price of natural gas. Because natural gas is the marginal fuel for facilities serving the ERCOT market during most hours, its price has a significant influence on the price of electric power. As a result, the price customers are willing to pay for entitlements to Texas Genco's solid fuel-fired base-load capacity generally rises and falls with natural gas prices. 32 Market prices in the ERCOT market may also fluctuate substantially due to other factors. Such fluctuations may occur over relatively short periods of time. Volatility in market prices may result from: - oversupply or undersupply of generation capacity; - power transmission or fuel transportation constraints or inefficiencies; - weather conditions; - seasonality; - availability and market prices for natural gas, crude oil and refined products, coal, enriched uranium and uranium fuels; - changes in electricity usage; - additional supplies of electricity from existing competitors or new market entrants as a result of the development of new generation facilities or additional transmission capacity; - illiquidity in the ERCOT market; - availability of competitively priced alternative energy sources; - natural disasters, wars, embargoes, terrorist attacks and other catastrophic events; and - federal and state energy and environmental regulation and legislation. THERE IS CURRENTLY A SURPLUS OF GENERATING CAPACITY IN THE ERCOT MARKET AND WE EXPECT THE MARKET FOR WHOLESALE POWER TO BE HIGHLY COMPETITIVE. The amount by which power generating capacity exceeded peak demand (reserve margin) in the ERCOT market has exceeded 20% since 2001, and the Texas Utility Commission and the ERCOT ISO have forecasted the reserve margin for 2003 to continue to exceed 20%. A market consulting firm specializing in the power industry has published a report that predicts there will be a surplus of generating capacity in the ERCOT market for the next several years. The commencement of commercial operation of new facilities in the ERCOT region will increase the competitiveness of the wholesale power market, which could have a material adverse effect on Texas Genco's results of operations, financial condition, cash flows and the market value of Texas Genco's assets. Texas Genco's competitors include generation companies affiliated with Texas-based utilities, independent power producers, municipal and co-operative generators and wholesale power marketers. The unbundling of vertically integrated utilities into separate generation, transmission and distribution and retail businesses pursuant to the Texas electric restructuring law could result in a significant number of additional competitors participating in the ERCOT market. Some of Texas Genco's competitors may have greater financial resources, lower cost structures, more effective risk management policies and procedures, greater ability to incur losses, greater potential for profitability from ancillary services, and greater flexibility in the timing of their sale of generating capacity and ancillary services than Texas Genco does. TEXAS GENCO IS SUBJECT TO OPERATIONAL AND MARKET RISKS ASSOCIATED WITH ITS CAPACITY AUCTIONS. Texas Genco is obligated to sell substantially all of its capacity and related ancillary services through 2003 pursuant to the capacity auctions more fully described under "Our Business -- Electric Generation" above. In these auctions, Texas Genco sells firm entitlements on a forward basis to capacity and ancillary services dispatched within specified operational constraints. Although Texas Genco has reserved a portion of its aggregate net generation capacity from its capacity auctions for planned or forced outages at its facilities, unanticipated plant outages or other problems with its generation facilities could result in its firm capacity and ancillary services commitments exceeding its available generation capacity. As a result, Texas Genco could be required to obtain replacement power from third parties in the open market to satisfy its firm commitments that could result in significant additional costs. In addition, an unexpected outage at one of Texas Genco's 33 lower cost facilities could require it to run one of its higher cost plants in order to satisfy its obligations even though the energy payments for the dispatched power are based on the cost at the lower-cost facility. Texas Genco sells capacity entitlements in state mandated auctions and in its other contractually mandated auctions. The mechanics, regulations and agreements governing Texas Genco's capacity auctions are complex, and the auction process in which Texas Genco sells entitlements to its capacity is relatively new. The state mandated auctions require, among other things, Texas Genco's capacity entitlements to be sold in pre-determined amounts. The characteristics of the capacity entitlements Texas Genco sells in state mandated auctions are defined by rules adopted by the Texas Utility Commission and, therefore, cannot be changed to respond to market demands or operational requirements without approval by the Texas Utility Commission. IF THE ERCOT MARKET DOES NOT FUNCTION IN THE MANNER CONTEMPLATED BY THE TEXAS ELECTRIC RESTRUCTURING LAW, TEXAS GENCO'S BUSINESS PROSPECTS, RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE ADVERSELY IMPACTED. The initiatives under the Texas electric restructuring law have had a significant impact on the nature of the electric power industry in Texas and the manner in which participants in the ERCOT market conduct their business. These changes are ongoing, and we cannot predict the future development of the ERCOT market or the ultimate effect that this changing regulatory environment will have on Texas Genco's business. Some restructured markets in other states have recently experienced supply problems and extreme price volatility. If the ERCOT market does not function as planned once the deregulation initiatives called for by the Texas electric restructuring law have taken their full effect, Texas Genco's results of operations, financial condition and cash flows could be adversely affected. In addition, any market failures could lead to revisions or reinterpretations of the Texas electric restructuring law, the adoption of new laws and regulations applicable to Texas Genco or its facilities and other future changes in laws and regulations that may have a detrimental effect on Texas Genco's business. As part of the transition to retail competition in Texas, the ERCOT market has changed from operating with multiple control areas, each managed by one of the utilities in the state, to a single control area managed by the ERCOT ISO. The ERCOT ISO is responsible for maintaining reliable operations of the bulk electric power supply system in the new combined control area. If the ERCOT ISO is unable to successfully manage these functions, the ERCOT market may not operate properly and Texas Genco's results of operations could be adversely affected. In addition, the ERCOT ISO may impose or the Texas Utility Commission may require price limitations, bidding rules and other mechanisms that could impact wholesale prices in the ERCOT market and the outcomes of Texas Genco's capacity auctions. THE OPERATION OF TEXAS GENCO'S POWER GENERATION FACILITIES INVOLVES RISKS THAT COULD ADVERSELY AFFECT ITS REVENUES, COSTS, RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. Texas Genco is subject to various risks associated with operating its power generation facilities, any of which could adversely affect its revenues, costs, results of operations, financial condition and cash flows. These risks include: - operating performance below expected levels of output or efficiency; - breakdown or failure of equipment or processes; - disruptions in the transmission of electricity; - shortages of equipment, material or labor; - labor disputes; - fuel supply interruptions; - limitations that may be imposed by regulatory requirements, including, among others, environmental standards; - limitations imposed by the ERCOT ISO; 34 - violations of permit limitations; - operator error; and - catastrophic events such as fires, hurricanes, explosions, floods, terrorist attacks or other similar occurrences. A significant portion of Texas Genco's facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep it operating at high efficiency and to meet regulatory requirements. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure to produce power, including failure caused by breakdown or forced outage, could result in reduced earnings. Texas Genco employs experienced personnel to maintain and operate its facilities and carries insurance to mitigate the effects of some of the operating risks described above. Texas Genco's insurance policies, however, are subject to certain limits and deductibles and do not include business interruption coverage. Should one or more of the events described above occur, revenues from Texas Genco's operations may be significantly reduced or its costs of operations may significantly increase. TEXAS GENCO RELIES ON POWER TRANSMISSION FACILITIES THAT IT DOES NOT OWN OR CONTROL AND THAT ARE SUBJECT TO TRANSMISSION CONSTRAINTS WITHIN THE ERCOT MARKET. IF THESE FACILITIES FAIL TO PROVIDE TEXAS GENCO WITH ADEQUATE TRANSMISSION CAPACITY, IT MAY NOT BE ABLE TO DELIVER WHOLESALE ELECTRIC POWER TO ITS CUSTOMERS AND IT MAY INCUR ADDITIONAL COSTS. Texas Genco depends on transmission and distribution facilities owned and operated by our wholly owned subsidiary, CenterPoint Houston, and on transmission and distribution systems owned by others to deliver the wholesale electric power it sells from its power generation facilities to its customers, who in turn deliver power to the end users. If transmission is disrupted, or if transmission capacity infrastructure is inadequate, Texas Genco's ability to sell and deliver wholesale electric energy may be adversely impacted. The single control area of the ERCOT market is currently organized into four congestion zones, referred to as the North, South, West and Houston zones. These congestion zones are determined by physical constraints on the ERCOT transmission system that make it difficult or impossible at times to move power from a zone on one side of the constraint to the zone on the other side of the constraint. All but two of Texas Genco's facilities are located in the Houston congestion zone. Texas Genco's Limestone facility is located in the North congestion zone and the South Texas Project is located in the South congestion zone. Texas Genco sells a portion of the entitlements offered in its state mandated auctions to customers located in congestion zones other than the Houston zone. Transmission congestion between these zones could impair Texas Genco's ability to schedule power for transmission across zonal boundaries, which are defined by the ERCOT ISO, thereby inhibiting its efforts to match its facility scheduled outputs with its customer scheduled requirements. The ERCOT ISO has instituted rules that directly assign congestion costs to the parties causing the congestion. Therefore, power generators participating in the ERCOT market could be liable for the congestion costs associated with transferring power between zones. Texas Genco schedules its anticipated requirements based on its own forecasted needs, which rely in part on demand forecasts made by its customers. These forecasts may prove to be inaccurate. Texas Genco could be deemed responsible for congestion costs if it schedules delivery of power between congestion zones during times when the ERCOT ISO expects congestion to occur between the zones. If Texas Genco is liable for congestion costs, its financial results could be adversely affected. For more information about the ERCOT market, please read "Our Business -- Overview -- ERCOT Market Framework" above. TEXAS GENCO'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE ADVERSELY IMPACTED BY A DISRUPTION OF ITS FUEL SUPPLIES. Texas Genco relies primarily on natural gas, coal, lignite and uranium to fuel its generation facilities. Texas Genco purchases its fuel from a number of different suppliers under long-term contracts and on the spot market. Under Texas Genco's capacity auctions, it sells firm entitlements to capacity and ancillary services. 35 Therefore, any disruption in the delivery of fuel could prevent Texas Genco from operating its facilities to meet its auction commitments, which could adversely affect its results of operations, financial condition and cash flows. Delivery of natural gas to each of Texas Genco's natural gas-fired facilities typically depends on the natural gas pipelines or distributors for that location. As a result, Texas Genco is subject to the risk that a natural gas pipeline or distributor may suffer disruptions or curtailments in its ability to deliver natural gas to it or that the amounts of natural gas Texas Genco requests are curtailed. These disruptions or curtailments could adversely affect Texas Genco's ability to operate its natural gas-fired generating facilities. Texas Genco leases gas storage facilities capable of storing approximately 6.3 billion cubic feet of natural gas, of which 4.2 billion cubic feet is working capacity. Texas Genco purchases coal from a limited number of suppliers. Generally, Texas Genco seeks to maintain average coal reserves sufficient to operate its coal-fired facilities for 30 days. Texas Genco also has long-term rail transportation contracts with two rail transportation companies to transport coal to its coal-fired facilities. Any extended disruption in Texas Genco's coal supply, including those caused by transportation disruptions, adverse weather conditions, labor relations or environmental regulations affecting Texas Genco's coal suppliers, could adversely affect its ability to operate its coal-fired facilities. Texas Genco is also exposed to the risk that suppliers that have agreed to provide it with fuel could breach their obligations. Should these suppliers fail to perform, Texas Genco may be forced to enter into alternative arrangements at then-current market prices. As a result, Texas Genco's results of operations, financial condition and cash flows could be adversely affected. TO DATE, TEXAS GENCO HAS SOLD A SUBSTANTIAL PORTION OF ITS AUCTIONED CAPACITY ENTITLEMENTS TO A SINGLE CUSTOMER, RELIANT RESOURCES. ACCORDINGLY, TEXAS GENCO'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE ADVERSELY AFFECTED IF RELIANT RESOURCES DECLINED TO PARTICIPATE IN TEXAS GENCO'S FUTURE AUCTIONS OR FAILED TO MAKE PAYMENTS WHEN DUE UNDER RELIANT RESOURCES' PURCHASED ENTITLEMENTS. By participating in Texas Genco's contractually mandated auctions, subsidiaries of Reliant Resources purchased entitlements to 63% of the aggregate 2002 capacity and 58% of the aggregate 2003 capacity that Texas Genco has sold to date through its capacity auctions. Reliant Resources made these purchases either through the exercise of its contractual rights to purchase 50% of the entitlements Texas Genco auctions in its contractually mandated auctions or through the submission of bids. In the event Reliant Resources declined to participate in Texas Genco's future auctions or failed to make payments when due, Texas Genco's results of operations, financial condition and cash flows could be adversely affected. In this regard, Reliant Resources has reported that it is facing large maturities of debt over the next year, and its securities ratings are now below investment grade. TEXAS GENCO MAY INCUR SUBSTANTIAL COSTS AND LIABILITIES AS A RESULT OF ITS OWNERSHIP OF NUCLEAR FACILITIES. Texas Genco owns a 30.8% interest in the South Texas Project, a nuclear powered generation facility. As a result, Texas Genco is subject to risks associated with the ownership and operation of nuclear facilities. These risks include: - the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; - limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and - uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines, shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial 36 capital expenditures at nuclear plants. In addition, although we have no reason to anticipate a serious nuclear incident at the South Texas Project, if an incident did occur, it could have a material adverse effect on Texas Genco's results of operations, financial condition and cash flows. CONTRACTUAL RESTRICTIONS ON THE OPERATION OF TEXAS GENCO'S BUSINESS MAY LIMIT ITS ABILITY TO TAKE ACTIONS AVAILABLE TO OTHER COMPANIES THAT ARE NOT SUBJECT TO SIMILAR RESTRICTIONS. Effective December 31, 2000, Reliant Resources and Reliant Energy entered into a master separation agreement, that now governs the rights and obligations of us and Reliant Resources in connection with the business separation plan of Reliant Energy adopted in response to the Texas electric restructuring law. Reliant Resources also has an option to purchase the shares of Texas Genco stock owned by us that is exercisable in January 2004. Texas Genco has agreed to comply with certain restrictions governing its operations as contemplated by the master separation agreement and option agreement. These restrictions limit Texas Genco's ability to: - merge or consolidate with another entity; - sell assets; - enter into long-term agreements and commitments for the purchase of fuel or the purchase or sale of power outside the ordinary course of business; - engage in other businesses; - construct or acquire new generation plants or capacity; - engage in hedging transactions; - encumber Texas Genco's assets; - issue additional equity securities; - pay special dividends; and - make certain loans, investments or advances to, or engage in certain transactions with, Texas Genco's affiliates. TEXAS GENCO MAY NOT HAVE ACCESS TO SUFFICIENT CAPITAL IN THE AMOUNTS AND AT THE TIMES NEEDED TO FINANCE ITS BUSINESS. To date, Texas Genco's capital has been provided by internally generated cash flows and borrowings and capital contributions from CenterPoint Energy. We can give no assurances that Texas Genco's current and future capital structure, operating performance, financial condition and cash flows will permit it to access the capital markets or to obtain other financing as needed to meet its working capital requirements and projected future capital expenditures on favorable terms. Texas Genco's projected future capital expenditures are substantial. Texas Genco's ability to secure third party credit lines or other debt financing may be adversely impacted by the factors described in this section, including the nature of its business, which may lead to volatility in its financial results and cash flows. CenterPoint Energy has agreed to lend funds to Texas Genco from time to time upon Texas Genco's request until the earlier of the closing date on which Reliant Resources acquires Texas Genco common stock from CenterPoint Energy pursuant to the Reliant Resources option or the expiration of the Reliant Resources option. In the event CenterPoint Energy were to experience liquidity problems or otherwise failed to perform, Texas Genco may be unable to obtain third party financing. In addition, Texas Genco's ability to raise capital is restricted under its agreements with CenterPoint Energy. These restrictions limit Texas Genco's ability to: - issue additional equity securities; - encumber its assets; or 37 - incur indebtedness, except to satisfy requirements for operating and maintenance expenditures and other capital expenditures contemplated under its agreements with CenterPoint Energy, to meet its working capital needs, or to refinance indebtedness incurred for the foregoing purposes. 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 Texas Genco's external borrowings to $500 million. In addition, the order issued to CenterPoint Energy under the 1935 Act restricts Texas Genco's ability to pay dividends out of capital accounts. Under these restrictions, Texas Genco is permitted to pay dividends out of its current or retained earnings, and it may also pay dividends in an amount of up to $100 million in excess of its current or retained earnings. TEXAS GENCO'S OPERATIONS ARE SUBJECT TO EXTENSIVE REGULATION. IF TEXAS GENCO FAILS TO COMPLY WITH APPLICABLE REGULATIONS OR OBTAIN OR MAINTAIN ANY NECESSARY GOVERNMENTAL PERMIT OR APPROVAL, IT MAY BE SUBJECT TO CIVIL, ADMINISTRATIVE AND/OR CRIMINAL PENALTIES THAT COULD ADVERSELY IMPACT ITS RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. Texas Genco's operations are subject to complex and stringent energy, environmental and other governmental laws and regulations. The acquisition, ownership and operation of power generation facilities require numerous permits, approvals and certificates from federal, state and local governmental agencies. These facilities are subject to regulation by the Texas Utility Commission regarding non-rate matters. Existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to Texas Genco or any of its generation facilities or future changes in laws and regulations may have a detrimental effect on its business. Operation of the South Texas Project is subject to regulation by the NRC. This regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstrations to the NRC that plant operations meet applicable requirements are also required. The NRC has the ultimate authority to determine whether any nuclear powered generating unit may operate. Water for certain of Texas Genco's facilities is obtained from public water authorities. New or revised interpretations of existing agreements by those authorities or changes in price or availability of water may have a detrimental effect on Texas Genco's business. If Texas Genco fails to comply with regulatory requirements that apply to its operations, regulatory agencies could seek to impose civil, administrative and/or criminal liabilities or could take other actions seeking to curtail its operations. These liabilities or actions could adversely impact its results of operations, financial condition and cash flows. TEXAS GENCO'S COSTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS ARE SIGNIFICANT AND THE COST OF COMPLIANCE WITH NEW ENVIRONMENTAL LAWS AND ITS EXPOSURE TO POTENTIAL LIABILITIES ASSOCIATED WITH THE ENVIRONMENTAL CONDITION OF ITS FACILITIES COULD ADVERSELY AFFECT ITS PROFITABILITY. Texas Genco's business is subject to extensive environmental regulation by federal, state and local authorities. Texas Genco is required to comply with numerous environmental laws and regulations, and to obtain numerous governmental permits, in operating its facilities. Texas Genco may incur significant additional costs to comply with these requirements. If Texas Genco fails to comply with these requirements, it could be subject to civil or criminal liability and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to Texas Genco or its facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions. If any of these events occurs, Texas Genco's business, results of operations, financial condition and cash flows could be adversely affected. Texas Genco may not be able to obtain or maintain from time to time all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals or if 38 Texas Genco fails to obtain and comply with them, it may not be able to operate its facilities or it may be required to incur additional costs. Texas Genco is generally responsible for all on-site liabilities associated with the environmental condition of its power generation facilities, regardless of when the liabilities arose and whether the liabilities are known or unknown. These liabilities may be substantial. CHANGES IN TECHNOLOGY MAY MAKE TEXAS GENCO'S POWER GENERATION FACILITIES LESS COMPETITIVE, WHICH COULD ADVERSELY IMPACT THEIR VALUE AND THE RESULTS OF TEXAS GENCO'S OPERATIONS. A significant portion of Texas Genco's generation facilities were constructed many years ago and rely on older technologies. Some of Texas Genco's competitors may have newer generation facilities and technologies that allow them to produce and sell power more efficiently, which could adversely affect Texas Genco's results of operations, financial condition and cash flows. In addition, research and development activities are ongoing to improve alternate technologies to produce electricity, including fuel cells, microturbines, windmills and photovoltaic (solar) cells. It is possible that advances in these or other technologies will reduce the current costs of electricity production to a level that is below that of Texas Genco's generation facilities. If this occurs, Texas Genco's generation facilities will be less competitive and the value of its power plants could be significantly impaired. Also, electricity demand could be reduced by increased conservation efforts and advances in technology that could likewise significantly reduce the value of Texas Genco's power generation facilities. RISK FACTORS AFFECTING THE RESULTS OF OUR NATURAL GAS DISTRIBUTION AND PIPELINES AND GATHERING BUSINESSES OUR NATURAL GAS DISTRIBUTION BUSINESS MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES. CERC competes 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 CERC 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 CERC's 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 CERC as a result of competition may have an adverse impact on CERC's results of operations, financial condition and cash flows. OUR NATURAL GAS DISTRIBUTION BUSINESS IS SUBJECT TO FLUCTUATIONS IN NATURAL GAS PRICING LEVELS. CERC is subject to risk associated with upward price movements of natural gas. High natural gas prices might affect CERC's ability to collect balances due from its customers and could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC's tariff rates. In addition, a sustained period of high natural gas prices could apply downward demand pressure on natural gas consumers in CERC's service territory. CERC MAY INCUR CARRYING COSTS ASSOCIATED WITH PASSING THROUGH CHANGES IN THE COSTS OF NATURAL GAS. Generally, the regulations of the states in which CERC operates allow it to pass through changes in the costs of natural gas to its customers through purchased gas adjustment provisions in the applicable tariffs. There is, however, a timing difference between its purchases of natural gas and the ultimate recovery of these costs. Consequently, CERC may incur carrying costs as a result of this timing difference that are not recoverable from its customers. The failure to recover those additional carrying costs may have an adverse effect on CERC's results of operations, financial condition and cash flows. 39 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 CERC's competitors could lead to lower prices, which may have an adverse impact on CERC's 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 CERC'S 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 CERC's results of operations, financial condition and cash flows. 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 CERC's results of operations, financial condition and cash flows. CERC'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL. A portion of CERC's revenues are derived from natural gas sales and transportation. Thus, CERC's 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. ITEM 2. PROPERTIES CHARACTER OF OWNERSHIP We own or lease our principal properties in fee, including our corporate office space and various real property and facilities relating to our generation assets and development activities. Most of our electric lines and gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others. ELECTRIC TRANSMISSION & DISTRIBUTION For information regarding the properties of our Electric Transmission & Distribution business segment, please read "Our Business -- Electric Transmission & Distribution" in Item 1 of this report, which information is incorporated herein by reference. ELECTRIC GENERATION For information regarding the properties of our Electric Generation business segment, please read "Our Business -- Electric Generation" in Item 1 of this report, which information is incorporated herein by reference. 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. 40 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. OTHER OPERATIONS For information regarding the properties of our Other Operations business segment, please read "Our Business -- Other Operations" in Item 1 of this report, which information is incorporated herein by reference. ITEM 3. LEGAL PROCEEDINGS For a brief description of certain legal and regulatory proceedings affecting us, see "Regulation" and "Environmental Matters" in Item 1 of this report and Notes 4 and 13 to our consolidated financial statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to the vote of our security holders during the fourth quarter of 2002. PART II ITEM 5. MARKET FOR COMMON STOCK AND RELATED STOCKHOLDER MATTERS As of February 25, 2003, our common stock was held of record by approximately 67,308 shareholders. Our common stock is listed on the New York and Chicago Stock Exchanges and is traded under the symbol "CNP." The following table sets forth the high and low sales prices of the common stock of CenterPoint Energy or its predecessor on the New York Stock Exchange composite tape during the periods indicated, as reported by Bloomberg, and the cash dividends declared in these periods. Prior to August 31, 2002, information shown is for our predecessor, Reliant Energy. Cash dividends paid aggregated $1.50 per share in 2001 and $1.07 per share in 2002.

MARKET PRICE ---------------- DIVIDEND DECLARED HIGH LOW PER SHARE ------ ------ ----------------- 2001 First Quarter..................................... $0.375 January 11...................................... $32.44 March 30........................................ $45.25 Second Quarter.................................... $0.375 May 1........................................... $50.02 June 26......................................... $30.50 Third Quarter..................................... $0.375 July 10......................................... $32.70 September 27.................................... $26.07 Fourth Quarter.................................... (1) October 16...................................... $28.88 December 17..................................... $23.64

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MARKET PRICE ---------------- DIVIDEND DECLARED HIGH LOW PER SHARE ------ ------ ----------------- 2002 First Quarter..................................... $0.375 January 7....................................... $26.85 February 25..................................... $20.35 Second Quarter.................................... $0.375 April 23........................................ $25.93 May 17.......................................... $14.30 Third Quarter..................................... $0.16 (2) July 8.......................................... $17.00 July 24......................................... $ 5.40 Fourth Quarter.................................... $0.16 October 3....................................... $ 9.00(3) October 22...................................... $ 5.65(3)

--------------- (1) The quarterly dividend of $0.375 per share normally declared in the fourth quarter for payment in the following first quarter was declared on February 8, 2002 and paid in March 2002. (2) The reduction in the quarterly dividend to $0.16 reflects the Restructuring of CenterPoint Energy and the Reliant Resources Distribution. (3) The fourth quarter 2002 stock prices reflect the distribution of our 83% ownership interest in Reliant Resources on September 30, 2002. The closing price of Reliant Resources' common stock on that date was $1.75. The closing market price of our common stock on December 31, 2002 was $8.01 per share. On February 28, 2003, our board of directors declared a quarterly dividend of $0.10 per share of our outstanding common stock, payable on March 31, 2003 to shareholders of record as of the close of business March 12, 2003. This quarterly dividend is the maximum allowed under our amended $3.85 billion bank facility. Under the terms of our amended $3.85 billion bank facility, we agreed that our quarterly common stock dividend will not exceed $0.10 per share. If we have not reduced the bank facility by a total of at least $400 million by the end of 2003, of which at least $200 million has come from the issuance of capital stock or securities linked to capital stock (such as convertible debt), the maximum dividend payable during 2004 and for the balance of the term of the facility is subject to an additional test. Under that test the maximum permitted quarterly dividend will be the lesser of (i) $0.10 per share or (ii) 12.5% of our net income per share for the 12 months ended on the last day of the previous quarter. In addition to the limitations imposed by our bank facility, the amount of future cash dividends will be subject to determination based upon our results of operations and financial condition, our future business prospects, any applicable contractual restrictions and other factors that our board of directors considers relevant and will be declared at the discretion of the board of directors. 42 ITEM 6. SELECTED FINANCIAL DATA The following table presents selected financial data with respect to our consolidated financial condition and consolidated results of operations and should be read in conjunction with our consolidated financial statements and the related notes in Item 8 of this report. The selected financial data presented below reflect certain reclassifications necessary to present Reliant Resources as discontinued operations as a result of the distribution of all of the shares of Reliant Resources common stock owned by CenterPoint Energy to its common shareholders on a pro rata basis (the Reliant Resources Distribution) and the retroactive effects of the adoption of Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144), as it relates to the Company's Latin America operations. The selected financial data also gives effect to the Restructuring. For additional information regarding the Reliant Resources Distribution and our investments in Latin America, please read Note 2 to our consolidated financial statements.

YEAR ENDED DECEMBER 31, ----------------------------------------------- 1998(1) 1999(2) 2000(3) 2001(4) 2002(5) ------- ------- ------- ------- ------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues............................................... $ 7,591 $ 7,601 $10,374 $10,656 $ 7,922 ------- ------- ------- ------- ------- Income (loss) from continuing operations before extraordinary items and cumulative effect of accounting change.................................... (164) 1,642 222 446 386 Income from discontinued operations, net of tax........ 23 23 225 475 82 Loss on disposal of discontinued operations............ -- -- -- -- (4,371) Extraordinary items, net of tax........................ -- (183) -- -- (17) Cumulative effect of accounting change, net of tax..... -- -- -- 59 -- ------- ------- ------- ------- ------- Net income (loss) attributable to common shareholders......................................... $ (141) $ 1,482 $ 447 $ 980 $(3,920) ======= ======= ======= ======= ======= Basic earnings (loss) per common share: Income (loss) from continuing operations before extraordinary items and cumulative effect of accounting change.................................... $ (0.58) $ 5.76 $ 0.78 $ 1.54 $ 1.30 Income from discontinued operations, net of tax...... 0.08 0.08 0.79 1.64 0.27 Loss on disposal of discontinued operations.......... -- -- -- -- (14.67) Extraordinary items, net of tax...................... -- (0.64) -- -- (0.06) Cumulative effect of accounting change, net of tax... -- -- -- 0.20 -- ------- ------- ------- ------- ------- Basic earnings (loss) per common share................. $ (0.50) $ 5.20 $ 1.57 $ 3.38 $(13.16) ======= ======= ======= ======= ======= Diluted earnings (loss) per common share: Income (loss) from continuing operations before extraordinary items and cumulative effect of accounting change.................................. $ (0.58) $ 5.74 $ 0.77 $ 1.53 $ 1.29 Income from discontinued operations, net of tax...... 0.08 0.08 0.79 1.62 0.27 Loss on disposal of discontinued operations.......... -- -- -- -- (14.58) Extraordinary items, net of tax...................... -- (0.64) -- -- (0.06) Cumulative effect of accounting change, net of tax... -- -- -- 0.20 -- ------- ------- ------- ------- ------- Diluted earnings (loss) per common share............... $ (0.50) $ 5.18 $ 1.56 $ 3.35 $(13.08) ======= ======= ======= ======= ======= Cash dividends paid per common share................... $ 1.50 $ 1.50 $ 1.50 $ 1.50 $ 1.07 Dividend payout ratio from continuing operations....... -- 26% 192% 97% 82% Return from continuing operations on average common equity............................................... (3.6)% 30.4% 4.1% 8.3% 9.1% Ratio of earnings from continuing operations to fixed charges.............................................. -- 5.41 1.75 2.05 1.76

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YEAR ENDED DECEMBER 31, ----------------------------------------------- 1998(1) 1999(2) 2000(3) 2001(4) 2002(5) ------- ------- ------- ------- ------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) At year-end: Book value per common share.......................... $ 15.16 $ 18.70 $ 19.10 $ 22.77 $ 4.74 Market price per common share........................ $ 32.06 $ 22.88 $ 43.31 $ 26.52 $ 8.01 Market price as a percent of book value.............. 211% 122% 227% 116% 169% Total assets, excluding assets of discontinued operations......................................... $18,301 $22,772 $21,127 $18,967 $19,634 Total assets......................................... $19,959 $28,658 $35,225 $31,266 $19,634 Short-term borrowings................................ $ 1,813 $ 3,015 $ 4,886 $ 3,529 $ 347 Long-term debt obligations, including current maturities......................................... $ 7,198 $ 8,883 $ 5,759 $ 5,557 $10,005 Trust preferred securities........................... $ 342 $ 705 $ 705 $ 706 $ 706 Cumulative preferred stock........................... $ 10 $ 10 $ 10 $ -- $ -- Capitalization: Common stock equity.............................. 36% 36% 46% 52% 12% Trust preferred securities....................... 3% 5% 6% 5% 6% Long-term debt, including current maturities..... 61% 59% 48% 43% 82% Capital expenditures, excluding discontinued operations....................................... $ 714 $ 879 $ 922 $ 1,227 $ 854

--------------- (1) 1998 net income includes a non-cash, unrealized loss on our indexed debt securities of $764 million (after-tax), or $2.69 loss per basic and diluted share. For additional information on the indexed debt securities, please read Note 7 to our consolidated financial statements. Fixed charges exceeded earnings by $225 million in 1998. (2) 1999 net income includes an aggregate non-cash, unrealized gain on our indexed debt securities and our Time Warner, Inc. (now AOL Time Warner Inc.) investment, of $1.2 billion (after-tax), or $4.09 earnings per basic share and $4.08 earnings per diluted share. For additional information on the indexed debt securities and AOL Time Warner investment, please read Note 7 to our consolidated financial statements. The extraordinary item in 1999 is a loss related to an accounting impairment of certain generation related regulatory assets of our Electric Generation business segment. For additional information regarding the impairment, please read Note 4 to our consolidated financial statements. (3) 2000 net income includes an aggregate non-cash loss on our indexed debt securities and our AOL Time Warner investment of $67 million (after-tax), or $0.24 loss per basic share and $0.23 loss per diluted share. 2000 net income also includes a $226 million (after-tax) charge (net of a tax benefit of $122 million), or $0.78 loss per basic share and $0.77 loss per diluted share, to reflect the loss on disposal of our Latin America investments. For additional information on the indexed debt securities and AOL Time Warner investment, please read Note 7 to our consolidated financial statements. For additional information regarding our investments in Latin America, please read Note 2 to our consolidated financial statements. (4) 2001 net income includes the following: (i) the cumulative effect of an accounting change resulting from the adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ($59 million after-tax gain, or $0.20 earnings per basic and diluted share) and (ii) an impairment of our Latin America operations ($51 million after-tax, or $0.17 loss per basic and diluted share). For additional information related to the cumulative effect of accounting change, please read Note 5 to our consolidated financial statements. For additional information regarding our investments in Latin America, please read Note 2 to our consolidated financial statements. (5) The extraordinary item in 2002 is a loss related to the early extinguishment of debt ($17 million after-tax, or $0.06 loss per basic and diluted share). For additional information related to the extraordinary item, please read Note 9 to our consolidated financial statements. 44 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis should be read in combination with our consolidated financial statements included in Item 8 herein. OVERVIEW We are a public utility holding company, created on August 31, 2002 as part of a corporate restructuring of Reliant Energy, Incorporated (Reliant Energy) in compliance with requirements of the Texas electric restructuring law. We are the successor to Reliant Energy for financial reporting purposes under the Securities Exchange Act of 1934. Our wholly owned operating subsidiaries own and operate electric generation plants, electric transmission and distribution facilities, natural gas distribution facilities and natural gas pipelines. We are subject to regulation as a "registered holding company" under the Public Utility Holding Company Act of 1935 (1935 Act). At December 31, 2002, our wholly owned subsidiaries included: - CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in our electric transmission and distribution business in the Texas Gulf Coast area; - Texas Genco Holdings, Inc. (Texas Genco), which owns and operates our Texas generating plants; and - CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC), which owns and operates our local gas distribution companies, gas gathering systems and interstate pipelines. We distributed our 83%-ownership interest in Reliant Resources, Inc. (Reliant Resources) to our shareholders on September 30, 2002 (the Reliant Resources Distribution). We distributed approximately 19% of the outstanding common stock of Texas Genco to our shareholders on January 6, 2003. In this section we discuss our results from continuing operations on a consolidated basis and individually for each of our business segments. We also discuss our liquidity, capital resources and critical accounting policies. Our reportable business segments include the following: - Electric Transmission & Distribution; - Electric Generation; - Natural Gas Distribution; - Pipelines and Gathering; and - Other Operations. Effective with the full deregulation of sales of electric energy to retail customers in Texas beginning in January 2002, power generators and retail electric providers in Texas ceased to be subject to traditional cost-based regulation. Since that date, we have sold generation capacity, energy and ancillary services related to power generation at prices determined by the market. Our transmission and distribution services remain subject to rate regulation. Beginning January 1, 2002, the basis of business segment reporting has changed for our Texas electric operations. Although our former retail sales business is no longer conducted by us, retail customers remained regulated customers of our former integrated electric utility, Reliant Energy HL&P, through the date of their first meter reading in 2002. Sales of electricity to retail customers in 2002 prior to this meter reading are reflected in the Electric Transmission & Distribution business segment. The Texas generation operations of Reliant Energy HL&P are now a separate reportable business segment, Electric Generation, whereas they previously had been part of the Electric Operations business segment. The remaining transmission and distribution function is now reported separately in the Electric Transmission & Distribution business segment. In 2001, Latin America was a separate business segment, but is now reported in the Other Operations business segment. Reportable business segments from 2001 have been restated to conform to the 2002 presentation. 45 For business segment reporting information, please read Notes 1 and 17 to our consolidated financial statements. The consolidated financial statements have been prepared to reflect the effects of the Reliant Resources Distribution on the CenterPoint Energy financial statements. The consolidated financial statements present the Reliant Resources businesses (previously reported as the Wholesale Energy, European Energy and Retail Energy business segments and related corporate costs) as discontinued operations, in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). Accordingly, the consolidated financial statements include the necessary reclassifications to reflect these operations as discontinued operations for each of the three years in the period ended December 31, 2002. As a result of the Reliant Resources Distribution, CenterPoint Energy recorded a non-cash loss on disposal of discontinued operations of $4.3 billion in the third quarter of 2002. This loss represents the excess of the carrying value of CenterPoint Energy's net investment in Reliant Resources over the market value of Reliant Resources' common stock. As of December 31, 2001 the Latin America business operations were no longer reported as discontinued operations and were presented as a single line item in continuing operations within the Statement of Consolidated Operations and as a single line item on the Consolidated Balance Sheet in accordance with Emerging Issues Task Force Issue No. 90-6, "Accounting for Certain Events, Not Addressed in Issue No. 87-11 Relating to an Acquired Operating Unit to Be Sold." Effective January 1, 2002, we adopted SFAS No. 144, which does not permit this single line presentation for assets held and used, such as our Latin America investments. Certain reclassifications have been made to our consolidated financial statements to show the retroactive effects of adoption of SFAS No. 144. In February 2003, the Company sold its interest in Argener, a cogeneration facility in Argentina, for $23.1 million. The carrying value of this investment was approximately $11 million as of December 31, 2002. 46 All dollar amounts in the tables that follow are in millions, except for per share amounts. CONSOLIDATED RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, --------------------------- 2000 2001 2002 ------- ------- ------- Revenues.................................................... $10,374 $10,656 $ 7,922 Operating Expenses.......................................... (8,987) (9,412) (6,593) ------- ------- ------- Operating Income............................................ 1,387 1,244 1,329 Loss from Equity Investments in Unconsolidated Subsidiaries.............................................. (29) -- -- Loss on AOL Time Warner Investment.......................... (205) (70) (500) Gain on Indexed Debt Securities............................. 102 58 480 Impairment of Latin America equity investments.............. (131) (4) -- Loss on Disposal of Latin America equity investments........ (176) -- -- Interest Expense and Distribution on Trust Preferred Securities................................................ (564) (607) (738) Other Income, net........................................... 72 54 23 ------- ------- ------- Income From Continuing Operations Before Income Taxes, Extraordinary Item, Cumulative Effect of Accounting Change and Preferred Dividends................................... 456 675 594 Income Tax Expense.......................................... (234) (228) (208) ------- ------- ------- Income From Continuing Operations Before Extraordinary Item, Cumulative Effect of Accounting Change and Preferred Dividends................................................. 222 447 386 Income From Discontinued Operations, net of tax............. 225 475 82 Loss on Disposal of Discontinued Operations................. -- -- (4,371) Extraordinary Item, net of tax.............................. -- -- (17) Cumulative Effect of Accounting Change, net of tax.......... -- 59 -- Preferred Dividends......................................... -- (1) -- ------- ------- ------- Net Income (Loss) Attributable to Common Shareholders..... $ 447 $ 980 $(3,920) ======= ======= ======= Basic Earnings Per Share: Income From Continuing Operations Before Extraordinary Item and Cumulative Effect of Accounting Change................ $ 0.78 $ 1.54 $ 1.30 Income From Discontinued Operations, net of tax............. 0.79 1.64 0.27 Loss on Disposal of Discontinued Operations................. -- -- (14.67) Extraordinary Item, net of tax.............................. -- -- (0.06) Cumulative Effect of Accounting Change, net of tax.......... -- 0.20 -- ------- ------- ------- Net Income (Loss) Attributable to Common Shareholders..... $ 1.57 $ 3.38 $(13.16) ======= ======= ======= Diluted Earnings Per Share: Income From Continuing Operations Before Extraordinary Item and Cumulative Effect of Accounting Change................ $ 0.77 $ 1.53 $ 1.29 Income From Discontinued Operations, net of tax............. 0.79 1.62 0.27 Loss on Disposal of Discontinued Operations................. -- -- (14.58) Extraordinary Item, net of tax.............................. -- -- (0.06) Cumulative Effect of Accounting Change, net of tax.......... -- 0.20 -- ------- ------- ------- Net Income (Loss) Attributable to Common Shareholders..... $ 1.56 $ 3.35 $(13.08) ======= ======= =======

47 The following discussion of consolidated results of operations and results of operations by business segment is based on earnings from continuing operations before interest expense, distribution on trust preferred securities, income taxes, extraordinary item and cumulative effect of accounting change (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 as well as in the individual business segment discussion that follows.

YEAR ENDED DECEMBER 31, ------------------------- 2000 2001 2002 ------ ------ ------- (IN MILLIONS) RECONCILIATION OF OPERATING INCOME TO EBIT AND EBIT TO NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS: Operating income............................................ $1,387 $1,244 $ 1,329 Loss from equity investments in unconsolidated subsidiaries.............................................. (29) -- -- Loss on AOL Time Warner investment.......................... (205) (70) (500) Gain on indexed debt securities............................. 102 58 480 Impairment of Latin America equity investments.............. (131) (4) -- Loss on disposal of Latin America equity investments........ (176) -- -- Other income, net........................................... 72 54 23 ------ ------ ------- EBIT...................................................... 1,020 1,282 1,332 Interest expense and distribution on trust preferred securities................................................ (564) (607) (738) Income tax expense.......................................... (234) (228) (208) ------ ------ ------- Income from continuing operations before income taxes, extraordinary item, cumulative effect of accounting change and preferred dividends......................... 222 447 386 Income from discontinued operations, net of tax............. 225 475 82 Loss on disposal of discontinued operations................. -- -- (4,371) Extraordinary item, net of tax.............................. -- -- (17) Cumulative effect of accounting change, net of tax.......... -- 59 -- Preferred dividends......................................... -- (1) -- ------ ------ ------- Net income (loss) attributable to common shareholders.......................................... $ 447 $ 980 $(3,920) ====== ====== =======

2002 COMPARED TO 2001 Income from Continuing Operations. We reported income from continuing operations before the cumulative effect of accounting change, extraordinary item, and preferred dividends of $386 million ($1.29 per diluted share) for 2002 compared to $447 million ($1.53 per diluted share) for 2001. Effective January 1, 2002, we discontinued amortizing goodwill in accordance with SFAS No. 142, "Goodwill and Other Intangibles" (SFAS No. 142). During 2001, we recognized $49 million of goodwill amortization expense. The $61 million decrease in income from continuing operations before the cumulative effect of accounting change, 48 extraordinary item and preferred dividends for the year ended December 31, 2002 as compared to the same period in 2001 was primarily due to the following: - a $160 million decrease in EBIT from our Electric business segments, reflecting the movement of a portion of this business to Reliant Resources' Retail Energy business segment and reduced rates of return on these regulated operations effective January 2002; - a $61 million increase in EBIT from our Natural Gas Distribution business segment; - a $20 million increase in EBIT from our Pipelines and Gathering business segment; - a $142 million increase in EBIT from our Other Operations business segment; - a $131 million increase in interest expense due to higher borrowing costs; and - a $20 million decrease in income tax expense. Income Tax Expense. The effective tax rates for 2002 and 2001 were 35.0% and 33.8%, respectively. The increase in the effective tax rate for 2002 compared to 2001 was primarily due to an increase in state taxes, a reduced benefit from the amortization of investment tax credits and a higher effective tax rate related to our Latin America operations, offset by the discontinuance of goodwill amortization in accordance with SFAS No. 142. Extraordinary Item. The 2002 results reflect a $17 million after-tax loss resulting from the early extinguishment of debt related to CenterPoint Houston's $850 million term loan and the repurchase of $175 million of CenterPoint Energy's pollution control bonds. Cumulative Effect of Accounting Change. The 2001 results reflect a $59 million after-tax non-cash gain from the adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133). For additional discussion of the adoption of SFAS No. 133, please read Note 5 to our consolidated financial statements. 2001 COMPARED TO 2000 Income From Continuing Operations. We reported income from continuing operations of $447 million ($1.53 per diluted share) for 2001, before a cumulative effect of accounting change of $59 million, net of tax, related to the adoption of SFAS No. 133, compared to $222 million ($0.77 per diluted share) for 2000. The increase in income from continuing operations of $225 million was primarily due to the following: - a $348 million decrease in loss before income and taxes from our Other Operations business segment, primarily due to a $269 million decrease in losses/impairments related to our Latin America operations and a $91 million decrease in a non-cash loss on our AOL Time Warner investment and our related indexed debt securities in 2001 as compared to 2000; and - a $27 million increase in EBIT from our Natural Gas Distribution segment. The above items were partially offset by: - a $102 million decrease in EBIT from our Electric business segments primarily due to the impact of milder weather, reduced rates charged to certain governmental agencies as mandated by the Texas electric restructuring law, fees paid for the early termination of an accounts receivable factoring agreement and higher benefit expenses; and - an increase in net interest expense of $43 million primarily related to interest rate swaps entered into in 2001 and the issuance of the Series 2001-1 Transition Bonds in 2001. Income Tax Expense. The effective tax rates for 2001 and 2000 were 33.8% and 51.3%, respectively. The decrease in the effective tax rate in 2001 compared to 2000 was primarily due to non-recurring increased tax expense arising from the sale of our Latin America investments, including the write-off of deferred tax 49 assets related to the Latin America business segment in 2000 and a decrease in state taxes in 2001 compared to 2000. AOL TIME WARNER INVESTMENT AND INDEXED DEBT SECURITIES In 2002, holders of approximately 16% of the 17.2 million 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) originally issued exercised their right to exchange their ZENS for cash, resulting in aggregate cash payments by CenterPoint Energy of approximately $45 million. One of our subsidiaries owns shares of AOL TW common stock (AOL TW Common) and elected to liquidate a portion of such holdings to facilitate the company's making the cash payments for the ZENS exchanged in 2002. In connection with the exchanges in 2002, we received net proceeds of approximately $43 million from the liquidation of approximately 4.1 million shares of AOL TW Common at an average price of $10.56 per share. We now hold 21.6 million shares of AOL TW Common which are classified as trading securities under SFAS No. 115 and are expected to be held to facilitate our ability to meet our obligation under the ZENS. For additional information regarding our investment in AOL TW, our indexed debt securities and the effect of adoption of SFAS No. 133 on January 1, 2001 on our ZENS obligation, please read Note 7 to our consolidated financial statements. RESULTS OF OPERATIONS BY BUSINESS SEGMENT The following table presents EBIT (in millions) for each of our business segments for 2000, 2001 and 2002. Some amounts from the previous years have been reclassified to conform to the 2002 presentation of the financial statements. These reclassifications do not affect consolidated net income. EBIT BY BUSINESS SEGMENT

YEAR ENDED DECEMBER 31, ------------------------ 2000 2001 2002 ------ ------ ------ (IN MILLIONS) Electric Transmission & Distribution....................... $ 953 $ 906 $1,118 Electric Generation........................................ 331 267 (130) Electric Eliminations...................................... (34) (25) -- ------ ------ ------ Total Electric Business Segments......................... 1,250 1,148 988 Natural Gas Distribution................................... 122 149 210 Pipelines and Gathering.................................... 137 138 158 Other Operations........................................... (485) (137) 5 Eliminations............................................... (4) (16) (29) ------ ------ ------ Total Consolidated EBIT............................... $1,020 $1,282 $1,332 ====== ====== ======

ELECTRIC BUSINESS SEGMENTS Beginning in 2002, we are reporting two new business segments for what was the former Electric Operations business segment: - Electric Transmission & Distribution; and - Electric Generation. The Electric Transmission & Distribution business segment reports results from two sources. This business segment includes the regulated electric transmission and distribution operations as well as impacts of 50 generation-related stranded costs recoverable by the regulated utility. The previously regulated generation operations in Texas are being reported in the new Electric Generation business segment. As a result of the implementation of deregulation and the corresponding new business segments, the regulated transmission and distribution utility recovers the cost of its service through an energy delivery charge, and not as a component of the prior bundled rate, which included energy and delivery charges. The design of the new energy delivery rate differs from the prior bundled rate. The winter/summer rate differential for residential customers has been eliminated and the energy component of the rate structure for commercial and industrial customers has been removed, which will tend to lessen some of the pronounced seasonal variation of revenues which has been experienced in prior periods. Although our former retail sales business is no longer conducted by us, retail customers remained regulated customers of Reliant Energy HL&P through the date of their first meter reading in 2002. Operations during this transition period are reflected in the Electric Transmission & Distribution business segment. The new Electric Transmission & Distribution business segment, CenterPoint Houston, reported EBIT of $1.1 billion for 2002, consisting of EBIT of $421 million for the regulated electric transmission and distribution business, including retail sales during the transition period as discussed above, and non-cash EBIT of $697 million of Excess Cost Over Market (ECOM) regulatory assets associated with costs recorded pursuant to the Texas electric restructuring law as explained below. Operating revenues were $1.5 billion, excluding ECOM, and purchased power costs were $66 million in 2002. The purchased power costs relate to operation of the regulated utility during the transition period discussed above. In the Electric Transmission & Distribution business segment, throughput declined 2% during 2002 as compared to 2001. The decrease was primarily due to reduced energy delivery in the industrial sector resulting from self-generation by several major customers, partially offset by increased residential usage primarily due to non-weather related factors. Additionally, despite a slowing economy, total metered customers continued to grow at an annual rate of approximately 2% during the year. The new Electric Generation business segment, Texas Genco, is comprised of over 14,000 megawatts of electric generation located entirely in the state of Texas. This business segment reported a loss before interest and taxes of $130 million for 2002, primarily due to low natural gas prices and ample generating capacity in Texas, which created a weak price environment when the capacity auctions described below were conducted in late 2001 and early 2002. Operating revenues were $1.5 billion and fuel and purchased power costs were $1.1 billion in 2002. Under the Texas electric restructuring law, each power generator that is unbundled from an integrated electric utility in Texas has an obligation to conduct state mandated capacity auctions of 15% of its capacity. In addition, under a master separation agreement between CenterPoint Energy and Reliant Resources, Texas Genco is contractually obligated to auction all capacity in excess of the state mandated capacity auctions. The auctions conducted periodically between September 2001 and January 2003 were consummated at prices below those used in the ECOM model by the Texas Utility Commission. Under the Texas electric restructuring law, a regulated utility, in our case, CenterPoint Houston, may recover in a regulatory proceeding scheduled for 2004 any difference between market prices received through the state mandated auctions and the Texas Utility Commission's earlier estimates of those market prices. This difference, recorded as a regulatory asset, produced $697 million of EBIT in 2002. 51 The following tables provide summary data of our Electric Transmission & Distribution and Electric Generation business segments for 2002 and our Electric Operations business segment for 2000 and 2001 (in millions, except throughput, power sales and electric sales data):

YEAR ENDED DECEMBER 31, 2002 --------------------------------------------------- ELECTRIC TRANSMISSION ELECTRIC & DISTRIBUTION GENERATION ELIMINATIONS TOTAL -------------- ---------- ------------ ------ (IN MILLIONS) Operating Revenues: Electric revenues.............................. $ 1,525 $ 1,541 $ (48) $3,018 ECOM true-up................................... 697 -- -- 697 ------- ------- ------ ------ Total operating revenues.................... 2,222 1,541 (48) 3,715 ------- ------- ------ ------ Operating Expenses: Fuel and purchased power....................... 66 1,083 (48) 1,101 Operation and maintenance...................... 575 391 -- 966 Depreciation and amortization.................. 271 157 -- 428 Taxes other than income taxes.................. 213 43 -- 256 ------- ------- ------ ------ Total operating expenses.................... 1,125 1,674 (48) 2,751 ------- ------- ------ ------ Operating Income (Loss).......................... 1,097 (133) -- 964 Other Income, net................................ 21 3 -- 24 ------- ------- ------ ------ Earnings Before Interest and Income Taxes........ $ 1,118 $ (130) $ -- $ 988 ======= ======= ====== ====== Throughput (in gigawatt-hours (GWh)): Residential.................................... 23,025 Commercial..................................... 18,377 Industrial..................................... 28,027 Other.......................................... 156 ------- Total....................................... 69,585 ======= Generation Power Sales (in GWh).................. 51,463 =======

52

YEAR ENDED DECEMBER 31, -------------------------- 2000 2001 2002 ------- ------- ------ Operating Revenues....................................... $ 5,494 $ 5,511 $3,715 ------- ------- ------ Operating Expenses: Fuel and purchased power............................... 2,397 2,527 1,101 Operation and maintenance.............................. 978 1,052 966 Depreciation and amortization.......................... 507 453 428 Taxes other than income taxes.......................... 382 376 256 ------- ------- ------ Total operating expenses............................ 4,264 4,408 2,751 ------- ------- ------ Operating Income......................................... 1,230 1,103 964 Other Income, net........................................ 20 45 24 ------- ------- ------ Earnings Before Interest and Income Taxes................ $ 1,250 $ 1,148 $ 988 ======= ======= ====== Electric Sales (in (GWh)): Residential............................................ 22,727 21,371 Commercial............................................. 17,594 17,967 Industrial............................................. 33,249 31,059 Other.................................................. 1,724 928 ------- ------- Total............................................... 75,294 71,325 ======= =======

2002 Compared to 2001. During 2001, our Electric Operations business segment reflected the regulated electric utility business, including generation, transmission and distribution, and retail electric sales. As of January 1, 2002, with the opening of the Texas market to full retail electric competition, generation and retail sales are no longer subject to cost of service regulation. Retail electric sales involve the sale of electricity and related services to end users of electricity and were included as part of the bundled regulated service prior to 2002. Beginning in January 2002, our operations no longer include retail electricity sales. Accordingly, there are no meaningful comparisons for these business segments against prior periods. Operation and maintenance expenses for the Electric Transmission & Distribution and Electric Generation segments decreased by $86 million in 2002 compared to those of the Electric Operations business segment in 2001. The decrease was primarily due to: - a $77 million decrease in factoring expense as a result of the termination of an agreement under which the former Electric Operations business segment had sold its customer accounts receivable; - a $22 million decrease due to fewer plant outages in 2002; - a $10 million decrease in transmission cost of service; and - a $16 million decrease in transmission line losses in 2002 as this is now a cost of retail electric providers. These decreases were partially offset by a $40 million increase in benefits expense, including severance costs of $23 million in connection with the voluntary early retirement program resulting from the mothballing of generating capacity by Texas Genco and the reduction in work force by CenterPoint Houston in 2002. In June 1998, the Texas Utility Commission issued an order approving a transition to competition plan (Transition Plan) filed by Reliant Energy in December 1997. In order to reduce Reliant Energy's exposure to potential stranded costs related to generation assets, the Transition Plan permitted the redirection of depreciation expense to generation assets that Reliant Energy otherwise would apply to transmission, distribution and general plant assets. In addition, the Transition Plan provided that all earnings above a stated overall annual rate of return on invested capital be used to recover Reliant Energy's investment in generation 53 assets. Reliant Energy implemented the Transition Plan effective January 1, 1998. For further discussion of the Transition Plan, please read Note 4(a) to our consolidated financial statements. Depreciation and amortization decreased $25 million in 2002, compared to 2001. The decrease was primarily due to a decrease in amortization of the book impairment regulatory asset ($281 million) recorded in June 1999, which was fully amortized in December 2001, offset by depreciation expense recorded in 2002 as a result of the discontinuance of redirection of depreciation expense related to electric transmission and distribution assets ($217 million) and increased amortization related to transition property associated with the transition bonds issued in November 2001 ($35 million). For further discussion related to the impairment recorded in June 1999, please read Note 4(a) to our consolidated financial statements. Taxes other than income taxes decreased $120 million compared to 2001. The decrease was primarily due to lower property taxes due to lower tax valuations of generation assets ($10 million), lower gross receipts taxes ($64 million), which became the responsibility of the retail electric providers upon deregulation, and lower franchise taxes ($46 million). Other income, net decreased $21 million in 2002 compared to 2001. The decrease was primarily due to a $37 million decrease in interest income from under-recovery of fuel in 2002 as compared to 2001, partially offset by a $19 million increase in interest income from affiliated parties. 2001 Compared to 2000. Our Electric Operations business segment's EBIT for 2001 decreased $102 million compared to 2000. The decrease was primarily due to milder weather, decreased customer demand, increased contract services and benefit expenses and a charge recorded in the fourth quarter of 2001 resulting from the early termination of an accounts receivable factoring agreement. The decrease was also due to the implementation of the pilot program for Texas deregulation in August 2001, reduced rates for certain governmental agencies and increased administrative expenses related to the separation of our regulated and unregulated businesses. These decreases were partially offset by decreased amortization expense and customer growth. Operating revenues increased $17 million in 2001. Base revenues decreased $119 million in 2001 due to decreased customer demand as a result of the effect of milder weather compared to 2000 and decreased customer usage on a weather normalized basis. The weather impact represented approximately $84 million of the decrease in base revenues in 2001 as compared to 2000. This decrease was offset by increased reconcilable fuel revenue of $136 million. The 6% increase in reconcilable fuel revenue in 2001 resulted primarily from increased fuel costs as discussed below. The Texas Utility Commission provides for recovery of certain fuel and purchased power costs through a fixed fuel factor included in electric rates. Revenues collected through this factor are adjusted monthly to equal expenses; therefore, these revenues and expenses have no effect on earnings unless fuel costs are subsequently determined not to be recoverable. The adjusted over/under recovery of fuel costs is recorded in our Consolidated Balance Sheets as regulatory liabilities or regulatory assets, respectively. Fuel and purchased power expenses in 2001 increased by $130 million, or 5%, over 2000 expenses. This increase is due to increased purchased power volume related to the load balancing requirements associated with ERCOT adapting to a single control area, with a slightly higher cost for purchased power ($44.26 and $44.42 per megawatt hour in 2000 and 2001, respectively). The purchased power increase was partially offset by the decline in the volume of natural gas used at a slightly higher rate ($3.98 and $4.23 per million British thermal units in 2000 and 2001, respectively). Operation and maintenance expenses increased $74 million in 2001 compared to 2000 primarily due to the following items: - a $32 million increase in benefits expense primarily driven by medical and pension costs; - a $16 million increase in contract services due to additional major and solid fuel outages at our generating plants in 2001 compared to shorter, routine outages in 2000; - an $11 million increase in administrative expenses related to the separation of our regulated and unregulated businesses; and 54 - a $20 million charge recorded in the fourth quarter of 2001 resulting from the early termination of an accounts receivable factoring agreement. Depreciation and amortization expense decreased $54 million primarily due to a decrease in amortization of the book impairment regulatory asset recorded in June 1999 and decreased amortization expense due to regulatory assets related to cancelled projects being fully amortized in June 2000, partially offset by accelerated amortization of certain regulatory assets related to energy conservation management as required by the Texas Utility Commission. Other income, net increased $25 million in 2001 compared to 2000. The increase was primarily due to an increase in interest income from under-recovery of fuel in 2001 compared to 2000. NATURAL GAS DISTRIBUTION Our Natural Gas Distribution business segment's operations consist of intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. This business segment's operations also include non-rate regulated natural gas sales to and transportation services for commercial and industrial customers in the six states listed above as well as several other Midwestern states. The following table provides summary data of our Natural Gas Distribution business segment for 2000, 2001 and 2002 (in millions, except throughput data):

YEAR ENDED DECEMBER 31, ------------------------ 2000 2001 2002 ------ ------ ------ Operating Revenues......................................... $4,504 $4,742 $3,960 ------ ------ ------ Operating Expenses: Natural gas.............................................. 3,590 3,814 2,995 Operation and maintenance................................ 553 541 539 Depreciation and amortization............................ 145 147 126 Taxes other than income taxes............................ 98 110 102 ------ ------ ------ Total operating expenses.............................. 4,386 4,612 3,762 ------ ------ ------ Operating Income........................................... 118 130 198 Other Income, net.......................................... 4 19 12 ------ ------ ------ Earnings Before Interest and Income Taxes.................. $ 122 $ 149 $ 210 ====== ====== ====== Throughput (in billion cubic feet (Bcf)): Residential and commercial sales......................... 320 310 324 Industrial sales......................................... 57 50 47 Transportation........................................... 50 49 57 Non-rate regulated commercial and industrial............. 565 445 471 ------ ------ ------ Total Throughput...................................... 992 854 899 ====== ====== ======

Generally, the utility operations of our Natural Gas Distribution business segment are allowed to flow through the cost of natural gas to our customers through purchased gas adjustment provisions in tariffs adopted pursuant to regulations of the states in which they operate. Differences between actual gas costs and the amount collected from customers are deferred on the balance sheet so that there is no material impact on EBIT. 2002 Compared to 2001. Our Natural Gas Distribution business segment's EBIT increased $61 million for the year ended December 31, 2002 as compared to the same period in 2001. Operating margins (revenues less fuel costs) in 2002 were $37 million higher than in 2001 primarily as a result of improved margins from 55 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. Operation and maintenance expenses decreased $2 million in 2002 as compared to 2001 primarily due to a reduction in bad debt expense in 2002 as a result of improved collections and lower gas prices, offset by higher benefits expense and administrative expenses. Depreciation and amortization expense decreased approximately $21 million for the year ended December 31, 2002 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 $31 million for the year ended December 31, 2001. This was partially offset by an increase in depreciation expense due to an increased asset base. Taxes other than income taxes decreased $8 million for the year ended December 31, 2002 as compared to the same period in 2001, due primarily to reduced franchise fees as a result of decreased revenues. 2001 Compared to 2000. Our Natural Gas Distribution business segment's EBIT increased $27 million in 2001 from 2000. Operating margins (revenues less fuel costs) in 2001 were $14 million higher than in 2000 primarily 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. Operation and maintenance expenses decreased $12 million in 2001 as compared to 2000 primarily due to expenses totaling approximately $31 million incurred in 2000 in connection with exiting certain non-rate regulated natural gas business activities outside our established market areas offset by the following items: - increased bad debt expense due to higher natural gas prices in the first quarter of 2001; and - higher employee benefit costs. Other income, net increased $15 million in 2001 compared to 2000. The increase was primarily due to a $12 million increase in interest income from affiliated parties. PIPELINES AND GATHERING Our Pipelines and Gathering business segment operates two interstate natural gas pipelines and provides gathering and pipeline services. 56 The following table provides summary data of our Pipelines and Gathering business segment for 2000, 2001 and 2002 (in millions, except throughput data):

YEAR ENDED DECEMBER 31, ------------------------ 2000 2001 2002 ------ ------ ------ Operating Revenues......................................... $ 384 $ 415 $ 374 ------ ------ ------ Operating Expenses: Natural gas.............................................. 76 79 32 Operation and maintenance................................ 100 121 130 Depreciation and amortization............................ 56 58 41 Taxes other than income taxes............................ 15 20 18 ------ ------ ------ Total operating expenses.............................. 247 278 221 ------ ------ ------ Operating Income........................................... 137 137 153 Other Income, net.......................................... -- 1 5 ------ ------ ------ Earnings Before Interest and Income Taxes.................. $ 137 $ 138 $ 158 ====== ====== ====== Throughput (Bcf): Natural gas sales........................................ 14 18 14 Transportation........................................... 845 819 845 Gathering................................................ 288 300 287 Elimination(1)........................................... (12) (9) (9) ------ ------ ------ Total Throughput...................................... 1,135 1,128 1,137 ====== ====== ======

--------------- (1) Elimination of volumes both transported and sold. 2002 Compared to 2001. Our Pipelines and Gathering business segment's EBIT increased $20 million in 2002 from 2001 as discussed below. Operation and maintenance expenses increased $9 million for the year ended December 31, 2002 compared to 2001 primarily due to project work consisting of construction management, material acquisition, engineering, project planning and other services as well as increased employee benefit costs. Project work expenses are offset by revenues billed for these services. Depreciation and amortization expense decreased $17 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. Other income increased $4 million in 2002 as compared to 2001 primarily due to interest accrued on a fuel-related sales tax refund. 2001 Compared to 2000. Our Pipelines and Gathering business segment's EBIT for 2001 was consistent with 2000 results. Increased gas gathering and processing revenues were offset by increased operating expenses associated with a rate case which began in 2001, higher employee benefit costs and increased franchise taxes. OTHER OPERATIONS Our Other Operations business segment consists primarily of our Latin America operations, office buildings and other real estate used in our business operations, district cooling in the central business district in downtown Houston, energy management services and other corporate operations which support all of our business operations. 57 The following table shows EBIT of our Other Operations business segment for the 2000, 2001 and 2002:

YEAR ENDED DECEMBER 31, ----------------------- 2000 2001 2002 ------ ------ ----- Operating Revenues.......................................... $ 97 $ 101 $ 32 Operating Expenses.......................................... 195 228 17 ----- ----- ---- Operating Income (Loss)..................................... (98) (127) 15 Other Expense, net.......................................... (387) (10) (10) ----- ----- ---- Earnings (Loss) Before Interest and Income Taxes............ $(485) $(137) $ 5 ===== ===== ====

2002 Compared to 2001. Our Other Operations business segment's EBIT increased by $142 million in 2002 compared to 2001. The increase was primarily due to a $79 million pre-tax decrease in losses/ impairments related to our Latin America investments, reductions in unallocated corporate costs of $34 million and reductions in corporate accruals, primarily benefits, of $27 million. 2001 Compared to 2000. Other Operations' loss before interest and taxes decreased by $348 million in 2001 compared to 2000. This decrease was primarily due to a $269 million pre-tax decrease in losses/ impairments related to our Latin America investments in 2000 and a $91 million pre-tax decrease in a non- cash loss on our AOL TW investment and related indexed debt securities in 2001 as compared to 2000. DISCONTINUED OPERATIONS On September 30, 2002, CenterPoint Energy distributed all of the shares of Reliant Resources common stock owned by CenterPoint Energy on a pro rata basis to shareholders of CenterPoint Energy common stock. The consolidated financial statements have been prepared to reflect the effect of the Reliant Resources Distribution as described above on the CenterPoint Energy consolidated financial statements. The consolidated financial statements present the Reliant Resources businesses (Wholesale Energy, European Energy, Retail Energy and related corporate costs) as discontinued operations for each of the years in the two year period ended December 31, 2001 and for the nine months ended September 30, 2002. We also recorded a $4.4 billion non-cash loss on disposal of these discontinued operations. This loss represents the excess of the carrying value of our net investment in Reliant Resources over the market value of Reliant Resources common stock. 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, including deregulation, re-regulation and restructuring of the electric utility industry, 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 with respect to: - approval of stranded costs; - allowed rates of return; - rate structures; 58 - recovery of investments; and - operation and construction of facilities; - non-payment for our services due to financial distress of our customers, including Reliant Resources; - 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; - 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; - commercial bank and financial market conditions, our access to capital, the cost of such capital, receipt of certain approvals under the 1935 Act, 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; - 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; - the outcome of the pending securities lawsuits against us, Reliant Energy and Reliant Resources; - the outcome of the Securities and Exchange Commission investigation relating to the treatment in our consolidated financial statements of certain activities of Reliant Resources; - the ability of Reliant Resources to satisfy its indemnity obligations to us; - the reliability of the systems, procedures and other infrastructure necessary to operate the retail electric business in our service territory, including the systems owned and operated by the ERCOT ISO; - 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." 59 LIQUIDITY AND CAPITAL RESOURCES HISTORICAL CASH FLOWS The net cash provided by/used in operating, investing and financing activities for 2000, 2001 and 2002 is as follows (in millions):

YEAR ENDED DECEMBER 31, ------------------------ 2000 2001 2002 ------ ------- ----- Cash provided by (used in): Operating activities..................................... $ 986 $ 1,762 $ 303 Investing activities..................................... (230) (1,151) (755) Financing activities..................................... 1,354 (1,044) 723

CASH PROVIDED BY OPERATING ACTIVITIES Net cash provided by operations in 2002 decreased $1.5 billion compared to 2001. This decrease primarily resulted from a $1.0 billion increase in net regulatory assets and liabilities due primarily to refunds of excess mitigation credits to ratepayers in 2002 ($224 million) and an increase in non-cash revenue related to the ECOM true-up, which resulted in a $697 million increase in regulatory assets in 2002, as well as $156 million paid in connection with the settlement of forward-starting interest rate swaps with an aggregate notional amount of $1.5 billion. Other changes in working capital also contributed to this decrease. Net cash provided by operations in 2001 increased $776 million compared to 2000. This increase primarily resulted from: - significant reductions in accounts receivable, partially offset by reductions in accounts payable, during 2001 compared to 2000 as a result of higher natural gas prices experienced in late 2000; and - an increase in recovered fuel costs by our Electric business segments. This increase was partially offset by other changes in working capital. CASH USED IN INVESTING ACTIVITIES Net cash used in investing activities decreased $396 million during 2002 compared to 2001 due primarily to decreased environmental-related capital expenditures in our electric business segments. Net cash used in investing activities increased $921 million during 2001 compared to 2000. This increase was primarily due to additional capital expenditures in 2001 of $305 million primarily related to our Electric business segments, offset by net proceeds of $729 million received in 2000 from the sale of our Latin America assets, net of investments and advances. CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES Cash flows provided by financing activities increased $1.8 billion in 2002 compared to 2001, primarily due to an increase in short-term borrowings of $668 million as compared to a decrease in short-term borrowings of $1.4 billion in 2001. Cash flows used in financing activities increased $2.4 billion in 2001 compared to 2000, primarily due to a decline in short term borrowings, partially offset by an increase in proceeds from long-term debt. FUTURE SOURCES AND USES OF CASH We believe that our borrowing capability combined with cash flows from operations will be sufficient to meet the operational capital and debt service needs of our businesses for the next twelve months. 60 Our liquidity and capital requirements will be affected by: - capital expenditures; - debt service requirements; - various regulatory actions; and - working capital requirements. The following table sets forth our capital requirements for 2002, and estimates of our capital requirements for 2003 through 2007 (in millions):

2002 2003 2004 2005 2006 2007 ---- ---- ---- ---- ---- ---- Electric Transmission & Distribution............... $261 $258 $300 $300 $295 $300 Electric Generation (with nuclear fuel)(1)......... 280 150 96 68 51 64 Natural Gas Distribution........................... 196 204 216 213 210 210 Pipelines and Gathering............................ 70 60 63 48 44 42 Other Operations................................... 47 12 25 21 15 9 ---- ---- ---- ---- ---- ---- Total............................................ $854 $684 $700 $650 $615 $625 ==== ==== ==== ==== ==== ====

--------------- (1) It is anticipated that Reliant Resources will purchase the majority interest in Texas Genco held by CenterPoint Energy in early 2004 pursuant to the terms of an option that Reliant Resources holds or that this interest or individual generating assets will otherwise be sold to one or more other parties. The following table sets forth estimates of our contractual obligations to make future payments for 2003 through 2007 and thereafter (in millions):

2008 AND CONTRACTUAL OBLIGATIONS TOTAL 2003 2004 2005 2006 2007 THEREAFTER ----------------------- ------- ------ ---- ------ ---- ---- ---------- Long-term debt(1)................... $ 9,985 $ 703 $ 42 $5,574 $206 $ 66 $3,394 Capital leases...................... 20 3 5 5 4 2 1 Short-term borrowing, including credit facilities................. 347 347 -- -- -- -- -- Trust preferred securities.......... 706 -- -- -- -- -- 706 Operating lease payments(2)......... 263 31 28 26 24 23 131 Non-trading derivative liabilities....................... 27 26 1 -- -- -- -- Other commodity commitments(3)...... 1,410 292 165 169 174 167 443 ------- ------ ---- ------ ---- ---- ------ Total contractual cash obligations.................... $12,758 $1,402 $241 $5,774 $408 $258 $4,675 ======= ====== ==== ====== ==== ==== ======

--------------- (1) On February 28, 2003, CenterPoint Energy extended the termination date of its $3.85 billion credit facility to June 30, 2005 as discussed further below. As a result of this extension, the $3.85 billion credit facility has been classified as long-term debt as of December 31, 2002 in the Consolidated Balance Sheet. (2) For a discussion of operating leases, please read Note 13(b) to our consolidated financial statements. (3) For a discussion of other commodity commitments, please read Note 13(a) to our consolidated financial statements. Long-Term Debt. Our long-term debt consists of our obligations and obligations of our subsidiaries, including transition bonds issued by an indirect wholly owned subsidiary (transition bonds). On February 28, 2003, we reached agreement with a syndicate of banks on a second amendment to our $3.85 billion bank facility (the "Second Amendment"). Under the Second Amendment, the maturity date of the bank facility was extended from October 2003 to June 30, 2005, and the $1.2 billion in mandatory prepayments that would have been required this year (including $600 million due on February 28, 2003) were 61 eliminated. The facility consists of a $2.35 billion term loan and a $1.5 billion revolver. The revolver was fully drawn as of February 28, 2003. Borrowings bear interest based on the London interbank offered rate (LIBOR) under a pricing grid tied to our credit rating. At our current credit ratings, the pricing for loans remains the same. The drawn cost for the facility at our current ratings is LIBOR plus 450 basis points. We have agreed to pay the banks an extension fee of 75 basis points on the amounts outstanding under the bank facility on October 9, 2003. We also paid $41 million in fees that were due on February 28, 2003, along with $20 million in fees that had been due on June 30, 2003. In addition, the interest rates will be increased by 25 basis points beginning May 28, 2003 if we do not grant the banks a security interest in our 81% stock ownership of Texas Genco. Granting the security interest in the stock of Texas Genco requires approval from the SEC under the 1935 Act, which is currently being sought. That security interest would be released when we sell Texas Genco, which is expected to occur in 2004. Proceeds from the sale will be used to reduce the bank facility. Also under the Second Amendment, on or before May 28, 2003, we expect to grant to the banks warrants to purchase up to 10%, on a fully diluted basis, of our common stock at a price equal to the greater of $6.56 per share or 110% of the closing price on the New York Stock Exchange on the date the warrants are issued. The warrants would not be exercisable for a year after issuance but would remain outstanding for four years; provided, that if we reduce the bank facility during 2003 by specified amounts, the warrants will be extinguished. To the extent that we reduce the bank facility by up to $400 million on or before May 28, 2003, up to half of the warrants will be extinguished on a basis proportionate to the reduction in the credit facility. To the extent such warrants are not extinguished on or before May 28, 2003, they will vest and become exercisable in accordance with their terms. Whether or not we are able to extinguish warrants on or before May 28, 2003, the remaining 50% of the warrants will be extinguished, again on a proportionate basis, if we reduce the bank facility by up to $400 million by the end of 2003. We plan to eliminate the warrants entirely before they vest by accessing the capital markets to fund the total payments of $800 million during 2003; however, because of current financial market conditions and uncertainties regarding such conditions over the balance of the year, there can be no assurance that we will be able to extinguish the warrants or to do so on favorable terms. The warrants and the underlying common stock would be registered with the SEC and could be exercised either through the payment of the purchase price or on a "cashless" basis under which we would issue a number of shares equal to the difference between the then-current market price and the warrant exercise price. Issuance of the warrants is also subject to obtaining SEC approval under the 1935 Act, which is currently being sought. If that approval is not obtained on or before May 28, 2003, we will provide the banks equivalent cash compensation over the term that our warrants would have been exercisable to the extent they are not otherwise extinguished. In the Second Amendment, we also agreed that our quarterly common stock dividend will not exceed $0.10 per share. If we have not reduced the bank facility by a total of at least $400 million by the end of 2003, of which at least $200 million has come from the issuance of capital stock or securities linked to capital stock (such as convertible debt), the maximum dividend payable during 2004 and for the balance of the term of the facility is subject to an additional test. Under that test the maximum permitted quarterly dividend will be the lesser of (i) $0.10 per share or (ii) 12.5% of our net income per share for the 12 months ended on the last day of the previous quarter. The Second Amendment provides that proceeds from capital stock or indebtedness issued or incurred by us must be applied (subject to a $200 million basket for CERC and another $250 million basket for borrowings by us and other limited exceptions) to repay bank loans and reduce the bank facility. Similarly, cash proceeds from the sale of assets of more than $30 million or, if less, a group of sales aggregating more than $100 million, must be applied to repay bank loans and reduce the bank facility, except that proceeds of up to $120 million can be reinvested in our businesses. On November 12, 2002, CenterPoint Houston entered into a $1.3 billion collateralized term loan maturing November 2005. The interest rate on the loan is LIBOR plus 9.75%, subject to a minimum rate of 12.75%. The loan is secured by CenterPoint Houston's general mortgage bonds. Proceeds from the loan were 62 used (1) to repay CenterPoint Houston's $850 million term loan, (2) to repay $300 million of debt that matured on November 15, 2002, (3) to purchase $100 million of pollution control bonds on December 2, 2002, and (4) to pay costs of issuance. The loan agreement contains various business and financial covenants, including a covenant restricting CenterPoint Houston's debt, excluding transition bonds, as a percent of its total capitalization to 68%. The loan agreement also limits incremental secured debt that may be issued by CenterPoint Houston to $300 million. One of our indirect finance subsidiaries, CenterPoint Energy Transition Bond Company, LLC, has $736 million aggregate principal amount of outstanding transition bonds that were issued in 2001 in accordance with the Texas electric restructuring law. Classes of the transition bonds have final maturity dates of September 15, 2007, September 15, 2009, September 15, 2011 and September 15, 2015 and bear interest at rates of 3.84%, 4.76%, 5.16% and 5.63%, respectively. The transition bonds are secured by "transition property," as defined in the Texas electric restructuring law, which includes the irrevocable right to recover, through non-bypassable transition charges payable by retail electric customers, qualified costs provided in the Texas electric restructuring law. The transition bonds are reported as our long-term debt, although the holders of the transition bonds have no recourse to any of our assets or revenues, and our creditors have no recourse to any assets or revenues (including, without limitation, the transition charges) of the transition bond company. CenterPoint Houston has no payment obligations with respect to the transition bonds except to remit collections of transition charges as set forth in a servicing agreement between CenterPoint Houston and the transition bond company and in an intercreditor agreement among CenterPoint Houston, our indirect transition bond subsidiary and other parties. We purchased $175 million principal amount of outstanding pollution control bonds in the fourth quarter of 2002 at 100% of their principal amount. If market conditions permit, we expect to remarket the $175 million principal amount of pollution control bonds in the first half of 2003. Long-term debt maturities in 2003 include $150 million principal amount of medium-term notes maturing in April 2003 and $16.6 million principal amount of pollution control bonds maturing in December 2003. In addition, CERC Corp. has $500 million principal amount of Term Enhanced Remarketable Securities that must be repaid or remarketed in November 2003. We have $840 million of outstanding ZENS that may be exchanged for cash at any time. Holders of ZENS submitted for exchange are entitled to receive a cash payment equal to 95% of the market value of the reference shares of AOL TW Common. There are 1.5 reference shares of AOL TW Common for each of the 17.2 million ZENS units originally issued (of which approximately 16% were exchanged for cash of approximately $45 million in 2002). The exchange market value is calculated using the average closing price per share of AOL TW Common on the New York Stock Exchange on one or more trading days following the notice date for the exchange. One of our subsidiaries owns the reference shares of AOL TW Common and generally liquidates such holdings to the extent of ZENS exchanged. Cash proceeds from such liquidations are used to fund ZENS exchanged for cash. Although proceeds from the sale of AOL TW Common offset the cash paid on exchanges, ZENS exchanges result in a cash outflow because of our current tax obligations. Current tax obligations in 2002 increased by $58 million as a result of the 2002 exchanges of ZENS having a principal amount of $160 million and the related sale of 4.1 million shares of AOL TW Common. CenterPoint Houston has issued approximately $1.2 billion aggregate principal amount of first mortgage bonds and approximately $1.8 billion aggregate principal amount of general mortgage bonds, of which approximately $1.1 billion combined aggregate principal amount of first mortgage bonds and general mortgage bonds collateralizes debt of CenterPoint Energy. The general mortgage bonds are issued under the General Mortgage Indenture dated as of October 10, 2002. The lien of the general mortgage indenture is junior to that of the Mortgage, pursuant to which the first mortgage bonds are issued. The aggregate amount of additional general mortgage bonds and first mortgage bonds that could be issued is approximately $900 million based on estimates of the value of property encumbered by the General Mortgage, the cost of such property and the 70% bonding ratio contained in the General Mortgage. The issuance of additional first mortgage and general mortgage bonds is currently contractually limited to an additional $300 million of general mortgage bonds. 63 Short-Term Debt and Receivables Facility. During 2003, the following bank and receivables facilities are scheduled to terminate on the dates indicated.

BORROWER/ SELLER AMOUNT OF FACILITY TERMINATION DATE TYPE OF FACILITY ---------------- ------------------ ----------------- ---------------- (IN MILLIONS) CERC Corp.......................... $350 March 31, 2003 Revolver CERC Corp.......................... 150 November 14, 2003 Receivables CenterPoint Houston................ 75 April 30, 2003 Revolver ---- Total............................ $575 ====

As of December 31, 2002, there was $347 million borrowed under CERC's $350 million revolving credit facility. On February 28, 2003, CERC executed a commitment letter with a major bank for a $350 million, 180-day bridge facility, which is subject to the satisfation of various closing conditions. This facility will be available for repaying borrowings under CERC's 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. CERC paid a commitment fee of 25 basis points on the commitment amount and will be required to pay a facility fee of 75 basis points on 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, CERC expects to provide the lender with collateral in the form of a security interest in the stock it owns in its interstate natural gas pipeline subsidiaries. On December 31, 2002, CERC Corp. had received proceeds from the sale of receivables of approximately $107 million under its $150 million receivables facility and its $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. In February 2003, CenterPoint Houston obtained a $75 million revolving credit facility that terminates on April 30, 2003. A condition precedent to utilizing the facility is that security in the form of general mortgage bonds must be delivered to the lender. Rates for borrowings under this facility, including the facility fee, will be LIBOR plus 250 basis points. On December 31, 2002, we had $265 million of temporary investments. Refunds to CenterPoint Houston Customers. An order issued by the Texas Utility Commission on October 3, 2001 established the transmission and distribution rates that became effective in January 2002. The Texas Utility Commission determined that CenterPoint Houston had overmitigated its stranded costs by redirecting transmission and distribution depreciation and by accelerating depreciation of generation assets (an amount equal to earnings above a stated overall rate of return on rate base that was used to recover our investment in generation assets) as provided under the 1998 transition plan and the Texas electric restructuring law. In this final order, CenterPoint Houston is required to reverse the amount of redirected depreciation and accelerated depreciation taken for regulatory purposes as allowed under the transition plan and the Texas electric restructuring law. Per the October 3, 2001 order, CenterPoint Houston recorded a regulatory liability to reflect the prospective refund of the accelerated depreciation. CenterPoint Houston began refunding excess mitigation credits with the January 2002 unbundled bills, to be refunded over a seven-year period. The annual refund of excess earnings is approximately $237 million. Under the Texas electric restructuring law, a final settlement of these stranded costs will occur in 2004. 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: - $167 million of maturing long-term debt; - approximately $684 million of capital expenditures; 64 - an estimated $237 million which we are obligated to return to customers as a result of the Texas Utility Commission's findings of over-mitigation of stranded costs; - remarketing or refinancing of $500 million of CERC Corp. 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; - payments expected to aggregate $350 million in connection with the termination of bank facilities unless replacement facilities or extensions are arranged; and - dividend payments on CenterPoint Energy common stock. We expect to meet our capital requirements through cash flows from operations, short-term borrowings and proceeds from debt and/or equity 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. Limits on our ability to issue secured debt, as described in this report, may adversely affect our ability to issue debt securities. In addition, the recent cost of our secured debt issuances has been very high. A similar cost with regard to additional issuances could significantly impact our debt service. Please read "Risk Factors -- Risk Factors Associated with Financial Condition and Other Risks -- If we are unable to arrange future financings on acceptable terms, our ability to fund future capital expenditures and refinance existing indebtedness could be limited" in Item 1 of this report. At December 31, 2002, CenterPoint Energy had a shelf registration statement for 15 million shares of common stock and CERC Corp. had a shelf registration statement covering $50 million of debt securities. The amount of any debt security or any security having equity characteristics that we can issue, whether registered or unregistered, or whether debt is secured or unsecured, is expected to be affected by the market's perception of our creditworthiness, general market conditions and factors affecting our industry. Proceeds from the sales of securities are expected to be used primarily to refinance debt. Principal Factors Affecting Cash Requirements in 2004 and 2005. We anticipate selling our 81% ownership interest in Texas Genco in 2004. Should Reliant Resources decline to exercise its option to purchase our interest in Texas Genco, we will explore other alternatives to monetize Texas Genco's assets, including possible sale of our ownership interest in Texas Genco or of its individual generating assets, which may significantly affect the timing of any cash proceeds. Proceeds from that sale, plus proceeds from the securitization in 2004 or 2005 of stranded costs related to generating assets of Texas Genco and generation related regulatory assets, are expected to aggregate in excess of $5 billion. We expect to issue securitization bonds in 2004 or 2005 to monetize and recover the balance of stranded costs relating to electric generation assets and other qualified costs as determined in the 2004 true-up proceeding. The issuance will be done pursuant to a financing order to be issued by the Texas Utility Commission. As with the debt of our existing transition bond company, payments on these new securitization bonds would also be made from funds obtained through non-bypassable charges assessed to retail electric customers required to take delivery service from CenterPoint Houston. The holders of the securitization bonds would not have recourse to any of our assets or revenues, and our creditors would not have recourse to any assets or revenues of the entity issuing the securitization bonds. All or a portion of the proceeds from the issuance of securitization bonds remaining after repayment of CenterPoint Houston's $1.3 billion collateralized term loan are expected to be utilized to retire other existing debt. Impact on Liquidity of a Downgrade in Credit Ratings. As of March 4, 2003, Moody's Investors Service, Inc. (Moody's), Standard & Poor's Ratings Services, a division of The McGraw Hill Companies 65 (S&P), and Fitch, Inc. (Fitch) had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:

MOODY'S S&P FITCH ------------------- ------------------- ------------------- RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3) ------ ---------- ------ ---------- ------ ---------- COMPANY/INSTRUMENT CenterPoint Energy Senior Unsecured Debt.............. Ba1 Negative BBB- Stable BBB- Negative CenterPoint Houston Senior Secured Debt (First Mortgage Bonds).......................... Baa2 Stable BBB Stable BBB+ Negative CERC Corp. Senior Debt........................ Ba1 Negative BBB Stable BBB Negative

--------------- (1) A "negative" outlook from Moody's reflects concerns over the next 12 to 18 months which will either lead to a review for a potential downgrade or a return to a stable outlook. A "stable outlook" from Moody's indicates that Moody's does not expect to put the rating on review for an upgrade or downgrade within 18 months from when the outlook was assigned or last affirmed. (2) A "stable" outlook from S&P indicates that the rating is not likely to change over the intermediate to longer term. (3) A "negative" outlook from Fitch encompasses a one- to two-year horizon as to the likely rating direction. 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 and may be revised or withdrawn at any time by the rating agency. 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 obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies. A decline in credit ratings would increase facility fees and borrowing costs under our existing bank credit facilities. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and would negatively impact our ability to complete capital market transactions. Our bank facilities contain "material adverse change" clauses that could impact our ability to make new borrowings under these facilities. The "material adverse change" clauses in most of our bank facilities relate to an event, development or circumstance that has or would reasonably be expected to have a material adverse effect on (a) the business, financial condition or operations of the borrower and its subsidiaries taken as a whole, or (b) the legality, validity or enforceability of the loan documents. The $150 million receivables facility of CERC Corp. requires the maintenance of credit ratings of at least BB from S&P and Ba2 from Moody's. Receivables would cease to be sold in the event a credit rating fell below the threshold. Each ZENS note is exchangeable at the holder's option at any time for an amount of cash equal to 95% of the market value of the reference shares of AOL TW Common attributable to each ZENS note. If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the AOL TW Common that we own or from other sources. We own shares of AOL TW Common equal to 100% of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS exchanges result in a cash outflow because deferred tax liabilities related to the ZENS and AOL TW Common become current tax obligations when ZENS are exchanged and AOL TW Common is sold. 66 CenterPoint Energy Gas Resources Corp., a wholly owned subsidiary of CERC Corp., provides comprehensive natural gas sales and services to industrial and commercial customers who are primarily located within or near the 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 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. Under our bank facility, a payment default by us or any of our significant subsidiaries on any indebtedness exceeding $50 million will cause a default. Pension Plan. As discussed in Note 11 to the consolidated financial statements, we maintain a non-contributory pension plan covering substantially all employees. Employer contributions are based on actuarial computations that establish the minimum contribution required under the Employee Retirement Income Security Act of 1974 (ERISA) and the maximum deductible contribution for income tax purposes. During 2001, we contributed from treasury stock $107 million of CenterPoint Energy common stock to the plan. No contributions were made to the plan during 2002. Under the terms of our pension plan, we reserve the right to change, modify or terminate the plan. Our funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA. Plan assets used to satisfy pension obligations have been adversely impacted by the recent decline in equity market values. However, based on current estimates, we will not be required to make pension contributions until 2005. In accordance with SFAS No. 87, "Employers' Accounting for Pensions," (SFAS 87) changes in pension obligations and assets may not be immediately recognized as pension costs in the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of benefit payments provided to plan participants. In 2000, we recorded a pension benefit of $39 million. Pension costs were $39 million and $35 million for 2001 and 2002, respectively. Included in the net pension benefit cost in 2001 was $45 million of expense related to Reliant Resources' participants. For 2002, a pension benefit of $4 million was recorded related to Reliant Resources' participants. Pension benefit and expense for Reliant Resources' participants are reflected in the Statement of Consolidated Operations as discontinued operations. The calculation of pension expense and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate. As of December 31, 2002, the expected long-term rate of return on plan assets was changed from 9.5% to 9.0%. The change in the assumption was developed by reviewing the plan's targeted asset allocation and asset class return expectations. We believe that our long-term asset allocation on average will approximate the targeted allocation. We regularly review our actual asset allocation and periodically rebalance plan assets as appropriate. As of December 31, 2002, the projected benefit obligation was calculated assuming a discount rate of 6.75%, which is a .5% decline from the 7.25% discount rate assumed in 2001. The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligation specific to the characteristics of our plan. 67 Pension expense for 2003 is estimated to be $90 million based on an expected return on plan assets of 9.0% and a discount rate of 6.75% as of December 31, 2002. If the expected return assumption was lowered by .5% (from 9.0% to 8.5%), 2003 pension expense would increase by approximately $5 million. Similarly, if the discount rate was lowered by .5% (from 6.75% to 6.25%), this assumption change would increase our projected benefit obligation, pension liabilities and 2003 pension expense by approximately $98 million, $88 million and $8 million, respectively. In addition, the assumption change would result in an additional charge to comprehensive income during 2002 of $57 million, net of tax. Primarily due to the decline in the market value of the pension plan's assets and increased benefit obligations associated with a reduction in the discount rate, the value of the plan's assets is less than our accumulated benefit obligation. As a result, we recorded a non-cash minimum liability adjustment, which resulted in a charge to other comprehensive income during the fourth quarter of 2002 of $414 million, net of tax. Recording a minimum liability adjustment did not affect our results of operations during 2002 nor our ability to meet any financial covenants related to our debt facilities. 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. Other Factors that Could Affect Cash Requirements. In addition to the above factors, our liquidity and capital resources could be affected by: - the need to provide cash collateral in connection with certain contracts; - acceleration of payment dates on certain gas supply contracts under certain circumstances; - increases in fees and interest expense in connection with debt refinancings; - various regulatory actions; and - the ability of Reliant Resources and its subsidiaries to satisfy its obligations as a principal customer of CenterPoint Houston and Texas Genco and in respect of its indemnity obligations to us. Money Pool. We have a "money pool" through which we and our participating subsidiaries 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 expected to be met with bank loans. The terms of the money pool are in accordance with requirements applicable to registered public utility holding companies under the 1935 Act. Capitalization. Factors affecting our capitalization include: - covenants in our and our subsidiaries' bank facilities and other borrowing agreements; and - limitations imposed on us as a registered public utility holding company. The bank facilities of CenterPoint Houston and CERC Corp. restrict debt as a percentage of total capitalization. Our $3.85 billion credit agreement limits dividend payments as described above, contains a debt to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant, an EBITDA to interest covenant and restrictions on the use of proceeds from debt issuances and asset sales. In connection with our registration as a public utility holding company under the 1935 Act, the SEC has placed the following limitations on our external debt: - the aggregate amount of CenterPoint Houston's external borrowings has been limited to $3.55 billion; - the aggregate amount of CERC Corp.'s external borrowings has been limited to $2.7 billion; and - the aggregate amount of Texas Genco's external borrowings has been limited to $500 million. Additionally, the SEC has placed limitations on our dividends and the dividends of our subsidiaries that require common equity as a percentage of total capitalization for CenterPoint Houston, CERC Corp. and Texas Genco to be at least 30% after the payment of such dividends. The order issued by the SEC that 68 authorizes our financing program expires on June 30, 2003, and we must seek a new financing order before that date. Any new order may contain restrictions or authorizations different from those described above. OFF BALANCE SHEET FINANCING In connection with the November 2002 amendment and extension of CERC Corp.'s $150 million 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 our Consolidated Balance Sheets. For additional information regarding this transaction, please read Note 3(i) to our consolidated financial statements. 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. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors. ACCOUNTING FOR RATE REGULATION SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Application of SFAS No. 71 to the electric generation portion of our business was discontinued as of June 30, 1999. Our Electric Transmission & Distribution business continues to apply SFAS No. 71 which results in our accounting for the regulatory effects of recovery of "stranded costs" and other "regulatory assets" resulting from the unbundling of the transmission and distribution business from our electric generation operations in our consolidated financial statements. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets reflected in our Consolidated Balance Sheets aggregated $3.3 billion and $4.0 billion as of December 31, 2001 and 2002, respectively. Significant accounting estimates embedded within the application of SFAS No. 71 with respect to our Electric Transmission & Distribution business segment relate to $2.0 billion of recoverable electric generation plant mitigation assets (stranded costs) and $697 million of ECOM true-up. The stranded costs are comprised of $1.1 billion of previously recorded accelerated depreciation and $841 million of previously redirected depreciation. These stranded costs are recoverable under the provisions of the Texas electric restructuring law. The ultimate amount of stranded cost recovery is subject to a final determination which will occur in 2004 and is contingent upon the market value of Texas Genco. Any 69 significant changes in our accounting estimate of stranded costs as a result of current market conditions or changes in the regulatory recovery mechanism currently in place could result in a material write-down of all or a portion of these regulatory assets. Regulatory assets related to ECOM true-up represent the regulatory assets associated with costs incurred as a result of mandated capacity auctions conducted beginning in 2002 by our Electric Generation business being consummated at market-based prices that have been substantially below the estimate of those prices made by the Texas Utility Commission in the spring of 2001. Any significant changes in our estimate of our regulatory asset associated with ECOM true-up could have a significant effect on our financial condition and results of operations. Additionally, any significant changes in our estimated stranded costs or ECOM true-up recovery could significantly affect our liquidity subsequent to the final true-up proceedings conducted by the Texas Utility Commission which are expected to conclude in late 2004. 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 $11.4 billion or 58% 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. 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. As a result of the distribution of approximately 19% of Texas Genco's common stock to our shareholders on January 6, 2003, we re-evaluated our electric generation assets for impairment as of December 31, 2002. This analysis required us to make long-term estimates of future cash receipts associated with the operation or sale of these electric generation assets and related cash outflows. These forecasts require assumptions about demand for electricity within the ERCOT market, future ERCOT market conditions, commodity prices and regulatory developments. As of December 31, 2002, no impairment had been indicated because the estimated cash flows associated with the operations of their assets exceeded their carrying value. However the effects of competition within the ERCOT market, the results of our capacity auctions, and the timing and extent of changes in commodity prices, particularly natural gas prices, could have a significant effect on our future cash flows and therefore affect any future determination of asset impairment. 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 would 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. 70 UNBILLED ENERGY REVENUES Revenues related to the sale and/or delivery of electricity or natural gas (energy) are generally recorded when energy is delivered to customers. However, the determination of energy 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 energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Unbilled electric delivery revenue is estimated each month based on daily supply volumes, applicable rates and analyses reflecting significant historical trends and experience. 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 were $33 million related to our Electric Operations business segment and $269 million related to our Natural Gas Distribution business segment. Accrued unbilled revenues recorded in the Consolidated Balance Sheet as of December 31, 2002 were $70 million related to our Electric Transmission & Distribution business segment and $284 million 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 that 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. As a result of the assessment, we have identified retirement obligations for nuclear decommissioning at the South Texas Project and for lignite mine operations at the Jewett mine supplying the Limestone electric generation facility. Nuclear decommissioning and the lignite mine have recorded liabilities under our previous method of accounting. Liabilities recorded for estimated decommissioning obligations were $138 million and $140 million at December 31, 2001 and 2002, respectively. Liabilities recorded for estimated lignite mine reclamation costs were $28 million and $40 million at December 31, 2001 and 2002, respectively. We have also identified other asset retirement obligations that cannot be calculated because the assets associated with the retirement obligations have an indeterminate life. 71 We used an expected cash flow approach to measure our asset retirement obligations under SFAS No. 143. The following amounts represent our asset retirement obligations on a pro-forma basis as if we had adopted SFAS No. 143 as of the respective dates:

DECEMBER 31, ------------- 2001 2002 ----- ----- (IN MILLIONS) Nuclear decommissioning..................................... $178 $187 Jewett lignite mine......................................... 2 4 ---- ---- Total..................................................... $180 $191 ==== ====

The net difference between the amounts determined under SFAS No. 143 and our previous method of accounting for estimated nuclear decommissioning costs of $16 million will be recorded as a liability. The net difference between the amounts determined under SFAS No. 143 and our previous method of accounting for estimated mine reclamation costs of $37 million will be recorded as a cumulative effect of accounting change. 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 $618 million do not represent SFAS No. 143 asset retirement obligations, but rather embedded regulatory liabilities. Our non-rate regulated businesses have also previously recognized removal costs as a component of depreciation expense. Upon adoption of SFAS No. 143, we will reverse $115 million of previously recognized removal costs with respect to these non-rate regulated businesses as a cumulative effect of accounting change. In August 2001, the FASB issued 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 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", 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. Adoption of SFAS No. 144 also resulted in the retroactive reclassification of our Latin America operations as discussed in Note 2 to our consolidated financial statements. We 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. We have applied this guidance prospectively as it relates to lease accounting and will apply the accounting provisions related to debt extinguishment in 2003. Upon adoption of SFAS No. 145, any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented shall be reclassified. 72 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 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 December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation, Transition and Disclosure -- an Amendment of SFAS No. 123" (SFAS No. 148). SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. SFAS No. 148 also requires that disclosures of the pro forma effect of using the fair value method of accounting for stock-based employee compensation be displayed more prominently and in a tabular format. Additionally, SFAS No. 148 requires disclosure of the pro forma effect in interim financial statements. The transition and annual disclosure requirements of SFAS No.148 are effective for fiscal years ending after December 15, 2002. We currently account for our stock-based compensation awards to employees and directors under the accounting prescribed by APB Opinion No. 25 and provide the disclosures required by SFAS No. 123. We will continue to account for our stock-based compensation awards to employees and directors under the accounting prescribed by APB Opinion No. 25 and have adopted the additional disclosure provisions of SFAS No. 148 in our consolidated financial statements as of December 31, 2002. In January 2003, the FASB issued FIN No. 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 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. See Note 5 to our consolidated financial statements for a discussion of our adoption of SFAS No. 133 on January 1, 2001 and adoption of subsequent cleared guidance. See Note 3(d) to our consolidated financial statements for a discussion of our adoption of SFAS No. 142, "Goodwill and Other Intangible Assets." 73 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, bank loans, mandatory redeemable preferred securities of subsidiary trusts holding solely our junior subordinated debentures (trust preferred securities), securities held in our nuclear decommissioning trusts, some lease obligations and our obligations under the ZENS that subject us to the risk of loss associated with movements in market interest rates. We utilize interest rate swaps in order to hedge portions of our floating-rate debt and to hedge a portion of the interest rate applicable to future offerings of long-term debt. Our floating-rate obligations aggregated $3.1 billion and $5.5 billion at December 31, 2001 and 2002, respectively. If the floating interest rates were to increase by 10% from December 31, 2002 rates, our combined interest expense would increase by a total of $3.3 million each month in which such increase continued. At December 31, 2001 and 2002, we had outstanding fixed-rate debt (excluding indexed debt securities) and trust preferred securities aggregating $6.1 billion and $5.4 billion, respectively, in principal amount and having a fair value of $6.1 billion and $5.4 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 9 and 10 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $260 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 13(f) to our consolidated financial statements, we contributed $14.8 million in each of 2000 and 2001 to a trust established to fund our share of the decommissioning costs for the South Texas 74 Project. In 2002, we contributed $2.9 million to this trust. The securities held by the trust for decommissioning costs had an estimated fair value of $163 million as of December 31, 2002, of which approximately 49% were fixed-rate debt securities that subject us to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 10% from their levels at December 31, 2002, the decrease in fair value of the fixed-rate debt securities would be approximately $1.0 million. In addition, the risk of an economic loss is mitigated. Any unrealized gains or losses are accounted for in accordance with SFAS No. 71 as a regulatory asset/liability because we believe that our future contributions, which are currently recovered through the ratemaking process, will be adjusted for these gains and losses. For further discussion regarding the recovery of decommissioning costs pursuant to the Texas electric restructuring law, please read Note 4(a) to our consolidated financial statements. As discussed in Note 9(b) to our consolidated financial statements, CERC Corp.'s $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. As discussed in Note 7 to our consolidated financial statements, upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of $104 million at December 31, 2002 is a fixed-rate obligation and, therefore, does not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $15 million if interest rates were to decline by 10% from levels at December 31, 2002. Changes in the fair value of the derivative component, $225 million at December 31, 2002, are recorded in our Statements of Consolidated Operations and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from December 31, 2002 levels, the fair value of the derivative component would increase by approximately $4 million, which would be recorded as an unrealized loss in our Statements of Consolidated Operations. As of December 31, 2002, we had interest rate swaps having an aggregate notional amount of $750 million to fix the interest rate applicable to floating rate debt. At December 31, 2002, the swaps relating to floating rate debt could be terminated at a cost of $16 million. The swaps relating to short-term debt do not qualify as cash flow hedges under SFAS No. 133, and are marked to market in our Consolidated Balance Sheets with changes reflected in interest expense in the Statements of Consolidated Operations. A decrease of 10% in the December 31, 2002 level of interest rates would increase the cost of terminating the swaps outstanding at December 31, 2002 by approximately $1 million. During 2002, we settled our forward-starting interest rate swaps having an aggregate notional amount of $1.5 billion at a cost of $156 million. For information regarding the accounting for interest rate swaps, please read Note 5 to our consolidated financial statements. EQUITY MARKET VALUE RISK We are exposed to equity market value risk through our ownership of 21.6 million shares of AOL TW Common, which are held by us to facilitate our ability to meet our obligations under the ZENS. Please read Note 7 to our consolidated financial statements for a discussion of the effect of adoption of SFAS No. 133 on our ZENS obligation and our historical accounting treatment of our ZENS obligation. A decrease of 10% from the December 31, 2002 market value of AOL TW Common would result in a net loss of approximately $3 million, which would be recorded as a loss in our Statements of Consolidated Operations. As discussed above under "-- Interest Rate Risk," we contribute to a trust established to fund our share of the decommissioning costs for the South Texas Project, which held debt and equity securities as of December 31, 2002. The equity securities expose us to losses in fair value. If the market prices of the 75 individual equity securities were to decrease by 10% from their levels at December 31, 2002, the resulting loss in fair value of these securities would be approximately $8 million. Currently, the risk of an economic loss is mitigated as discussed above under "-- Interest Rate Risk." 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 future operational gas requirements. 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 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. We have established a Risk Oversight Committee, comprised of corporate and business segment officers, that oversees all commodity price and credit risk activities, including trading, marketing, risk management services and hedging activities. The committee's duties are to establish 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 our board of directors. Our 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. 76 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA OF THE COMPANY CENTERPOINT ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED OPERATIONS

YEAR ENDED DECEMBER 31, ------------------------------------------ 2000 2001 2002 ------------ ------------ ------------ (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) REVENUES.................................................... $10,374,202 $10,656,357 $ 7,922,498 ----------- ----------- ----------- EXPENSES: Fuel and cost of gas sold................................. 5,270,937 5,142,040 3,895,365 Purchased power........................................... 755,924 1,223,437 94,749 Operation and maintenance................................. 1,702,209 1,786,269 1,599,023 Depreciation and amortization............................. 726,467 671,349 615,770 Taxes other than income taxes............................. 490,366 514,044 388,155 Impairment of Latin America assets........................ 40,711 75,342 -- ----------- ----------- ----------- Total................................................... 8,986,614 9,412,481 6,593,062 ----------- ----------- ----------- OPERATING INCOME............................................ 1,387,588 1,243,876 1,329,436 ----------- ----------- ----------- OTHER INCOME (EXPENSE): Unrealized loss on AOL Time Warner investment............. (204,969) (70,215) (499,704) Unrealized gain on indexed debt securities................ 101,851 58,033 480,027 Loss from equity investments in unconsolidated subsidiaries............................................ (28,813) -- -- Impairment of Latin America equity investments............ (130,842) (4,093) -- Loss on disposal of Latin America equity investments...... (176,400) -- -- Interest expense.......................................... (509,974) (551,534) (682,700) Distribution on trust preferred securities................ (54,358) (55,598) (55,545) Other, net................................................ 72,155 54,708 22,795 ----------- ----------- ----------- Total................................................... (931,350) (568,699) (735,127) ----------- ----------- ----------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES, EXTRAORDINARY ITEM, CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND PREFERRED DIVIDENDS................................... 456,238 675,177 594,309 INCOME TAX EXPENSE.......................................... 234,196 228,252 208,026 ----------- ----------- ----------- INCOME FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEM, CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND PREFERRED DIVIDENDS................................................. 222,042 446,925 386,283 INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX............. 225,458 475,078 82,157 LOSS ON DISPOSAL OF DISCONTINUED OPERATIONS................. -- -- (4,371,464) EXTRAORDINARY ITEM, NET OF TAX OF $9,267.................... -- -- (17,210) CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX.......... -- 58,556 -- ----------- ----------- ----------- INCOME (LOSS) BEFORE PREFERRED DIVIDENDS.................... 447,500 980,559 (3,920,234) PREFERRED DIVIDENDS......................................... 389 858 -- ----------- ----------- ----------- NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS....... $ 447,111 $ 979,701 $(3,920,234) =========== =========== =========== BASIC EARNINGS PER SHARE: Income from Continuing Operations Before Extraordinary Item and Cumulative Effect of Accounting Change......... $ 0.78 $ 1.54 $ 1.30 Income from Discontinued Operations, net of tax........... 0.79 1.64 0.27 Loss on disposal of Discontinued Operations............... -- -- (14.67) Extraordinary Item, net of tax............................ -- -- (0.06) Cumulative Effect of Accounting Change, net of tax........ -- 0.20 -- ----------- ----------- ----------- Net Income (Loss) Attributable to Common Shareholders..... $ 1.57 $ 3.38 $ (13.16) =========== =========== =========== DILUTED EARNINGS PER SHARE: Income from Continuing Operations Before Extraordinary Item and Cumulative Effect of Accounting Change......... $ 0.77 $ 1.53 $ 1.29 Income from Discontinued Operations, net of tax........... 0.79 1.62 0.27 Loss on disposal of Discontinued Operations............... -- -- (14.58) Extraordinary Item, net of tax............................ -- -- (0.06) Cumulative Effect of Accounting Change, net of tax........ -- 0.20 -- ----------- ----------- ----------- Net Income (Loss) Attributable to Common Shareholders..... $ 1.56 $ 3.35 $ (13.08) =========== =========== ===========

See Notes to the Company's Consolidated Financial Statements 77 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

YEAR ENDED DECEMBER 31, ---------------------------------- 2000 2001 2002 -------- --------- ----------- (IN THOUSANDS OF DOLLARS) Net income (loss) attributable to common shareholders..... $447,111 $ 979,701 $(3,920,234) -------- --------- ----------- Other comprehensive income (loss), net of tax: Foreign currency translation adjustments (net of tax of $40,862, $13 and $291)............................... 75,887 (24) (540) Additional minimum pension liability adjustment (net of tax of $9,918, $6,873 and $223,060).................. (18,419) 12,764 (414,254) Cumulative effect of adoption of SFAS No. 133 (net of tax of $20,511)...................................... -- 38,092 -- Net deferred loss from cash flow hedges (net of tax of $23,794 and $25,192)................................. -- (15,549) (69,615) Reclassification of deferred loss (gain) from cash flow hedges realized in net income (net of tax of $18,978 and $13,539)......................................... -- (59,055) 39,705 Other comprehensive income (loss) from discontinued operations (net of tax of $7,078, $84,563 and $87,078)............................................. 13,144 (157,045) 161,716 -------- --------- ----------- Other comprehensive income (loss)......................... 70,612 (180,817) (282,988) -------- --------- ----------- Comprehensive income (loss)............................... $517,723 $ 798,884 $(4,203,222) ======== ========= ===========

See Notes to the Company's Consolidated Financial Statements 78 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

DECEMBER 31, DECEMBER 31, 2001 2002 ------------ ------------ (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 35,500 $ 311,710 Investment in AOL Time Warner common stock................ 826,609 283,486 Accounts receivable, net.................................. 523,172 562,977 Accrued unbilled revenues................................. 302,879 354,497 Inventory................................................. 405,638 351,816 Non-trading derivative assets............................. 6,996 27,275 Current assets of discontinued operations................. 4,657,187 -- Prepaid expense and other current assets.................. 34,539 71,367 ----------- ----------- Total current assets.................................. 6,792,520 1,963,128 ----------- ----------- PROPERTY, PLANT AND EQUIPMENT, NET.......................... 11,199,505 11,409,369 ----------- ----------- OTHER ASSETS: Goodwill, net............................................. 1,740,510 1,740,510 Other intangibles, net.................................... 62,294 65,880 Regulatory assets......................................... 3,283,492 4,000,646 Non-trading derivative assets............................. 2,234 3,866 Non-current assets of discontinued operations............. 7,642,276 -- Other..................................................... 543,532 450,880 ----------- ----------- Total other assets.................................... 13,274,338 6,261,782 ----------- ----------- TOTAL ASSETS........................................ $31,266,363 $19,634,279 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Short-term borrowings..................................... $ 3,528,614 $ 347,000 Current portion of long-term debt......................... 636,987 810,325 Indexed debt securities derivative........................ 730,225 224,881 Accounts payable.......................................... 526,758 623,457 Taxes accrued............................................. 286,668 118,669 Interest accrued.......................................... 111,629 197,274 Non-trading derivative liabilities........................ 72,744 26,387 Regulatory liabilities.................................... 154,783 168,173 Accumulated deferred income taxes, net.................... 322,186 285,275 Current liabilities of discontinued operations............ 3,737,636 -- Other..................................................... 346,846 288,547 ----------- ----------- Total current liabilities............................. 10,455,076 3,089,988 ----------- ----------- OTHER LIABILITIES: Accumulated deferred income taxes, net.................... 2,353,375 2,449,206 Unamortized investment tax credits........................ 247,407 230,037 Non-trading derivative liabilities........................ 9,825 873 Benefit obligations....................................... 420,356 834,989 Regulatory liabilities.................................... 1,210,888 959,421 Non-current liabilities of discontinued operations........ 3,616,498 -- Other..................................................... 589,534 747,355 ----------- ----------- Total other liabilities............................... 8,447,883 5,221,881 ----------- ----------- LONG-TERM DEBT.............................................. 4,919,737 9,194,320 ----------- ----------- COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 13) COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF THE COMPANY.................... 705,744 706,140 ----------- ----------- SHAREHOLDERS' EQUITY........................................ 6,737,923 1,421,950 ----------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY............ $31,266,363 $19,634,279 =========== ===========

See Notes to the Company's Consolidated Financial Statements 79 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS

YEAR ENDED DECEMBER 31, --------------------------------------- 2000 2001 2002 ----------- ----------- ----------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) attributable to common shareholders..... $ 447,111 $ 979,701 $(3,920,234) Less: Income from discontinued operations, net of tax..... (225,458) (475,078) (82,157) Add: Loss on disposal of discontinued operations.......... -- -- 4,371,464 ----------- ----------- ----------- Income from continuing operations and cumulative effect of accounting change, less extraordinary item.............. 221,653 504,623 369,073 Adjustments to reconcile income from continuing operations to net cash provided by operating activities: Depreciation and amortization........................... 726,467 671,349 615,770 Fuel-related amortization............................... 44,645 29,410 12,729 Deferred income taxes................................... (3,306) (132,719) 317,056 Investment tax credit................................... (18,330) (18,330) (17,370) Cumulative effect of accounting change, net............. -- (58,556) -- Unrealized loss on AOL Time Warner investment........... 204,969 70,215 499,704 Unrealized gain on indexed debt securities.............. (101,851) (58,033) (480,027) Undistributed losses of unconsolidated subsidiaries..... 41,482 -- -- Impairment of Latin America assets...................... 40,711 75,342 -- Loss on impairment/disposal of Latin America equity investments........................................... 241,587 -- -- Extraordinary item...................................... -- -- 17,210 Changes in other assets and liabilities: Accounts receivable and unbilled revenues, net........ (1,030,765) 1,126,756 (243,865) Inventory............................................. (66,300) (15,550) 53,822 Accounts payable...................................... 1,055,105 (1,122,771) 96,699 Federal tax refund.................................... 86,155 -- -- Fuel cost over (under) recovery/surcharge............. (480,895) 422,672 250,191 Interest and taxes accrued............................ (195,420) 258,549 (73,213) Net regulatory assets and liabilities................. (15,962) (49,523) (1,058,439) Non-trading derivatives, net.......................... -- 14,781 (108,478) Other current assets.................................. 22,008 (16,205) (36,828) Other current liabilities............................. 158,593 (99,661) (86,566) Other assets.......................................... (19,907) 90,700 263 Other liabilities..................................... 71,906 6,610 147,256 Other, net.............................................. 3,944 62,828 27,966 ----------- ----------- ----------- Net cash provided by operating activities........... 986,489 1,762,487 302,953 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures...................................... (922,165) (1,227,175) (854,376) Proceeds from sale of AOL Time Warner investment.......... -- -- 43,419 Investments in unconsolidated subsidiaries................ (60,799) -- -- Proceeds from sale of Latin America equity investments.... 790,166 -- -- Other, net................................................ (37,392) 76,559 55,995 ----------- ----------- ----------- Net cash used in investing activities............... (230,190) (1,150,616) (754,962) ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term debt.............................. 329,475 1,296,779 1,320,723 Increase (decrease) in short-term borrowings, net......... 1,902,371 (1,356,162) 668,386 Payments of long-term debt................................ (493,286) (632,116) (696,218) Debt issuance costs....................................... (8,684) (10,608) (196,830) Payment of common stock dividends......................... (426,859) (433,918) (324,682) Proceeds from issuance of common stock, net............... 53,809 100,430 12,994 Purchase of treasury stock................................ (27,306) -- -- Redemption of preferred stock............................. -- (10,227) -- Increase in restricted cash related to securitization financing............................................... -- (6,775) -- Redemption of indexed debt securities..................... -- -- (45,085) Other, net................................................ 24,231 8,877 (16,525) ----------- ----------- ----------- Net cash provided by (used in) financing activities........................................ 1,353,751 (1,043,720) 722,763 ----------- ----------- ----------- NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS...... (2,067,533) 365,278 5,456 ----------- ----------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ 42,517 (66,571) 276,210 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 59,554 102,071 35,500 ----------- ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 102,071 $ 35,500 $ 311,710 =========== =========== =========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest................................................ $ 737,217 $ 534,812 $ 584,595 Income taxes............................................ 447,658 321,927 82,516

See Notes to the Company's Consolidated Financial Statements 80 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED SHAREHOLDERS' EQUITY

2000 2001 2002 -------------------- -------------------- --------------------- SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT ------- ---------- ------- ---------- ------- ----------- (THOUSANDS OF DOLLARS AND SHARES) PREFERENCE STOCK, NONE OUTSTANDING.......................... -- $ -- -- $ -- -- $ -- CUMULATIVE PREFERRED STOCK, $0.01 PAR VALUE; AUTHORIZED 20,000,000 SHARES Balance, beginning of year................................ 97 9,740 97 9,740 -- -- Redemption of preferred stock............................. -- -- (97) (9,740) -- -- ------- ---------- ------- ---------- ------- ----------- Balance, end of year...................................... 97 9,740 -- -- -- -- ------- ---------- ------- ---------- ------- ----------- COMMON STOCK, $0.01 PAR VALUE; AUTHORIZED 1,000,000,000 SHARES Balance, beginning of year................................ 297,612 2,976 299,914 2,999 302,944 3,029 Issuances related to benefit and investment plans......... 2,302 23 3,030 30 2,073 21 ------- ---------- ------- ---------- ------- ----------- Balance, end of year...................................... 299,914 2,999 302,944 3,029 305,017 3,050 ------- ---------- ------- ---------- ------- ----------- ADDITIONAL PAID-IN-CAPITAL Balance, beginning of year................................ -- 3,179,775 -- 3,254,191 -- 3,894,272 Issuances related to benefit and investment plans......... -- 74,424 -- 130,630 -- 11,866 Gain (loss) on issuance of subsidiaries' stock............ -- -- -- 509,499 -- (12,835) Distribution of Reliant Resources......................... -- -- -- -- -- (847,200) Other..................................................... -- (8) -- (48) -- (60) ------- ---------- ------- ---------- ------- ----------- Balance, end of year...................................... -- 3,254,191 -- 3,894,272 -- 3,046,043 ------- ---------- ------- ---------- ------- ----------- TREASURY STOCK Balance, beginning of year................................ (3,625) (93,296) (4,811) (120,856) -- -- Shares acquired........................................... (1,184) (27,306) -- -- -- -- Contribution to pension plan.............................. -- -- 4,512 113,336 -- -- Other..................................................... (2) (254) 299 7,520 -- -- ------- ---------- ------- ---------- ------- ----------- Balance, end of year...................................... (4,811) (120,856) -- -- -- -- ------- ---------- ------- ---------- ------- ----------- UNEARNED ESOP STOCK Balance, beginning of year................................ (10,679) (199,226) (8,639) (161,158) (7,070) (131,888) Issuances related to benefit plan......................... 2,040 38,068 1,569 29,270 2,154 53,839 ------- ---------- ------- ---------- ------- ----------- Balance, end of year...................................... (8,639) (161,158) (7,070) (131,888) (4,916) (78,049) ------- ---------- ------- ---------- ------- ----------- RETAINED EARNINGS (DEFICIT) Balance, beginning of year................................ 2,500,181 2,520,350 3,176,533 Net income (loss)......................................... 447,111 979,701 (3,920,234) Common stock dividends -- $1.50 per share in 2000, $1.125 per share in 2001 and $1.07 per share in 2002........... (426,942) (323,518) (318,382) ---------- ---------- ----------- Balance, end of year...................................... 2,520,350 3,176,533 (1,062,083) ---------- ---------- ----------- ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Balance, beginning of year................................ (93,818) (23,206) (204,023) ---------- ---------- ----------- Other comprehensive income (loss), net of tax: Foreign currency translation adjustments from continuing operations.............................................. 75,887 (24) (540) Additional minimum pension liability adjustment........... (18,419) 12,764 (414,254) Cumulative effect of adoption of SFAS No. 133............. -- 38,092 -- Net deferred gain from cash flow hedges................... -- (15,549) (69,615) Reclassification of deferred loss (gain) from cash flow hedges realized in net income........................... -- (59,055) 39,705 Other comprehensive income (loss) from discontinued operations.............................................. 13,144 (157,045) 161,716 ---------- ---------- ----------- Other comprehensive income (loss)......................... 70,612 (180,817) (282,988) ---------- ---------- ----------- Balance, end of year...................................... (23,206) (204,023) (487,011) ---------- ---------- ----------- Total Shareholders' Equity.............................. $5,482,060 $6,737,923 $ 1,421,950 ========== ========== ===========

See Notes to the Company's Consolidated Financial Statements 81 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) BACKGROUND AND BASIS OF PRESENTATION RESTRUCTURING CenterPoint Energy, Inc. (CenterPoint Energy or the Company) is a public utility holding company, created on August 31, 2002 as part of a corporate restructuring of Reliant Energy, Incorporated (Reliant Energy) that implemented certain requirements of the Texas electric restructuring law described below. In December 2000, Reliant Energy transferred a significant portion of its unregulated businesses to Reliant Resources, Inc. (Reliant Resources), which, at the time, was a wholly owned subsidiary of Reliant Energy. Reliant Resources conducted an initial public offering of approximately 20% of its common stock in May 2001 (the Reliant Resources Offering). In December 2001, Reliant Energy's shareholders approved an agreement and plan of merger pursuant to which the following steps 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 became subsidiaries of CenterPoint Energy; and - Each share of Reliant Energy common stock was converted into one share of CenterPoint Energy common stock. On September 5, 2002, CenterPoint Energy announced that its board of directors had declared a distribution of all of the shares of Reliant Resources common stock owned by CenterPoint Energy to its common shareholders on a pro rata basis (the Reliant Resources Distribution). The Reliant Resources Distribution was made on September 30, 2002 to shareholders of record of CenterPoint Energy common stock as of the close of business on September 20, 2002. CenterPoint Energy is the successor to Reliant Energy for financial reporting purposes under the Securities Exchange Act of 1934. The Company's indirect wholly owned operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, natural gas pipelines and electric generating plants. The Company is subject to regulation as a "registered holding company" under the Public Utility Holding Company Act of 1935 (1935 Act). As of December 31, 2002, the Company's indirect wholly owned subsidiaries include: - CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in Reliant Energy's former electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes Houston; - CenterPoint Energy Resources Corp. (CERC Corp., and together with its subsidiaries, CERC), formerly Reliant Energy Resources Corp. (RERC Corp., and, together with its subsidiaries, RERC), which owns gas distribution systems that together form one of the United States' largest natural gas distribution operations in terms of number of customers served. Through wholly owned subsidiaries, CERC owns two interstate natural gas pipelines and gas gathering systems and provides various ancillary services; and - Texas Genco Holdings, Inc. (Texas Genco), which owns and operates the Texas generating plants formerly belonging to the integrated electric utility that was a part of Reliant Energy. The Company distributed approximately 19% of the 80 million outstanding shares of common stock of Texas Genco to the Company's shareholders on January 6, 2003. As a result of the distribution of Texas Genco common stock, CenterPoint Energy recorded an impairment charge of $396 million, which will be reflected as a regulatory asset representing stranded costs in the Consolidated Balance Sheet in the first quarter of 2003. This impairment charge represents the excess of the carrying value of CenterPoint Energy's net investment in Texas Genco over the market value of Texas Genco's common stock. Additionally, in connection with the distribution, CenterPoint Energy will record minority interest ownership in Texas Genco of $146 million in its Consolidated Balance Sheet in the first quarter of 2003. 82 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) BASIS OF PRESENTATION The consolidated financial statements have been prepared to reflect the effect of the Reliant Resources Distribution on the CenterPoint Energy financial statements. The consolidated financial statements present the Reliant Resources businesses (Wholesale Energy, European Energy, Retail Energy and related corporate costs) as discontinued operations, in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). Accordingly, the consolidated financial statements for each of the two years in the period ended December 31, 2001 and for the nine months ended September 30, 2002 reflect these operations as discontinued operations. The Company's reportable business segments include the following: Electric Transmission & Distribution, Electric Generation, Natural Gas Distribution, Pipelines and Gathering and Other Operations. Effective with the deregulation of the Texas electric industry beginning January 1, 2002, the basis of business segment reporting has changed for the Company's electric operations. The Texas generation operations of CenterPoint Energy's former integrated electric utility, Reliant Energy HL&P (Texas Genco), are now a separate reportable business segment, Electric Generation, whereas they previously had been part of the Electric Operations business segment. The remaining transmission and distribution function (CenterPoint Houston) is now reported separately in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers and non-rate regulated retail gas marketing operations to commercial and industrial customers. Pipelines and Gathering includes the interstate natural gas pipeline operations and the natural gas gathering and pipeline services businesses. Other Operations consists primarily of the Company's Latin America operations, office buildings and other real estate used in our business operations, district cooling in the central business district in downtown Houston, energy management services and other corporate operations which support all of the Company's business operations. Latin America operations primarily consist of an electric utility and an electric cogeneration plant located in Argentina. In February 2003, the Company sold its interest in Argener, a cogeneration facility in Argentina, for $23.1 million. The carrying value of this investment was approximately $11 million as of December 31, 2002. (2) RECLASSIFICATION OF FINANCIAL STATEMENTS DISCONTINUED OPERATIONS On September 30, 2002, CenterPoint Energy distributed to its shareholders 240 million shares of Reliant Resources common stock, which represented CenterPoint Energy's approximately 83% ownership interest in Reliant Resources, by means of a tax-free spin-off in the form of a dividend. Holders of CenterPoint Energy common stock on the record date received 0.788603 shares of Reliant Resources common stock for each share of CenterPoint Energy stock that they owned on the record date. The total value of the Reliant Resources Distribution, after the impairment charge discussed below, was $847 million. As a result of the spin-off of Reliant Resources, CenterPoint Energy recorded a non-cash loss on disposal of discontinued operations of $4.4 billion in 2002. This loss represents the excess of the carrying value of CenterPoint Energy's net investment in Reliant Resources over the market value of Reliant Resources' common stock. CenterPoint Energy's financial statements reflect the reclassifications necessary to present Reliant Resources as discontinued operations for all periods shown. Through the date of the spin-off, Reliant Resources' assets and liabilities are shown in CenterPoint Energy's Consolidated Balance Sheets as current and non-current assets and liabilities of discontinued operations. Reliant Resources' revenues for the years ended December 31, 2000 and 2001 and the nine months ended September 30, 2002 included in discontinued operations were $18.7 billion, $31.1 billion and $29.2 billion, respectively. Income from discontinued operations for the years ended December 31, 2000 and 2001 and the 83 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) nine months ended September 30, 2002 is reported net of income tax expense of $84.3 million, $271.6 million and $290.1 million, respectively. These amounts have not been restated to reflect Reliant Resources' adoption of Emerging Issues Task Force (EITF) Issue No. 02-3, "Recognition and Reporting Gains and Losses on Energy Trading Contracts under Issues No. 98-10 and 00-17" during the third quarter of 2002. Reliant Resources' energy trading, marketing, power origination and risk management services activities and contracted sales of electricity to large commercial, industrial and institutional customers are accounted for under mark-to-market accounting. Under the mark-to-market method of accounting, financial instruments and contractual commitments are recorded at fair value in revenues upon contract execution. The net changes in their fair values are reported as revenues in the period of change. Trading and marketing revenues related to the physical sale of natural gas, electric power and other energy related commodities are recorded on a gross basis in the delivery period. Reliant Resources' gains and losses related to financial instruments and contractual commitments qualifying and designated as hedges related to the sale of electric power and sales and purchases of natural gas are recognized in the same period as the settlement of the underlying physical transaction. These realized gains and losses are included in income from discontinued operations. Summarized balance sheet information related to discontinued operations is as follows as of December 31, 2001:

DECEMBER 31, 2001 -------------- (IN MILLIONS) CURRENT ASSETS: Accounts and notes receivable, principally customer....... $ 1,182,140 Trading and marketing assets.............................. 1,611,393 Other current assets...................................... 1,863,654 ------------ Total current assets................................... 4,657,187 ------------ PROPERTY, PLANT AND EQUIPMENT, NET.......................... 4,558,393 ------------ OTHER ASSETS: Goodwill.................................................. 891,060 Other noncurrent assets................................... 2,192,823 ------------ Total other assets..................................... 3,083,883 ------------ TOTAL ASSETS........................................... 12,299,463 ------------ CURRENT LIABILITIES: Accounts payable, principally trade....................... 1,002,326 Trading and marketing liabilities......................... 1,478,336 Other current liabilities................................. 1,256,974 ------------ Total current liabilities.............................. 3,737,636 ------------ OTHER LONG-TERM LIABILITIES................................. 2,748,304 ------------ LONG-TERM DEBT.............................................. 868,194 ------------ TOTAL LIABILITIES...................................... 7,354,134 ------------ NET ASSETS OF DISCONTINUED OPERATIONS....................... $ 4,945,329 ============

84 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) OTHER RECLASSIFICATIONS Effective December 1, 2000, the Company's board of directors approved a plan to dispose of its Latin America operations through sales of its assets. Accordingly, in the Company's 2000 consolidated financial statements, the Company reported the results of its Latin America operations as discontinued operations 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) for each of the three years in the period ended December 31, 2000. In the fourth quarter of 2000, the Latin America business segment sold its investments in El Salvador, Colombia and Brazil for an aggregate $790 million in after-tax proceeds. The Company recorded a $242 million after-tax ($294 million pre-tax) loss in connection with the sale of these investments. In the fourth quarter of 2000 and in the first quarter of 2001, the Company recorded additional after-tax impairments related to its Latin America operations of $89 million and $7 million ($95 million and $6 million pre-tax), respectively, based on the expected net realizable value of the businesses upon their disposition. On December 20, 2001, negotiations for the sale of the remaining Latin America investments were terminated as a result of adverse economic developments in Argentina. During December 2001, the Company concluded there were indicators of impairment related to the remaining assets in this business segment, and accordingly, an impairment evaluation was conducted at the end of the fourth quarter under the guidelines of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed of" (SFAS No. 121). This evaluation resulted in an after-tax impairment charge of $43 million ($74 million pre-tax), representing the excess of book value over estimated net realizable value. The fair value of the remaining net assets was determined using a net discounted cash flows approach. The charge was included as a component of operating income with respect to consolidated subsidiaries and other income with respect to equity investments in unconsolidated subsidiaries. The impairment was primarily related to the economic deterioration in Argentina. As of December 31, 2001 the Latin America business operations were no longer reported as discontinued operations and were presented as a single line item in continuing operations within the Statement of Consolidated Income and as a single line item on the Consolidated Balance Sheet in accordance with EITF Issue No. 90-6, "Accounting for Certain Events, Not Addressed in Issue No. 87-11 Relating to an Acquired Operating Unit to Be Sold". Effective January 1, 2002 the Company adopted SFAS No. 144 which does not permit this single line presentation for assets held and used, such as the Company's Latin America investments. Certain reclassifications have been made to the Company's consolidated financial statements to show the retroactive effects of adoption of SFAS No. 144. (3) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (A) RECLASSIFICATIONS AND USE OF ESTIMATES In addition to the items discussed in Note 2, 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. 85 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (B) PRINCIPLES OF CONSOLIDATION The accounts of CenterPoint Energy and its wholly owned and majority owned subsidiaries are included in the consolidated financial statements. All significant intercompany transactions and balances are eliminated in consolidation. The Company uses the equity method of accounting for investments in entities in which the Company has an ownership interest between 20% and 50% and exercises significant influence. Other investments, excluding marketable securities, are generally carried at cost. (C) REVENUES The Company records revenue for electricity and natural gas sales and services to retail customers under the accrual method and these revenues are generally recognized upon delivery. The Pipelines and Gathering business segment records revenues as transportation services are provided. Energy sales and services not billed by month-end are accrued based upon estimated energy and services delivered. (D) LONG-LIVED ASSETS AND INTANGIBLES The Company records property, plant and equipment at historical cost. The Company expenses repair and maintenance costs as incurred. Property, plant and equipment includes the following:

DECEMBER 31, ESTIMATED USEFUL ----------------- LIVES (YEARS) 2001 2002 ---------------- ------- ------- (IN MILLIONS) Electric transmission & distribution............. 5-75 $ 6,211 $ 5,960 Electric generation.............................. 5-60 9,356 9,610 Natural gas distribution......................... 5-50 1,980 2,151 Pipelines and gathering.......................... 5-75 1,633 1,686 Other property................................... 3-40 146 494 ------- ------- Total.......................................... 19,326 19,901 Accumulated depreciation and amortization........ (8,126) (8,492) ------- ------- Property, plant and equipment, net.......... $11,200 $11,409 ======= =======

In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), which provides that goodwill and certain intangibles with indefinite lives will not be amortized into results of operations, but instead will be reviewed periodically for impairment and written down and charged to results of operations only in the periods in which the recorded value of goodwill and certain intangibles with indefinite lives is more than its fair value. On January 1, 2002, the Company adopted the provisions of the statement that apply to goodwill and intangible assets acquired prior to June 30, 2001. 86 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) With the adoption of SFAS No. 142, the Company ceased amortization of goodwill as of January 1, 2002. A reconciliation of previously reported net income and earnings per share to the amounts adjusted for the exclusion of goodwill amortization follows:

YEAR ENDED DECEMBER 31, ------------------------ 2000 2001 2002 ------ ------ ------ (IN MILLIONS, EXCEPT PER SHARE) Reported income from continuing operations before extraordinary item and cumulative effect of accounting change.................................................... $ 222 $ 446 $ 386 Add: Goodwill amortization, net of tax...................... 50 49 -- ----- ----- ----- Adjusted income from continuing operations before extraordinary item and cumulative effect of accounting change.................................................... $ 272 $ 495 $ 386 ===== ===== ===== Basic Earnings Per Share: Reported income from continuing operations before extraordinary item and cumulative effect of accounting change.................................................... $0.78 $1.54 $1.30 Add: Goodwill amortization, net of tax...................... 0.18 0.17 -- ----- ----- ----- Adjusted income from continuing operations before extraordinary item and cumulative effect of accounting change.................................................... $0.96 $1.71 $1.30 ===== ===== ===== Diluted Earnings Per Share: Reported income from continuing operations before extraordinary item and cumulative effect of accounting change.................................................... $0.77 $1.53 $1.29 Add: Goodwill amortization, net of tax...................... 0.18 0.17 -- ----- ----- ----- Adjusted income from continuing operations before extraordinary item and cumulative effect of accounting change.................................................... $0.95 $1.70 $1.29 ===== ===== =====

The components of the Company's other intangible assets consist of the following:

DECEMBER 31, 2001 DECEMBER 31, 2002 ----------------------- ----------------------- CARRYING ACCUMULATED CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION -------- ------------ -------- ------------ (IN MILLIONS) Land Use Rights.......................... $59 $(11) $61 $(12) Other.................................... 16 (2) 19 (2) --- ---- --- ---- Total.................................. $75 $(13) $80 $(14) === ==== === ====

The Company recognizes specifically identifiable intangibles, including land use rights and permits, when specific rights and contracts are acquired. The Company has no intangible assets with indefinite lives recorded as of December 31, 2002. The Company amortizes other acquired intangibles on a straight-line basis over the lesser of their contractual or estimated useful lives that range from 40 to 75 years for land rights and 4 to 25 years for other intangibles. 87 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Amortization expense for other intangibles for 2000, 2001 and 2002 was $1.3 million, $1.2 million and $1.9 million, respectively. Estimated amortization expense for the five succeeding fiscal years is as follows (in millions): 2003........................................................ $ 2 2004........................................................ 2 2005........................................................ 2 2006........................................................ 2 2007........................................................ 2 --- Total..................................................... $10 === Goodwill by reportable business segment is as follows (in millions):

DECEMBER 31, 2001 AND 2002 ------------- Natural Gas Distribution.................................... $1,085 Pipelines and Gathering..................................... 601 Other Operations............................................ 55 ------ Total..................................................... $1,741 ======

The Company completed its review during the second quarter of 2002 pursuant to SFAS No. 142 for its reporting units in the Natural Gas Distribution, Pipelines and Gathering and Other Operations business segments. No impairment was indicated as a result of this assessment. The Company periodically evaluates long-lived assets, including property, plant and equipment, goodwill and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. An impairment analysis of generating facilities requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the facilities. A resulting impairment loss is highly dependent on these underlying assumptions. During the fourth quarter of 2001, the Reliant Resources Distribution was deemed to be a probable event. As Reliant Resources has an option to purchase the Company's 81% interest in its generation subsidiary, Texas Genco, in 2004 (see Note 4(b)), the Company was required to evaluate Texas Genco's assets for potential impairment in accordance with SFAS No. 121, due to an expected decrease in the number of years the Company expects to hold and operate these assets. As of December 31, 2001, no impairment had been indicated. As a result of the distribution of approximately 19% of Texas Genco's common stock to CenterPoint Energy's shareholders on January 6, 2003, the Company re-evaluated these assets for impairment as of December 31, 2002 in accordance with SFAS No. 144. As of December 31, 2002, no impairment had been indicated. The Company anticipates that future events, such as a change in the estimated holding period of Texas Genco's generation assets, will require the Company to re-evaluate these assets for impairment between now and 2004. If an impairment is indicated, it could be material and will not be fully recoverable through the 2004 true-up proceeding calculations (see Note 4(a)). The Texas electric restructuring law provides the Company recovery of the regulatory book value of its Texas generating assets for the amount the net regulatory book value exceeds the estimated market value. If the Company's 81% interest in Texas Genco is sold to Reliant Resources or to a third party in the future, a loss on sale of these assets, or an impairment of the recorded recoverable electric generation plant mitigation regulatory asset (see Note 3(e)), will occur to the extent the recorded book value of the Texas generating 88 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) assets exceeds the regulatory book value. As of December 31, 2002, the recorded book value was $649 million in excess of the regulatory book value. This amount declines each year as the recorded book value is depreciated and increases by the amount of capital expenditures. For further discussion of the difference between the regulatory book value and the recorded book value, see Note 4. (E) REGULATORY ASSETS AND LIABILITIES The Company applies the accounting policies established in SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the accounts of the Electric Transmission & Distribution business segment and the utility operations of the Natural Gas Distribution business segment and to some of the accounts of the Pipelines and Gathering business segment. For information regarding Texas Genco's discontinuance of the application of SFAS No. 71 in 1999 and the effect on its regulatory assets and the Texas electric restructuring law, see Note 4(a). The following is a list of regulatory assets/liabilities reflected on the Company's Consolidated Balance Sheets as of December 31, 2001 and 2002:

DECEMBER 31, ---------------- 2001 2002 ------- ------ (IN MILLIONS) Excess cost over market (ECOM) true-up...................... $ -- $ 697 Recoverable electric generation related regulatory assets, net....................................................... 160 100 Securitized regulatory asset................................ 740 706 Regulatory tax asset, net................................... 111 178 Unamortized loss on reacquired debt......................... 62 58 Recoverable electric generation plant mitigation............ 1,967 2,051 Excess mitigation liability................................. (1,126) (969) Other long-term assets/liabilities.......................... 4 52 ------- ------ Total..................................................... $ 1,918 $2,873 ======= ======

If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Company would be required to write off or write down these regulatory assets and liabilities. In addition, the Company would be required to determine any impairment of the carrying costs of plant and inventory assets. Through December 31, 2001, the Public Utility Commission of Texas (Texas Utility Commission) provided for the recovery of most of the Company's fuel and purchased power costs from customers through a fixed fuel factor included in electric rates. Included in the above table in recoverable electric generation related regulatory assets, net are $126 million and $66 million of net regulatory assets related to the recovery of fuel costs as of December 31, 2001 and 2002, respectively. For additional information regarding CenterPoint Houston's fuel filings, see Note 4(c). Texas Genco sells, through auctions, entitlements to substantially all of its installed electric generation capacity, excluding reserves for planned and forced outages. In September, October and December 2001, and March, July, October and November 2002, Texas Genco conducted auctions as required by the Texas Utility Commission and by the master separation agreement with Reliant Resources. The capacity auctions were consummated at market-based prices that are substantially below the estimate of those prices made by the Texas Utility Commission in the spring of 2001. The Texas electric restructuring law provides for the recovery in a "true-up" proceeding in 2004 of any difference between market power prices and the earlier estimates of those prices by the Texas Utility Commission, using the prices received in the auctions required by the Texas Utility Commission as the measure of market prices (ECOM 89 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) true-up). In 2002, CenterPoint Energy recorded approximately $697 million in non-cash revenue related to the cost recovery of the difference between the market power prices and the Texas Utility Commission's earlier estimates. For additional information regarding the capacity auctions and the related true-up proceeding, see Note 4(a). In 2001, the Company monetized $738 million of regulatory assets in a securitization financing authorized by the Texas Utility Commission pursuant to the Texas electric restructuring law. The securitized regulatory assets are being amortized ratably as transition charges are collected over the life of the outstanding transition bonds. For additional information regarding the securitization financing, see Note 4(a). For additional information regarding recoverable impaired plant costs and recoverable electric generation related assets and the related amortization during 2000 and 2001, see Notes 3(g) and 4(a). (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. See Notes 3(f) and 4(a) for additional discussion of these items. The following table presents depreciation, goodwill amortization and other amortization expense for 2000, 2001 and 2002.

YEAR ENDED DECEMBER 31, ------------------------ 2000 2001 2002 ------ ------ ------ (IN MILLIONS) Depreciation expense........................................ $285 $290 $539 Goodwill amortization expense............................... 50 49 -- Other amortization expense.................................. 391 332 77 ---- ---- ---- Total depreciation and amortization expense............... $726 $671 $616 ==== ==== ====

(G) CAPITALIZATION OF INTEREST AND ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION Allowance for funds used during construction (AFUDC) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash through depreciation provisions included in rates for subsidiaries that apply SFAS No. 71. Interest and AFUDC for subsidiaries that apply SFAS No. 71 are capitalized as a component of projects under construction and will be amortized over the assets' estimated useful lives. During 2000, 2001 and 2002, the Company capitalized interest and AFUDC related to debt of $11 million, $9 million and $12 million, respectively. (H) INCOME TAXES The Company files a consolidated federal income tax return and follows a policy of comprehensive interperiod income tax allocation. The Company uses the liability method of accounting for deferred income taxes and measures deferred income taxes for all significant income tax temporary differences. Investment tax credits were deferred and are being amortized over the estimated lives of the related property. Unremitted earnings from the Company's foreign operations are deemed to be permanently reinvested in foreign operations. For additional information regarding income taxes, see Note 12. (I) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS Accounts receivable are net of an allowance for doubtful accounts of $46 million and $24 million at December 31, 2001 and 2002, respectively. The provision for doubtful accounts in the Company's Statements 90 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of Consolidated Operations for 2000, 2001 and 2002 was $38 million, $59 million and $26 million, respectively. During 2000 and 2001, substantially all of the customer accounts receivable of the Company's integrated electric utility were sold. Receivables aggregating $4.9 billion and $5.8 billion were sold in 2000 and 2001, respectively. In December 2001, the Company terminated the agreement under which it sold electric customer accounts receivable and recorded an early termination charge of $20 million in the Statements of Consolidated Operations. Proceeds for the repurchase of receivables, which occurred in January 2002, were obtained from a combination of bank loans and the sale of commercial paper. Net proceeds from the sale of accounts receivable were $523 million at December 31, 2001. Such proceeds were not reflected as debt in the Consolidated Balance Sheets. 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. 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 Sheet. (J) INVENTORY Inventory consists principally of materials and supplies, coal and lignite and natural gas. Inventories used in the production of electricity and in the retail natural gas distribution operations are valued at the lower of average cost or market except for coal and lignite, which are valued under the last-in, first-out method.

DECEMBER 31, ------------- 2001 2002 ----- ----- (IN MILLIONS) Materials and supplies...................................... $208 $185 Coal and lignite............................................ 58 43 Natural gas................................................. 131 119 Other....................................................... 9 5 ---- ---- Total inventory........................................... $406 $352 ==== ====

(K) INVESTMENT IN OTHER DEBT AND EQUITY SECURITIES In accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities" (SFAS No. 115), the Company reports "available-for-sale" securities at estimated fair value within other long-term assets in the Company's Consolidated Balance Sheets and any unrealized gain or loss, net of tax, as a separate component of shareholders' equity and accumulated other comprehensive income. In accordance with SFAS No. 115, the Company reports "trading" securities at estimated fair value in the Company's Consolidated Balance Sheets, and any unrealized holding gains and losses are recorded as other income (expense) in the Company's Statements of Consolidated Operations. As of December 31, 2001 and 2002, the Company held debt and equity securities in its nuclear decommissioning trust, which is reported at its fair value of $169 million and $163 million, respectively, in the Company's Consolidated Balance Sheets in other long-term assets. Any unrealized losses or gains are 91 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) accounted for as a long-term asset/liability as the Company will not benefit from any gains, and losses will be recovered through the rate-making process. As of December 31, 2001 and 2002, the Company held an investment in AOL Time Warner Inc. (AOL TW) common stock (AOL TW Common), which was classified as a "trading" security. For information regarding the Company's investment in AOL TW Common, see Note 7. (L) ENVIRONMENTAL COSTS The Company expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit. The Company expenses amounts that relate to an existing condition caused by past operations, and that do not have future economic benefit. The Company records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Subject to SFAS No. 71, a corresponding regulatory asset is recorded in anticipation of recovery through the rate making process by subsidiaries that apply SFAS No. 71. (M) FOREIGN CURRENCY ADJUSTMENTS Local currencies are the functional currency of the Company's foreign operations. Foreign subsidiaries' assets and liabilities have been translated into U.S. dollars using the exchange rate in effect at the balance sheet date. Revenues, expenses, gains and losses have been translated using the weighted average exchange rate for each month prevailing during the periods reported. Cumulative adjustments resulting from translation have been recorded as a component of accumulated other comprehensive loss in shareholders' equity. (N) STATEMENTS OF CONSOLIDATED CASH FLOWS For purposes of reporting cash flows, the Company considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase. In connection with the issuance of transition bonds in October 2001, the Company was required to establish restricted cash accounts to collateralize the bonds that were issued in this financing transaction. These restricted cash accounts are classified as long-term as they are not available for withdrawal until the maturity of the bonds. Cash and Cash Equivalents does not include restricted cash. For additional information regarding the securitization financing, see Note 4(a). (O) 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. The Company 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 the Company'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, 92 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. The Company adopted SFAS No. 143 on January 1, 2003. The Company has completed an assessment of the applicability and implications of SFAS No. 143. As a result of the assessment, the Company has identified retirement obligations for nuclear decommissioning at the South Texas Nuclear Project (South Texas Project) and for lignite mine operations at the Jewett mine supplying the Limestone electric generation facility. Nuclear decommissioning and the lignite mine have recorded liabilities under the Company's previous method of accounting. Liabilities recorded for estimated decommissioning obligations were $138 million and $140 million at December 31, 2001 and 2002, respectively. Liabilities recorded for estimated lignite mine reclamation costs were $28 million and $40 million at December 31, 2001 and 2002, respectively. The Company has also identified other asset retirement obligations that cannot be calculated because the assets associated with the retirement obligations have an indeterminate life. The Company used an expected cash flow approach to measure its asset retirement obligations under SFAS No. 143. The following amounts represent the Company's asset retirement obligations on a pro-forma basis as if it had adopted SFAS No. 143 as of the respective dates:

DECEMBER 31, ------------- 2001 2002 ----- ----- (IN MILLIONS) Nuclear decommissioning..................................... $178 $187 Jewett lignite mine......................................... 2 4 ---- ---- Total..................................................... $180 $191 ==== ====

The net difference between the amounts determined under SFAS No. 143 and the Company's previous method of accounting for estimated nuclear decommissioning costs of $16 million will be recorded as a liability. The net difference between the amounts determined under SFAS No. 143 and the Company's previous method of accounting for estimated mine reclamation costs of $37 million will be recorded as a cumulative effect of accounting change. The Company'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 $618 million do not represent SFAS No. 143 asset retirement obligations, but rather embedded regulatory liabilities. The Company's non-rate regulated businesses have also previously recognized removal costs as component of depreciation expense. Upon adoption of SFAS No. 143, the Company will reverse $115 million of previously recognized removal costs with respect to these non-rate regulated businesses as a cumulative effect of accounting change. In August 2001, the FASB issued 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 the Company 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. The 93 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Company adopted SFAS No. 144 on January 1, 2002. Adoption of SFAS No. 144 also resulted in the retroactive reclassification of the Company's Latin America operations as discussed in Note 2. 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. The Company has applied this guidance prospectively as it relates to lease accounting and will apply the accounting provision related to debt extinguishment in 2003. Upon adoption of SFAS No. 145, any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented shall be reclassified. 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. The Company will apply the provisions of SFAS No. 146 to all exit or disposal activities initiated after December 31, 2002. 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 the Company's consolidated financial statements. The Company has adopted the additional disclosure provisions of FIN 45 in its consolidated financial statements as of December 31, 2002. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation, Transition and Disclosure -- an Amendment of SFAS No. 123" (SFAS No. 148). SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. SFAS No. 148 also requires that disclosures of the pro forma effect of using the fair value method of accounting for stock-based employee compensation be displayed more prominently and in a tabular format. Additionally, SFAS No. 148 requires disclosure of the pro forma effect in interim financial statements. The transition and annual disclosure requirements of SFAS No. 148 are effective for fiscal years ending after December 15, 2002. The Company currently accounts for its stock-based compensation awards to employees and directors under the accounting prescribed by APB Opinion No. 25 and provides the disclosures required by SFAS No. 123. The Company will continue to account for its stock-based 94 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) compensation awards to employees and directors under the accounting prescribed by APB Opinion No. 25 and has adopted the additional disclosure provisions of SFAS No. 148 in its consolidated financial statements as of December 31, 2002. (See Note 11). 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 period beginning after June 15, 2003. The Company 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 the Company'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 the Company's adoption of SFAS No. 142 on January 1, 2002. (4) REGULATORY MATTERS (A) TEXAS ELECTRIC RESTRUCTURING LAW AND DISCONTINUANCE OF SFAS NO. 71 FOR ELECTRIC GENERATION OPERATIONS In June 1999, the Texas legislature adopted the Texas electric restructuring law, which substantially amended the regulatory structure governing electric utilities in Texas in order to allow retail electric competition. Retail pilot projects allowing competition for up to 5% of each utility's load in all customer classes began in the third quarter of 2001, and retail electric competition for all other customers began in January 2002. In preparation for competition, the Company made significant changes in the electric utility operations it conducts through its former electric utility division, Reliant Energy HL&P (now CenterPoint Houston). In addition, the Texas Utility Commission issued a number of new rules and determinations in implementing the Texas electric restructuring law. The Texas electric restructuring law defined the process for competition and created a transition period during which most utility rates were frozen at rates not in excess of their then-current levels. The Texas electric restructuring law provided for utilities to recover their generation related stranded costs and regulatory assets (as defined in the Texas electric restructuring law). Unbundling. As of January 1, 2002, electric utilities in Texas such as CenterPoint Houston unbundled their businesses in order to separate power generation, transmission and distribution, and retail activities into different units. Pursuant to the Texas electric restructuring law, the Company submitted a plan in January 2000 that was later amended and updated to accomplish the required separation (the business separation plan). The transmission and distribution business continues to be subject to cost-of-service rate regulation and is responsible for the delivery of electricity to retail customers. The Company transferred the Texas generation facilities that were formerly part of Reliant Energy HL&P (Texas generation business) to Texas Genco in connection with the Restructuring. As a result of these changes, the Company's Texas generation operations are no longer conducted as part of an integrated utility and comprise a new business segment, Electric Generation. Additionally, these operations will not be part of the Company's business if they are acquired in 2004 by Reliant Resources pursuant to an option agreement described below or they are otherwise sold. Generation. Power generators began selling electric energy to wholesale purchasers, including retail electric providers, at unregulated prices on January 1, 2002. To facilitate a competitive market, each power generation company affiliated with a transmission and distribution utility is required to sell at auction 15% of the output of its installed generating capacity. The first auction was held in September 2001 for power 95 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) delivered beginning January 1, 2002. This obligation continues until January 1, 2007 unless before that date the Texas Utility Commission determines that at least 40% of the quantity of electric power consumed in 2000 by residential and small commercial load in the electric utility's service area is being served by retail electric providers other than an affiliated or formerly affiliated retail electric provider. Texas Genco plans to auction all of its remaining capacity (less approximately 10% withheld to provide for unforeseen outages) during the time period prior to Reliant Resources' exercise of the Texas Genco Option discussed below. Pursuant to the business separation plan, Reliant Resources is entitled to purchase, at prices established in these auctions, 50% (but no less than 50%) of the remaining capacity, energy and ancillary services auctioned by Texas Genco. Sales to Reliant Resources represented approximately 66% of Texas Genco's total revenues in 2002. Transmission and Distribution Rates. All retail electric providers in CenterPoint Houston's service area pay the same rates and other charges for transmission and distribution services. CenterPoint Houston's distribution rates charged to retail electric providers are generally based on amounts of energy delivered. Transmission rates charged to other distribution companies are based on amounts of energy transmitted under "postage stamp" rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay CenterPoint Houston the same rates and other charges for transmission services. The transmission and distribution rates for CenterPoint Houston have been in effect since January 1, 2002, when electric competition began. This regulated delivery charge includes the transmission and distribution rate (which includes costs for nuclear decommissioning and municipal franchise fees), a system benefit fund fee imposed by the Texas electric restructuring law, a transition charge associated with securitization of regulatory assets and an excess mitigation credit imposed by the Texas Utility Commission. Stranded Costs. CenterPoint Houston will be entitled to recover its stranded costs (the excess of net regulatory book value of generation assets (as defined by the Texas electric restructuring law) over the market value of those assets) and its regulatory assets related to generation. The Texas electric restructuring law prescribes specific methods for determining the amount of stranded costs and the details for their recovery. During the transition period to deregulation (the Transition Period), which included 1998 and the first six months of 1999, and extending through the base rate freeze period from July 1999 through 2001, the Texas electric restructuring law provided that earnings above a stated overall annual rate of return on invested capital be used to recover the Company's investment in generation assets (Accelerated Depreciation). In addition, during the Transition Period, the redirection of depreciation expense to generation assets that CenterPoint Houston would otherwise apply to transmission, distribution and general plant assets was permitted for regulatory purposes (Redirected Depreciation). Please read the discussion of the accounting treatment for depreciation for financial reporting purposes below under "-- Accounting." The Company cannot predict the amount, if any, of these costs that may not be recovered. In accordance with the Texas electric restructuring law, beginning on January 1, 2002, and ending December 31, 2003, any difference between market power prices received in the generation capacity auctions mandated by the Texas electric restructuring law and the Texas Utility Commission's earlier estimates of those prices will be included in the 2004 stranded cost true-up proceeding, as further discussed below. This component of the true-up is intended to ensure that neither the customers nor the Company is disadvantaged economically as a result of the two-year transition period by providing this pricing structure. On October 24, 2001, CenterPoint Energy Transition Bond Company, LLC (Bond Company), a Delaware limited liability company and direct wholly owned subsidiary of CenterPoint Houston, issued $749 million aggregate principal amount of its Series 2001-1 Transition Bonds pursuant to a financing order of the Texas Utility Commission. Classes of the bonds have final maturity dates of September 15, 2007, September 15, 2009, September 15, 2011 and September 15, 2015, and bear interest at rates of 3.84%, 4.76%, 5.16% and 5.63%, respectively. Scheduled payments on the bonds are from 2002 through 2013. Net proceeds to the Bond Company from the issuance were $738 million. The Bond Company paid CenterPoint Houston 96 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) $738 million for the transition property. Proceeds were used for general corporate purposes, including the repayment of indebtedness. The Transition Bonds are secured primarily by the "transition property," which includes the irrevocable right to recover, through non-bypassable transition charges payable by certain retail electric customers, the qualified costs of CenterPoint Houston authorized by the financing order. The holders of the Bond Company's bonds have no recourse to any assets or revenues of CenterPoint Houston, and the creditors of CenterPoint Houston have no recourse to any assets or revenues (including, without limitation, the transition charges) of the Bond Company. CenterPoint Houston has no payment obligations with respect to the Transition Bonds except to remit collections of transition charges as set forth in a servicing agreement between CenterPoint Houston and the Bond Company and in an intercreditor agreement among CenterPoint Houston, the Bond Company and other parties. The non-bypassable transition charges are required by the financing order to be trued-up annually, effective November 1, for the term of the transition charge. CenterPoint Houston filed an annual true-up with the Texas Utility Commission on August 2, 2002 for transition charges that became effective November 1, 2002. Costs associated with nuclear decommissioning will continue to be subject to cost-of-service rate regulation and are included in a charge to transmission and distribution customers. For further discussion of the effect of the business separation plan on funding of the nuclear decommissioning trust fund, see Note 4(b). True-Up Proceeding. The Texas electric restructuring law and current Texas Utility Commission implementation guidance provide for a true-up proceeding to be initiated in or after January 2004. The purpose of the true-up proceeding is to quantify and reconcile the amount of stranded costs, the capacity auction true-up, unreconciled fuel costs (see Note 3(e)), and other regulatory assets associated with CenterPoint Houston's former electric generating operations that were not previously securitized through the Transition Bonds. The 2004 true-up proceeding will result in either additional charges being assessed on or credits being issued to certain retail electric customers. The Company appealed the Texas Utility Commission's true-up rule on the basis that there are no negative stranded costs, that the Company should be allowed to collect interest on stranded costs, and that the premium on the partial stock valuation applies to only the equity of Texas Genco, not equity plus debt. The Texas court of appeals issued a decision on February 6, 2003 upholding the rule in part and reversing in part. The court ruled that there are no negative stranded costs and that the premium on the partial stock valuation applies only to equity. The court upheld the Texas Utility Commission's rule that interest on stranded costs begins upon the date of the final true-up order. On February 21, 2003, the Company filed a motion for rehearing on the issue that interest on amounts determined in the true-up proceeding should accrue from an earlier date . The Company has not accrued interest in its consolidated financial statements, but estimates that interest could be material. If the court of appeals denies the Company's motion, then the Company will have 45 days to appeal to the Texas Supreme Court. The Company has not decided what action, if any, it will take if the motion for rehearing is denied. Accounting. Historically, the Company has applied the accounting policies established in SFAS No. 71. Effective June 30, 1999, the Company applied SFAS No. 101 to Texas Genco. In 1999, the Company evaluated the effects that the Texas electric restructuring law would have on the recovery of its generation related regulatory assets and liabilities. The Company determined that a pre-tax accounting loss of $282 million existed because it believes only the economic value of its generation related regulatory assets (as defined by the Texas electric restructuring law) will be recoverable. Therefore, the Company recorded a $183 million after-tax extraordinary loss in the fourth quarter of 1999. Pursuant to EITF Issue No. 97-4 "Deregulation of the Pricing of Electricity -- Issues Related to the Application of FASB Statements No. 71 and No. 101" (EITF No. 97-4), the remaining recoverable regulatory assets are now 97 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) associated with the transmission and distribution portion of the Company's electric utility business. For details regarding the Company's regulatory assets, see Note 3(e). At June 30, 1999, the Company performed an impairment test of its previously regulated electric generation assets pursuant to SFAS No. 121 on a plant specific basis. Under SFAS No. 121, an asset is considered impaired, and should be written down to fair value, if the future undiscounted net cash flows expected to be generated by the use of the asset are insufficient to recover the carrying amount of the asset. For assets that are impaired pursuant to SFAS No. 121, the Company determined the fair value for each generating plant by estimating the net present value of future cash flows over the estimated life of each plant. The difference between fair value and net book value was recorded as a reduction in the current book value. The Company determined that $797 million of electric generation assets were impaired in 1999. Of this amount, $745 million related to the South Texas Project and $52 million related to two gas-fired generation plants. The Texas electric restructuring law provides for recovery of this impairment through regulated cash flows during the transition period and through charges to transmission and distribution customers. As such, a regulatory asset was recorded for an amount equal to the impairment loss and was included on the Company's Consolidated Balance Sheets as a regulatory asset. The Company recorded amortization expense related to the recoverable impaired plant costs and other assets created from discontinuing SFAS No. 71 of $221 million during the six months ended December 31, 1999, $329 million in 2000 and $247 million in 2001. The impairment analysis requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the plants. The resulting impairment loss is highly dependent on these underlying assumptions. In addition, after January 10, 2004, CenterPoint Houston must finalize and reconcile stranded costs (as defined by the Texas electric restructuring law) in a filing with the Texas Utility Commission. Any positive difference between the regulatory net book value and the fair market value of the generation assets (as defined by the Texas electric restructuring law) will be collected through future charges. Any overmitigation of stranded costs may be refunded by a reduction in future charges. This final reconciliation allows alternative methods of third party valuation of the fair market value of these assets, including outright sale, stock valuations and asset exchanges. In order to reduce potential exposure to stranded costs related to generation assets, CenterPoint Houston recognized Redirected Depreciation of $195 million and $99 million in 1998 and for the six months ended June 30, 1999, respectively, for regulatory and financial reporting purposes. This redirection was in accordance with the Company's Transition Plan. Subsequent to June 30, 1999, Redirected Depreciation expense could no longer be recorded by the Company's electric generation business for financial reporting purposes as these operations are no longer accounted for under SFAS No. 71. During the six months ended December 31, 1999 and during 2000 and 2001, $99 million, $218 million and $230 million in depreciation expense, respectively, was redirected from transmission and distribution for regulatory and financial reporting purposes and was established as an embedded regulatory asset included in transmission and distribution related plant and equipment balances. As of December 31, 2001, the cumulative amount of Redirected Depreciation for regulatory purposes was $841 million, prior to the effects of the October 3, 2001 order discussed below. Additionally, as allowed by the Texas Utility Commission, in an effort to further reduce potential exposure to stranded costs related to generation assets, CenterPoint Houston recorded Accelerated Depreciation of $194 million and $104 million in 1998 and for the six months ended June 30, 1999, respectively, for regulatory and financial reporting purposes. Accelerated Depreciation expense was recorded in accordance with the Company's Transition Plan during this period. Subsequent to June 30, 1999, Accelerated Depreciation expense could no longer be recorded by the Company's electric generation business for financial reporting purposes, as these operations are no longer accounted for under SFAS No. 71. During the six months ended December 31, 1999 and during 2000 and 2001, $179 million, $385 million and $264 million, respectively, of Accelerated Depreciation was recorded for regulatory reporting purposes, reducing the regulatory book value of the Company's electric generation assets. 98 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Texas Utility Commission issued a final order on October 3, 2001 (October 3, 2001 Order) that established the transmission and distribution utility rates that became effective in January 2002. In this Order, the Texas Utility Commission found that CenterPoint Houston had overmitigated its stranded costs by redirecting transmission and distribution depreciation and by accelerating depreciation of generation assets as provided under the Transition Plan and Texas electric restructuring law. As a result of the October 3, 2001 Order, CenterPoint Houston was required to reverse the $841 million embedded regulatory asset related to Redirected Depreciation, thereby reducing the net book value of transmission and distribution assets. CenterPoint Houston was required to record a regulatory liability of $1.1 billion related to Accelerated Depreciation. The October 3, 2001 Order requires this amount to be refunded through excess mitigation credits to certain retail electric customers during a seven-year period which began in January 2002. As of December 31, 2002, in contemplation of the 2004 true-up proceeding, CenterPoint Houston has recorded a regulatory asset of $2.0 billion representing the estimated future recovery of previously incurred stranded costs, which includes $1.1 billion of previously recorded Accelerated Depreciation plus Redirected Depreciation, both reversed in 2001. Offsetting this regulatory asset is a $969 million regulatory liability to refund the excess mitigation to ratepayers. This estimated recovery is based upon current projections of the market value of the Company's Texas generation assets to be covered by the 2004 true-up proceeding calculations. The regulatory liability reflects a current refund obligation arising from prior mitigation of stranded costs deemed excessive by the Texas Utility Commission. CenterPoint Houston began refunding excess mitigation credits with January 2002 bills. These credits are to be refunded over a seven-year period. Because accounting principles generally accepted in the United States of America require CenterPoint Houston to estimate fair market values in advance of the final reconciliation, the financial impacts of the Texas electric restructuring law with respect to the final determination of stranded costs in the 2004 true-up proceeding are subject to material changes. Factors affecting such changes may include estimation risk, uncertainty of future energy and commodity prices and the economic lives of the plants. If events were to occur that made the recovery of some of the remaining generation related regulatory assets no longer probable, the Company would write off the unrecoverable balance of such assets as a charge against earnings. (B) AGREEMENTS RELATED TO TEXAS GENERATING ASSETS Pursuant to the business separation plan, on January 6, 2003, the Company distributed approximately 19% of Texas Genco's 80 million outstanding shares of common stock to its shareholders in order to establish a public market value for shares of that stock which will be used in 2004 to calculate how much CenterPoint Houston will be able to recover as stranded costs. Reliant Resources has an option to purchase the Company's remaining 81% interest in Texas Genco (Texas Genco Option). The Texas Genco Option may be exercised between January 10, 2004 and January 24, 2004. The per share exercise price under the option will be the average daily closing price on the applicable national exchange for publicly held shares of common stock of Texas Genco for the 30 consecutive trading days with the highest average closing price during the 120 trading days immediately preceding January 10, 2004, plus a control premium, up to a maximum of 10%, to the extent a control premium is included in the valuation determination made by the Texas Utility Commission relating to the market value of Texas Genco's common stock equity. The exercise price is also subject to adjustment based on the difference between the cash dividends paid during the period there is a public ownership interest in Texas Genco and Texas Genco's earnings during that period. Reliant Resources has agreed that if it exercises the Texas Genco Option and purchases the shares of Texas Genco common stock, Reliant Resources will also purchase all notes and other receivables from Texas Genco then held by CenterPoint Energy, at their principal amount plus accrued interest. Similarly, if Texas Genco holds notes or receivables from the Company, Reliant Resources will assume those obligations in exchange for a payment to Reliant Resources by the Company of an amount equal to the principal plus accrued interest. Exercise of the Texas Genco Option by Reliant Resources will be subject to various regulatory approvals, including Hart-Scott-Rodino antitrust clearance and United States Nuclear Regulatory Commission (NRC) license transfer approval. 99 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Texas Genco is the beneficiary of the decommissioning trust that has been established to provide funding for decontamination and decommissioning of a nuclear electric generation station in which Texas Genco owns a 30.8% interest (see Note 6). CenterPoint Houston collects through rates or other authorized charges to its electric utility customers amounts designated for funding the decommissioning trust, and pays the amounts to Texas Genco. Texas Genco in turn deposits these amounts into the decommissioning trust. Upon decommissioning of the facility, in the event funds from the trust are inadequate, CenterPoint Houston or its successor will be required to collect through rates or other authorized charges to customers as contemplated by the Texas Utilities Code all additional amounts required to fund Texas Genco's obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trust, the excess will be refunded to the ratepayers of CenterPoint Houston or its successor. (C) CENTERPOINT HOUSTON REGULATORY FILINGS CenterPoint Houston and Texas Genco filed their joint application to reconcile fuel revenues and expenses with the Texas Utility Commission on July 1, 2002. This final fuel reconciliation filing covers reconcilable fuel revenue, fuel expense and interest of approximately $8.5 billion incurred from August 1, 1997 through January 30, 2002. Also included in this amount is an under-recovery of $94 million, which was the balance at July 31, 1997 as approved in CenterPoint Houston's last fuel reconciliation. On January 28, 2003, a settlement agreement was reached under which it was agreed that certain items totaling $24 million were written off during the fourth quarter of 2002 and items totaling $203 million will be carried forward for resolution by the Texas Utility Commission in late 2003 or early 2004. (D) ARKLA RATE CASE In November 2001, CenterPoint Energy Arkla (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) that 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 that 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. (E) 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. (5) DERIVATIVE INSTRUMENTS Effective January 1, 2001, the Company 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) or (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. 100 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax increase in net income of $59 million and 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 the Company's Consolidated Balance Sheet. The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company 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, the Company enters into energy derivatives in order to hedge certain expected purchases and sales of natural gas (non-trading energy derivatives). The Company 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. The Company analyzes its physical transaction portfolio to determine its net exposure by delivery location and delivery period. Because the Company's physical transactions with similar delivery locations and periods are highly correlated and share similar risk exposures, the Company 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, the Company realizes in net income the deferred gains and losses recognized in accumulated other comprehensive loss. 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 loss is reclassified and included in the Company's Statements of Consolidated Operations 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, the Company expects $1 million in accumulated other comprehensive loss to be reclassified into net income during the next twelve months. The maximum length of time the Company 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 five years. The Company's policy is not to exceed five years in hedging its exposure. Interest Rate Swaps. As of December 31, 2002, the Company had outstanding interest rate swaps with an aggregate notional amount of $750 million to fix the interest rate applicable to floating rate short-term debt. These swaps do not qualify as cash flow hedges under SFAS No. 133, and are marked to market in the Company's Consolidated Balance Sheets with changes reflected in interest expense in the Statements of Consolidated Operations. During the year ended December 31, 2002, the Company settled its forward-starting interest rate swaps having an aggregate notional amount of $1.5 billion at a cost of $156 million. The Company has designated and accounted for the forward-interest rate swaps as a cash flow hedge of the Company's exposure to variability in future interest payments on fixed rate debt the Company anticipates issuing. Accordingly, the Company recorded the $156 million cost in other comprehensive income, which will be amortized into interest expense in the same period during which the forecasted interest payments affect earnings. The Company assesses and measures the hedging relationship on a quarterly basis by comparing the 101 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) critical terms of the forward starting interest rate swaps with the expected terms of the forecasted debt issuance as well as evaluating the probability of the underlying interest payments occurring. The Company reclassified approximately $36 million in 2002 as a result of interest payments it believes are no longer probable of occurring for certain periods. (B) CREDIT RISKS. In addition to the risk associated with price movements, credit risk is also inherent in the Company'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 the Company as of December 31, 2001 and 2002:

DECEMBER 31, 2001 DECEMBER 31, 2002 ------------------- ----------------------- INVESTMENT INVESTMENT NON-TRADING DERIVATIVE ASSETS GRADE(1)(2) TOTAL GRADE(1)(2) TOTAL (3) ----------------------------- ----------- ----- ----------- --------- (IN MILLIONS) Energy marketers..................................... $ 9 $ 9 $ 7 $22 Financial institutions............................... -- -- 9 9 --- --- --- --- Total.............................................. $ 9 $ 9 $16 $31 === === === ===

--------------- (1) "Investment Grade" is primarily determined using publicly available credit ratings along with the consideration of credit support (such as parent company guarantees) and collateral, which encompass cash and standby letters of credit. (2) For unrated counterparties, the Company performs financial statement analysis, considering contractual rights and restrictions and collateral, to create a synthetic credit rating. (3) The $22 million non-trading derivative asset includes a $15 million asset due to trades with Reliant Energy Services, Inc. (Reliant Energy Services) an affiliate until the date of the Reliant Resources Distribution. As of December 31, 2002, Reliant Energy Services did not have an Investment Grade rating. (C) GENERAL POLICY. The Company has established a Risk Oversight Committee comprised of corporate and business segment officers that oversees all commodity price and credit risk activities, including the Company's trading, marketing, risk management services and hedging activities. The committee's duties are to establish the Company's commodity risk policies, allocate risk capital within limits established by the Company's board of directors, approve trading of new products and commodities, monitor risk positions and ensure compliance with the Company's risk management policies and procedures and trading limits established by the Company's board of directors. The Company'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. (6) JOINTLY OWNED ELECTRIC UTILITY PLANT Texas Genco owns a 30.8% interest in the South Texas Project, which consists of two 1,250 MW nuclear generating units and bears a corresponding 30.8% share of capital and operating costs associated with the project. The South Texas Project is owned as a tenancy in common among Texas Genco and three other co-owners, with each owner retaining its undivided ownership interest in the two generating units and the electrical output from those units. Texas Genco is severally liable, but not jointly liable, for the expenses and 102 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) liabilities of the South Texas Project. Texas Genco and the three other co-owners organized the STP Nuclear Operating company (STPNOC) to operate and maintain the South Texas Project. STPNOC is managed by a board of directors comprised of one director appointed by each of the four co-owners, along with the chief executive officer of STPNOC. Texas Genco's share of direct expenses of the South Texas Project is included in the corresponding operating expense categories in the accompanying consolidated financial statements. As of December 31, 2001, the total utility plant in service and construction work in progress for the total South Texas Project was $5.8 billion and $120 million, respectively. As of December 31, 2002, the total utility plant in service and construction work in progress for the total South Texas Project was $5.8 billion and $158 million, respectively. As of December 31, 2001 and 2002, Texas Genco's investment in the South Texas Project was $316 million and $323 million, respectively, (net of $2.2 billion accumulated depreciation which includes an impairment loss recorded in 1999 of $745 million). For additional information regarding the impairment loss, see Note 4(a). As of December 31, 2001 and 2002, Texas Genco's investment in nuclear fuel was $35 million (net of $286 million amortization) and $42 million (net of $302 million amortization), respectively. (7) INDEXED DEBT SECURITIES (ACES AND ZENS) AND AOL TIME WARNER SECURITIES (A) ORIGINAL INVESTMENT IN TIME WARNER SECURITIES In 1995, the Company sold a cable television subsidiary to Time Warner Inc.(TW) and received TW convertible preferred stock (TW Preferred) as consideration. On July 6, 1999, the Company converted its 11 million shares of TW Preferred into 45.8 million shares of Time Warner common stock (TW Common). Prior to the conversion, the Company's investment in the TW Preferred was accounted for under the cost method at a value of $990 million in the Company's Consolidated Balance Sheets. The TW Preferred which was redeemable after July 6, 2000, had an aggregate liquidation preference of $100 per share (plus accrued and unpaid dividends), was entitled to annual dividends of $3.75 per share until July 6, 1999 and was convertible by the Company. Effective on the conversion date, the shares of TW Common were classified as trading securities under SFAS No. 115 and an unrealized gain was recorded in the amount of $2.4 billion ($1.5 billion after-tax) to reflect the cumulative appreciation in the fair value of the Company's investment in Time Warner securities. Unrealized gains and losses resulting from changes in the market value of the TW Common (now AOL TW Common) are recorded in the Company's Statements of Consolidated Operations. (B) ACES In July 1997, in order to monetize a portion of the cash value of its investment in TW Preferred, the Company issued 22.9 million of its unsecured 7% Automatic Common Exchange Securities (ACES) having an original principal amount of $1.052 billion and maturing July 1, 2000. The market value of ACES was indexed to the market value of TW Common. On the July 1, 2000 maturity date, the Company tendered 37.9 million shares of TW Common to fully settle its obligations in connection with its unsecured 7% ACES having a value of $2.9 billion. (C) ZENS On September 21, 1999, the Company issued approximately 17.2 million of its 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. The principal amount per ZENS will increase each quarter to the extent that the sum of the quarterly cash dividends and the interest paid during a quarter on the reference shares attributable to one ZENS is less than $.045, so that the annual yield to investors is not less than 2.309%. At December 31, 2002, 14.4 million ZENS were outstanding. At maturity the holders of the ZENS will receive in cash the higher of the original principal amount of the ZENS (subject to adjustment as discussed above) or an amount based on the then-current market value of AOL TW Common, or other securities distributed with respect to AOL TW Common 103 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (1.5 shares of AOL TW Common and such other securities, if any, are referred to as reference shares). Each ZENS has a principal amount of $58.25, and is exchangeable at any time at the option of the holder for cash equal to 95% (100% in some cases) of the market value of the reference shares attributable to one ZENS. The Company pays interest on each ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the quarterly interest period on the reference shares attributable to each ZENS. Subject to some conditions, the Company has the right to defer interest payments from time to time on the ZENS for up to 20 consecutive quarterly periods. As of December 31, 2002, no interest payments on the ZENS had been deferred. In 2002, holders of approximately 16% of the 17.2 million ZENS originally issued exercised their right to exchange their ZENS for cash, resulting in aggregate cash payments by CenterPoint Energy of approximately $45 million. A subsidiary of the Company owns shares of AOL TW Common and elected to liquidate a portion of such holdings to facilitate the Company's making the cash payments for the ZENS exchanged in 2002. In connection with the exchanges in 2002, the Company received net proceeds of approximately $43 million from the liquidation of approximately 4.1 million shares of AOL TW Common at an average price of $10.56 per share. The Company now holds 21.6 million shares of AOL TW Common which are classified as trading securities under SFAS No. 115 and are expected to be held to facilitate the Company's ability to meet its obligation under the ZENS. Prior to January 1, 2001, an increase in the market value per share of TW Common above $58.25 (subject to some adjustments) resulted in an increase in the Company's liability for the ZENS. However, as the market value per share of TW Common declined below $58.25 (subject to some adjustments), the liability for the ZENS did not decline below the original principal amount. Upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component (the holder's option to receive the appreciated value of AOL TW Common at maturity). The derivative component was valued at fair value and determined the initial carrying value assigned to the debt component ($121 million) as the difference between the original principal amount of the ZENS ($1.0 billion) and the fair value of the derivative component at issuance ($879 million). Effective January 1, 2001 the debt component was recorded at its accreted amount of $122 million and the derivative component was recorded at its fair value of $788 million, as a current liability, resulting in a transition adjustment pre-tax gain of $90 million ($59 million net of tax). The transition adjustment gain was reported in the first quarter of 2001 as the effect of a change in accounting principle. Subsequently, the debt component accretes through interest charges at 17.5% annually up to the minimum amount payable upon maturity of the ZENS in 2029 (approximately $915 million) which reflects exchanges and adjustments to maintain a 2.309% annual yield, as discussed above. Changes in the fair value of the derivative component are recorded in the Company's Statements of Consolidated Operations. During 2001 and 2002, the Company recorded a loss of $70 million and $500 million, respectively, on the Company's investment in AOL TW Common. During 2001 and 2002, the Company recorded a gain of $58 million and $480 million, respectively, associated with the fair value of the derivative component of the ZENS obligation. Changes in the fair value of the AOL TW Common held by the Company are expected to substantially offset changes in the fair value of the derivative component of the ZENS. 104 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table sets forth summarized financial information regarding the Company's investment in AOL TW securities and the Company's ACES and ZENS obligations (in millions).

DEBT DERIVATIVE AOL TW COMPONENT COMPONENT INVESTMENT ACES OF ZENS OF ZENS ---------- ------- --------- ---------- Balance at December 31, 1999....................... $ 3,979 $ 2,738 $1,241 $ -- Loss (gain) on indexed debt securities............. -- 139 (241) -- Loss on TW Common.................................. (205) -- -- -- Settlement of ACES................................. (2,877) (2,877) -- -- ------- ------- ------ ----- Balance at December 31, 2000....................... 897 -- 1,000 -- Transition adjustment from adoption of SFAS No. 133.............................................. -- -- (90) -- Bifurcation of ZENS obligation..................... -- -- (788) 788 Accretion of debt component of ZENS................ -- -- 1 -- Gain on indexed debt securities.................... -- -- -- (58) Loss on AOL TW Common.............................. (70) -- -- -- ------- ------- ------ ----- Balance at December 31, 2001....................... 827 -- 123 730 Accretion of debt component of ZENS................ -- -- 1 -- Gain on indexed debt securities.................... -- -- -- (480) Loss on AOL TW Common.............................. (500) -- -- -- Liquidation of AOL TW Common....................... (43) -- -- -- Liquidation of ZENS, net of gain................... -- -- (20) (25) ------- ------- ------ ----- Balance at December 31, 2002....................... $ 284 $ -- $ 104 $ 225 ======= ======= ====== =====

(8) EQUITY (A) CAPITAL STOCK Effective with the Restructuring, all outstanding shares of Reliant Energy no par value common stock were exchanged for shares of CenterPoint Energy common stock with a par value of $0.01 per share. The capital accounts of CenterPoint Energy have been restated as of December 31, 2000 and 2001 to give effect to the change in par value per share. CenterPoint Energy has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value preferred stock. (B) PREFERRED STOCK On December 14, 2001, Reliant Energy redeemed all outstanding shares of its $4.00 Preferred Stock at $105 per share plus accrued dividends of $0.478 per share for a total redemption payment of $10.3 million. At December 31, 2001, Reliant Energy had 10,000,000 authorized shares of cumulative preferred stock, none of which was outstanding. At December 31, 2002, CenterPoint Energy had 20,000,000 authorized shares of preferred stock, none of which was outstanding. (C) PREFERENCE STOCK At December 31, 2001, Reliant Energy had 10,000,000 authorized shares of preference stock, none of which was outstanding for financial reporting purposes. At December 31, 2001, Reliant Energy had issued and outstanding shares of preference stock that were held by various financing subsidiaries of the Company to 105 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) support debt obligations of the subsidiaries to third party lenders. The aggregate amount of debt outstanding at these subsidiaries at December 31, 2001 was $2.9 billion. These shares of preference stock were cancelled in 2002 effective with the extinguishment of debt by the financing subsidiaries. (D) SHAREHOLDER RIGHTS PLAN The Company has a Shareholder Rights Plan that states that each share of its common stock includes one associated preference stock purchase right (Right) which entitles the registered holder to purchase from the Company a unit consisting of one-thousandth of a share of Series A Preference Stock. The Rights, which expire on December 11, 2011, are exercisable upon some events involving the acquisition of 20% or more of the Company's outstanding common stock. Upon the occurrence of such an event, each Right entitles the holder to receive common stock with a current market price equal to two times the exercise price of the Right. At anytime prior to becoming exercisable, the Company may repurchase the Rights at a price of $0.005 per Right. There are 700,000 shares of Series A Preference Stock reserved for issuance upon exercise of the Rights. 106 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (9) LONG-TERM DEBT AND SHORT-TERM BORROWINGS

DECEMBER 31, 2001 DECEMBER 31, 2002 ------------------- ------------------- LONG- LONG- TERM CURRENT(1) TERM CURRENT(1) ------ ---------- ------ ---------- (IN MILLIONS) Short-term borrowings: Commercial paper and bank loans..................... $2,792 $ 347 Receivables facility(2)............................. 346 -- Other(3)............................................ 391 -- ------ ------ Total short-term borrowings...................... 3,529 347 ------ ------ Long-term debt: CenterPoint Energy: ZENS(4)............................................. $ -- $ 123 $ -- $ 104 Debentures 7.88% due 2002........................... -- 100 -- -- Medium-term notes and pollution control bonds 4.90% to 6.70% due 2003 to 2027(5)(8).................. 547 -- 380 167 Pollution control bonds 4.70% to 5.95% due 2011 to 2030(6).......................................... 1,046 100 871 -- Bank loan due 2005(7)............................... -- -- 3,850 -- CenterPoint Houston: First mortgage bonds 7.50% to 9.15% due 2021 to 2023(8).......................................... 615 -- 615 -- Series 2001-1 Transition Bonds 3.84% to 5.63% due 2002 to 2013(9).................................. 736 13 717 19 Term loan, LIBOR plus 9.75%, due 2005(10)........... -- -- 1,310 -- Debentures 7.40% due 2002........................... -- 300 -- -- CERC Corp.:(11) Convertible debentures 6.00% due 2012............... 82 -- 76 -- Debentures 6.38% to 8.90% due 2003 to 2011.......... 1,833 -- 1,331 500 Other................................................. 56 1 52 7 Unamortized discount and premium...................... 5 -- (8) 13 ------ ------ ------ ------ Total long-term debt............................. 4,920 637 9,194 810 ------ ------ ------ ------ Total borrowings................................. $4,920 $4,166 $9,194 $1,157 ====== ====== ====== ======

--------------- (1) Includes amounts due or exchangeable within one year of the date noted. (2) In the first quarter of 2002, CERC reduced its trade receivables facility from $350 million to $150 million. Advances under the receivables facility aggregating $196 million were repaid in January 2002 with proceeds from the issuance of commercial paper and from the liquidation of short-term investments. For further discussion of the receivables facility, see Note 3(i). (3) The $391 million of other short-term borrowings at December 31, 2001 reflects a note payable to Reliant Resources, which was repaid in 2002. (4) Upon adoption of SFAS No. 133 effective January 1, 2001, the Company's ZENS obligation was bifurcated into a debt component and an embedded derivative component. For additional information regarding ZENS, see Note 7(c). As ZENS are exchangeable for cash at any time at the option of the holders, these notes are classified as a current portion of long-term debt. 107 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (5) These series of debt are secured by first mortgage bonds of CenterPoint Houston. (6) $527 million of these series of debt is secured by general mortgage bonds of CenterPoint Houston. (7) On February 28, 2003, CenterPoint Energy amended and extended the termination date of its $3.85 billion credit facility to June 30, 2005 as discussed further below. As a result of this extension, the $3.85 billion credit facility has been classified as long-term debt as of December 31, 2002 in the Consolidated Balance Sheet. (8) The December 31, 2001 debt balances have been reclassified to give effect to the Restructuring, which occurred on August 31, 2002. (9) For further discussion of the securitization financing, see Note 4(a). (10) London inter-bank offered rate (LIBOR) has a minimum rate of 3%. This term loan is secured by general mortgage bonds of CenterPoint Houston. (11) Debt acquired in business acquisitions is adjusted to fair market value as of the acquisition date. Included in long-term debt is additional unamortized premium related to fair value adjustments of long-term debt of $9 million and $7 million at December 31, 2001 and 2002, respectively, which is being amortized over the respective remaining term of the related long-term debt. During 2002, the Company recorded a $17 million after-tax extraordinary item related to a loss on the early extinguishment of debt related to CenterPoint Houston's $850 million term loan and the repurchase of $175 million of the Company's pollution control bonds. (a) SHORT-TERM BORROWINGS Credit Facilities. As of December 31, 2002, CenterPoint Energy and its subsidiaries had credit facilities that provided for an aggregate of $4.2 billion in committed credit. As of December 31, 2002, such credit facilities were fully utilized in the form of letters of credit aggregating $2.5 million and loans. The weighted average interest rate on short-term borrowings at December 31, 2001 and December 31, 2002 was 2.9% and 5.4%, respectively. These interest rates exclude facility fees and other fees paid in connection with the arrangement of the bank facilities. As of December 31, 2002, cash aggregating $265 million was invested in a money market fund. In July 2002, the termination dates of facilities aggregating $4.7 billion were extended from July 12, 2002 to October 10, 2002. Upon the Restructuring, CenterPoint Energy became the borrower under facilities aggregating $4.3 billion, CenterPoint Houston remained the borrower under its $400 million facility and CERC Corp. remained both the borrower under its $350 million revolver and the seller under its $150 million receivables facility. The $150 million receivables facility is not recorded as a financing as it provides for the sale of receivables to third parties as discussed in Note 3(i) to the consolidated financial statements. On October 10, 2002, the agreements relating to $4.3 billion of bank facilities at CenterPoint Energy and $400 million of bank facilities at CenterPoint Houston were amended and extended. On November 12, 2002, $850 million of bank facilities were terminated with the proceeds of CenterPoint Houston's $1.3 billion collateralized term loan as discussed below. The remaining $3.85 billion of CenterPoint Energy's outstanding bank facilities were originally scheduled to expire on October 9, 2003, with two $600 million mandatory principal reduction payments under the facilities due on or prior to June 30, 2003. On February 28, 2003, the $3.85 billion bank facility was amended and extended as discussed below. Accordingly, the $3.85 billion of outstanding bank loans as of December 31, 2002 have been reclassified as long-term debt in the Consolidated Balance Sheet. As of December 31, 2002, there was $347 million borrowed under CERC's $350 million revolving credit facility. On February 28, 2003, CERC executed a commitment letter with a major bank for a $350 million, 180-day bridge facility, which is subject to the satisfaction of various closing conditions. This facility will be 108 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) available for repaying borrowings under CERC's 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. CERC paid a commitment fee of 25 basis points on the commitment amount and will be required to pay a facility fee of 75 basis points on 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, CERC expects to provide the lender with collateral in the form of a security interest in the stock it owns in its interstate natural gas pipeline subsidiaries. In February 2003, CenterPoint Houston obtained a $75 million revolving credit facility that terminates on April 30, 2003. A condition precedent to utilizing the facility is that security in the form of general mortgage bonds must be delivered to the lender. Rates for borrowings under this facility, including the facility fee, will be LIBOR plus 250 basis points. The bank facilities contain various business and financial covenants. The borrowers are currently in compliance with the covenants under the applicable credit agreements. At the beginning of 2002, commercial paper programs aggregated $5 billion. A reduction in the size of the commercial paper programs occurred in the third and fourth quarters of 2002 as revolving credit facilities were converted to term loan facilities. The maximum amount of each issuer's outstanding commercial paper was limited to the amount of its revolving credit facility less any direct loans or letters of credit obtained under its revolver. In October 2002, all commercial paper was repaid with proceeds from bank loans. The extent to which commercial paper is issued in lieu of bank loans depends, in part, on market conditions and the credit ratings of the commercial paper issuer. The commercial paper programs were terminated in December 2002. (b) LONG-TERM DEBT On February 28, 2003, the Company reached agreement with a syndicate of banks on a second amendment to its $3.85 billion bank facility (the "Second Amendment"). Under the Second Amendment, the maturity date of the bank facility was extended from October 2003 to June 30, 2005, and the $1.2 billion in mandatory prepayments that would have been required this year (including $600 million due on February 28, 2003) were eliminated. The facility consists of a $2.35 billion term loan and a $1.5 billion revolver. Borrowings bear interest based on LIBOR rates under a pricing grid tied to the Company's credit rating. At our current credit ratings, the pricing for loans remains the same. The drawn cost for the facility at our current ratings is LIBOR plus 450 basis points. The Company has agreed to pay the banks an extension fee of 75 basis points on the amounts outstanding under the bank facility on October 9, 2003. The Company also paid $41 million in fees that were due on February 28, 2003, along with $20 million in fees that had been due on June 30, 2003. In addition, the interest rates will be increased by 25 basis points beginning May 28, 2003 if the Company does not grant the banks a security interest in our 81% stock ownership of Texas Genco. Granting the security interest in the stock of Texas Genco requires approval from the Securities and Exchange Commission (SEC) under the 1935 Act, which is currently being sought. That security interest would be released when the Company sells Texas Genco, which is expected to occur in 2004. Proceeds from the sale will be used to reduce the bank facility. Also under the Second Amendment, on or before May 28, 2003, the Company expects to grant to the banks warrants to purchase up to 10%, on a fully diluted basis, of our common stock at a price equal to the greater of $6.56 per share or 110% of the closing price on the New York Stock Exchange on the date the warrants are issued. The warrants would not be exercisable for a year after issuance but would remain outstanding for four years; provided, that if the Company reduces the bank facility during 2003 by specified amounts, the warrants will be extinguished. To the extent that the Company reduces the bank facility by up to 109 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) $400 million on or before May 28, 2003, up to half of the warrants will be extinguished on a basis proportionate to the reduction in the credit facility. To the extent such warrants are not extinguished on or before May 28, 2003, they will vest and become exercisable in accordance with their terms. Whether or not the Company is able to extinguish warrants on or before May 28, 2003, the remaining 50% of the warrants will be extinguished, again on a proportionate basis, if the Company reduces the bank facility by up to $400 million by the end of 2003. The Company plans to eliminate the warrants entirely before they vest by accessing the capital markets to fund the total payments of $800 million during 2003; however, because of current financial market conditions and uncertainties regarding such conditions over the balance of the year, there can be no assurance that the Company will be able to extinguish the warrants or to do so on favorable terms. The warrants and the underlying common stock would be registered with the SEC and could be exercised either through the payment of the purchase price or on a "cashless" basis under which the Company would issue a number of shares equal to the difference between the then-current market price and the warrant exercise price. Issuance of the warrants is also subject to obtaining SEC approval under the 1935 Act, which is currently being sought. If that approval is not obtained on or before May 28, 2003, the Company will provide the banks equivalent cash compensation over the term that its warrants would have been exercisable to the extent they are not otherwise extinguished. In the Second Amendment, the Company also agreed that its quarterly common stock dividend will not exceed $0.10 per share. If the Company has not reduced the bank facility by a total of at least $400 million by the end of 2003, of which at least $200 million has come from the issuance of capital stock or securities linked to capital stock (such as convertible debt), the maximum dividend payable during 2004 and for the balance of the term of the facility is subject to an additional test. Under that test the maximum permitted quarterly dividend will be the lesser of (i) $0.10 per share or (ii) 12.5% of the Company's net income per share for the 12 months ended on the last day of the previous quarter. The Second Amendment provides that proceeds from capital stock or indebtedness issued or incurred by the Company must be applied (subject to a $200 million basket for CERC and another $250 million basket for borrowings by the Company and other limited exceptions) to repay bank loans and reduce the bank facility. Similarly, cash proceeds from the sale of assets of more than $30 million or, if less, a group of sales aggregating more than $100 million, must be applied to repay bank loans and reduce the bank facility, except that proceeds of up to $120 million can be reinvested in the Company's businesses. On November 12, 2002, CenterPoint Houston entered into a $1.3 billion collateralized term loan maturing November 2005. The interest rate on the loan is LIBOR plus 9.75%, subject to a minimum rate of 12.75%. The loan is secured by CenterPoint Houston's general mortgage bonds. Proceeds from the loan were used to (1) repay CenterPoint Houston's $850 million term loan, (2) pay costs of issuance, (3) repay $300 million of debt that matured on November 15, 2002 and (4) to purchase $100 million of pollution control bonds on December 1, 2002. The loan agreement contains various business and financial covenants including a covenant restricting CenterPoint Houston's debt, excluding transition bonds, as a percent of its total capitalization to 68%. The loan agreement also limits incremental secured debt that may be issued by CenterPoint Houston to $300 million. Maturities. The Company's maturities of long-term debt and sinking fund requirements, excluding the ZENS obligation, are $706 million in 2003 (of which $500 million may be remarketed by an option holder to a maturity of 2013), $47 million in 2004, $5.6 billion in 2005, $210 million in 2006 and $68 million in 2007. The 2003 and 2004 amounts are net of sinking fund payments that can be satisfied with bonds that had been acquired and retired as of December 31, 2002. Liens. CenterPoint Houston's assets are subject to liens securing approximately $1.2 billion of first mortgage bonds. Sinking or improvement fund and replacement fund requirements on the first mortgage bonds may be satisfied by certification of property additions. Sinking fund and replacement fund requirements 110 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) for 2000, 2001 and 2002 have been satisfied by certification of property additions. The replacement fund requirement to be satisfied in 2003 is approximately $347 million, and the sinking fund requirement to be satisfied in 2003 is approximately $15 million. The Company expects CenterPoint Houston to meet these 2003 obligations by certification of property additions. CenterPoint Houston's assets are subject to liens securing approximately $1.8 billion of general mortgage bonds which are junior to the liens of the first mortgage bonds. Securitization. For a discussion of the securitization financing completed in October 2001, see Note 4(a). Purchase of Pollution Control Bonds. In the fourth quarter of 2002, the Company purchased $175 million of pollution control bonds issued on its behalf. The Company expects to remarket the bonds during the first half of 2003. Purchase of Convertible Debentures. 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 principal amount of Subordinated Debentures into 0.65 shares of Reliant Energy common stock and $14.24 in cash. After the Restructuring, but prior to the Reliant Resources Distribution, each $50 principal amount of Subordinated Debentures was convertible into 0.65 shares of CenterPoint Energy common stock and $14.24 in cash. The Reliant Resources Distribution and the Texas Genco stock distribution changed the conversion rights for each $50 principal amount of Subordinated Debentures as follows:

SHARES OF CENTERPOINT ENERGY DATE EVENT CASH COMMON STOCK ----------------------------------- ---------------------- ------ ------------------ October 1, 2002.................... Distribution of $14.24 1.02 Reliant Resources common stock December 21, 2002.................. Distribution of Texas $14.24 1.11 Genco common stock

During 2002, CERC Corp. purchased $6.6 million aggregate principal amount of its Subordinated Debentures. TERM Notes. CERC Corp.'s $500 million aggregate principal amount of 6 3/8% Term Enhanced ReMarketable Securities (TERM Notes) provide an investment bank with a call option, that gives it the right to have the TERM Notes tendered to it by the holders on November 1, 2003 and then remarketed if it chooses to exercise the option. The TERM Notes are unsecured obligations of CERC Corp. that bear interest at an annual rate of 6 3/8% through November 1, 2003. On November 1, 2003, the holders of the TERM Notes are required to tender their notes at 100% of their principal amount. The portion of the proceeds attributable to the call option premium will be amortized over the stated term of the securities. If the option is not exercised by the investment bank, CERC Corp. will repurchase the TERM Notes at 100% of their principal amount on November 1, 2003. If the option is exercised, the TERM Notes will be remarketed on a date, selected by CERC Corp., within the 52-week period beginning November 1, 2003. CERC Corp. may elect into this 52-week remarketing window only if its senior unsecured debt securities are rated at least Baa3 by Moody's Investors Service, Inc. and BBB- by Standard & Poor's Ratings Services, a division of The McGraw Hill Companies (unless the investment banker waives that requirement). During this period and prior to remarketing, the TERM Notes will bear interest at rates, adjusted weekly, based on an index selected by CERC Corp. CERC Corp. may elect to redeem the TERM Notes in whole, but not in part, from the 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 111 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) remarketed TERM Notes will be 5.66% plus CERC Corp.'s applicable credit spread at the time of such remarketing. Transportation Agreement. 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, the Company had recorded $41 million in long-term debt and as of December 31, 2002, the Company had recorded $5 million and $36 million in current portion of long-term debt and long-term debt, respectively, in its 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. (10) TRUST PREFERRED SECURITIES In February 1997, two Delaware statutory business trusts created by CenterPoint Energy (HL&P Capital Trust I and HL&P Capital Trust II) issued to the public (a) $250 million aggregate amount of preferred securities and (b) $100 million aggregate amount of capital securities, respectively. In February 1999, a Delaware statutory business trust created by CenterPoint Energy (REI Trust I) issued $375 million aggregate amount of preferred securities to the public. CenterPoint Energy accounts for REI Trust I, HL&P Capital Trust I and HL&P Capital Trust II as wholly owned consolidated subsidiaries. Each of the trusts used the proceeds of the offerings to purchase junior subordinated debentures issued by CenterPoint Energy having interest rates and maturity dates that correspond to the distribution rates and the mandatory redemption dates for each series of preferred securities or capital securities. The junior subordinated debentures are the trusts' sole assets and their entire operations. CenterPoint Energy considers its obligations under the Amended and Restated Declaration of Trust, Indenture, Guaranty Agreement and, where applicable, Agreement as to Expenses and Liabilities, relating to each series of preferred securities or capital securities, taken together, to constitute a full and unconditional guarantee by CenterPoint Energy of each trust's obligations with respect to the respective series of preferred securities or capital securities. The preferred securities and capital securities are mandatorily redeemable upon the repayment of the related series of junior subordinated debentures at their stated maturity or earlier redemption. Subject to some limitations, CenterPoint Energy has the option of deferring payments of interest on the junior subordinated debentures. During any deferral or event of default, CenterPoint Energy may not pay dividends on its capital stock. As of December 31, 2002, no interest payments on the junior subordinated debentures had been deferred. 112 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The outstanding aggregate liquidation amount, distribution rate and mandatory redemption date of each series of the preferred securities or capital securities of the trusts described above and the identity and similar terms of each related series of junior subordinated debentures are as follows:

AGGREGATE LIQUIDATION AMOUNTS AS OF MANDATORY DECEMBER 31, DISTRIBUTION REDEMPTION 2001 AND 2002 RATE/ DATE/ TRUST (IN MILLIONS) INTEREST RATE MATURITY DATE JUNIOR SUBORDINATED DEBENTURES ----- ------------- ------------- ------------- ------------------------------ REI Trust I............... $375 7.20% March 2048 7.20% Junior Subordinated Debentures HL&P Capital Trust I...... $250 8.125% March 2046 8.125% Junior Subordinated Deferrable Interest Debentures Series A HL&P Capital Trust II..... $100 8.257% February 2037 8.257% Junior Subordinated Deferrable Interest Debentures Series B

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 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. (11) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS (a) INCENTIVE COMPENSATION PLANS The Company has long-term incentive compensation plans (LICP) that provide for the issuance of stock-based incentives, including performance-based shares, performance-based units, restricted shares, stock options and stock appreciation rights to key employees of the Company, including officers. As of December 31, 2002, 344 current and 443 former employees of the Company participate in the plans. A maximum of approximately 37 million shares of CenterPoint Energy common stock may be issued under these plans. Performance-based shares, performance-based units and restricted shares are granted to employees without cost to the participants. The performance shares and units vest three years after the grant date based 113 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) upon the performance of the Company over a three-year cycle, except as discussed below. The restricted shares vest at various times ranging from immediately to at the end of a three-year period. Upon vesting, the shares are issued to the plan participants. During 2000, 2001 and 2002, the Company recorded compensation expense of $22 million, $6 million and $2 million, respectively, related to performance-based shares, performance-based units and restricted share grants. Included in these amounts is $7 million and $5 million in compensation expense for 2000 and 2001, respectively, related to Reliant Resources' participants. In addition, compensation benefit of $1 million was recorded in 2002 related to Reliant Resources' participants. Amounts for Reliant Resources' participants are reflected in discontinued operations in the Statements of Consolidated Operations. The following table summarizes the Company's performance-based units, performance-based shares and restricted share grant activity for the years 2000 through 2002:

NUMBER OF NUMBER OF PERFORMANCE-BASED PERFORMANCE-BASED NUMBER OF UNITS SHARES RESTRICTED SHARES ----------------- ----------------- ----------------- Outstanding at December 31, 1999............. -- 928,467 270,623 Granted.................................... -- 394,942 206,395 Canceled................................... -- (81,541) (13,060) Released to participants................... -- (174,001) (5,346) ------ ---------- --------- Outstanding at December 31, 2000............. -- 1,067,867 458,612 Granted.................................... 83,670 -- 2,623 Canceled................................... -- (17,154) (2,778) Released to participants................... -- (424,623) (249,895) ------ ---------- --------- Outstanding at December 31, 2001............. 83,670 626,090 208,562 Granted.................................... -- 451,050 -- Canceled................................... (5,625) (176,258) (41,892) Released to participants................... (120) (447,060) (78,768) ------ ---------- --------- Outstanding at December 31, 2002............. 77,925 453,822 87,902 ====== ========== ========= Weighted average fair value granted for 2000....................................... $ 25.19 $ 28.03 ========== ========= Weighted average fair value granted for 2001....................................... $ -- $ 38.13 ========== ========= Weighted average fair value granted for 2002....................................... $ 12.00 $ -- ========== =========

The maximum value associated with the performance-based units granted in 2001 was $150 per unit. Effective with the Reliant Resources Distribution which occurred on September 30, 2002, the Company's compensation committee authorized the conversion of outstanding CenterPoint Energy performance-based shares for the performance cycle ending December 31, 2002 to a number of time-based restricted shares of CenterPoint Energy's common stock equal to the number of performance-based shares that would have vested if the performance objectives for the performance cycle were achieved at the maximum level for substantially all shares. These time-based restricted shares vested if the participant holding the shares remained employed with the Company or with Reliant Resources and its subsidiaries through December 31, 2002. On the date of the Reliant Resources Distribution, holders of these time-based restricted shares received shares of Reliant Resources common stock in the same manner as other holders of CenterPoint Energy common stock, but these shares of common stock were subject to the same time-based vesting schedule, as well as to the terms and conditions of the plan under which the original performance shares were granted. Thus, following the 114 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Reliant Resources Distribution, employees who held performance-based shares under the LICP for the performance cycle ending December 31, 2002 held time-based restricted shares of CenterPoint Energy common stock and time-based restricted shares of Reliant Resources common stock, which vested following continuous employment through December 31, 2002. Effective with the Reliant Resources Distribution, the Company converted all outstanding CenterPoint Energy stock options granted prior to the Reliant Resources Offering to a combination of adjusted CenterPoint Energy stock options and Reliant Resources stock options. For the converted stock options, the sum of the intrinsic value of the CenterPoint Energy stock options immediately prior to the record date of the Reliant Resources Distribution equaled the sum of the intrinsic values of the adjusted CenterPoint Energy stock options and the Reliant Resources stock options granted immediately after the record date of the Reliant Resources Distribution. As such, Reliant Resources employees who do not work for the Company hold stock options of the Company. Both the number and the exercise price of all outstanding CenterPoint Energy stock options that were granted on or after the Reliant Resources Offering were adjusted to maintain the total intrinsic value of the grants. During January 2003, due to the distribution of Texas Genco stock, the Company granted additional CenterPoint Energy shares to participants with performance-based and time-based shares that had not yet vested as of the record date of December 20, 2002. These additional shares are subject to the same vesting schedule and the terms and conditions of the plan under which the original shares were granted. Also in connection with this distribution, both the number and the exercise price of all outstanding CenterPoint Energy stock options were adjusted to maintain the total intrinsic value of the stock option grants. Under the Company's plans, stock options generally become exercisable in one-third increments on each of the first through third anniversaries of the grant date. The exercise price is the average of the high and low sales price of the common stock on the New York Stock Exchange on the grant date. The Company applies APB Opinion No. 25, "Accounting for Stock Issued to Employees" (APB Opinion No. 25), and related interpretations in accounting for its stock option plans. Accordingly, no compensation expense has been recognized for these fixed stock options. The following table summarizes stock option activity related to the Company for the years 2000 through 2002:

NUMBER OF WEIGHTED AVERAGE SHARES EXERCISE PRICE ---------- ---------------- Outstanding at December 31, 1999......................... 6,462,971 $25.99 Options granted........................................ 5,936,510 22.14 Options exercised...................................... (1,061,169) 25.01 Options canceled....................................... (1,295,877) 23.96 ---------- Outstanding at December 31, 2000......................... 10,042,435 24.13 Options granted........................................ 1,887,668 46.23 Options exercised...................................... (1,812,022) 24.11 Options canceled....................................... (289,610) 27.38 ---------- Outstanding at December 31, 2001......................... 9,828,471 28.34 Options granted........................................ 3,115,399 7.12 Options converted at Reliant Resources Distribution.... 742,636 29.01 Options exercised...................................... (71,273) 20.59 Options canceled....................................... (1,155,351) 16.11 ---------- Outstanding at December 31, 2002......................... 12,459,882 $18.26 ========== ======

115 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NUMBER OF WEIGHTED AVERAGE SHARES EXERCISE PRICE ---------- ---------------- Options exercisable at December 31, 2000................. 2,258,397 $25.76 ========== ====== Options exercisable at December 31, 2001................. 3,646,228 $25.38 ========== ====== Options exercisable at December 31, 2002................. 6,854,910 $19.78 ========== ======

Exercise prices for CenterPoint Energy stock options outstanding held by Company employees ranged from $5.00 to $40.00. The following tables provide information with respect to outstanding CenterPoint Energy stock options held by the Company's employees on December 31, 2002:

REMAINING AVERAGE OPTIONS AVERAGE CONTRACTUAL LIFE OUTSTANDING EXERCISE PRICE (YEARS) ----------- -------------- ----------------- Ranges of Exercise Prices: $5.00-$15.00.............................. 6,330,830 $11.40 8.0 $15.01-$20.00............................. 2,981,020 19.05 5.9 $20.01-$30.00............................. 731,891 23.07 6.9 $30.01-$40.00............................. 2,416,141 33.80 8.3 ---------- Total.................................. 12,459,882 18.26 7.5 ==========

The following table provides information with respect to CenterPoint Energy stock options exercisable at December 31, 2002:

OPTIONS AVERAGE EXERCISABLE EXERCISE PRICE ----------- -------------- Ranges of Exercise Prices: $5.00-$15.00.............................................. 2,446,317 $14.82 $15.01-$20.00............................................. 2,929,020 19.09 $20.01-$30.00............................................. 598,556 22.76 $30.01-$40.00............................................. 881,017 33.81 --------- Total.................................................. 6,854,910 19.78 =========

In accordance with SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123), and SFAS No. 148, the Company applies the guidance contained in APB Opinion No. 25 and discloses the required pro forma effect on net income of the fair value based method of accounting for stock compensation. The weighted average fair values at date of grant for CenterPoint Energy options granted during 2000, 2001 and 2002 were $5.07, $9.25 and $1.40, respectively. The fair values were estimated using the Black-Scholes option valuation model with the following weighted-average assumptions:

2000 2001 2002 ------ ------ ------ Expected life in years..................................... 5 5 5 Interest rate.............................................. 6.57% 4.87% 2.83% Volatility................................................. 24.00% 31.91% 48.95% Expected common stock dividend............................. $ 1.50 $ 1.50 $ 0.64

Pro forma information for 2000, 2001 and 2002 is provided to take into account the amortization of stock-based compensation to expense on a straight-line basis over the vesting period. Had compensation costs been 116 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) determined as prescribed by SFAS No. 123, the Company's net income and earnings per share would have been as follows:

2000 2001 2002 ----- ----- ------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Net Income (loss): As reported............................................... $ 447 $ 980 $(3,920) Pro forma................................................. $ 437 $ 968 $(3,929) Basic Earnings Per Share: As reported............................................... $1.57 $3.38 $(13.16) Pro forma................................................. $1.54 $3.34 $(13.16) Diluted Earnings Per Share: As reported............................................... $1.56 $3.35 $(13.08) Pro forma................................................. $1.52 $3.31 $(13.08)

(B) PENSION AND POSTRETIREMENT BENEFITS The Company maintains a pension plan which is a non-contributory defined benefit plan covering substantially all employees using a cash balance formula. 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. The Company's funding policy is to review amounts annually in accordance with applicable regulations in order to achieve adequate funding of projected benefit obligations. The assets of the pension plans consist principally of common stocks and interest bearing obligations. Included in such assets are approximately 4.5 million shares of CenterPoint Energy common stock contributed from treasury stock during 2001. As of December 31, 2002, the fair value of CenterPoint Energy common stock was $38 million or 4.7% of the pension plan assets. The Company provides certain healthcare 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. The net unrecognized transition obligation, resulting from the implementation of accrual accounting, is being amortized over approximately 20 years. The Company 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. 117 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company's net periodic cost (benefit) includes the following components relating to pension and postretirement benefits:

YEAR ENDED DECEMBER 31, --------------------------------------------------------------------------------- 2000 2001 2002 ------------------------- ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- -------- -------------- (IN MILLIONS) Service cost..................... $ 31 $ 6 $ 35 $ 5 $ 32 $ 5 Interest cost.................... 88 27 99 31 104 32 Expected return on plan assets... (146) (11) (138) (13) (126) (13) Net amortization................. (12) 11 (3) 14 16 13 Curtailment...................... -- -- (23) 40 -- -- Benefit enhancement.............. -- -- 69 -- 9 3 Settlement....................... -- -- -- -- -- (18) ----- ---- ----- ---- ----- ---- Net periodic cost (benefit)...... $ (39) $ 33 $ 39 $ 77 $ 35 $ 22 ===== ==== ===== ==== ===== ==== Above amounts reflect the following net periodic cost (benefit) related to discontinued operations........ $ -- $ -- $ 45 $ 42 $ (4) $(16) ===== ==== ===== ==== ===== ====

The following table displays the change in the benefit obligation, the fair value of plan assets and the amounts included in the Company's Consolidated Balance Sheets as December 31, 2001 and 2002 for the Company's pension and postretirement benefit plans:

DECEMBER 31, ----------------------------------------------------- 2001 2002 ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN MILLIONS) CHANGE IN BENEFIT OBLIGATION Benefit obligation, beginning of year.......... $ 1,317 $ 425 $ 1,485 $ 456 Service cost................................... 35 5 32 5 Interest cost.................................. 99 31 104 32 Participant contributions...................... -- 5 -- 7 Benefits paid.................................. (92) (17) (136) (26) Actuarial loss................................. 69 7 56 20 Curtailment, benefit enhancement and settlement................................... 57 -- 9 (15) -------- ----- -------- ----- Benefit obligation, end of year................ $ 1,485 $ 456 $ 1,550 $ 479 ======== ===== ======== ===== CHANGE IN PLAN ASSETS Plan assets, beginning of year................. $ 1,417 $ 122 $ 1,376 $ 139 Employer contributions......................... 107 40 -- 30 Participant contributions...................... -- 5 -- 7 Benefits paid.................................. (92) (17) (136) (26) Actual investment return....................... (56) (11) (186) (19) -------- ----- -------- ----- Plan assets, end of year....................... $ 1,376 $ 139 $ 1,054 $ 131 ======== ===== ======== =====

118 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

DECEMBER 31, ----------------------------------------------------- 2001 2002 ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN MILLIONS) RECONCILIATION OF FUNDED STATUS Funded status.................................. $ (109) $(317) $ (496) $(348) Unrecognized actuarial loss.................... 470 (25) 811 27 Unrecognized prior service cost................ (93) 65 (84) 60 Unrecognized transition (asset) obligation..... (2) 94 -- 87 -------- ----- -------- ----- Prepaid (accrued) pension cost................. $ 266 $(183) $ 231 $(174) ======== ===== ======== ===== AMOUNTS RECOGNIZED IN BALANCE SHEETS Other assets-Other............................. $ 266 $ -- $ -- $ -- Benefits obligations........................... -- (183) (392) (174) Accumulated other comprehensive income......... -- -- 623 -- -------- ----- -------- ----- Prepaid (accrued) pension cost................. $ 266 $(183) $ 231 $(174) ======== ===== ======== ===== ACTUARIAL ASSUMPTIONS Discount rate.................................. 7.25% 7.25% 6.75% 6.75% Expected return on plan assets................. 9.5% 9.5% 9.0% 9.0% Rate of increase in compensation levels........ 3.5-5.5% -- 3.5-5.5% --

For the year ended December 31, 2001, the assumed health care cost trend rates were 7.5% for participants under age 65 and 8.5% for participants age 65 and over. For the year ended December 31, 2002, the assumed health cost trend rate was increased to 12% for all participants. The health care cost trend rates decline by .75% annually to 5.5% by 2011. If the health care cost trend rate assumption were increased by 1%, the accumulated postretirement benefit obligation as of December 31, 2002 would increase by 2.9%. The annual effect of a 1% increase on the sum of service and interest cost would be an increase of approximately 2.4%. If the health care cost trend rate assumption were decreased by 1%, the accumulated postretirement benefit obligation as of December 31, 2002 would decrease approximately 2.8%. The annual effect of a 1% decrease on the sum of service and interest cost would be a decrease of 2.4%. In addition to the non-contributory pension plans discussed above, the Company maintains a non-qualified pension plan which allow participants to retain the benefits to which they would have been entitled under the Company's non-contributory pension plan except for the federally mandated limits on these benefits or on the level of compensation on which these benefits may be calculated. The expense associated with this non-qualified plan was $25 million, $25 million and $9 million in 2000, 2001 and 2002, respectively. Included in the net benefit cost in 2001 and 2002 is $17 million and $3 million, respectively, of expense related to Reliant Resources' participants, which is reflected in discontinued operations in the Statements of Consolidated Operations. The accrued benefit liability for the non-qualified pension plan was $99 million and $83 million at December 31, 2001 and 2002, respectively. In addition, these accrued benefit liabilities include the recognition of minimum liability adjustments of $20 million as of December 31, 2001 and $23 million as of December 31, 2002, which are reported as a component of other comprehensive income, net of income tax effects. Included in these amounts is $30 million of accrued benefit liabilities for Reliant Resources' participants as of December 31, 2001. Of these liabilities, $11 million represents the recognition of minimum 119 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) liability adjustments, which are reported as discontinued operations on the Statements of Consolidated Comprehensive Income, net of income tax effects. (C) SAVINGS PLAN The Company has an employee savings plan that includes a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code of 1986, as amended (the Code). 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. The Company matches 75% of the first 6% of each employee's compensation contributed. The Company 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 Company's match is initially invested in CenterPoint Energy common stock. Participating employees may elect to invest all or a portion of their contributions to the plan in CenterPoint Energy common stock, to have dividends reinvested in additional shares or to receive dividend payments in cash on any investment in CenterPoint Energy common stock, and to transfer all or part of their investment in CenterPoint Energy common stock to other investment options offered by the plan. The Company's savings plan includes an Employee Stock Ownership Plan (ESOP), which contains company stock, a portion of which is encumbered by a loan. Upon the release from the encumbrance of the loan, the Company may use released shares to satisfy its obligation to make matching contributions under the Company's savings plan. Generally, debt service on the loan is paid using all dividends on shares currently or formerly encumbered by the loan, interest earnings on funds held in trust and cash contributions by the Company. Shares of CenterPoint Energy common stock are released from the encumbrance of the loan based on the proportion of debt service paid during the period. The Company recognizes benefit expense equal to the fair value of the shares committed to be released. The Company credits to unearned shares the original purchase price of shares committed to be released to plan participants with the difference between the fair value of the shares and the original purchase price recorded to common stock. Dividends on allocated shares are recorded as a reduction to retained earnings. Dividends on unallocated shares are recorded as a reduction of principal or accrued interest on the loan. Share balances currently or formerly encumbered by a loan at December 31, 2001 and 2002 were as follows:

DECEMBER 31, -------------------------- 2001 2002 ------------ ----------- Allocated shares transferred/distributed from the savings plan...................................................... 2,740,328 5,943,297 Allocated shares............................................ 8,951,967 8,734,810 Unearned shares(1).......................................... 7,069,889 4,915,577 ------------ ----------- Total ESOP shares(1)...................................... 18,762,184 19,593,684 ============ =========== Fair value of unearned ESOP shares.......................... $187,493,456 $41,782,405 ============ ===========

--------------- (1) During 2002, unearned shares and total shares were increased by 831,500 shares. This is due to additional shares purchased with proceeds from the sale of Reliant Resources common stock, which was received in connection with the Reliant Resources Distribution. As a result of the ESOP, the savings plan has significant holdings of CenterPoint Energy common stock. As of December 31, 2002, an aggregate of 32,099,870 shares of CenterPoint Energy's common stock were held by the savings plan, which represented 30% of its investments. Given the concentration of the investments in 120 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CenterPoint Energy's common stock, the savings plan and its participants have market risk related to this investment. The Company's savings plan benefit expense was $52 million, $51 million and $47 million in 2000, 2001 and 2002, respectively. Included in these amounts are $5 million $16 million and $6 million of savings plan benefit expense for 2000, 2001 and 2002, respectively, related to Reliant Resources' participants, which is reflected as discontinued operations in the Statements of Consolidated Operations. (D) POSTEMPLOYMENT BENEFITS Net postemployment benefit costs for former or inactive employees, their beneficiaries and covered dependents, after employment but before retirement (primarily health care and life insurance benefits for participants in the long-term disability plan) were $2 million, $6 million and $12 million in 2000, 2001 and 2002, respectively. The Company's postemployment obligation is presented as a liability in the Consolidated Balance Sheets under the caption "Benefit Obligations." (E) OTHER NON-QUALIFIED PLANS The Company has in effect 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. In general, employees who attain the age of 60 during employment and participate in the Company'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 that in which a participant attains age 65. During 2000, 2001 and 2002, the Company recorded interest expense related to its deferred compensation obligation of $14 million, $17 million and $11 million, respectively. Included in these amounts are $1 million, $4 million and $0.2 million of interest expense for 2000, 2001 and 2002, respectively, related to Reliant Resources' participants, which is reflected as discontinued operations in the Statements of Consolidated Operations. The discounted deferred compensation obligation recorded by the Company was $161 million and $132 million as of December 31, 2001 and 2002, respectively. The Company's obligations under other non-qualified plans are presented as a liability in the Consolidated Balance Sheets under the caption "Benefit Obligations." (F) OTHER EMPLOYEE MATTERS As of December 31, 2002, approximately 38% of the Company's employees are subject to collective bargaining agreements. Three of these agreements, covering approximately 24% of the Company's employees, will expire in 2003. 121 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (12) INCOME TAXES The components of income from continuing operations before income taxes are as follows:

YEAR ENDED DECEMBER 31, ------------------------ 2000 2001 2002 ------ ------ ------ (IN MILLIONS) United States............................................... $514 $687 $592 Foreign..................................................... (58) (12) 2 ---- ---- ---- Income from continuing operations before income taxes..... $456 $675 $594 ==== ==== ====

The Company's current and deferred components of income tax expense (benefit) were as follows:

YEAR ENDED DECEMBER 31, ------------------------- 2000 2001 2002 ------ ------ ------- (IN MILLIONS) Current: Federal................................................... $199 $378 $(102) State..................................................... 9 (3) 9 Foreign................................................... 48 4 2 ---- ---- ----- Total current.......................................... 256 379 (91) ---- ---- ----- Deferred: Federal................................................... (23) (151) 288 State..................................................... 1 -- 11 ---- ---- ----- Total deferred......................................... (22) (151) 299 ---- ---- ----- Income tax expense.......................................... $234 $228 $ 208 ==== ==== =====

122 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

2000 2001 2002 ---- ---- ---- (IN MILLIONS) Income from continuing operations before income taxes....... $456 $675 $594 Federal statutory rate...................................... 35% 35% 35% ---- ---- ---- Income taxes at statutory rate.............................. 160 236 208 ---- ---- ---- Net addition (reduction) in taxes resulting from: State income taxes, net of valuation allowances and federal income tax benefit............................. 6 (2) 13 Capital loss benefit...................................... -- -- (72) Amortization of investment tax credit..................... (18) (18) (13) Excess deferred taxes..................................... (4) (5) (3) Goodwill amortization..................................... 17 16 -- Latin America operations.................................. 69 (5) -- Valuation allowance, capital loss......................... -- -- 72 Other, net................................................ 4 6 3 ---- ---- ---- Total.................................................. 74 (8) -- ---- ---- ---- Income tax expense.......................................... $234 $228 $208 ==== ==== ==== Effective rate.............................................. 51.3% 33.8% 35.0%

Following are the Company's tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases:

DECEMBER 31, ---------------- 2001 2002 ------ ------ (IN MILLIONS) Deferred tax assets: Current: Allowance for doubtful accounts........................ $ 14 $ 9 Non-trading derivative assets, net..................... 19 35 Current portion of capital loss........................ -- 8 ------ ------ Total current deferred tax assets.................... 33 52 ------ ------ Non-current: Employee benefits...................................... 127 374 Disallowed plant cost, net............................. 53 -- Operating and capital loss carryforwards............... 29 86 Contingent liabilities associated with discontinuance of SFAS No. 71........................................ 74 108 Foreign exchange gains................................. 16 16 Impairment of foreign asset............................ 52 51 Other.................................................. 74 90 Valuation allowance.................................... (15) (83) ------ ------ Total non-current deferred tax assets................ 410 642 ------ ------ Total deferred tax assets............................ 443 694 ------ ------

123 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

DECEMBER 31, ---------------- 2001 2002 ------ ------ (IN MILLIONS) Deferred tax liabilities: Current: Unrealized gain on indexed debt securities............. 113 276 Unrealized gain on AOL Time Warner investment.......... 244 61 ------ ------ Total current deferred tax liabilities............... 357 337 ------ ------ Non-current: Depreciation........................................... 2,237 2,397 Regulatory assets, net................................. 403 634 Deferred gas costs..................................... 47 3 Other.................................................. 75 57 ------ ------ Total non-current deferred tax liabilities........... 2,762 3,091 ------ ------ Total deferred tax liabilities....................... 3,119 3,428 ------ ------ Accumulated deferred income taxes, net............ $2,676 $2,734 ====== ======

Tax Attribute Carryforwards. At December 31, 2002, the Company had $7 million and $387 million of federal and state net operating loss carryforwards, respectively. The losses are available to offset future respective federal and state taxable income through the year 2022. In conjunction with the Reliant Resources Distribution, the Company realized a previously unrecorded capital loss attributable to the excess of the tax basis over the book carrying value in former subsidiaries sold to Reliant Resources. The tax benefit of this excess tax basis is recorded under SFAS No. 109, "Accounting for Income Taxes," when realizable under the facts, such as a loss from a previously deferred taxable disposition that is triggered by a spin-off. This loss is a capital loss which may be used in the three taxable years preceding the year of the loss, or the five taxable years following the year of the loss. Federal tax law only allows utilization of capital losses to offset capital gains. A valuation allowance is provided against 100% of the expected benefit due to the uncertainty in the Company's ability to generate capital gains during the utilization period. The valuation allowance reflects a net decrease of $32 million in 2001 and a net increase of $68 million in 2002. These net changes resulted from a reassessment of the Company's future ability to use federal capital loss carryforwards and state tax net operating loss carryforwards. Tax Refunds. In 2000, the Company received refunds from the Internal Revenue Service totaling $126 million in taxes and interest following audits of tax returns and refund claims for CenterPoint Energy's 1985, 1986 and 1990 through 1995 tax years, and CERC Corp.'s 1979 through 1993 tax years. The pre-tax income statement effect of $40 million ($26 million after-tax) was recorded in 2000 in other income in the Company's Statements of Consolidated Operations. Of the refunds, $26 million was recorded as a reduction in goodwill. CenterPoint Energy's consolidated federal income tax returns have been audited and settled through the 1996 tax year. All of CERC Corp.'s consolidated federal income tax returns for tax years ending on or prior to CenterPoint Energy's acquisition of CERC Corp. have been audited and settled. 124 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (13) COMMITMENTS AND CONTINGENCIES (a) COMMITMENTS AND GUARANTEES Environmental Capital Commitments. CenterPoint Energy anticipates investing up to $131 million in capital and other special project expenditures between 2003 and 2007 for environmental compliance. CenterPoint Energy anticipates expenditures to be as follows (in millions): 2003........................................................ $ 98 2004........................................................ 33 2005........................................................ -- 2006(1)..................................................... -- 2007(1)..................................................... -- ---- Total $131 ==== --------------- (1) NOx control estimates for 2006 and 2007 have not been finalized. Fuel and Purchased Power. Fuel commitments include several long-term coal, lignite and natural gas contracts related to Texas power generation operations, which have various quantity requirements and durations that are not classified as non-trading derivatives assets and liabilities in the Company's Consolidated Balance Sheets as of December 31, 2002 as these contracts meet the SFAS No. 133 exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Minimum payment obligations for coal and transportation agreements that extend through 2012 are approximately $292 million in 2003, $165 million in 2004, $169 million in 2005, $174 million in 2006 and $167 million in 2007. Purchase commitments related to lignite mining and lease agreements and purchased power are not material to CenterPoint Energy's operations. Prior to January 1, 2002, CenterPoint Houston was allowed recovery of these costs through rates for electric service. As of December 31, 2002, some of these contracts are above market. CenterPoint Energy anticipates that stranded costs associated with these obligations will be recoverable through the stranded cost recovery mechanisms contained in the Texas electric restructuring law. For information regarding the Texas electric restructuring law, see Note 4(a). CenterPoint Energy's other long-term fuel supply commitments, which have various quantity requirements and durations, are not considered material either individually or in the aggregate to its results of operations or cash flows. (b) LEASE COMMITMENTS The following table sets forth information concerning the Company's obligations under non-cancelable long-term operating leases at December 31, 2002, which primarily consist of rental agreements for building space, data processing equipment and vehicles, including major work equipment (in millions). 2003........................................................ $ 31 2004........................................................ 28 2005........................................................ 26 2006........................................................ 24 2007........................................................ 23 2008 and beyond............................................. 131 ---- Total..................................................... $263 ==== 125 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Total lease expense for all operating leases was $46 million, $45 million and $43 million during 2000, 2001 and 2002, respectively. (C) LEGAL, ENVIRONMENTAL AND OTHER REGULATORY MATTERS Legal Matters The Company's predecessor, Reliant Energy, and certain of its former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between Reliant Energy and Reliant Resources, the Company and its subsidiaries are entitled to be indemnified by Reliant Resources for any losses arising out of the lawsuits described under "California Class Actions and Attorney General Cases," "Long-Term Contract Class Action," "Washington and Oregon Class Actions," "Bustamante Price Reporting Class Action" and "Trading and Marketing Activities," including attorneys' fees and other costs. Pursuant to the indemnification obligation, Reliant Resources is defending the Company and its subsidiaries to the extent named in these lawsuits. The ultimate outcome of these matters cannot be predicted at this time. California Class Actions and Attorney General Cases. Reliant Energy, Reliant Resources, Reliant Energy Services, Inc.(Reliant Energy Services), Reliant Energy Power Generation, Inc. (REPG) and several other subsidiaries of Reliant Resources, as well as two former officers and one present officer of some of these companies, have been named as defendants in class action lawsuits and other lawsuits filed against a number of companies that own generation plants in California and other sellers of electricity in California markets. While the plaintiffs allege various violations by the defendants of antitrust laws and state laws against unfair and unlawful business practices, each of the lawsuits is grounded on the central allegation that the defendants conspired to drive up the wholesale price of electricity. In addition to injunctive relief, the plaintiffs in these lawsuits seek treble the amount of damages alleged, restitution of alleged overpayments, disgorgement of alleged unlawful profits for sales of electricity, costs of suit and attorneys' fees. All of these suits originally were filed in state courts in San Diego, San Francisco and Los Angeles Counties. The suits in San Diego and Los Angeles Counties were consolidated and removed to the federal district court in San Diego, but on December 13, 2002, that court remanded the suits to the state courts. Prior to the remand, Reliant Energy was voluntarily dismissed from two of the suits. Several parties, including the Reliant defendants, have appealed the judge's remand decision. The United States court of appeals has entered a briefing schedule that could result in oral arguments by summer of 2003. Proceedings before the state court are expected to resume during the first quarter of 2003. In March and April 2002, the California Attorney General filed three complaints, two in state court in San Francisco and one in the federal district court in San Francisco, against Reliant Energy, Reliant Resources, Reliant Energy Services and other subsidiaries of Reliant Resources alleging, among other matters, violations by the defendants of state laws against unfair and unlawful business practices arising out of transactions in the markets for ancillary services run by the California independent systems operator, charging unjust and unreasonable prices for electricity, in violation of antitrust laws in connection with the acquisition in 1998 of electric generating facilities located in California. The complaints variously seek restitution and disgorgement of alleged unlawful profits for sales of electricity, civil penalties and fines, injunctive relief against unfair competition, and undefined equitable relief. Reliant Resources has removed the two state court cases to the federal district court in San Francisco where all three cases are now pending. Following the filing of the Attorney General cases, seven additional class action cases were filed in state courts in Northern California. Each of these purports to represent the same class of California ratepayers, assert the same claims as asserted in the other California class action cases, and in some instances repeat as well the allegations in the Attorney General cases. All of these cases have been removed to federal district court in San Diego. Reliant Resources has not filed an answer in any of these cases. The plaintiffs have agreed to a stipulated order that would require the filing of a consolidated complaint by early March 2003 and the filing of the defendants' initial response to the complaint within 60 days after the consolidated complaint is 126 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) filed. In all of these cases filed before the federal and state courts in California, the Reliant defendants have filed or intend to file motions to dismiss on grounds that the claims are barred by federal preemption and the filed rate doctrine. Long-Term Contract Class Action. In October 2002, a class action was filed in state court in Los Angeles against Reliant Energy and several subsidiaries of Reliant Resources. The complaint in this case repeats the allegations asserted in the California class actions as well as the Attorney General cases and also alleges misconduct related to long-term contracts purportedly entered into by the California Department of Water Resources. None of the Reliant entities, however, has a long-term contract with the Department of Water Resources. This case has been removed to federal district court in San Diego. Washington and Oregon Class Actions. In December 2002, a lawsuit was filed in Circuit Court of the State of Oregon for the County of Multnomah on behalf of a class of all Oregon purchasers of electricity and natural gas. Reliant Energy, Reliant Resources and several Reliant Resources subsidiaries are named as defendants, along with many other electricity generators and marketers. Like the other lawsuits filed in California, the plaintiffs claim the defendants manipulated wholesale power prices in violation of state and federal law. The plaintiffs seek injunctive relief and payment of damages based on alleged overcharges for electricity. Also in December 2002, a nearly identical lawsuit on behalf of consumers in the State of Washington was filed in federal district court in Seattle. Reliant Resources has removed the Oregon suit to federal district court in Portland. It is anticipated that before answering the lawsuits, the defendants will file motions to dismiss on the grounds that the claims are barred by federal preemption and by the filed rate doctrine. Bustamante Price Reporting Class Action. In November 2002, California Lieutenant Governor Cruz Bustamante filed a lawsuit in state court in Los Angeles on behalf of a class of purchasers of gas and power alleging violations of state antitrust laws and state laws against unfair and unlawful business practices based on an alleged conspiracy to report and publish false and fraudulent natural gas prices with an intent to affect the market prices of natural gas and electricity in California. Reliant Energy, Reliant Resources and several Reliant Resources subsidiaries are named as defendants, along with other market participants and publishers of some of the price indices. The complaint seeks injunctive relief, compensatory and punitive damages, restitution of alleged overpayment, disgorgement of all profits and funds acquired by the alleged unlawful conduct, costs of suit and attorneys' fees. The parties have stipulated to a schedule that would require the defendants to respond to the complaint by March 31, 2003. The Reliant defendants intend to deny both their alleged violation of any laws and their alleged participation in any conspiracy. Trading and Marketing Activities. Reliant Energy has been named as a party in several lawsuits and regulatory proceedings relating to the trading and marketing activities of its former subsidiary, Reliant Resources. In June 2002, the SEC advised Reliant Resources and Reliant Energy that it had issued a formal order in connection with its investigation of Reliant Resources' financial reporting, internal controls and related matters. The Company understands that the investigation is focused on Reliant Resources' same-day commodity trading transactions involving purchases and sales with the same counterparty for the same volume at substantially the same price and certain structured transactions. These matters were previously the subject of an informal inquiry by the SEC. Reliant Resources and the Company are cooperating with the SEC staff. In connection with the Texas Utility Commission's industry-wide investigation into potential manipulation of the ERCOT market on and after July 31, 2001, Reliant Energy and Reliant Resources have provided information to the Texas Utility Commission concerning their scheduling and trading activities. Fifteen class action lawsuits filed in May, June and July 2002 on behalf of purchasers of securities of Reliant Resources and/or Reliant Energy have been consolidated in federal district court in Houston. Reliant Resources and certain of its executive officers are named as defendants. Reliant Energy is also named as a 127 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) defendant in seven of the lawsuits. Two of the lawsuits also name as defendants the underwriters of the Reliant Resources Offering. One lawsuit names Reliant Resources' and Reliant Energy's independent auditors as a defendant. The consolidated amended complaint seeks monetary relief purportedly on behalf of three classes: (1) purchasers of Reliant Energy common stock from February 3, 2000 to May 13, 2002; (2) purchasers of Reliant Resources common stock on the open market from May 1, 2001 to May 13, 2002; and (3) purchasers of Reliant Resources common stock in the Reliant Resources Offering or purchasers of shares that are traceable to the Reliant Resources Offering. The plaintiffs allege, among other things, that the defendants misrepresented their revenues and trading volumes by engaging in round-trip trades and improperly accounted for certain structured transactions as cash-flow hedges, which resulted in earnings from these transactions being accounted for as future earnings rather than being accounted for as earnings in fiscal year 2001. In February 2003, a lawsuit was filed by three individuals in federal district court in Chicago against CenterPoint Energy and certain former and current officers of Reliant Resources for alleged violations of federal securities laws. The plaintiffs in this lawsuit allege that the defendants violated federal securities laws by issuing false and misleading statements to the public, and that the defendants made false and misleading statements as part of an alleged scheme to inflate artificially trading volumes and revenues. In addition, the plaintiffs assert claims of fraudulent and negligent misrepresentation and violations of Illinois consumer law. The defendants expect to file a motion to transfer this lawsuit to the federal district court in Houston and to consolidate this lawsuit with the consolidated lawsuits described above. The Company believes that none of these lawsuits has merit because, among other reasons, the alleged misstatements and omissions were not material and did not result in any damages to any of the plaintiffs. In May 2002, three class action lawsuits were filed in federal district court in Houston on behalf of participants in various employee benefits plans sponsored by Reliant Energy. Reliant Energy and its directors are named as defendants in all of the lawsuits. Two of the lawsuits have been dismissed without prejudice. The remaining lawsuit alleges that the defendants breached their fiduciary duties to various employee benefits plans, directly or indirectly sponsored by Reliant Energy, in violation of the Employee Retirement Income Security Act. The plaintiffs allege that the defendants permitted the plans to purchase or hold securities issued by Reliant Energy when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaints seek monetary damages for losses suffered by a putative class of plan participants whose accounts held Reliant Energy or Reliant Resources securities, as well as equitable relief in the form of restitution. In October 2002, a derivative action was filed in the federal district court in Houston, against the directors and officers of the Company. The complaint sets forth claims for breach of fiduciary duty, waste of corporate assets, abuse of control and gross mismanagement. Specifically, the shareholder plaintiff alleges that the defendants caused the Company to overstate its revenues through so-called "round trip" transactions. The plaintiff also alleges breach of fiduciary duty in connection with the spin-off and the Reliant Resources Offering. The complaint seeks monetary damages on behalf of the Company as well as equitable relief in the form of a constructive trust on the compensation paid to the defendants. The defendants have filed a motion to dismiss this case on the ground that the plaintiff did not make an adequate demand on the Company before filing suit. A Special Litigation Committee appointed by the Company's board of directors is investigating similar allegations made in a June 28, 2002 demand letter sent on behalf of a Company shareholder. The letter states that the shareholder and other shareholders are considering filing a derivative suit on behalf of the Company and demands that the Company take several actions in response to alleged round-trip trades occurring in 1999, 2000, and 2001. The Special Litigation Committee is reviewing the demands made by the shareholder to determine if these proposed actions are in the best interests of the Company. 128 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Reliant Energy Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena filed suit, for themselves and a proposed class of all similarly situated cities in Reliant Energy's electric service area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a wholly owned subsidiary of Reliant Energy) alleging underpayment of municipal franchise fees. The plaintiffs claim that they are entitled to 4% of all receipts of any kind for business conducted within these cities over the previous four decades. A jury trial of the original claimant cities (but not the class of cities) in the 269th Judicial District Court for Harris County, Texas, ended in April 2000 (the Three Cities case). Although the jury found for Reliant Energy on many issues, it found in favor of the original claimant cities on three issues, and assessed a total of $4 million in actual and $30 million in punitive damages. However, the jury also found in favor of Reliant Energy on the affirmative defense of laches, a defense similar to a statute of limitations defense, due to the original claimant cities having unreasonably delayed bringing their claims during the 43 years since the alleged wrongs began. The trial court in the Three Cities case granted most of Reliant Energy's motions to disregard the jury's findings. The trial court's rulings reduced the judgment to $1.7 million, including interest, plus an award of $13.7 million in legal fees. In addition, the trial court granted Reliant Energy's motion to decertify the class. Following this ruling, 45 cities filed individual suits against Reliant Energy in the District Court of Harris County. On February 27, 2003, the state court of appeals in Houston rendered an opinion reversing the judgment against the Company and rendering judgment that the Three Cities take nothing by their claims. The court of appeals found that the jury's finding of laches barred all of the Three Cities' claims and that the Three Cities were not entitled to recovery of any attorneys' fees. The judgment of the court of appeals is subject to motions for rehearing and an appeal to the Texas Supreme Court. The extent to which issues in the Three Cities case may affect the claims of the other cities served by Reliant Energy cannot be assessed until judgments are final and no longer subject to appeal. However, the court of appeals' ruling appears to be consistent with Texas Supreme Court opinions. The Company estimates the range of possible outcomes for recovery by the plaintiffs in the Three Cities case to be between $-0- and $18 million inclusive of interest and attorneys' fees. 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 CenterPoint Energy Entex (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 129 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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 Cost Recovery Suits. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, 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 the alleged overcharges, exemplary damages and penalties. The Company denies that CERC 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. The Company is involved in other proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. The Company's management currently believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. Environmental Matters Clean Air Standards. Based on current limitations of the Texas Commission on Environmental Quality regarding NOx emissions in the Houston area, the Company anticipates it will have invested at least $682 million for emission control equipment through 2005, including $551 million expended from January 1, 1999 through December 31, 2002, with possible additional expenditures after 2005. NOx control estimates for 2006 and 2007 have not been finalized. The Texas electric restructuring law provides for stranded cost recovery for expenditures incurred before May 1, 2003 to achieve the NOx reduction requirements. Incurred costs include costs for which contractual obligations have been made. The Texas Utility Commission has determined that the Company's emission control plan is the most effective control option and that up to $699 million is eligible for cost recovery, the exact amount to be determined in the 2004 true-up proceeding. In addition, the Company is required to provide $16.2 million in funding for certain NOx reduction projects associated with East Texas pipeline companies. These funds are also eligible for cost recovery. Hydrocarbon Contamination. On August 24, 2001, 37 plaintiffs filed suit against REGT, Reliant Energy Pipeline Services, Inc., RERC Corp., Reliant Energy Services, other Reliant Energy entities and third parties in the 1st Judicial District Court, Caddo Parish, Louisiana. The petition has now been supplemented seven times. As of November 21, 2002, there were 695 plaintiffs, a majority of whom are Louisiana residents. In addition to the Reliant Energy entities, the plaintiffs have sued the State of Louisiana through its Department of Environmental Quality, several individuals, some of whom are present employees of the State of Louisiana, the Bayou South Gas Gathering Company, L.L.C., Martin Timber Company, Inc., and several trusts. Additionally on April 4, 2002, two plaintiffs filed a separate suit with identical allegations against the same parties in the same court. More recently, on January 6, 2003, two other plaintiffs filed a third suit of 130 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) similar allegations against the Company, as well as other defendants, in Bossier Parish (26th Judicial District Court). 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, the Company 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 CERC's Minnesota service territory, two of which CERC believes were neither owned or 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 other sites. Based on current information, the Company has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Mercury Contamination. The Company'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 the Company at some sites in the past, and the Company 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 the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows. 131 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Other Environmental. From time to time the Company 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. In addition, the Company has been named as a defendant in litigation related to such sites and in recent years has been named, along with numerous others, as a defendant in several lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast. Most of these claimants have been workers who participated in construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by the Company. The Company anticipates that additional claims like those received may be asserted in the future and intends to continue vigorously contesting claims which it does not consider to have merit. Although their ultimate outcome cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, 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 the Company'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 the Company 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. Other Matters The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. (d) OPERATIONS AGREEMENT WITH CITY OF SAN ANTONIO Texas Genco has a joint operating agreement with the City Public Service Board of San Antonio (CPS) to share savings from the joint dispatching of each party's generating assets. Dispatching the two generating systems jointly results in savings of fuel and related expenses because there is a more efficient utilization of each party's lowest cost resources. The two parties equally share the savings resulting from joint dispatch. The agreement terminates in 2009. (e) NUCLEAR INSURANCE Texas Genco and the other owners of the South Texas Project maintain nuclear property and nuclear liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. The owners of the South Texas Project currently maintain $2.75 billion in property 132 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) damage insurance coverage, which is above the legally required minimum, but is less than the total amount of insurance currently available for such losses. Pursuant to the Price Anderson Act, the maximum liability to the public of owners of nuclear power plants was $9.3 billion as of December 31, 2002. Owners are required under the Price Anderson Act to insure their liability for nuclear incidents and protective evacuations. Texas Genco and the other owners of the South Texas Project currently maintain the required nuclear liability insurance and participate in the industry retrospective rating plan. There can be no assurance that all potential losses or liabilities will be insurable, or that the amount of insurance will be sufficient to cover them. Any substantial losses not covered by insurance would have a material effect on the Company's financial condition, results of operations and cash flows. (f) NUCLEAR DECOMMISSIONING Texas Genco contributed $14.8 million per year in 2000 and 2001 to trusts established to fund its share of the decommissioning costs for the South Texas Project. In 2002, Texas Genco contributed $2.9 million to these trusts. There are various investment restrictions imposed upon Texas Genco by the Texas Utility Commission and the NRC relating to Texas Genco's nuclear decommissioning trusts. Additionally, Texas Genco's board of directors and CenterPoint Energy's board of directors have each appointed two members to the Nuclear Decommissioning Trust Investment Committee which establishes the investment policy of the trusts and oversees the investment of the trusts' assets. The securities held by the trusts for decommissioning costs had an estimated fair value of $163 million as of December 31, 2002, of which approximately 49% were fixed-rate debt securities and the remaining 51% were equity securities. For a discussion of the accounting treatment for the securities held in the nuclear decommissioning trust, see Note 3(k). In July 1999, an outside consultant estimated Texas Genco's portion of decommissioning costs to be approximately $363 million. While the funding levels currently exceed minimum NRC requirements, no assurance can be given that the amounts held in trust will be adequate to cover the actual decommissioning costs of the South Texas Project. Such costs may vary because of changes in the assumed date of decommissioning and changes in regulatory requirements, technology and costs of labor, materials and equipment. Pursuant to the Texas electric restructuring law, costs associated with nuclear decommissioning that have not been recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be included in a charge to transmission and distribution customers. CenterPoint Energy is contractually obligated to indemnify Texas Genco from and against any obligations relating to the decommissioning not otherwise satisfied through collections by CenterPoint Houston. For information regarding the effect of the business separation plan on funding of the nuclear decommissioning trust fund, see Note 4(b). (14) 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 approximately 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 133 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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.

DECEMBER 31, 2001 ----------------- CARRYING FAIR AMOUNT VALUE -------- ------ (IN MILLIONS) Financial liabilities: Long-term debt (excluding capital leases)................. $5,545 $5,550 Trust preferred securities................................ 706 664

DECEMBER 31, 2002 ----------------- CARRYING FAIR AMOUNT VALUE -------- ------ (IN MILLIONS) Financial liabilities: Long-term debt (excluding capital leases)................. $6,135 $6,349 Trust preferred securities................................ 706 476

(15) EARNINGS PER SHARE The following table reconciles numerators and denominators of the Company's basic and diluted earnings per share (EPS) calculations:

FOR THE YEAR ENDED DECEMBER 31, --------------------------------------------------- 2000 2001 2002 --------------- --------------- --------------- (IN MILLIONS, EXCEPT PER SHARE AND SHARE AMOUNTS) Basic EPS calculation: Income from continuing operations before extraordinary item and cumulative effect of accounting change............................. $ 222 $ 446 $ 386 Income from discontinued operations, net of tax........................................... 225 475 82 Loss on disposal of discontinued operations...... -- -- (4,371) Extraordinary item, net of tax................... -- -- (17) Cumulative effect of accounting change, net of tax........................................... -- 59 -- ------------ ------------ ------------ Net income (loss) attributable to common shareholders.................................. $ 447 $ 980 $ (3,920) ============ ============ ============ Weighted average shares outstanding................ 284,652,000 289,776,000 297,997,000 Basic EPS: Income from continuing operations before extraordinary item and cumulative effect of accounting change............................. $ 0.78 $ 1.54 $ 1.30 Income from discontinued operations, net of tax........................................... 0.79 1.64 0.27 Loss on disposal of discontinued operations...... -- -- (14.67) Extraordinary item, net of tax................... -- -- (0.06) Cumulative effect of accounting change, net of tax........................................... -- 0.20 -- ------------ ------------ ------------ Net income (loss) attributable to common shareholders.................................. $ 1.57 $ 3.38 $ (13.16) ============ ============ ============ Diluted EPS calculation: Net income (loss) attributable to common shareholders.................................. $ 447 $ 980 $ (3,920) Plus: Income impact of assumed conversions: Interest on 6 1/4% convertible trust preferred securities.................................. -- -- -- ------------ ------------ ------------ Total earnings effect assuming dilution.......... $ 447 $ 980 $ (3,920) ============ ============ ============

134 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

FOR THE YEAR ENDED DECEMBER 31, --------------------------------------------------- 2000 2001 2002 --------------- --------------- --------------- (IN MILLIONS, EXCEPT PER SHARE AND SHARE AMOUNTS) Weighted average shares outstanding................ 284,652,000 289,776,000 297,997,000 Plus: Incremental shares from assumed conversions(1) Stock options................................. 1,652,000 1,650,000 846,000 Restricted stock.............................. 955,000 754,000 784,000 6 1/4% convertible trust preferred securities.................................. 14,000 13,000 17,000 ------------ ------------ ------------ Weighted average shares assuming dilution........ 287,273,000 292,193,000 299,644,000 ============ ============ ============ Diluted EPS: Income from continuing operations before extraordinary item and cumulative effect of accounting change............................. $ 0.77 $ 1.53 $ 1.29 Income from discontinued operations, net of tax........................................... 0.79 1.62 0.27 Loss on disposal of discontinued operations...... -- -- (14.58) Extraordinary item, net of tax................... -- -- (0.06) Cumulative effect of accounting change, net of tax........................................... -- 0.20 -- ------------ ------------ ------------ Net income (loss) attributable to common shareholders.................................. $ 1.56 $ 3.35 $ (13.08) ============ ============ ============

--------------- (1) Options to purchase 442,385, 2,074,437 and 9,709,272 shares were outstanding for the years ended December 31, 2000, 2001 and 2002, respectively, but were not included in the computation of diluted EPS because the options' exercise price was greater than the average market price of the common shares for the respective years. (16) UNAUDITED QUARTERLY INFORMATION The consolidated financial statements have been prepared to reflect the effect of the Reliant Resources Distribution as described above on the CenterPoint Energy financial statements. The consolidated financial statements present the Reliant Resources businesses (previously reported as the Wholesale Energy, European Energy and Retail Energy business segments and related corporate costs) as discontinued operations, in accordance with SFAS No. 144. Accordingly, the consolidated financial statements reflect these operations as discontinued operations for each of the three years in the period ended December 31, 2002. 135 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Summarized quarterly financial data is as follows:

YEAR ENDED DECEMBER 31, 2001 ----------------------------------------- FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER -------- -------- -------- -------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues................................................... $3,839 $2,509 $2,300 $2,008 Operating income........................................... 340 321 435 148 Income from continuing operations before cumulative effect of accounting change..................................... 122 122 183 19 Income from discontinued operations, net of tax............ 82 194 172 27 Cumulative effect of accounting change, net of tax......... 59 -- -- -- Net income attributable to common shareholders............. 263 316 355 46 Basic earnings per share:(1) Income from continuing operations before cumulative effect of accounting change........................... $ 0.43 $ 0.42 $ 0.63 $ 0.07 Income from discontinued operations, net of tax.......... 0.28 0.67 0.59 0.09 Cumulative effect of accounting change, net of tax....... 0.20 -- -- -- ------ ------ ------ ------ Net income attributable to common shareholders........... $ 0.91 $ 1.09 $ 1.22 $ 0.16 ====== ====== ====== ====== Diluted earnings per share:(1) Income from continuing operations before cumulative effect of accounting change........................... $ 0.42 $ 0.42 $ 0.63 $ 0.07 Loss from discontinued operations, net of tax............ 0.28 0.66 0.58 0.09 Cumulative effect of accounting change, net of tax....... 0.20 -- -- -- ------ ------ ------ ------ Net income attributable to common shareholders........... $ 0.90 $ 1.08 $ 1.21 $ 0.16 ====== ====== ====== ======

136 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

YEAR ENDED DECEMBER 31, 2002 ----------------------------------------- FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER -------- -------- -------- -------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues.................................................. $2,078 $1,804 $ 1,923 $2,117 Operating income.......................................... 350 289 431 259 Income (loss) from continuing operations before extraordinary item...................................... 145 88 161 (8) Income (loss) from discontinued operations, net of tax.... (114) 148 48 -- Loss on disposal of discontinued operations............... -- -- (4,333) (38) Extraordinary item, net of tax............................ -- -- -- (17) Net income (loss) attributable to common shareholders..... 31 236 (4,124) (63) Basic earnings (loss) per share:(1) Income (loss) from continuing operations before extraordinary item................................... $ 0.49 $ 0.29 $ 0.54 $(0.03) Income (loss) from discontinued operations, net of tax.................................................. (0.38) 0.50 0.16 -- Loss on disposal of discontinued operations............. -- -- (14.50) (0.12) Extraordinary item, net of tax.......................... -- -- -- (0.06) ------ ------ ------- ------ Net (loss) income attributable to common shareholders... $ 0.11 $ 0.79 $(13.80) $(0.21) ====== ====== ======= ====== Diluted (loss) earnings per share:(1) Income (loss) from continuing operations before extraordinary item................................... $ 0.49 $ 0.29 $ 0.54 $(0.03) Income (loss) from discontinued operations, net of tax.................................................. (0.38) 0.50 0.16 -- Loss on disposal of discontinued operations............. -- -- (14.47) (0.12) Extraordinary item, net of tax.......................... -- -- -- (0.06) ------ ------ ------- ------ Net income (loss) attributable to common shareholders... $ 0.11 $ 0.79 $(13.77) $(0.21) ====== ====== ======= ======

--------------- (1) Quarterly earnings per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings per common share. (17) REPORTABLE BUSINESS SEGMENTS The Company's determination of reportable business segments considers the strategic operating units under which the Company manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies except that some executive benefit costs have not been allocated to business segments. Effective with the deregulation of the Texas electric industry beginning January 1, 2002, the basis of business segment reporting has changed for the Company's electric operations. The Texas generation operations of CenterPoint Energy's former integrated electric utility, Reliant Energy HL&P, are now a separate reportable business segment, Electric Generation, whereas they previously had been part of the Electric Operations business segment. The remaining transmission and distribution function is now reported separately in the Electric Transmission & Distribution business segment In 2001, Latin America was a separate business segment, but beginning in 2002 is reported in the Other Operations business segment. Reportable business segments for all prior periods presented have been restated to conform to the 2002 presentation. Reportable business segments presented herein do not include Wholesale Energy, European Energy, Retail Energy and related corporate costs as these 137 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) business segments operated within Reliant Resources which is presented as discontinued operations within these consolidated financial statements. Note that certain estimates and allocations have been used to separate historical, (pre-January 1, 2002) Electric Generation business segment data from the Electric Transmission & Distribution segment data. Beginning in the first quarter of 2002, the Company began to evaluate business segment performance on an earnings (loss) before interest expense, distribution on trust preferred securities, income taxes, extraordinary item and cumulative effect of accounting change (EBIT) basis. Prior to 2002, the Company evaluated performance based upon operating income. EBIT, as defined, is shown because it is a measure we use to evaluate the performance of our business segments and the Company believes 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. The Company expects that some analysts and investors will want to review EBIT when evaluating the Company. EBIT is not defined under accounting principles generally accepted in the United States of America (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, the Company's 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. Long-lived assets include net property, plant and equipment, net goodwill and other intangibles and equity investments in unconsolidated subsidiaries. The Company accounts for intersegment sales as if the sales were to third parties, that is, at current market prices. The Company has identified the following reportable business segments: Electric Transmission & Distribution, Electric Generation, Natural Gas Distribution, Pipelines and Gathering and Other Operations. For a description of the financial reporting business segments, see Note 1. Financial data for business segments, products and services and geographic areas are as follows:

ELECTRIC OPERATIONS --------------------------- ELECTRIC NATURAL PIPELINES TRANSMISSION & ELECTRIC GAS AND OTHER DISCONTINUED DISTRIBUTION GENERATION DISTRIBUTION GATHERING OPERATIONS OPERATIONS -------------- ---------- ------------ --------- ---------- ------------ (IN MILLIONS) AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2000: Revenues from external customers... $ 2,160 $ 3,334 $4,503 $ 280 $ 97 $ -- Intersegment revenues.............. -- -- 1 104 -- -- Depreciation and amortization...... 356 151 145 56 18 -- EBIT............................... 953 331 122 137 (485) -- Total assets....................... 6,659 4,032 4,518 2,358 4,537 14,098 Equity investments in unconsolidated subsidiaries...... -- -- -- -- 13 -- Expenditures for long-lived assets........................... 391 252 195 61 23 -- AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2001: Revenues from external customers... 2,100 3,411 4,737 307 101 -- Intersegment revenues.............. -- -- 5 108 -- -- Depreciation and amortization...... 299 154 147 58 13 -- EBIT............................... 906 267 149 138 (137) -- Total assets....................... 7,689 4,323 3,732 2,361 1,296 12,299 Expenditures for long-lived assets........................... 527 409 209 54 28 --

RECONCILING ELIMINATIONS CONSOLIDATED ------------ ------------ (IN MILLIONS) AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2000: Revenues from external customers... $ -- $10,374 Intersegment revenues.............. (105) -- Depreciation and amortization...... -- 726 EBIT............................... (38) 1,020 Total assets....................... (977) 35,225 Equity investments in unconsolidated subsidiaries...... -- 13 Expenditures for long-lived assets........................... -- 922 AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2001: Revenues from external customers... -- 10,656 Intersegment revenues.............. (113) -- Depreciation and amortization...... -- 671 EBIT............................... (41) 1,282 Total assets....................... (434) 31,266 Expenditures for long-lived assets........................... -- 1,227

138 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

ELECTRIC OPERATIONS --------------------------- ELECTRIC NATURAL PIPELINES TRANSMISSION & ELECTRIC GAS AND OTHER DISCONTINUED DISTRIBUTION GENERATION DISTRIBUTION GATHERING OPERATIONS OPERATIONS -------------- ---------- ------------ --------- ---------- ------------ (IN MILLIONS) AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2002: Revenues from external customers... 2,222(1) 1,488(2) 3,927 253 32 -- Intersegment revenues.............. -- 5 33 121 -- -- Depreciation and amortization...... 271 157 126 41 21 -- EBIT............................... 1,118 (130) 210 158 5 -- Total assets....................... 9,098 4,416 4,051 2,481 1,408 -- Expenditures for long-lived assets........................... 261 280 196 70 47 --

RECONCILING ELIMINATIONS CONSOLIDATED ------------ ------------ (IN MILLIONS) AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2002: Revenues from external customers... -- 7,922 Intersegment revenues.............. (159) -- Depreciation and amortization...... -- 616 EBIT............................... (29) 1,332 Total assets....................... (1,820) 19,634 Expenditures for long-lived assets........................... -- 854

--------------- (1) Sales to Reliant Resources represented approximately $940 million of CenterPoint Houston's transmission and distribution revenues since deregulation began in 2002. (2) Sales to Reliant Resources represented approximately 66% of Texas Genco's total revenues in 2002. 139 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

YEAR ENDED DECEMBER 31, --------------------------- 2000 2001 2002 ------- ------- ------- (IN MILLIONS) RECONCILIATION OF OPERATING INCOME TO EBIT AND EBIT TO NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS: Operating income............................................ $ 1,387 $ 1,244 $ 1,329 ------- ------- ------- Loss from equity investments in unconsolidated subsidiaries.............................................. (29) -- -- Loss on AOL Time Warner investment.......................... (205) (70) (500) Gain on indexed debt securities............................. 102 58 480 Impairment on Latin America equity investments.............. (131) (4) -- Loss on disposal of Latin America equity investments........ (176) -- -- Other income, net........................................... 72 54 23 ------- ------- ------- EBIT...................................................... 1,020 1,282 1,332 Interest expense and other charges.......................... (564) (607) (738) Income tax expense.......................................... (234) (228) (208) ------- ------- ------- Income from continuing operations before income taxes, extraordinary item, cumulative effect of accounting change and preferred dividends......................... 222 447 386 Income from discontinued operations, net of tax............. 225 475 82 Loss on disposal of discontinued operations................. -- -- (4,371) Extraordinary item, net of tax.............................. -- -- (17) Cumulative effect of accounting change, net of tax.......... -- 59 -- Preferred dividends......................................... -- (1) -- ------- ------- ------- Net income (loss) attributable to common shareholders......................................... $ 447 $ 980 $(3,920) ======= ======= ======= REVENUES BY PRODUCTS AND SERVICES: Retail electricity sales.................................... $ 5,583 $ 5,598 $ -- Wholesale electricity sales................................. -- -- 1,503 Electric delivery sales..................................... -- -- 1,525 ECOM true-up................................................ -- -- 697 Retail gas sales............................................ 4,416 4,645 3,832 Gas transport............................................... 280 307 253 Energy products and services................................ 95 106 112 ------- ------- ------- Total.................................................. $10,374 $10,656 $ 7,922 ======= ======= ======= REVENUES AND LONG-LIVED ASSETS BY GEOGRAPHIC AREAS: Revenues: U.S. ..................................................... $10,285 $10,564 $ 7,906 Other..................................................... 89 92 16 ------- ------- ------- Total.................................................. $10,374 $10,656 $ 7,922 ======= ======= ======= Long-lived assets: U.S. ..................................................... $13,021 $13,002 $13,216 Other..................................................... 143 -- -- ------- ------- ------- Total.................................................. $13,164 $13,002 $13,216 ======= ======= =======

140 CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (18) 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. As part of its normal business operations, Texas Genco, LP, a wholly owned indirect subsidiary of Texas Genco, has also entered into power purchase and sale agreements to buy less expensive power than Texas Genco's marginal cost of generation or to sell power to another party who is willing to pay more than Texas Genco's marginal cost of generation. Texas Genco has guaranteed the payment obligations of Texas Genco, LP under certain of these agreements, typically for a one-year term. As of December 31, 2002, Texas Genco had delivered 7 such guarantees with an aggregate maximum potential exposure of $28.2 million and an aggregate carrying amount of $-0-. CenterPoint Energy has delivered guarantees in support of Texas Genco's obligations to ERCOT under qualified scheduling entity and transmission congestion rights agreements. These guarantees expire in October, 2003 and as of December 31, 2002, have an aggregate maximum potential exposure of $45 million and an aggregate carrying amount of $-0-. 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. CenterPoint Energy has entered standard indemnification agreements with various surety companies to support the issuance of surety bonds on behalf of CenterPoint Energy and its subsidiaries. These indemnification agreements vary in duration to coincide with the term of the bonds issued. As of December 31, 2002, these agreements covered surety bonds in the aggregate amount of $14.5 million. In addition, CenterPoint Energy has provided $8.9 million in cash deposits to secure its indemnity to one surety company. 141 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of CenterPoint Energy, Inc. and Subsidiaries: We have audited the accompanying consolidated balance sheets of CenterPoint Energy, Inc. and its subsidiaries (the Company) as of December 31, 2001 and 2002, and the related consolidated statements of income, shareholders' equity, comprehensive income and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedules listed in the Index at Item 15(a)(2). These financial statements and the financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the financial statement schedules based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company 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 schedules, 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 2 to the consolidated financial statements, the Company distributed its 83% ownership interest in Reliant Resources, Inc. on September 30, 2002. The loss on distribution and the results of operations for Reliant Resources, Inc. for periods prior to the distribution are included in discontinued operations of the accompanying consolidated financial statements. As discussed in Note 3(d) to the consolidated financial statements, on January 1, 2002, the Company 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 142 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, to the extent not set forth in "Executive Officers" in Item 1, is or will be set forth in the definitive proxy statement relating to CenterPoint Energy's 2003 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 10 are incorporated herein by reference pursuant to Instruction G to Form 10-K. ITEM 11. EXECUTIVE COMPENSATION The information called for by Item 11 is or will be set forth in the definitive proxy statement relating to CenterPoint Energy's 2003 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 11 are incorporated herein by reference pursuant to Instruction G to Form 10-K. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information called for by Item 12 is or will be set forth in the definitive proxy statement relating to CenterPoint Energy's 2003 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 12 are incorporated herein by reference pursuant to Instruction G to Form 10-K. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information called for by Item 13 is or will be set forth in the definitive proxy statement relating to CenterPoint Energy's 2003 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 13 are incorporated herein by reference pursuant to Instruction G to Form 10-K. 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. 143 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a)(1) Financial Statements. Statements of Consolidated Operations for the Three Years Ended December 31, 2002................................ 77 Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2002.................... 78 Consolidated Balance Sheets at December 31, 2002 and 2001................................................... 79 Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2002................................ 80 Statements of Consolidated Shareholders' Equity for the Three Years Ended December 31, 2002.................... 81 Notes to Consolidated Financial Statements................ 82 Independent Auditors' Report.............................. 142 (a)(2) Financial Statement Schedules for the Three Years Ended December 31, 2002. I -- Financial Statements of CenterPoint Energy, Inc. .... 146 II -- Reserves............................................ 152 The following schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements: III, IV and V. (a)(3) Exhibits. See Index of Exhibits on page 156, which index also includes the management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K. (g) Reports on Form 8-K. On October 1, 2002, we filed a Current Report on Form 8-K dated September 30, 2002, announcing that our board of directors had declared a distribution of all of the shares of Reliant Resources, Inc. common stock owned by us to our common shareholders on a pro rata basis. The distribution was completed on September 30, 2002 to our shareholders of record as of the close of business on September 20, 2002. On October 11, 2002, we filed a Current Report on Form 8-K dated October 11, 2002, to announce that we had negotiated new, one-year credit facilities totaling $4.7 billion to replace similar facilities that expired on October 10, 2002. On October 17, 2002, we filed a Current Report on Form 8-K dated October 17, 2002, relating to the announcement of third quarter 2002 results. On November 8, 2002, we filed a Current Report on Form 8-K dated November 8, 2002, to announce that we had negotiated a new $1.31 billion senior secured credit facility at CenterPoint Energy Houston Electric, LLC. On December 6, 2002, we filed a Current Report on Form 8-K dated December 5, 2002, to announce that our board of directors had declared a stock distribution of approximately 19% of the 80,000,000 outstanding shares of common stock of our wholly owned subsidiary, Texas Genco Holdings, Inc., to our shareholders to be made on January 6, 2003. On December 12, 2002, we filed a Current Report of Form 8-K dated December 11, 2002, to announce that the Securities and Exchange Commission had declared Texas Genco's Form 10 registration statement relating to its common stock effective under the Securities Exchange Act of 1934. Payment of the distribution had been conditional upon the Securities and Exchange Commission declaring the Form 10 registration statement effective. 144 On December 23, 2002, we filed a Current Report on Form 8-K dated December 20, 2002, to announce that our board of directors had established the distribution ratio for the previously declared pro rata distribution of approximately 19% of the 80,000,000 outstanding shares of Texas Genco common stock to our shareholders to be made on January 6, 2003. On January 7, 2003, we filed a Current Report on Form 8-K dated January 6, 2003, announcing that we had distributed approximately 19% of the 80 million outstanding shares of Texas Genco common stock to our shareholders of record as of the close of business on December 20, 2002. On February 13, 2003, we filed a Current Report on Form 8-K dated February 13, 2003, relating to the announcement of fourth quarter 2002 and year-end 2002 results. On March 3, 2003, we filed a Current Report on Form 8-K dated February 28, 2003, announcing that we had amended and extended our $3.85 billion credit facility from October 2003 to June 30, 2005. 145 CENTERPOINT ENERGY, INC. SCHEDULE I -- FINANCIAL STATEMENTS OF CENTERPOINT ENERGY, INC. STATEMENT OF OPERATIONS

FOR THE PERIOD SEPTEMBER 1, 2002 THROUGH DECEMBER 31, 2002 ------------------ (IN THOUSANDS) Equity Losses of Subsidiaries............................... $ (4,907) Interest Income from Subsidiaries........................... 29,878 Loss on Disposal of Subsidiary.............................. (4,371,464) Loss on Indexed Debt Securities............................. (7,964) Operation and Maintenance Expenses.......................... (5,793) Depreciation and Amortization............................... (5,978) Taxes Other than Income..................................... (6,024) Interest Expense to Subsidiaries............................ (31,198) Interest Expense............................................ (186,923) Income Tax Benefit.......................................... 64,916 ----------- Loss Before Extraordinary Item.............................. (4,525,457) Extraordinary Item, net of tax of $595...................... (1,104) ----------- Net Loss.................................................... $(4,526,561) ===========

See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8 146 CENTERPOINT ENERGY, INC. SCHEDULE I -- FINANCIAL STATEMENTS OF CENTERPOINT ENERGY, INC. BALANCE SHEETS

DECEMBER 31, DECEMBER 31, 2001 2002 ------------ ------------ (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 3 $ 222,511 Notes receivable -- affiliated companies.................. -- 492,246 Accounts receivable -- affiliated companies............... -- 130,712 Other assets.............................................. -- 10,197 ----- ----------- Total current assets.................................. 3 855,666 ----- ----------- PROPERTY, PLANT AND EQUIPMENT, NET.......................... -- 114,240 ----- ----------- OTHER ASSETS: Investment in wholly-owned subsidiaries................... -- 8,090,581 Notes receivable -- affiliated companies.................. -- 984,063 Accumulated deferred tax asset............................ -- 319,675 Other assets.............................................. -- 185,719 ----- ----------- Total other assets.................................... -- 9,580,038 ----- ----------- TOTAL ASSETS........................................ $ 3 $10,549,944 ===== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Short-term borrowings..................................... $ -- $ -- Notes payable -- affiliated companies..................... -- 37,292 Current portion of long-term debt......................... -- 272,422 Indexed debt securities derivative........................ -- 224,881 Accounts payable: Affiliated companies.................................... -- 50,948 Other................................................... -- 8,869 Taxes accrued............................................. -- 609,512 Interest accrued.......................................... -- 89,206 Other..................................................... -- 73,334 ----- ----------- Total current liabilities............................. -- 1,366,464 ----- ----------- OTHER LIABILITIES: Benefit obligations....................................... -- 622,284 Notes payable -- affiliated companies..................... -- 1,679,706 Other..................................................... -- 365,646 ----- ----------- Total non-current liabilities......................... -- 2,667,636 ----- ----------- LONG-TERM DEBT.............................................. -- 5,104,474 ----- ----------- SHAREHOLDERS' EQUITY: Common stock.............................................. 3 3,050 Additional paid-in capital................................ -- 3,046,043 Retained deficit.......................................... -- (1,062,083) Unearned ESOP stock....................................... -- (78,049) Accumulated other comprehensive loss...................... -- (497,591) ----- ----------- Total shareholders' equity............................ 3 1,411,370 ----- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY.......... $ 3 $10,549,944 ===== ===========

See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8 147 CENTERPOINT ENERGY, INC. SCHEDULE I -- FINANCIAL STATEMENTS OF CENTERPOINT ENERGY, INC. STATEMENT OF CASH FLOWS

FOR THE PERIOD SEPTEMBER 1, 2002 THROUGH DECEMBER 31, 2002 ----------------- (IN THOUSANDS) OPERATING ACTIVITIES: Net loss.................................................. $(4,526,561) Add: Loss on disposal of subsidiary....................... 4,371,464 ----------- Loss less extraordinary item.............................. (155,097) Non-cash items included in net loss: Equity losses of subsidiaries........................ 4,907 Deferred income tax benefit.......................... (52,117) Depreciation and amortization........................ 5,978 Loss on indexed debt securities...................... 7,964 Extraordinary item................................... 1,104 Changes in working capital: Accounts receivable to affiliates, net............ 39,540 Accounts payable.................................. (1,302) Other current assets.............................. (6,571) Other current liabilities......................... (101,273) Common stock dividends received from subsidiaries...... 57,645 Other.................................................. (68,934) ----------- Net cash used in operating activities....................... (268,156) ----------- INVESTING ACTIVITIES: Investment in subsidiaries............................. (181,654) Capital expenditures, net.............................. (4,274) ----------- Net cash used in investing activities....................... (185,928) ----------- FINANCING ACTIVITIES: Changes in short-term borrowings.......................... (21,000) Payments on long-term debt................................ (168,558) Common stock dividends paid............................... (48,672) Notes receivable to affiliated companies.................. 914,825 ----------- Net cash provided by financing activities................... 676,595 ----------- NET INCREASE IN CASH AND CASH EQUIVALENTS................... 222,511 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............ -- ----------- CASH AND CASH EQUIVALENTS AT END OF PERIOD.................. $ 222,511 ===========

See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8 148 CENTERPOINT ENERGY, INC. SCHEDULE I -- NOTES TO CONDENSED FINANCIAL STATEMENTS (1) The condensed parent company financial statements and notes should be read in conjunction with the consolidated financial statements and notes of CenterPoint Energy, Inc. (CenterPoint Energy) appearing in the Annual Report on Form 10-K. CenterPoint Energy, Inc. is a public utility holding company that became the parent of Reliant Energy, Incorporated (Reliant Energy) and its subsidiaries on August 31, 2002 as part of a corporate restructuring of Reliant Energy (the Restructuring). We are a registered public utility holding company under the 1935 Act. Prior to the Restructuring, Reliant Energy was a public utility holding company that was exempt from registration under the 1935 Act. After the Restructuring, an exemption was no longer available for the corporate structure that the Texas Utility Commission required us to adopt under the Texas electric restructuring law. CenterPoint Energy did not conduct any activities other than those incident to its formation until September 1, 2002. Accordingly, statements of operations and cash flows would not provide meaningful information and have been omitted for periods prior to September 1, 2002. (2) As a registered public utility holding company, CenterPoint Energy and its subsidiaries 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, CenterPoint Energy is 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 Reliant Resources Distribution, and granted it 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, primarily related to its financing activities subsequent to June 30, 2003. In the July 2002 order, the SEC limited the aggregate amount of external borrowings of Texas Genco, CenterPoint Houston and CERC to $500 million, $3.55 billion and $2.7 billion, respectively. In addition, the order restricts CenterPoint Energy's ability to pay dividends out of capital accounts to the extent current or retained earnings are insufficient for those dividends. Under these restrictions, CenterPoint Energy, Texas Genco, CenterPoint Houston and CERC are permitted to pay dividends in excess of the respective current or retained earnings in an amount up to $200 million, $100 million, $200 million and $100 million, respectively. (3) Effective with the Restructuring, all outstanding shares of Reliant Energy no par value common stock were exchanged for shares of CenterPoint Energy common stock with a par value of $0.01 per share. The capital accounts of CenterPoint Energy have been restated as of December 31, 2000 and 2001 to give effect to the change in par value per share. CenterPoint Energy has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value preferred stock. (4) On September 30, 2002, CenterPoint Energy distributed to its shareholders 240 million shares of Reliant Resources common stock, which represented CenterPoint Energy's approximately 83% ownership interest in Reliant Resources, by means of a tax-free spin-off in the form of a dividend. Holders of CenterPoint Energy common stock on the record date received 0.788603 shares of Reliant Resources common stock for each share of CenterPoint Energy stock that they owned on the record date. The total value of the Reliant Resources Distribution, after the impairment charge discussed below, was $847 million. As a result of the spin-off of Reliant Resources, CenterPoint Energy recorded a non-cash loss on disposal of discontinued operations of $4.4 billion in 2002. This loss represents the excess of the carrying value of CenterPoint Energy's net investment in Reliant Resources over the market value of Reliant Resources' common stock. CenterPoint Energy's financial statements reflect the reclassifications necessary to present Reliant Resources as discontinued operations for all periods shown. Through the date of the spin-off, Reliant 149 CENTERPOINT ENERGY, INC. SCHEDULE I -- NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED) Resources' assets and liabilities are shown in CenterPoint Energy's Consolidated Balance Sheets as current and non-current assets and liabilities of discontinued operations. (5) CenterPoint Energy distributed approximately 19% of the 80 million outstanding shares of common stock of Texas Genco to its shareholders on January 6, 2003. As a result of the distribution of Texas Genco common stock, CenterPoint Energy recorded a pre-tax impairment charge of $396 million, which will be reflected as a regulatory asset in the Consolidated Balance Sheet in the first quarter of 2003. This impairment charge represents the excess of the carrying value of CenterPoint Energy's net investment in Texas Genco over the market value of Texas Genco's common stock. Additionally, in connection with the distribution, CenterPoint Energy will record minority interest ownership in Texas Genco of $146 million in its Consolidated Balance Sheet in the first quarter of 2003. (6) On February 28, 2003, the Company reached agreement with a syndicate of banks on a second amendment to its $3.85 billion bank facility (the "Second Amendment"). Under the Second Amendment, the maturity date of the bank facility was extended from October 2003 to June 30, 2005, and the $1.2 billion in mandatory prepayments that would have been required this year (including $600 million due on February 28, 2003) were eliminated. The facility consists of a $2.35 billion term loan and a $1.5 billion revolver. Borrowings bear interest based on LIBOR rates under a pricing grid tied to the Company's credit rating. At our current credit ratings, the pricing for loans remains the same. The drawn cost for the facility at our current ratings is LIBOR plus 450 basis points. The Company has agreed to pay the banks an extension fee of 75 basis points on the amounts outstanding under the bank facility on October 9, 2003. The Company also paid $41 million in fees that were due on February 28, 2003, along with $20 million in fees that had been due on June 30, 2003. In addition, the interest rates will be increased by 25 basis points beginning May 28, 2003 if the Company does not grant the banks a security interest in our 81% stock ownership of Texas Genco. Granting the security interest in the stock of Texas Genco requires approval from the SEC under the 1935 Act, which is currently being sought. That security interest would be released when the Company sells Texas Genco, which is expected to occur in 2004. Proceeds from the sale will be used to reduce the bank facility. Also under the Second Amendment, on or before May 28, 2003, the Company expects to grant to the banks warrants to purchase up to 10%, on a fully diluted basis, of its common stock at a price equal to the greater of $6.56 per share or 110% of the closing price on the New York Stock Exchange on the date the warrants are issued. The warrants would not be exercisable for a year after issuance but would remain outstanding for four years; provided, that if the Company reduces the bank facility during 2003 by specified amounts, some or all of the warrants (or the related rights to equivalent cash compensation) will be extinguished. To the extent that the Company reduces the bank facility by up to $400 million on or before May 28, 2003, up to half of the warrants will be extinguished on a basis proportionate to the reduction in the credit facility. To the extent such warrants are not extinguished on or before May 28, 2003, they will vest and become exercisable in accordance with their terms. Whether or not the Company is able to extinguish warrants on or before May 28, 2003, the remaining 50% of the warrants will be extinguished, again on a proportionate basis, if the Company reduces the bank facility by up to $400 million by the end of 2003. The Company plans to eliminate the warrants entirely before they vest by accessing the capital markets to fund the total payments of $800 million during 2003; however, because of current financial market conditions and uncertainties regarding such conditions over the balance of the year, there can be no assurance that the Company will be able to extinguish the warrants or to do so on favorable terms. The warrants and the underlying common stock would be registered with the SEC and could be exercised either through the payment of the purchase price or on a "cashless" basis under which the Company would issue a number of shares equal to the difference between the then-current market price and the warrant exercise price. Issuance of the warrants is also subject to obtaining SEC approval under the 1935 Act, which is currently being sought. If that approval is not obtained on or before May 28, 2003, the Company will provide 150 CENTERPOINT ENERGY, INC. SCHEDULE I -- NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED) the banks equivalent cash compensation over the term that its warrants would have been exercisable to the extent they are not otherwise extinguished. In the Second Amendment, the Company also agreed that its quarterly common stock dividend will not exceed $0.10 per share. If the Company has not reduced the bank facility by a total of at least $400 million by the end of 2003, of which at least $200 million has come from the issuance of capital stock or securities linked to capital stock (such as convertible debt), the maximum dividend payable during 2004 and for the balance of the term of the facility is subject to an additional test. Under that test the maximum permitted quarterly dividend will be the lesser of (i) $0.10 per share or (ii) 12.5% of the Company's net income per share for the 12 months ended on the last day of the previous quarter. The Second Amendment provides that proceeds from capital stock or indebtedness issued or incurred by the Company must be applied (subject to a $200 million basket for CERC and its subsidiaries and another $250 million basket for borrowings by the Company and its other subsidiaries and other limited exceptions) to repay bank loans and reduce the bank facility. Similarly, cash proceeds from the sale of assets of more than $30 million or, if less, a group of sales aggregating more than $100 million, must be applied to repay bank loans and reduce the bank facility, except that proceeds of up to $120 million can be reinvested in the Company's businesses. 151 CENTERPOINT ENERGY, INC. SCHEDULE II -- RESERVES FOR THE THREE YEARS ENDED DECEMBER 31, 2002 (IN THOUSANDS)

COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E --------------------------------------------------- ---------- --------- ----------- ---------- ADDITIONS BALANCE AT --------- DEDUCTIONS BALANCE AT BEGINNING CHARGED FROM END OF DESCRIPTION OF PERIOD TO INCOME RESERVES(1) PERIOD ----------- ---------- --------- ----------- ---------- Year Ended December 31, 2002: Accumulated provisions: Uncollectible accounts receivable............. $46,047 $25,883 $47,636 $24,294 Reserves for inventory........................ 123 72 103 92 Reserves for severance........................ 1,964 16,157 1,887 16,234 Deferred tax asset valuation allowance........ 15,439 67,490 -- 82,929 Year Ended December 31, 2001: Accumulated provisions: Uncollectible accounts receivable............. $37,521 $58,745 $50,219 $46,047 Reserves for inventory........................ 399 72 348 123 Reserves for severance........................ 11,347 4,759 14,142 1,964 Deferred tax asset valuation allowance........ 47,677 (32,238) -- 15,439 Year Ended December 31, 2000: Accumulated provisions: Uncollectible accounts receivable............. $19,217 $37,910 $19,606 $37,521 Reserves for inventory........................ 90 372 63 399 Reserves for severance........................ 11,780 4,152 4,585 11,347 Deferred tax asset valuation allowance........ 16,111 31,566 -- 47,677

--------------- (1) Deductions from reserves represent losses or expenses for which the respective reserves were created. In the case of the uncollectible accounts reserve, such deductions are net of recoveries of amounts previously written off. 152 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 10th day of March, 2003. CENTERPOINT ENERGY, INC. (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 10, 2003.

SIGNATURE TITLE --------- ----- /s/ DAVID M. MCCLANAHAN President, Chief Executive Officer and Director ------------------------------------------ (Principal Executive Officer and Director) (David M. McClanahan) /s/ GARY L. WHITLOCK Executive Vice President and Chief Financial Officer ------------------------------------------ (Principal Financial Officer) (Gary L. Whitlock) /s/ JAMES S. BRIAN Senior Vice President and Chief Accounting Officer ------------------------------------------ (Principal Accounting Officer) (James S. Brian) /s/ MILTON CARROLL Chairman of the Board of Directors ------------------------------------------ (Milton Carroll) /s/ JOHN T. CATER Director ------------------------------------------ (John T. Cater) /s/ O. HOLCOMBE CROSSWELL Director ------------------------------------------ (O. Holcombe Crosswell) /s/ ROBERT J. CRUIKSHANK Director ------------------------------------------ (Robert J. Cruikshank) /s/ T. MILTON HONEA Director ------------------------------------------ (T. Milton Honea) /s/ THOMAS F. MADISON Director ------------------------------------------ (Thomas F. Madison) /s/ MICHAEL E. SHANNON Director ------------------------------------------ (Michael E. Shannon)

153 CERTIFICATIONS I, David M. McClanahan, certify that: 1. I have reviewed this annual report on Form 10-K of CenterPoint Energy, Inc.; 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 quarterly 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 10, 2003 By: /s/ DAVID M. MCCLANAHAN ----------------------------------------------------------- David M. McClanahan President and Chief Executive Officer 154 CERTIFICATIONS I, Gary L. Whitlock, certify that: 1. I have reviewed this annual report on Form 10-K of CenterPoint Energy, Inc.; 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 10, 2003 By: /s/ GARY L. WHITLOCK ----------------------------------------------------------- Gary L. Whitlock Executive Vice President and Chief Financial Officer 155 CENTERPOINT ENERGY, INC. 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. Exhibits designated by an asterisk (*) are management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- 2 -- Agreement and Plan of Merger, CenterPoint Energy's Form 10-K 1-31447 2 dated as of October 19, 2001, by for the year ended December 31, and among Reliant Energy, 2001 Incorporated ("Reliant Energy"), CenterPoint Energy, Inc. ("CenterPoint Energy") and Reliant Energy MergerCo, Inc. 3(a)(1) -- Amended and Restated Articles of CenterPoint Energy's Registration 3-69502 3.1 Incorporation of CenterPoint Statement on Form S-4 Energy 3(a)(2) -- Articles of Amendment to Amended CenterPoint Energy's Form 10-K 1-31447 3.1.1 and Restated Articles of for the year ended December 31, Incorporation of CenterPoint 2001 Energy 3(b) -- Amended and Restated Bylaws of CenterPoint Energy's Form 10-K 1-31447 3.2 CenterPoint Energy for the year ended December 31, 2001 3(c) -- Statement of Resolution CenterPoint Energy's Form 10-K 1-31447 3.3 Establishing Series of Shares for the year ended December 31, designated Series A Preferred 2001 Stock of CenterPoint Energy 4(a) -- Form of CenterPoint Energy Stock CenterPoint Energy's Registration 3-69502 4.1 Certificate Statement on Form S-4 4(b) -- Rights Agreement dated January 1, CenterPoint Energy's Form 10-K 1-31447 4.2 2002, between CenterPoint Energy for the year ended December 31, and JP Morgan Chase Bank, as 2001 Rights Agent 4(c) -- Contribution and Registration CenterPoint Energy's Form 10-K 1-31447 4.3 Agreement dated December 18, 2001 for the year ended December 31, among Reliant Energy, CenterPoint 2001 Energy and the Northern Trust Company, trustee under the Reliant Energy, Incorporated Master Retirement Trust 4(d)(1) -- Mortgage and Deed of Trust, dated HL&P's Form S-7 filed on August 2-59748 2(b) November 1, 1944 between Houston 25, 1977 Lighting and Power Company ("HL&P") and Chase Bank of Texas, National Association (formerly, South Texas Commercial National Bank of Houston), as Trustee, as amended and supplemented by 20 Supplemental Indentures thereto 4(d)(2) -- Twenty-First through Fiftieth HL&P's Form 10-K for the year 1-3187 4(a)(2) Supplemental Indentures to ended December 31, 1989 Exhibit 4(a)(1) 4(d)(3) -- Fifty-First Supplemental HL&P's Form 10-Q for the quarter 1-3187 4(a) Indenture to Exhibit 4(a)(1) ended June 30, 1991 dated as of March 25, 1991 4(d)(4) -- Fifty-Second through Fifty-Fifth HL&P's Form 10-Q for the quarter 1-3187 4 Supplemental Indentures to ended March 31, 1992 Exhibit 4(a)(1) each dated as of March 1, 1992 4(d)(5) -- Fifty-Sixth and Fifty-Seventh HL&P's Form 10-Q for the quarter 1-3187 4 Supplemental Indentures to ended September 30, 1992 Exhibit 4(a)(1) each dated as of October 1, 1992

156

SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- 4(d)(6) -- Fifty-Eighth and Fifty-Ninth HL&P's Form 10-Q for the quarter 1-3187 4 Supplemental Indentures to ended March 31, 1993 Exhibit 4(a)(1) each dated as of March 1, 1993 4(d)(7) -- Sixtieth Supplemental Indenture HL&P's Form 10-Q for the quarter 1-3187 4 to Exhibit 4(a)(1) dated as of ended June 30, 1993 July 1, 1993 4(d)(8) -- Sixty-First through Sixty-Third HL&P's Form 10-K for the year 1-3187 4(a)(8) Supplemental Indentures to ended December 31, 1993 Exhibit 4(a)(1) each dated as of December 1, 1993 4(d)(9) -- Sixty-Fourth and Sixty-Fifth HL&P's Form 10-K for the year 1-3187 4(a)(9) Supplemental Indentures to ended December 31, 1995 Exhibit 4(a)(1) each dated as of July 1, 1995 4(e)(1) -- General Mortgage Indenture, dated CenterPoint Houston's Form 10-Q 1-3187 4(j)(1) as of October 10, 2002, between for the quarter ended September CenterPoint Energy Houston 30, 2002 Electric, LLC and JPMorgan Chase Bank, as Trustee 4(e)(2) -- First Supplemental Indenture to CenterPoint Houston's Form 10-Q 1-3187 4(j)(2) Exhibit 4(e)(1), dated as of for the quarter ended September October 10, 2002 30, 2002 4(e)(3) -- Second Supplemental Indenture to CenterPoint Houston's Form 10-Q 1-3187 4(j)(3) Exhibit 4(e)(1), dated as of for the quarter ended September October 10, 2002 30, 2002 4(e)(4) -- Third Supplemental Indenture to CenterPoint Houston's Form 10-Q 1-3187 4(j)(4) Exhibit 4(e)(1), dated as of for the quarter ended September October 10, 2002 30, 2002 4(e)(5) -- Fourth Supplemental Indenture to CenterPoint Houston's Form 10-Q 1-3187 4(j)(5) Exhibit 4(e)(1), dated as of for the quarter ended September October 10, 2002 30, 2002 4(e)(6) -- Fifth Supplemental Indenture to CenterPoint Houston's Form 10-Q 1-3187 4(j)(6) Exhibit 4(e)(1), dated as of for the quarter ended September October 10, 2002 30, 2002 4(e)(7) -- Sixth Supplemental Indenture to CenterPoint Houston's Form 10-Q 1-3187 4(j)(7) Exhibit 4(e)(1), dated as of for the quarter ended September October 10, 2002 30, 2002 4(e)(8) -- Seventh Supplemental Indenture to CenterPoint Houston's Form 10-Q 1-3187 4(j)(8) Exhibit 4(e)(1), dated as of for the quarter ended September October 10, 2002 30, 2002 4(e)(9) -- Eighth Supplemental Indenture to CenterPoint Houston's Form 10-Q 1-3187 4(j)(9) Exhibit 4(e)(1), dated as of for the quarter ended September October 10, 2002 30, 2002 +4(e)(10) -- Ninth Supplemental Indenture to Exhibit 4(e)(1), dated as of November 12, 2002 4(f)(1) -- $3,850,000 Amended and Restated CenterPoint Energy's Form 10-Q 1-31447 10(a) Credit Agreement, dated as of for the quarter ended September October 31, 2002, among 30, 2002 CenterPoint Energy and the banks named therein +4(f)(2) -- First Amendment to Exhibit 4(f)(1) effective December 5, 2002 +4(f)(3) -- Second Amendment to Exhibit 4(f)(1) effective February 28, 2003 +4(f)(4) -- Form of warrant agreement related to Exhibit 4(f)(3) +4(f)(5) -- Form of warrant registration rights agreement related to Exhibit 4(f)(3) +4(f)(6) -- Form of pledge agreement related to Exhibit 4(f)(3) +4(g)(1) -- $1,310,000,000 Credit Agreement, dated as of November 12, 2002, among CenterPoint Houston and the banks named therein

157

SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- +4(g)(2) -- Pledge Agreement, dated as of November 12, 2002 executed in connection with Exhibit 4(g)(1)

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy has not filed as exhibits to this Form 10-K certain long-term debt instruments, including indentures, under which the total amount of securities authorized do not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any such instrument to the SEC upon request.

EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- *10(a)(1) -- Executive Benefit Plan of Houston HI's Form 10-Q for the quarter 1-7629 10(a)(1), Industries Incorporated ("HI") ended March 31, 1987 10(a)(2), and and First and Second Amendments 10(a)(3) thereto effective as of June 1, 1982, July 1, 1984, and May 7, 1986, respectively *10(a)(2) -- Third Amendment dated September Reliant Energy's Form 10-K for 1-3187 10(a)(2) 17, 1999 to Exhibit 10(a)(1) the year ended December 31, 2000 *10(b)(1) -- Executive Incentive Compensation HI's Form 10-K for the year ended 1-7629 10(b) Plan of HI effective as of December 31, 1991 January 1, 1982 *10(b)(2) -- First Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(a) 10(b)(1) effective as of March ended March 31, 1992 30, 1992 *10(b)(3) -- Second Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(b) 10(b)(1) effective as of November December 31, 1992 4, 1992 *10(b)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(b)(4) 10(b)(1) effective as of December 31, 1994 September 7, 1994 *10(b)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(b)(5) 10(b)(1) effective as of August December 31, 1997 6, 1997 *10(c)(1) -- Executive Incentive Compensation HI's Form 10-Q for the quarter 1-7629 10(b)(1) Plan of HI effective as of ended March 31, 1987 January 1, 1985 *10(c)(2) -- First Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(b)(3) 10(c)(1) effective as of January December 31, 1988 1, 1985 *10(c)(3) -- Second Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(c)(3) 10(c)(1) effective as of January December 31, 1991 1, 1985 *10(c)(4) -- Third Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(b) 10(c)(1) effective as of March ended March 31, 1992 30, 1992 *10(c)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(c)(5) 10(c)(1) effective as of November December 31, 1992 4, 1992 *10(c)(6) -- Fifth Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(c)(6) 10(c)(1) effective as of December 31, 1994 September 7, 1994 *10(c)(7) -- Sixth Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(c)(7) 10(c)(1) effective as of August December 31, 1997 6, 1997 *10(d) -- Executive Incentive Compensation HI's Form 10-Q for the quarter 1-7629 10(b)(2) Plan of HL&P effective as of ended March 31, 1987 January 1, 1985 *10(e)(1) -- Executive Incentive Compensation HI's Form 10-Q for the quarter 1-7629 10(b) Plan of HI as amended and ended June 30, 1989 restated on January 1, 1989

158

EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- *10(e)(2) -- First Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(e)(2) 10(e)(1) effective as of January December 31, 1991 1, 1989 *10(e)(3) -- Second Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(c) 10(e)(1) effective as of March ended March 31, 1992 30, 1992 *10(e)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(c)(4) 10(e)(1) effective as of November December 31, 1992 4, 1992 *10(e)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(e)(5) 10(e)(1) effective as of December 31, 1994 September 7, 1994 *10(f)(1) -- Executive Incentive Compensation HI's Form 10-K for the year ended 1-7629 10(b) Plan of HI as amended and December 31, 1990 restated on January 1, 1991 *10(f)(2) -- First Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(f)(2) 10(f)(1) effective as of January December 31, 1991 1, 1991 *10(f)(3) -- Second Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(d) 10(f)(1) effective as of March ended March 31, 1992 30, 1992 *10(f)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(f)(4) 10(f)(1) effective as of November December 31, 1992 4, 1992 *10(f)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(f)(5) 10(f)(1) effective as of January December 31, 1992 1, 1993 *10(f)(6) -- Fifth Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(f)(6) 10(f)(1) effective in part, December 31, 1994 January 1, 1995, and in part, September 7, 1994 *10(f)(7) -- Sixth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(a) 10(f)(1) effective as of August ended June 30, 1995 1, 1995 *10(f)(8) -- Seventh Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(a) 10(f)(1) effective as of January ended June 30, 1996 1, 1996 *10(f)(9) -- Eighth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(a) 10(f)(1) effective as of January ended June 30, 1997 1, 1997 *10(f)(10) -- Ninth Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(f)(10) 10(f)(1) effective in part, December 31, 1997 January 1, 1997, and in part, January 1, 1998 *10(g) -- Benefit Restoration Plan of HI HI's Form 10-Q for the quarter 1-7629 10(c) effective as of June 1, 1985 ended March 31, 1987 *10(h) -- Benefit Restoration Plan of HI as HI's Form 10-K for the year ended 1-7629 10(g)(2) amended and restated effective as December 31, 1991 of January 1, 1988 *10(i)(1) -- Benefit Restoration Plan of HI, HI's Form 10-K for the year ended 1-7629 10(g)(3) as amended and restated effective December 31, 1991 as of July 1, 1991 *10(i)(2) -- First Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(i)(2) 10(i)(1) effective in part, December 31, 1997 August 6, 1997, in part, September 3, 1997, and in part, October 1, 1997 *10(j)(1) -- Deferred Compensation Plan of HI HI's Form 10-Q for the quarter 1-7629 10(d) effective as of September 1, 1985 ended March 31, 1987 *10(j)(2) -- First Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(d)(2) 10(j)(1) effective as of December 31, 1990 September 1, 1985 *10(j)(3) -- Second Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(e) 10(j)(1) effective as of March ended March 31, 1992 30, 1992 *10(j)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(h)(4) 10(j)(1) effective as of June 2, December 31, 1993 1993

159

EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- *10(j)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(h)(5) 10(j)(1) effective as of December 31, 1994 September 7, 1994 *10(j)(6) -- Fifth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(d) 10(j)(1) effective as of August ended June 30, 1995 1, 1995 *10(j)(7) -- Sixth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(b) 10(j)(1) effective as of December ended June 30, 1995 1, 1995 *10(j)(8) -- Seventh Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(b) 10(j)(1) effective as of January ended June 30, 1997 1, 1997 *10(j)(9) -- Eighth Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(j)(9) 10(j)(1) effective as of October December 31, 1997 1, 1997 *10(j)(10) -- Ninth Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(j)(10) 10(j)(1) effective as of December 31, 1997 September 3, 1997 *+10(j)(11) -- Tenth Amendment to Exhibit 10(j)(1) effective as of January 1, 2001 *+10(j)(12) -- Eleventh Amendment to Exhibit 10(j)(1) effective as of August 31, 2002 *10(k)(1) -- Deferred Compensation Plan of HI HI's Form 10-Q for the quarter 1-7629 10(a) effective as of January 1, 1989 ended June 30, 1989 *10(k)(2) -- First Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(e)(3) 10(k)(1) effective as of January December 31, 1989 1, 1989 *10(k)(3) -- Second Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(f) 10(k)(1) effective as of March ended March 31, 1992 30, 1992 *10(k)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(i)(4) 10(k)(1) effective as of June 2, December 31, 1993 1993 *10(k)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(i)(5) 10(k)(1) effective as of December 31, 1994 September 7, 1994 *10(k)(6) -- Fifth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(c) 10(k)(1) effective as of August ended June 30, 1995 1, 1995 *10(k)(7) -- Sixth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(c) 10(k)(1) effective December 1, ended June 30, 1995 1995 *10(k)(8) -- Seventh Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(c) 10(k)(1) effective as of January ended June 30, 1997 1, 1997 *10(k)(9) -- Eighth Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(k)(9) 10(k)(1) effective in part December 31, 1997 October 1, 1997 and in part January 1, 1998 *10(k)(10) -- Ninth Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(k)(10) 10(k)(1) effective as of December 31, 1997 September 3, 1997 *+10(k)(11) -- Tenth Amendment to Exhibit 10(k)(1) effective as of January 1, 2001 *+10(k)(12) -- Eleventh Amendment to Exhibit 10(k)(1) effective as of August 31, 2002 *10(l)(1) -- Deferred Compensation Plan of HI HI's Form 10-K for the year ended 1-7629 10(d)(3) effective as of January 1, 1991 December 31, 1990 *10(l)(2) -- First Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(j)(2) 10(l)(1) effective as of January December 31, 1991 1, 1991 *10(l)(3) -- Second Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(g) 10(l)(1) effective as of March ended March 31, 1992 30, 1992

160

EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- *10(l)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(j)(4) 10(l)(1) effective as of June 2, December 31, 1993 1993 *10(l)(5) -- Fourth Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(j)(5) 10(l)(1) effective as of December December 31, 1993 1, 1993 *10(l)(6) -- Fifth Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(j)(6) 10(l)(1) effective as of December 31, 1994 September 7, 1994 *10(l)(7) -- Sixth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(b) 10(l)(1) effective as of August ended June 30, 1995 1, 1995 *10(l)(8) -- Seventh Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(d) 10(l)(1) effective as of December ended June 30, 1996 1, 1995 *10(l)(9) -- Eighth Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(d) 10(l)(1) effective as of January ended June 30, 1997 1, 1997 *10(l)(10) -- Ninth Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(l)(10) 10(l)(1) effective in part August December 31, 1997 6, 1997, in part October 1, 1997, and in part January 1, 1998 *10(l)(11) -- Tenth Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(i)(11) 10(l)(1) effective as of December 31, 1997 September 3, 1997 *+10(l)(12) -- Eleventh Amendment to Exhibit 10(l)(1) effective as of January 1, 2001 *+10(l)(13) -- Twelfth Amendment to Exhibit 10(l)(1) effective as of August 31, 2002 *10(m)(1) -- Long-Term Incentive Compensation HI's Form 10-Q for the quarter 1-7629 10(c) Plan of HI effective as of ended June 30, 1989 January 1, 1989 *10(m)(2) -- First Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(f)(2) 10(m)(1) effective as of January December 31, 1989 1, 1990 *10(m)(3) -- Second Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(k)(3) 10(m)(1) effective as of December December 31, 1992 22, 1992 *10(m)(4) -- Third Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(m)(4) 10(m)(1) effective as of August December 31, 1997 6, 1997 *10(m)(5) -- Fourth Amendment to Exhibit Reliant Energy's Form 10-Q for 1-3187 10.4 10(m)(1) effective as of January the quarter ended June 30, 2002 1, 2001 *10(n) -- Form of stock option agreement HI's Form 10-Q for the quarter 1-7629 10(h) for non-qualified stock options ended March 31, 1992 granted under Exhibit 10(m)(1) *10(o) -- Forms of restricted stock HI's Form 10-Q for the quarter 1-7629 10(i) agreement for restricted stock ended March 31, 1992 granted under Exhibit 10(m)(1) *10(p)(1) -- 1994 Long-Term Incentive HI's Form 10-K for the year ended 1-7629 10(n)(1) Compensation Plan of HI effective December 31, 1993 as of January 1, 1994 *10(p)(2) -- Form of stock option agreement HI's Form 10-K for the year ended 1-7629 10(n)(2) for non-qualified stock options December 31, 1993 granted under Exhibit 10(p)(1) *10(p)(3) -- First Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10(e) 10(p)(1) effective as of May 9, ended June 30, 1997 1997 *10(p)(4) -- Second Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(p)(4) 10(p)(1) effective as of August December 31, 1997 6, 1997 *10(p)(5) -- Third Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(p)(5) 10(p)(1) effective as of January December 31, 1998 1, 1998

161

EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- *10(p(6) -- Reliant Energy 1994 Long-Term Reliant Energy's Form 10-Q for 1-3187 10.6 Incentive Compensation Plan, as the quarter ended June 30, 2002 amended and restated effective January 1, 2001 *10(q)(1) -- Savings Restoration Plan of HI HI's Form 10-K for the year ended 1-7629 10(f) effective as of January 1, 1991 December 31, 1990 *10(q)(2) -- First Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(l)(2) 10(q)(1) effective as of January December 31, 1991 1, 1992 *10(q)(3) -- Second Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(q)(3) 10(q)(1) effective in part, December 31, 1997 August 6, 1997, and in part, October 1, 1997 *10(r)(1) -- Director Benefits Plan effective HI's Form 10-K for the year ended 1-7629 10(m) as of January 1, 1992 December 31, 1991 *10(r)(2) -- First Amendment to Exhibit HI's Form 10-K for the year ended 1-7629 10(m)(1) 10(r)(1) effective as of August December 31, 1998 6, 1997 *10(s)(1) -- Executive Life Insurance Plan of HI's Form 10-K for the year ended 1-7629 10(q) HI effective as of January 1, December 31, 1993 1994 *10(s)(2) -- First Amendment to Exhibit HI's Form 10-Q for the quarter 1-7629 10 10(s)(1) effective as of January ended June 30, 1995 1, 1994 *10(s)(3) -- Second Amendment to Exhibit HI's Form 10-K for the year ended 1-3187 10(s)(3) 10(s)(1) effective as of August December 31, 1997 6, 1997 *10(t) -- Employment and Supplemental HI's Form 10-Q for the quarter 1-7629 10(f) Benefits Agreement between HL&P ended March 31, 1987 and Hugh Rice Kelly *10(u)(1) -- Reliant Energy Savings Plan, as Reliant Energy's Form 10-K for 1-3187 10(cc)(1) amended and restated effective the year ended December 31, 1999 April 1, 1999 *10(u)(2) -- First Amendment to Exhibit Reliant Energy's Form 10-Q for 1-3187 10.9 10(u)(1) effective January 1, the quarter ended June 30, 2002 1999 *10(u)(3) -- Second Amendment to Exhibit Reliant Energy's Form 10-Q for 1-3187 10.10 10(u)(1) effective January 1, the quarter ended June 30, 2002 1997 *10(u)(4) -- Third Amendment to Exhibit Reliant Energy's Form 10-Q for 1-3187 10.11 10(u)(1) effective January 1, the quarter ended June 30, 2002 2001 *10(u)(5) -- Fourth Amendment to Exhibit Reliant Energy's Form 10-Q for 1-3187 10.12 10(u)(1) effective May 6, 2002 the quarter ended June 30, 2002 *+10(u)(6) -- Fifth Amendment to Exhibit 10(u)(1) effective January 1, 2002 and as renamed effective October 2, 2002 *+10(u)(7) -- Reliant Energy Savings Trust between Reliant Energy and The Northern Trust Company, as Trustee, as amended and restated effective April 1, 1999 *+10(u)(8) -- First Amendment to Exhibit 10(u)(7) effective September 30, 2002 10(u)(9) -- Note Purchase Agreement between HI's Form 10-K for the year ended 1-7629 10(j)(3) HI and the ESOP Trustee, dated as December 31, 1990 of October 5, 1990 *+10(u)(10) -- Reliant Energy Retirement Plan between Reliant Energy and The Northern Trust Company, as Trustee, as amended and restated effective January 1, 1999 *+10(u)(11) -- First Amendment to Exhibit 10(u)(10) effective as of January 1, 1995

162

EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- *+10(u)(12) -- Second Amendment to Exhibit 10(u)(10) effective as of January 1, 1995 *+10(u)(13) -- Third Amendment to Exhibit 10(u)(10) effective as of January 1, 2001 *+10(u)(14) -- Fourth Amendment to Exhibit 10(u)(10) effective as of January 1, 2001 *+10(u)(15) -- Fifth Amendment to Exhibit 10(u)(10) effective as of November 15, 2002, and as renamed effective October 2, 2002 *+10(u)(16) -- Sixth Amendment to Exhibit 10(u)(10) effective as of January 1, 2002 10(u)(17) -- Reliant Energy, Incorporated Reliant Energy's Form 10-K for 1-3187 10(u)(3) Master Retirement Trust (as the year ended December 31, 1999 amended and restated effective January 1, 1999 and renamed effective May 5, 1999) 10(u)(18) -- Contribution and Registration Reliant Energy's Form 10-K for 1-3187 10(u)(4) Agreement dated December 18, 2001 the year ended December 31, 2001 among the Company, CenterPoint Energy, Inc. and the Northern Trust Company, trustee under the Reliant Energy, Incorporated Master Retirement Trust 10(v)(1) -- Stockholder's Agreement dated as Schedule 13-D dated July 6, 1995 5-19351 2 of July 6, 1995 between the Company and Time Warner Inc. 10(v)(2) -- Amendment to Exhibit 10(v)(1) HI's Form 10-K for the year ended 1-7629 10(x)(4) dated November 18, 1996 December 31, 1996 *10(w)(1) -- Houston Industries Incorporated HI's Form 10-K for the year ended 1-7629 10(7) Executive Deferred Compensation December 31, 1995 Trust effective as of December 19, 1995 *10(w)(2) -- First Amendment to Exhibit HI's Form 10-Q for the quarter 1-3187 10 10(w)(1) effective as of August ended June 30, 1998 6, 1997 *+10(x) -- Supplemental compensation agreement, dated November 27, 2002, between CenterPoint Energy and Milton Carroll *10(y)(1) -- Reliant Energy, Incorporated and Reliant Energy's Form 10-K for 1-3187 10(y) Subsidiaries Common Stock the year ended December 31, 2000 Participation Plan for Designated New Employees and Non-Officer Employees effective as of March 4, 1998 *+10(y)(2) -- Reliant Energy, Incorporated and Subsidiaries Common Stock Participation Plan for Designated New Employees and Non-Officer Employees, as amended and restated effective January 1, 2001 *10(z) -- Reliant Energy, Incorporated Reliant Energy's Definitive Proxy 1-3187 Appendix I Annual Incentive Compensation Statement for 2000 Annual Meeting Plan, as amended and restated of Shareholders effective January 1, 1999 *10(aa)(1) -- Long Term Incentive Plan of Reliant Energy's Registration 333-60260 4.6 Reliant Energy, Incorporated Statement on Form S-8 dated May effective as of January 1, 2001 4, 2001 *10(aa)(2) -- First Amendment to exhibit Reliant Energy's Registration 333-60260 4.7 10(aa)(1) effective as of January Statement on Form S-8 dated May 1, 2001 4, 2001 10(bb)(1) -- Master Separation Agreement Reliant Energy's Form 10-Q for 1-3187 10.1 entered into as of December 31, the quarter ended March 31, 2001 2000 between Reliant Energy, Incorporated and Reliant Resources, Inc.

163

EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- 10(bb)(2) -- Transition Services Agreement, Reliant Energy's Form 10-Q for 1-3187 10.2 dated as of December 31, 2000, the quarter ended March 31, 2001 between Reliant Energy, Incorporated and Reliant Resources, Inc. 10(bb)(3) -- Technical Services Agreement, Reliant Energy's Form 10-Q for 1-3187 10.3 dated as of December 31, 2000, the quarter ended March 31, 2001 between Reliant Energy, Incorporated and Reliant Resources, Inc. 10(bb)(4) -- Texas Genco Option Agreement, Reliant Energy's Form 10-Q for 1-3187 10.4 dated as of December 31, 2000, the quarter ended March 31, 2001 between Reliant Energy, Incorporated and Reliant Resources, Inc. +10(bb)(5) -- First Amendment to Exhibit 10(bb)(4) effective as of February 1, 2003 10(bb)(6) -- Employee Matters Agreement, Reliant Energy's Form 10-Q for 1-3187 10.5 entered into as of December 31, the quarter ended March 31, 2001 2000, between Reliant Energy, Incorporated and Reliant Resources, Inc. 10(bb)(7) -- Retail Agreement, entered into as Reliant Energy's Form 10-Q for 1-3187 10.6 of December 31, 2000, between the quarter ended March 31, 2001 Reliant Energy, Incorporated and Reliant Resources, Inc. 10(bb)(8) -- Registrations Rights Agreement, Reliant Energy's Form 10-Q for 1-3187 10.7 dated as of December 31, 2000, the quarter ended March 31, 2001 between Reliant Energy, Incorporated and Reliant Resources, Inc. 10(bb)(9) -- Tax Allocation Agreement, entered Reliant Energy's Form 10-Q for 1-3187 10.8 into as of December 31, 2000, the quarter ended March 31, 2001 between Reliant Energy, Incorporated and Reliant Resources, Inc. +10(cc)(1) -- Separation Agreement entered into as of August 31, 2002 between CenterPoint Energy and Texas Genco Holdings, Inc. ("Texas Genco") +10(cc)(2) -- Transition Services Agreement, dated as of August 31, 2002, between CenterPoint Energy and Texas Genco +10(cc)(3) -- Tax Allocation Agreement, dated as of August 31, 2002, between CenterPoint Energy and Texas Genco 10(cc)(4) -- Assignment and Assumption Texas Genco's Registration 1-31449 10.11 Agreement for the Technical Statement on Form 10 Services Agreement entered into as of August 31, 2002, by and between CenterPoint Energy and Texas Genco, LP *10(dd) -- Retention Agreement effective Reliant Energy's Form 10-K for 1-3187 10(jj) October 15, 2001 between Reliant the year ended December 31, 2001 Energy, Incorporated and David G. Tees *10(ee) -- Retention Agreement effective Reliant Energy's Form 10-K for 1-3187 10(kk) October 15, 2001 between Reliant the year ended December 31, 2001 Energy, Incorporated and Michael A. Reed *+10(ff)(1) -- Non-Qualified Executive Disability Income Plan of Arkla, Inc. effective as of August 1, 1983 *+10(ff)(2) -- Executive Disability Income Agreement effective July 1, 1984 between Arkla, Inc. and T. Milton Honea *+10(gg) -- Non-Qualified Unfunded Executive Supplemental Income Retirement Plan of Arkla, Inc. effective as of August 1, 1983 *+10(hh)(1) -- Deferred Compensation Plan for Directors of Arkla, Inc. effective as of November 10, 1988

164

EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE ------- --------------------------------- --------------------------------- ------------ ------------- *+10(hh)(2) -- First Amendment to Exhibit 10(hh)(1) effective as of August 6, 1997 +12 -- Computation of Ratios of Earnings to Fixed Charges +21 -- Subsidiaries of CenterPoint Energy +23 -- Consent of Deloitte & Touche LLP

165