1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-K (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 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 1-14756 AMEREN CORPORATION (Exact name of registrant as specified in its charter) Missouri 43-1723446 (State or other jurisdiction (I.R.S. Employer Identification of incorporation or organization) No.) 1901 Chouteau Avenue, St. Louis, Missouri 63103 (Address of principal executive offices and Zip Code) Registrant's telephone number, including area code: (314) 621-3222 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Title of each class Name of each exchange on which registered ----------------------------- ----------------------------------------- Common Stock, $ .01 par value New York Stock Exchange SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X]. No [ ]. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]. Aggregate market value of voting stock held by non-affiliates as of March 6, 2000, based on closing prices most recently available as reported in The Wall Street Journal: $3,867,760,835. Shares of Common Stock, $ .01 par value, outstanding as of March 6, 2000: 137,215,462 shares. DOCUMENTS INCORPORATED BY REFERENCES. Portions of the registrant's 1999 Annual Report to Stockholders (the "1999 Annual Report") are incorporated by reference into Parts I, II and IV. Portions of the registrant's definitive proxy statement for the 2000 annual meeting are incorporated by reference into Part III.

2 TABLE OF CONTENTS <TABLE> <CAPTION> PART I PAGE ---- <S> <C> <C> Item 1 - Business General............................................................................... 1 Capital Program and Financing......................................................... 2 Rates................................................................................. 3 Fuel Supply........................................................................... 3 Regulation............................................................................ 4 Industry Issues....................................................................... 6 Operating Statistics(1)............................................................... 6 Item 2 - Properties.................................................................................. 6 Item 3 - Legal Proceedings........................................................................... 8 Item 4 - Submission of Matters to a Vote of Security Holders(2) Executive Officers of the Company (Item 401(b) of Regulation S-K)......................................... 9 PART II Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters(1)................................................................ 10 Item 6 - Selected Financial Data(1).................................................................. 11 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations(1).......................................................... 11 Item 7A - Quantitative and Qualitative Disclosures about Market Risk(1)............................... 11 Item 8 - Financial Statements and Supplementary Data(1).............................................. 11 Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure(2) PART III Item 10 - Directors and Executive Officers of the Registrant(1)....................................... 11 Item 11 - Executive Compensation(1)................................................................... 12 Item 12 - Security Ownership of Certain Beneficial Owners and Management(1)..................................................................... 12 Item 13 - Certain Relationships and Related Transactions(1)........................................... 12 PART IV Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 12 SIGNATURES................................................................................................ 16 EXHIBITS.................................................................................................. 17 </TABLE> --------------------- (1) Incorporated herein by reference. (2) Not applicable and not included herein.

3 PART I ITEM 1. BUSINESS. GENERAL The Registrant, Ameren Corporation (Ameren or the Company), was incorporated in Missouri on August 7, 1995. On December 31, 1997, following the receipt of all required approvals, CIPSCO Incorporated (CIPSCO) and Union Electric Company (AmerenUE) combined with the result that the common shareholders of CIPSCO and AmerenUE became the common shareholders of the Company, and the Company became the owner of 100% of the common stock of AmerenUE and CIPSCO's utility operating subsidiary, Central Illinois Public Service Company (AmerenCIPS) (the Merger). For additional information about the Merger, see "Overview" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Notes 1 and 2 to the "Notes to Consolidated Financial Statements" on Pages 15, 28, and 29, respectively, of the 1999 Annual Report pages incorporated herein by reference. Ameren is a public utility holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA) and does not own or operate any significant assets other than the stock of its subsidiaries, including its two utility operating subsidiaries, AmerenCIPS and AmerenUE. Dividends on Ameren's Common Stock are dependent on distributions to be made to it by AmerenCIPS, AmerenUE, and its other subsidiaries. The 1999 Annual Reports Form 10-K for AmerenCIPS and AmerenUE are available from the Company upon request. AmerenCIPS is an Illinois corporation organized in 1902. It supplies electric and gas service to territories in central and southern Illinois having an estimated population of 820,000 within an area of approximately 20,000 square miles. AmerenUE was incorporated in Missouri in 1922, and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the State of Missouri and supplies electric and gas service in territories in Missouri and Illinois having an estimated population of 2,600,000 within an area of approximately 24,500 square miles, including the greater St. Louis area. On a consolidated basis, 93.3% of the Company's 1999 operating revenues were derived from the sale of electric energy, 6.5% came from the sale of natural gas, and 0.2% came from other sources. Consolidated electric operating revenues as a percentage of total operating revenues for the years 1998 and 1997 were 93.3% and 92%, respectively. The Company also owns all of the common stock of other subsidiary companies as follows: (a) CIPSCO Investment Company, a nonregulated investment company incorporated in Illinois; (b) Ameren Services Company, a Missouri corporation which provides administrative, accounting, legal, engineering, executive, and other support services to Ameren and all of its subsidiaries; (c) AmerenEnergy, Inc., a Missouri corporation which primarily serves as a power marketing agent for the operating utility companies and provides a range of energy and risk management services to targeted customers; (d) Ameren Development Company, a nonregulated holding company incorporated in Missouri encompassing Ameren's nonregulated products and services; and (e) Ameren Energy Resources Company (until March 2000, known as Ameren Intermediate Holding Co., Inc.), a nonregulated Illinois holding company for an Illinois nonregulated generating subsidiary (Ameren Energy Generating Company) and its marketing affiliate (Ameren Energy Marketing Company) scheduled to be operational in May 2000. In addition, through its operating subsidiaries, the Company owns 60% of the Common Stock of Electric Energy, Inc., which owns and operates a generating plant with a nominal capacity of 1,000 mW. Of the plant's total output, 50% is committed to the Department of Energy, 15% to AmerenUE, 7.5% to AmerenCIPS, and the remainder to its other owners. 1

4 At December 31, 1999, the Company and its subsidiaries had 7,347 employees. Approximately 70% of such employees are represented by local unions affiliated with the AFL-CIO. New contracts with collective bargaining units representing approximately 60% of these employees were ratified in 1999 with terms expiring in 2002. Labor agreements which expired in 1999 have not been renewed with International Brotherhood of Electrical Workers (IBEW) Locals 1439, 309, 649 and 1455, who collectively represent approximately 2,000 employees. Negotiations with Local 1455 are still ongoing. However, after engaging in extensive good-faith bargaining with IBEW Locals 1439, 309 and 649, the Company submitted a last, best and final offer to these collective bargaining units on February 2, 2000. The offer was rejected and the Company informed these locals that it would implement the noneconomic portion of its offer effective March 6, 2000. The employees are currently working under the noneconomic portion of the Company's last, best and final offer. The Company is unable to predict what further action, if any, these collective bargaining units will take or the response of the Company's other union represented employees to any action by its employees. The Company is also unable to determine what, if any, impact these labor matters could have on its future financial condition, results of operations or liquidity. For more information on labor agreements and other labor matters, see Note 12 to the "Notes to Consolidated Financial Statements" on Page 38 of the 1999 Annual Report pages incorporated herein by reference. For additional information regarding the Company's business operations, see "Regulation" section below and "Management's Discussion and Analysis" on Pages 15-22 and the Consolidated Financial Information on Pages 23-45 of the 1999 Annual Report pages incorporated herein by reference. CAPITAL PROGRAM AND FINANCING The Company is engaged in a capital program under which capital expenditures are expected to approximate $749 million in 2000. During 1999, the Company committed to purchase combustion turbine generators which will add more than 2,700 megawatts to its net peaking capacity and are expected to cost approximately $1.2 billion. Except for nearly 200 megawatts, the new capacity is expected to be operated by Ameren Energy Generating Company, the new Illinois nonregulated generating subsidiary. For the five-year period 2000 through 2004, construction expenditures are estimated at $3.3 billion. This estimate includes capital expenditures for the purchase of the new combustion turbine generators, as well as expenditures that will be incurred by the Company to meet new air quality standards for ozone and particulate matter. In addition to the funds required for construction during the 2000-2004 period, $897 million will be required to repay long-term debt as follows: $129 million in 2000; $45 million in 2001; $275 million in 2002; $160 million in 2003; and $288 million in 2004. Amounts for years subsequent to 2000 do not include AmerenUE's nuclear fuel lease payments since the amounts of such payments are not currently determinable. To issue first mortgage bonds and preferred stock, AmerenCIPS and AmerenUE each must comply with earnings tests contained in their respective mortgages and Articles of Incorporation. For the issuance of additional first mortgage bonds, generally, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required. Generally, for the issuance of additional preferred stock, earnings coverage of one and one-half times annual interest charges and preferred stock dividends is required under the AmerenCIPS Articles, and earnings coverage of at least two and one-half times the annual dividend on preferred stock outstanding and to be issued is required under AmerenUE's Articles. The ability to issue such securities in the future will depend on coverages at that time. Currently, each company expects to have adequate coverage ratios for anticipated requirements. For additional information on the Company's capital program and financial needs, see "Liquidity and Capital Resources" in "Management's Discussion and Analysis of Financial Condition 2

5 and Results of Operations" on Page 17, and Notes 5, 7, 8, and 12 to the "Notes to Consolidated Financial Statements" on Pages 32, 33, 34 and 38, of the 1999 Annual Report pages incorporated herein by reference. RATES For the year 1999, approximately 61%, 23%, and 16% of the Company's electric operating revenues were based on rates regulated by the Missouri Public Service Commission (MoPSC), the Illinois Commerce Commission (ICC), and the Federal Energy Regulatory Commission (FERC) of the U. S. Department of Energy, respectively. For information on rate matters in these jurisdictions, see "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 2 to the "Notes to Consolidated Financial Statements" on Pages 19 and 29, respectively, of the 1999 Annual Report pages incorporated herein by reference. Reference is being made to Note 2 (Missouri Electric) to the "Notes to Consolidated Financial Statements" on Page 29 of the 1999 Annual Report pages incorporated herein by reference for a discussion of the December 1999 Report and Order (Order) of the MoPSC relating to or impacting customer credits under AmerenUE's original and new experimental electric alternative regulation plans. On February 24, 2000, AmerenUE filed a Petition for Writ of Review with the Circuit Court of Cole County, Missouri asking that the MoPSC's Order be reversed. AmerenUE has also requested that the court issue a stay of the Order. While it is unable to predict the ultimate outcome of the judicial appeal of the MoPSC's Order, Ameren believes that the final decision will not have a material adverse effect on its financial position, results of operations or liquidity. Further reference is being made to Note 2 (Illinois Electric Restructuring) to the "Notes to Consolidated Financial Statements" for a discussion of the August 1999 order of the ICC approving the delivery service tariffs filed by AmerenUE and AmerenCIPS and the rehearing of that order granted by the ICC on certain issues. The ICC issued an order in 2000 on this reopened proceeding resolving all outstanding issues. In February 2000, AmerenUE filed a request with the MoPSC to increase rates approximately $12 million annually for natural gas service in its Missouri jurisdiction. The MoPSC has until January 2001 to render a decision. <TABLE> <CAPTION> FUEL SUPPLY COST OF FUELS YEAR ------------- ------------------------------------------------------------------------------ 1999 1998 1997 1996 1995 ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> AMERENUE -------- Per Million BTU - Coal 100.685(cent) 100.015(cent) 105.600(cent) 112.250(cent) 117.645(cent) - Nuclear 46.552(cent) 48.803(cent) 47.472(cent) 47.499(cent) 48.592(cent) - System 89.833(cent) 90.378(cent) 92.816(cent) 96.596(cent) 101.590(cent) AMERENCIPS ---------- Per Million BTU - System (Coal) 139.700(cent) 152.738(cent) 163.000(cent) 171.000(cent) 176.000(cent) </TABLE> OIL. The actual and prospective use of such fuel is minimal, and the Company has not experienced and does not expect to experience difficulty in obtaining adequate supplies. GAS. The combustion turbine generators which the Company has committed to purchase (see "Capital Program and Financing" section above) will be fueled by natural gas. Consequently, the prospective use of natural gas to supply such facilities is expected to increase significantly. The Company does not expect to experience difficulty in obtaining adequate supplies to support the new generation facilities. 3

6 COAL. Because of uncertainties of supply due to potential work stoppages, equipment breakdowns and other factors, the Company has a policy of maintaining a coal inventory consistent with its expected burn practices. NUCLEAR. The components of the nuclear fuel cycle required for nuclear generating units are as follows: (1) uranium; (2) conversion of uranium into uranium hexafluoride; (3) enrichment of uranium hexafluoride; (4) conversion of enriched uranium hexafluoride into uranium dioxide and the fabrication into nuclear fuel assemblies; and (5) disposal and/or reprocessing of spent nuclear fuel. The Company has agreements and/or inventories to fulfill its Callaway Nuclear Plant needs for uranium, enrichment, fabrication and conversion services through 2002. Additional contracts will have to be entered into in order to supply nuclear fuel during the remainder of the life of the Plant, at prices which cannot now be accurately predicted. The Callaway Plant normally requires refueling at 18-month intervals, with the next regular refueling presently scheduled for the spring of 2001. Under the Nuclear Waste Policy Act of 1982, the U. S. Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel. DOE currently charges one mill per nuclear generated kilowatt-hour sold for future disposal of spent fuel. Electric rates charged to customers provide for recovery of such costs. DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. The Company has sufficient storage capacity at the Callaway site until 2020 and has the capability for additional storage capacity through the licensed life of the plant in 2024. The delayed availability of the DOE's disposal facility is not expected to adversely affect the continued operation of Callaway Plant. For additional information on the Company's "Fuel Supply", see "Results of Operations" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Notes 12 and 13 to the "Notes to Consolidated Financial Statements" on Pages 15, 38 and 41, respectively, of the 1999 Annual Report pages incorporated herein by reference. REGULATION As a holding company registered under the PUHCA, Ameren, along with its subsidiaries, is subject to the regulatory provisions of said Act, including provisions relating to the issuance of securities, sales and acquisitions of securities and utility assets, the services performed by Ameren Services Company, and the activities of certain other subsidiaries. AmerenCIPS and AmerenUE are subject to regulation, as applicable, by the MoPSC and the ICC as to rates, service, accounts, issuance of equity securities, issuance of debt having a maturity of more than twelve months, mergers, and various other matters. Said companies are also subject to regulation by the FERC as to rates and charges in connection with the transmission of electric energy in interstate commerce and the sale of such energy at wholesale in interstate commerce, mergers, and certain other matters. Authorization to issue debt having a maturity of twelve months or less is obtained from the Securities and Exchange Commission. For information on regulatory matters in these jurisdictions, including the current status of electric utility restructuring in Illinois and Missouri, see "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 2 to the "Notes to Consolidated Financial Statements" on Pages 19 and 29, respectively, of the 1999 Annual Report pages incorporated herein by reference. Reference is being made to "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 2 (Illinois Electric Restructuring) to the "Notes to Consolidated Financial Statements" on Pages 19 and 29, respectively, of the 1999 Annual Report pages incorporated herein by reference, for a discussion of AmerenCIPS' transfer of its 4

7 generating facilities to a new nonregulated subsidiary of Ameren. In conjunction with Illinois' Electric Service Customer Choice and Rate Relief Law of 1997, in July 1999, AmerenCIPS filed a notice with the ICC that it intends to transfer AmerenCIPS' generating facilities (all in Illinois) to a new nonregulated subsidiary of the Company. The formation of the new generating subsidiary, as well as the transfer of AmerenCIPS' generating assets and liabilities (at historical net book value of approximately $600 million) and certain power sales contracts, was subject to various regulatory approvals from the ICC, the FERC, and the MoPSC, all of which have been received as of March 10, 2000. An additional PUHCA-related determination that will permit the new generating subsidiary to operate as an Exempt Wholesale Generator is being sought from the FERC. The generating subsidiary (Ameren Energy Generating Company) will include most of the new combustion turbine generators being acquired by the Company, in addition to the AmerenCIPS facilities. The new generating subsidiary is expected to be operational in May 2000. The proposed transfer of AmerenCIPS' generating assets and liabilities had no effect on the Company's financial statements as of December 31, 1999. Operation of the Company's Callaway Plant is subject to regulation by the Nuclear Regulatory Commission. Its Facility Operating License for the Callaway Plant expires on October 18, 2024. The Company's Osage hydroelectric plant and its Taum Sauk pumped-storage hydro plant, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other things, the general operation and maintenance of the projects. The license for the Osage Plant expires on February 28, 2006, and the license for the Taum Sauk Plant expires on June 30, 2010. The Company's Keokuk Plant and dam located in the Mississippi River between Hamilton, Illinois and Keokuk, Iowa, are operated under authority, unlimited in time, granted by an Act of Congress in 1905. Ameren and its subsidiaries are regulated, in certain of their operations, by air and water pollution and hazardous waste regulations at the city, county, state and federal levels. These companies are in substantial compliance with existing regulations. ENVIRONMENTAL ISSUES. On December 22, 1995, a complaint was filed in the Circuit Court for the Seventh Judicial Circuit, Sangamon County, Illinois against AmerenCIPS and several other defendants. The complaint sought unspecified monetary damages and alleged that, as a result of exposure to carcinogens contained in coal tar at the AmerenCIPS Taylorville gas plant site, plaintiffs' children had suffered from a rare form of childhood cancer known as "neuroblastoma". In 1998, a jury awarded plaintiffs $3.2 million. In March 2000, the Illinois Appellate Court, on an appeal by AmerenCIPS, upheld the plaintiffs' verdict. AmerenCIPS plans to seek an appeal of the court's decision to the Illinois Supreme Court. The Company believes that final disposition of this matter will not have a material adverse effect on the financial position, results of operations or liquidity of the Company. On August 2, 1996, the Illinois Attorney General filed a complaint with the Illinois Pollution Control Board alleging various violations of wastewater discharge permit conditions and ground water standards at AmerenCIPS' Hutsonville Power Station. The complaint seeks monetary penalties and the award of attorney fees. AmerenCIPS, the Illinois Environmental Protection Agency and the Attorney General have reached a settlement in principle resolving the complaint which will require the Company to perform remedial actions at the site. Any final settlement of this matter must be approved by the Illinois Pollution Control Board. While the Company cannot predict the final outcome of this matter, it does not believe that the final resolution will have a material adverse effect on financial position, results of operations or liquidity of the Company. For additional discussion of environmental matters, see "Liquidity and Capital Resources" in Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 12 to the "Notes to Consolidated Financial Statements" on Pages 17 and 38, respectively, of the 1999 Annual Report pages incorporated by reference. Reference is being made to these 1999 Annual Report pages for a discussion of regulations issued by the United States Environmental Protection Agency (EPA) to reduce NOx emissions from coal-fired boilers and other sources in 22 states, including Missouri and Illinois (where all of the Company's coal-fired power plant boilers are located). In March 2000, the U.S. Court of Appeals for the District of Columbia substantially upheld the proposed NOx regulations but remanded 5

8 portions of them to the EPA for further consideration. The implementation date of the regulations is uncertain and further legal challenge is possible. The Company is unable to predict the outcome of the litigation, the regulation implementation date or the ultimate impact of these standards on its future financial condition, results of operations or liquidity. INDUSTRY ISSUES The Company is facing issues common to the electric and gas utility industries which have emerged during the past several years. These issues include: the potential for more intense competition and for changing the structure of regulation; changes in the structure of the industry as a result of changes in federal and state laws, including the formation of unregulated generating entities; on-going consideration of additional changes of the industry by federal and state authorities; continually developing environmental laws, regulations and issues, including proposed new air quality standards; public concern about the siting of new facilities; proposals for demand side management programs; public concerns about nuclear decommissioning and the disposal of nuclear wastes; and global climate issues. The Company is monitoring these issues and is unable to predict at this time what impact, if any, these issues will have on its operations, financial condition, or liquidity. Also see "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Notes 2 and 12 to the "Notes to Consolidated Financial Statements" on Pages 19 and 38, respectively, of the 1999 Annual Report pages incorporated herein by reference. YEAR 2000 ISSUE. The Year 2000 Issue relates to how dates are stored and used in computer systems, applications, and embedded systems. As the century date change occurred, certain date-sensitive systems had to recognize and properly treat the year as 2000 and not as 1900. This inability to recognize and properly treat the year as 2000 could have caused these systems to process critical financial and operational information incorrectly. The Company encountered no significant problems associated with the Year 2000 Issue at year-end. For additional information on this issue, see "Year 2000 Issue" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" on Page 20 of the 1999 Annual Report pages incorporated herein by reference. OPERATING STATISTICS The information on Pages 44 and 45 in the Company's 1999 Annual Report is incorporated herein by reference. ITEM 2. PROPERTIES. In planning its construction program, the Company is presently utilizing a forecast of kilowatthour sales growth of approximately 2.0% and peak load growth of 1.5%, each compounded annually, and is providing for a minimum reserve margin of approximately 15% above its anticipated peak load requirements. The Company plans to add more than 2,700 megawatts to its net peaking capacity with the purchase of combustion turbine generators (CTs). CTs with a total capacity of approximately 590 megawatts are planned to be installed in 2000, 560 megawatts in 2001, 590 megawatts in 2002, and 325 megawatts each in 2003 through 2005. For additional information, see Note 12 to the "Notes to Consolidated Financial Statements" on Page 38 of the 1999 Annual Report pages incorporated herein by reference. The Company is a member of one of the ten regional electric reliability councils organized for coordinating the planning and operation of the nation's bulk power supply - MAIN (Mid-America 6

9 Interconnected Network) operating primarily in Wisconsin, Illinois and Missouri. The Company's bulk power system is operated as an Ameren-wide control area and transmission system under the FERC approved Joint Dispatch Agreement between AmerenUE and AmerenCIPS. Ameren has interconnections for transmission service and the exchange of electric energy, directly and through the facilities of others, with more than twenty power suppliers. The following table sets forth information with respect to the Company's generating facilities and capability at the time of the expected 2000 peak. <TABLE> <CAPTION> GROSS KILOWATT ENERGY INSTALLED SOURCE PLANT LOCATION CAPABILITY ------ ----- -------- ---------- <S> <C> <C> <C> Coal Labadie Franklin County, MO 2,400,000 Rush Island Jefferson County, MO 1,224,000 Newton Newton, IL 1,170,000 Sioux St. Charles County, MO 1,006,000 Meramec St. Louis County, MO 859,000 Coffeen Coffeen, IL 950,000 Meredosia Meredosia, IL 359,000 Grand Tower Grand Tower, IL 202,000 Hutsonville Hutsonville, IL 161,000 ------------ Total Coal 8,331,000 Nuclear Callaway Callaway County, MO 1,181,000 Hydro Osage Lakeside, MO 212,000 Keokuk Keokuk, IA 126,000 ------------ Total Hydro 338,000 Oil and Venice Venice, IL 441,000 Natural Other Various 1,078,000* ------------- Gas Total Oil and Natural Gas 1,519,000 Pumped- storage Taum Sauk Reynolds County, MO 440,000 ------------ TOTAL 11,809,000 ============ </TABLE> * Includes 517,000 gross kilowatt installed capability of new combustion turbine generators scheduled for service before the expected 2000 peak. As of December 31, 1999, AmerenCIPS owned approximately 4,700 circuit miles of electric transmission lines. AmerenCIPS operates one propane-air plant and 4,800 miles of gas mains. As of that date, AmerenUE owned approximately 3,300 circuit miles of electric transmission lines. AmerenUE operates three propane-air plants and 2,800 miles of gas mains. Other properties of the companies include distribution lines, underground cable, office buildings, warehouses, garages and repair shops. Substantially all of the properties and plant of AmerenCIPS and AmerenUE are subject to the direct first liens of the indentures securing their first mortgage bonds. Pursuant to the Illinois electric restructuring legislation enacted in December 1997 as the Electric Service Customer Choice and Rate Relief Law of 1997, AmerenCIPS expects to transfer all of its generating facilities and related assets to a new nonregulated generating subsidiary of Ameren in May 2000. As a part of this transfer, AmerenCIPS' generating property and plant will be released from the lien of the indenture securing its first mortgage bonds. For additional information on this generating asset transfer, see "Regulation" section under Item 1 herein and "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial 7

10 Condition and Results of Operations" and Note 2 to the "Notes to Consolidated Financial Statements" on Pages 19 and 30, respectively, of the 1999 Annual Report pages incorporated herein by reference. ITEM 3. LEGAL PROCEEDINGS. The Company is involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business, some of which involve substantial amounts. The Company believes that the final disposition of these proceedings will not have a material adverse effect on its financial position, results of operations or liquidity. For additional information on legal and administrative proceedings, see "Rates" and "Regulation -- Environmental Issues" under Item 1 herein and "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Notes 2 and 12 to the "Notes to Consolidated Financial Statements" on Pages 19, 29 and 38, respectively, of the 1999 Annual Report pages incorporated herein by reference. ------------------ Statements made in this report which are not based on historical facts, are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, financial performance and the Year 2000 Issue. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Company is providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in subsequent securities filings, could cause results to differ materially from management expectations as suggested by such "forward-looking" statements: the effects of regulatory actions; changes in laws and other governmental actions; the impact on the Company of current regulations related to the phasing-in of the opportunity for some customers to choose alternative energy suppliers in Illinois; the effects of increased competition in the future due to, among other things, deregulation of certain aspects of the Company's business at both the state and Federal levels; future market prices for fuel and purchased power, electricity, and natural gas, including the use of financial instruments; average rates for electricity in the Midwest; business and economic conditions; interest rates; weather conditions; fuel prices and availability; generation plant performance; the impact of current environmental regulations on utilities and generating companies and the expectation that more stringent requirements will be introduced over time, which could potentially have a negative financial effect; monetary and fiscal policies; future wages and employee benefits costs; and legal and administrative proceedings. 8

11 INFORMATION REGARDING EXECUTIVE OFFICERS REQUIRED BY ITEM 401(B) OF REGULATION S-K: <TABLE> <CAPTION> DATE FIRST ELECTED AGE AT OR APPOINTED TO NAME 12/31/99 PRESENT POSITION PRESENT POSITION ---- -------- ---------------- ---------------- <S> <C> <C> <C> Ameren Corporation ------------------ Charles W. Mueller 61 Chairman, President and Chief Executive Officer, and Director 12/31/97 Donald E. Brandt 45 Senior Vice President 12/31/97 Steven R. Sullivan 39 Vice President, General Counsel 7/1/98 and Secretary 9/1/98 Warner L. Baxter 38 Vice President 5/1/98 and Controller 12/31/97 Jerre E. Birdsong 45 Treasurer 4/23/96 AmerenUE (Subsidiary) --------------------- Charles W. Mueller 61 President, 7/1/93 Chief Executive Officer 1/1/94 and Director 6/11/93 Donald E. Brandt 45 Senior Vice President 7/1/88 and Director 4/28/98 Daniel F. Cole 46 Senior Vice President 7/12/99 Thomas F. Voss 52 Senior Vice President 6/1/99 Warner L. Baxter 38 Vice President, 5/1/98 Controller and 8/1/96 Director 4/22/99 William J. Carr 62 Vice President 10/1/88 Michael J. Montana 53 Vice President 7/1/88 Charles D. Naslund 47 Vice President 2/1/99 Garry L. Randolph 51 Vice President 3/1/91 William C. Shores 61 Vice President 7/1/88 Steven R. Sullivan 39 Vice President, General Counsel 7/1/98 and Secretary 9/1/98 Jerre E. Birdsong 45 Treasurer 7/1/93 AmerenCIPS (Subsidiary) ----------------------- Gary L. Rainwater 53 President, Chief Executive Officer 1/1/98 and Director 12/31/97 Thomas R. Voss 52 Senior Vice President 6/1/99 Warner L. Baxter 38 Vice President, 4/22/99 Controller and 12/31/97 Director 4/22/99 Michael J. Montana 53 Vice President 4/28/98 Gilbert W. Moorman 56 Vice President 6/1/88 Craig D. Nelson 46 Vice President 4/28/98 Jerry L. Simpson 43 Vice President 6/1/99 Steven R. Sullivan 39 Vice President, General Counsel and Secretary 11/7/98 Jerre E. Birdsong 45 Treasurer 12/31/97 </TABLE> 9

12 INFORMATION REGARDING EXECUTIVE OFFICERS REQUIRED BY ITEM 401(B) OF REGULATION S-K: <TABLE> <CAPTION> DATE FIRST ELECTED AGE AT OR APPOINTED TO NAME 12/31/99 PRESENT POSITION PRESENT POSITION ---- -------- ---------------- ---------------- <S> <C> <C> <C> Ameren Services Company (Subsidiary) ------------------------------------ Charles W. Mueller 61 President, Chief Executive Officer and Director 11/4/97 Paul A. Agathen 52 Senior Vice President 12/31/97 and Director 4/27/99 Donald E. Brandt 45 Senior Vice President 12/31/97 and Director 11/4/97 Daniel F. Cole 46 Senior Vice President 6/1/99 Thomas F. Voss 52 Senior Vice President 6/1/99 Warner L. Baxter 38 Vice President 4/28/98 and Controller 12/31/97 Charles A. Bremer 55 Vice President 12/31/97 Donald W. Capone 64 Vice President 12/31/97 William J. Carr 62 Vice President 7/7/99 J. L. Davis 52 Vice President 12/31/97 Jean M. Hannis 52 Vice President 12/31/97 R. Alan Kelley 47 Vice President 12/31/97 Michael J. Montana 53 Vice President 12/31/97 Craig D. Nelson 46 Vice President 12/31/97 Gregory L. Nelson 42 Vice President 2/16/99 J. Kay Smith 54 Vice President 7/1/99 Steven R. Sullivan 39 Vice President, General Counsel 7/1/98 and Secretary 9/1/98 Samuel E. Willis 55 Vice President 12/31/97 Ronald C. Zdellar 55 Vice President 12/31/97 Jerre E. Birdsong 45 Treasurer 12/31/97 </TABLE> All officers are elected or appointed annually by the respective Board of Directors of such company following the election of such Board at the annual meetings of stockholders held in April. There are no family relationships between the foregoing officers of the Company. Except for Messrs. Baxter, Gregory L. Nelson and Sullivan, each of the above-named executive officers has been employed by the Company or its affiliates for more than five years in executive or management positions. Mr. Baxter was previously employed by PricewaterhouseCoopers LLP. Mr. Nelson was previously employed by the law firm of Thelen Reid & Priest LLP. Mr. Sullivan was previously employed by Anheuser Busch Companies, Inc. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. On October 9, 1998, the Company adopted a Shareholder Rights Plan and declared a dividend of one preferred share purchase right (a Right) for each outstanding share of common stock, par value $ .01 per share, of the Company. Each Right entitles the registered holder to purchase from the Company one one-hundredth of a share of Series A Junior Participating Preferred Stock, par value $ .01 per share, of the Company at a price of $180 per one one-hundredth of a share of such Preferred Stock, subject to adjustment. The Rights will become exercisable if someone buys 15 percent or more of the 10

13 Company's common stock. In addition, if someone buys 15 percent or more of the Company's common stock, each right will entitle its holder (other than that buyer) to purchase a number of shares of the Company's common stock having a market value of twice the Right's $180 exercise price. If the Company is acquired in a merger, each Right will entitle its holder to purchase a number of the acquiring company's common shares having a market value at the time of twice the Right's exercise price. The Rights will expire on October 9, 2008. The Rights do not have voting or dividend rights, and until they become exercisable, have no dilutive effect on the per-share earnings of the Company. The Company has 4 million shares of Preferred Stock initially reserved for issuance upon exercise of the Rights. There is no Junior Participating Preferred Stock issued or outstanding. For additional information on the Shareholder Rights Plan, see Note 6 to the "Notes to Consolidated Financial Statements" on Page 33 of the 1999 Annual Report pages incorporated herein by reference. Additional information required to be reported by this item is included on the inside back cover of the 1999 Annual Report and is incorporated herein by reference. ITEM 6. SELECTED FINANCIAL DATA. Information for the 1994-1999 period required to be reported by this item is included on Page 43 of the 1999 Annual Report and is incorporated herein by reference. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Information required to be reported by this item is included on Pages 15 through 22 of the 1999 Annual Report and is incorporated herein by reference. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Information required to be reported by this item is included under "Market Risk Related to Financial Instruments and Commodity Instruments" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" on Page 21 of the 1999 Annual Report and is incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The financial statements of the Company on Pages 23 through 42, the report thereon of PricewaterhouseCoopers LLP appearing on Page 14 and the Selected Quarterly Information on Page 27 of the 1999 Annual Report are incorporated herein by reference. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. Information concerning directors required to be reported by this item is included under "Item (1): Election of Directors" in the Company's 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference. 11

14 Information concerning executive officers required by this item is reported in Part I of this Form 10-K. ITEM 11. EXECUTIVE COMPENSATION. Any information required to be reported by this item is included under "Compensation" in the Company's 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. Any information required to be reported by this item is included under "Security Ownership of Management" in the Company's 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Any information required to be reported by this item is included under "Item (1): Election of Directors" in the Company's 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) The following documents are filed as a part of this report: 1. Financial Statements: * <TABLE> <CAPTION> Page From 1999 Annual Report ------------- <S> <C> Consolidated Report of Independent Accountants.................................. 14 Consolidated Statement of Income - Years 1999, 1998, and 1997................... 23 Consolidated Balance Sheet - December 31, 1999 and 1998......................... 24 Consolidated Statement of Cash Flows - Years 1999, 1998, and 1997............... 26 Consolidated Statement of Retained Earnings - Years 1999, 1998, and 1997................................................. 27 Notes to Consolidated Financial Statements...................................... 28 </TABLE> * Incorporated by reference from the indicated pages of the 1999 Annual Report 12

15 2. Financial Statement Schedule: The following schedule, for the years ended December 31, 1999, 1998 and 1997, should be read in conjunction with the aforementioned financial statements (schedules not included have been omitted because they are not applicable or the required data is shown in the aforementioned financial statements). <TABLE> <CAPTION> Pages Herein ------------ <S> <C> Report of Independent Accountants on Financial Statement Schedule........................................................... 14 Valuation and Qualifying Accounts (Schedule II)................................. 15 </TABLE> 3. Exhibits: See EXHIBITS beginning on Page 17 (b) Reports on Form 8-K. The Company filed a report on Form 8-K dated December 20, 1999 reporting AmerenCIPS' termination of coal supply contracts, the resulting estimated pretax fuel cost savings and the recording of a nonrecurring charge. Further, a report dated January 20, 2000 was filed reporting the issuance of a Report and Order dated December 23, 1999 by the Missouri Public Service Commission regarding AmerenUE's electric alternative regulation plans. 13

16 REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE To the Board of Directors of Ameren Corporation Our audits of the financial statements referred to in our report dated February 2, 2000 appearing in the 1999 Annual Report to Shareholders of Ameren Corporation (which report and financial statements are incorporated by reference in this Annual Report on Form 10-K) also included an audit of the Financial Statement Schedule listed in Item 14(a)(2) of this Form 10-K. In our opinion, this Financial Statement Schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. /s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP St. Louis, Missouri February 2, 2000 14

17 AMEREN CORPORATION SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 <TABLE> <CAPTION> Col. A Col. B Col. C Col. D Col. E ------ ------ ------ ------ ------ Additions --------------------------------- (1) (2) Balance at Charged to Balance at beginning costs and Charged to end of Description of period expenses other accounts Deductions period ----------- --------- -------- -------------- ---------- ------ (Note) <S> <C> <C> <C> <C> <C> Year ended December 31, 1999 Reserves deducted in the balance sheet from assets to which they apply: Allowance for doubtful accounts $8,392,655 $12,240,000 $13,496,315 $7,136,340 ========== =========== =========== ========== Year ended December 31, 1998 Reserves deducted in the balance sheet from assets to which they apply: Allowance for doubtful accounts $4,845,328 $21,167,000 $17,619,673 $8,392,655 ========== =========== =========== ========== Year ended December 31, 1997 Reserves deducted in the balance sheet from assets to which they apply: Allowance for doubtful accounts $5,795,332 $12,648,812 $13,598,816 $4,845,328 ========== =========== =========== ========== </TABLE> Note: Uncollectible accounts charged off, less recoveries. 15

18 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. AMEREN CORPORATION (Registrant) CHARLES W. MUELLER Chairman, President and Chief Executive Officer Date March 29, 2000 By /s/ Steven R. Sullivan --------------- -------------------------- (Steven R. Sullivan, Attorney-in-Fact) 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 and on the date indicated. <TABLE> <CAPTION> <S><C> SIGNATURE TITLE --------- ----- /s/ C. W. Mueller Chairman, President, Chief -------------------------------------------------- Executive Officer and Director CHARLES W. MUELLER (Principal Executive Officer) /s/ Donald E. Brandt Senior Vice President -------------------------------------------------- (Principal Financial Officer) DONALD E. BRANDT /s/ Warner L. Baxter Vice President and Controller -------------------------------------------------- (Principal Accounting Officer) WARNER L. BAXTER /s/ William E. Cornelius -------------------------------------------------- WILLIAM E. CORNELIUS, Director /s/ Clifford L. Greenwalt -------------------------------------------------- ------------------------------------------------ CLIFFORD L. GREENWALT, Director HANNE M. MERRIMAN, Director /s/ Thomas A. Hays /s/ Paul L. Miller, Jr. -------------------------------------------------- ------------------------------------------------ THOMAS A. HAYS, Director PAUL L. MILLER, JR., Director /s/ Richard A. Liddy /s/ Robert H. Quenon -------------------------------------------------- ------------------------------------------------ RICHARD A. LIDDY, Director ROBERT H. QUENON, Director /s/ Gordon R. Lohman /s/ Harvey Saligman -------------------------------------------------- ------------------------------------------------ GORDON R. LOHMAN, Director HARVEY SALIGMAN, Director /s/ Richard A. Lumpkin /s/ Janet McAfee Weakley -------------------------------------------------- ------------------------------------------------ RICHARD A. LUMPKIN, Director JANET McAFEE WEAKLEY, Director /s/ John Peters MacCarthy -------------------------------------------------- ------------------------------------------------ JOHN PETERS MacCARTHY, Director JAMES W. WOGSLAND, Director By /s/ Steven R. Sullivan March 29, 2000 ------------------------------------------- (Steven R. Sullivan, Attorney-in Fact) </TABLE> 16

19 EXHIBITS EXHIBITS FILED HEREWITH ----------------------- EXHIBIT NO. DESCRIPTION ----------- ----------- 13 - Those pages of the 1999 Annual Report incorporated herein by reference. 21 - Subsidiaries of the Company. 23 - Consent of Independent Accountants. 24 - Powers of Attorney. 27 - Financial Data Schedule. EXHIBITS INCORPORATED BY REFERENCE ---------------------------------- The following exhibits heretofore have been filed with the Securities and Exchange Commission pursuant to requirements of the Acts administered by the Commission. Such exhibits are identified by the references following the listing of each such exhibit, and they are hereby incorporated herein by reference. EXHIBIT NO. DESCRIPTION ----------- ----------- 2 - Agreement and Plan of Merger, dated as of August 11, 1995, by and among the Company, CIPSCO Incorporated, UE, and Arch Merger Inc. (June 30, 1995 Form 10-Q/A (Amendment No. 1), Exhibit 2(a).) 3(i) - Restated Articles of Incorporation of the Company. (Registration No. 33-64165, Annex F.) 3(ii) - Certificate of Amendment to the Restated Articles of Incorporation filed with the Secretary of State of the State of Missouri on December 14, 1998. (1998 Form 10-K, Exhibit 3(i).) 3(iii) - By-Laws of the Company as amended to December 31, 1997. (1997 Form 10-K, Exhibit 3(ii).) 4.1 - Indenture of Mortgage and Deed of Trust of Union Electric Company dated June 15, 1937, as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941. (Registration No. 2-4940, Exhibit B-1.) 17

20 <TABLE> <CAPTION> <S><C> EXHIBIT NO. DESCRIPTION ----------- ----------- 4.2 - Supplemental Indentures to the Union Electric Company Mortgage DATED AS OF FILE REFERENCE EXHIBIT NO. ----------- -------------- ----------- March 1, 1967 2-58274 2.9 April 1, 1971 Form 8-K, April 1971 6 February 1, 1974 Form 8-K, February 1974 3 July 7, 1980 2-69821 4.6 May 1, 1990 Form 10-K, 1990 4.6 December 1, 1991 33-45008 4.4 December 4, 1991 33-45008 4.5 January 1, 1992 Form 10-K, 1991 4.6 October 1, 1992 Form 10-K, 1992 4.6 December 1, 1992 Form 10-K, 1992 4.7 February 1, 1993 Form 10-K, 1992 4.8 May 1, 1993 Form 10-K, 1993 4.6 August 1, 1993 Form 10-K, 1993 4.7 October 1, 1993 Form 10-K, 1993 4.8 January 1, 1994 Form 10-K, 1993 4.9 December 1, 1996 Form 10-K, 1996 4.36 4.3 - Indenture of Mortgage or Deed of Trust dated October 1, 1941, from CIPS to Continental Illinois National Bank and Trust Company of Chicago and Edmond B. Stofft, as Trustees. (Exhibit 2.01 in File No. 2-60232.) 4.4 - Supplemental Indentures dated, respectively September 1, 1947, January 1, 1949, February 1, 1952, September 1, 1952, June 1, 1954, February 1, 1958, January 1, 1959, May 1, 1963, May 1, 1964, June 1, 1965, May 1, 1967, April 1, 1970, April 1, 1971, September 1, 1971, May 1, 1972, December 1, 1973, March 1, 1974, April 1, 1975, October 1, 1976, November 1, 1976, October 1, 1978, August 1, 1979, February 1, 1980, February 1, 1986, May 15, 1992, July 1, 1992, September 15, 1992, April 1, 1993, and June 1, 1995 between CIPS and the Trustees under the Indenture of Mortgage or Deed of Trust referred to above (Amended Exhibit 7(b) in File No. 2-7341; Second Amended Exhibit 7.03 in File No. 2-7795; Second Amended Exhibit 4.07 in File No. 2-9353; Amended Exhibit 4.05 in file No. 2-9802; Amended Exhibit 4.02 in File No. 2-10944; Amended Exhibit 2.02 in File No. 2-13866; Amended Exhibit 2.02 in File No. 2-14656; Amended Exhibit 2.02 in File No.2-21345; Amended Exhibit 2.02 in File No. 2-22326; Amended Exhibit 2.02 in File No. 2-23569; Amended Exhibit 2.02 in File No. 2-26284; Amended Exhibit 2.02 in File No. 2-36388; Amended Exhibit 2.02 in File No. 2-39587; Amended Exhibit 2.02 in File No. 2-41468; Amended Exhibit 2.02 in File No. 2-43912; Exhibit 2.03 in File No. 2-60232; Amended Exhibit 2.02 in File No. 2-50146; Amended Exhibit 2.02 in File No. 2-52886; Second Amended Exhibit 2.04 in File No. 2-57141; Amended Exhibit 2.04 in File No. 2-57557; Amended Exhibit 2.06 in File No. 2-62564; Exhibit 2.02(a) in File No. 2-65914; Amended Exhibit 2.02(a) in File No. 2-66380; and Amended Exhibit 4.02 in File No. 33-3188; Exhibit 4.02 to Form 8-K dated May 15, 1992; Exhibit 4.02 to Form 8-K dated July 1, 1992; Exhibit 4.02 to Form 8-K dated September 15, 1992; Exhibit 4.02 to Form 8-K dated March 30, 1993; Exhibit 4.03 to Form 8-K dated June 5, 1995; Exhibit 4.03 to Form 8-K dated March 15, 1997; Exhibit 4.03 to Form 8-K dated June 1, 1997; and Exhibit 4.02, Post-Effective Amendment No. 1 in File No. 333-18473.) </TABLE> 18

21 <TABLE> <CAPTION> EXHIBIT NO. DESCRIPTION ----------- ----------- <S> <C> 4.5 - Agreement, dated as of October 9, 1998, between the Company and First Chicago Trust Company of New York, as Rights Agent, which includes the form of Certificate of Designation of the Preferred Shares as Exhibit A, the form of Right Certificate as Exhibit B and the Summary of Rights as Exhibit C. (October 14, 1998 Form 8-K, Exhibit 4.) 4.6 - Indenture dated as of December 1, 1998 from CIPS to the Bank of New York relating to CIPS' Senior Notes, 5.375% due 2008 and 6.125% due 2028. (Exhibit 4.03, Post-Effective Amendment No. 1 to File No. 333-18473.) 10.1 - Long-Term Incentive Plan of 1998. (1998 Form 10-K, Exhibit 10.1.) 10.2 - Change of Control Severance Plan. (1998 Form 10-K, Exhibit 10.2.) 10.3 - Deferred Compensation Plan for Members of the Ameren Leadership Team. (1998 Form 10-K, Exhibit 10.3.) 10.4 - Deferred Compensation Plan for Members of the Board of Directors. (1998 Form 10-K, Exhibit 10.4.) </TABLE> Note: Reports of Union Electric Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-2967. Reports of Central Illinois Public Service Company on Forms 8-K, 10-Q and Form 10-K are on file with the SEC under File Number 1-3672. 19

1 EXHIBIT 13 page 14 Ameren Corporation 1999 Annual Report RESPONSIBILITY FOR FINANCIAL STATEMENTS The management of Ameren Corporation is responsible for the information and representations contained in the consolidated financial statements and in other sections of this Annual Report. The consolidated financial statements have been prepared in conformity with generally accepted accounting principles. Other information included in this report is consistent, where applicable, with the consolidated financial statements. The Company maintains a system of internal accounting controls designed to provide reasonable assurance as to the integrity of the financial records and the protection of assets. Qualified personnel are selected and an organization structure is maintained that provides for appropriate functional responsibility. Written policies and procedures have been developed and are revised as necessary. The Company maintains and supports an extensive program of internal audits with appropriate management follow up. The Board of Directors, through its Auditing Committee comprised of outside directors, is responsible for ensuring that both management and the independent accountants fulfill their respective responsibilities relative to the financial statements. Moreover, the independent accountants have full and free access to meet with the Auditing Committee, with or without management present, to discuss auditing or financial reporting matters. Charles W. Mueller Donald E. Brandt Charles W. Mueller Donald E. Brandt Chairman, President and Chief Executive Officer Senior Vice President, Finance February 2, 2000 February 2, 2000 REPORT OF INDEPENDENT ACCOUNTANTS TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF AMEREN CORPORATION: In our opinion, based upon our audits and the report of other auditors, the accompanying consolidated balance sheet and the related consolidated statements of income and retained earnings and of cash flows appearing on pages 23-27 of this annual report present fairly, in all material respects, the financial position of Ameren Corporation and its subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Central Illinois Public Service Company and CIPSCO Investment Company, wholly-owned subsidiaries of Ameren Corporation, for the year ended December 31, 1997, which combined statements reflect total revenues of $863,441,000 for the year ended December 31, 1997. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for Central Illinois Public Service Company and CIPSCO Investment Company for the year ended December 31, 1997, is based solely on the report of the other auditors. We conducted our audits of these statements in accordance with generally accepted auditing standards in the United States, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP St. Louis, Missouri February 2, 2000

2 www.ameren.com page 15 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Ameren Corporation (Ameren) is a holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA). In December 1997, Union Electric Company (AmerenUE) and CIPSCO Incorporated (CIPSCO) combined to form Ameren, with AmerenUE and CIPSCO's subsidiaries, Central Illinois Public Service Company (AmerenCIPS) and CIPSCO Investment Company (CIC), becoming subsidiaries of Ameren (the Merger). As a result of the Merger, Ameren has a 60% ownership interest in Electric Energy, Inc. (EEI). That interest is consolidated for financial reporting purposes. Since the Merger, Ameren has formed AmerenEnergy, Inc. (AmerenEnergy), Ameren Development Company, Ameren Intermediate Holding Company, Inc., and Ameren Services Company. AmerenEnergy, an energy marketing subsidiary, primarily serves as a power marketing agent for the operating utility subsidiaries and provides a range of energy and risk management services to targeted customers. Ameren Development Company is a nonregulated subsidiary encompassing Ameren's nonregulated products and services. Ameren Intermediate Holding Company, Inc. is a holding company for the proposed Illinois nonregulated generating subsidiary and its proposed marketing affiliate (see discussion below under "Electric Industry Restructuring - Illinois" and Note 2- Regulatory Matters under Notes to Consolidated Financial Statements for further information). Ameren Services Company provides shared support services to Ameren and all of its subsidiaries. The Merger was accounted for as a pooling of interests; therefore, the consolidated financial statements are presented as if the Merger were consummated as of the beginning of the earliest period presented. However, the consolidated financial statements are not necessarily indicative of the results of operations, financial position or cash flows that would have occurred had the Merger been consummated for the periods for which it is given effect, nor is it necessarily indicative of the future results of operations, financial position or cash flows. References to the Company are to Ameren on a consolidated basis; however, in certain circumstances, the subsidiaries are separately referred to in order to distinguish between their different business activities. RESULTS OF OPERATIONS EARNINGS Earnings for 1999, 1998 and 1997, were $385 million ($2.81 per share), $386 million ($2.82 per share) and $335 million ($2.44 per share), respectively. Earnings and earnings per share fluctuated due to many conditions, primarily: sales growth, weather variations, credits to electric customers, electric rate reductions, gas rate increases, competitive market forces, fluctuating operating costs (including Callaway Nuclear Plant refueling outages), charges for coal contract terminations and a targeted employee separation plan, merger-related expenses, changes in interest expense, changes in income and property taxes, and an extraordinary charge. In the fourth quarter of 1999, the Company recorded a nonrecurring charge to earnings in connection with coal contract terminations with two coal suppliers. The charge reduced earnings $31 million, net of income taxes, or 23 cents per share (see discussion below under "Electric Operations" and Note 12 - Commitments and Contingencies under Notes to Consolidated Financial Statements for further information). In 1998, the Company also recorded a nonrecurring charge to earnings in connection with a targeted separation plan it offered to employees in July 1998. That charge reduced earnings $15 million, net of income taxes, or 11 cents per share (see Note 3 - Targeted Separation Plan under Notes to Consolidated Financial Statements for further information). In addition, the Company recorded an extraordinary charge to earnings in the fourth quarter of 1997 for the write-off of generation-related regulatory assets and liabilities of the Company's Illinois retail electric business as a result of electric industry restructuring legislation enacted in Illinois in December 1997. The write-off reduced earnings $52 million, net of income taxes, or 38 cents per share (see Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information). The significant items affecting revenues, expenses and earnings for the years ended December 31, 1999, 1998 and 1997 are detailed in the following pages. ELECTRIC OPERATIONS ELECTRIC REVENUES <TABLE> <CAPTION> Variations from Prior Year In Millions 1999 1998 1997 ----------------------------------------------------------- <S> <C> <C> <C> Rate variations $ (17) $(13) $ - Credit to customers 5 (24) 28 Effect of abnormal weather (53) 61 3 Growth and other 57 45 5 Interchange sales 177 16 (43) EEI sales 24 (55) 9 --------------------------- $ 193 $ 30 $ 2 --------------------------- </TABLE> Electric revenues for 1999 increased $193 million, compared to 1998, primarily due to a 9% increase in total kilowatthour sales. This increase was primarily driven by a 60% increase in interchange sales, due to strong marketing efforts by AmerenEnergy, and a 12% increase in EEI sales. Also contributing to the revenue increase was a decrease in the credit to Missouri electric customers, partially offset by the credit to Illinois electric customers (see Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information). Partially offsetting these increases, weather-sensitive residential and commercial sales decreased 2% and 1%, respectively, while industrial sales remained flat. In addition, revenues were lower due to rate decreases in both Missouri and Illinois (see Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information). Electric revenues for 1998 increased $30 million, compared to 1997. Revenues increased primarily due to higher sales to retail customers within the Company's service territory, as a result of warm summer weather and economic growth in the service area. Weather-sensitive residential and commercial sales increased 6% and 4%, respectively, while industrial sales grew 2%. Additionally, interchange revenues increased 7%, despite a 14%

3 page 16 Ameren Corporation 1999 Annual Report decline in interchange sales, due to market conditions. These increases were partially offset by an increase in credits to Missouri electric customers (see Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information) and lower sales by EEI. Electric revenues for 1997 were flat compared to 1996, reflecting a decrease in the Missouri electric customer credits recorded in 1997, versus 1996 (see Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information), partly offset by a 1% decrease in kilowatthour sales. The kilowatthour sales decrease was due to a 13% decrease in interchange sales, due to market conditions; a 1% decline in residential sales; and differences in the classification of certain interchange and purchased power transactions, resulting from the Federal Energy Regulatory Commission (FERC) Order 888. These decreases were partly offset by increases in commercial and industrial sales of 1% and 2%, respectively, attributable to economic growth. In addition, sales at EEI were up 6% over 1996. FUEL AND PURCHASED POWER <TABLE> <CAPTION> Variations from Prior Year In Millions 1999 1998 1997 ------------------------------------------------------------------ <S> <C> <C> <C> Fuel: Generation $ 10 $ 9 $ 25 Price (15) (23) (24) Generation efficiencies and other (8) - (5) Coal contract termination payments 52 - - Purchased power 117 (3) (50) EEI 37 (39) 10 ------------------------ $193 $(56) $(44) ------------------------ </TABLE> The $193 million increase in fuel and purchased power costs for 1999, compared to 1998, was primarily due to increased generation and purchased power, resulting from higher sales volume, increased fuel and purchased power costs at EEI and coal contract termination payments discussed below, partially offset by lower fuel costs. In the fourth quarter of 1999, AmerenCIPS and two of its coal suppliers executed agreements to terminate their existing coal supply contracts effective December 31, 1999. Under these agreements, AmerenCIPS made termination payments to the suppliers totaling approximately $52 million. These termination payments were recorded as a nonrecurring charge in the fourth quarter of 1999. Total pretax fuel cost savings from these termination agreements are estimated to be $183 million (or $131 million net of the termination payments) through 2010, which is the maximum period that would have remained on any of the terminated coal supply contracts. Approximately $66 million of pretax fuel cost savings is expected to be realized over the next three years. See Note 12 - Commitments and Contingencies under Notes to Consolidated Financial Statements for further information. The $56 million decrease in fuel and purchased power costs for 1998, compared to 1997, was primarily driven by lower fuel and purchased power costs at EEI as a result of fewer sales. In addition, fuel cost reductions were realized due to lower fuel prices, as well as through the joint dispatch of generation. Upon consummation of the Merger, AmerenUE and AmerenCIPS began jointly dispatching generation, therefore allowing the Company to utilize the most cost efficient plants of both operating companies to serve customers in either service territory. These decreases were partially offset by increased generation to serve native load demand. The decrease in 1997 fuel and purchased power costs was primarily due to reduced purchased power costs, resulting from relatively flat native load sales and lower interchange sales, as well as lower fuel prices, offset by greater generation. GAS OPERATIONS Gas revenues in 1999 increased $12 million, compared to 1998, primarily due to Illinois gas rate increases which became effective in February 1999 (see Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information) and higher gas costs recovered through the Company's purchased gas adjustment clauses. These increases were partially offset by an 8% decline in retail sales, resulting primarily from milder weather, as well as a decrease in off-system sales of gas to others. Gas revenues in 1998 decreased $33 million, compared to 1997, primarily due to an 8% decline in retail sales resulting from milder winter weather and lower gas costs reflected in the Company's purchased gas adjustment clauses. These decreases were partially offset by benefits realized from a Missouri gas rate increase effective February 1998 (see Note 2-Regulatory Matters under Notes to Consolidated Financial Statements for further information). Gas revenues in 1997 decreased $4 million, primarily due to a 12% decrease in retail sales. Milder winter weather resulted in a decline in weather-sensitive residential and commercial sales of 15% and 18%, respectively. These decreases were partly offset by a 20% increase in industrial sales and an increase in off-system sales of gas to others. Gas costs in 1999 increased $13 million compared to 1998. This increase in gas costs was primarily due to higher gas prices, partially offset by lower total sales. Gas costs in 1998 declined $42 million, compared to 1997, due to lower sales and lower gas prices. Gas costs for 1997 remained flat, as compared to those of 1996. OTHER OPERATING EXPENSES Other operating expense variations in 1997 through 1999 reflected recurring factors such as growth, inflation, labor and benefit increases, in addition to the capitalization of certain costs as a result of a Missouri Public Service Commission (MoPSC) Order and a charge for the targeted employee separation plan (TSP), as discussed below. In 1998, the Company announced plans to reduce its other operating expenses, including plans to eliminate approximately 400 employee positions by mid-1999 through a hiring freeze and the TSP. During the third quarter of 1998, a nonrecurring, pretax charge of $25 million was recorded, representing costs incurred to implement the TSP. The elimination of these positions, exclusive of the nonrecurring charge, reduced the Company's operating expenses approximately $15 million in 1998, and approximately $22 million in 1999, and is expected to reduce the Company's operating expenses by approximately $20 million to $25 million

4 www.ameren.com page 17 each year thereafter. See Note 3 - Targeted Separation Plan under Notes to Consolidated Financial Statements for further information. Other operating expenses decreased $18 million in 1999, compared to 1998. This decrease was primarily due to the 1998 charge for the TSP and related reduced workforce and the capitalization of certain costs (including computer software costs) that had previously been expensed for the Company's Missouri electric operations. The capitalization was a result of the MoPSC Order received in December 1999 (see Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information). These decreases were partially offset by current year expenses associated with electric industry deregulation in Illinois. The $62 million increase in other operations expense in 1998, compared to 1997, was primarily due to the charge for the TSP and increases in injuries and damages expense and information system-related costs. In 1997, other operations expenses increased $41 million, primarily due to increases in information system-related costs, labor, and injuries and damages expenses. Maintenance expenses increased $59 million in 1999, compared to 1998. This increase was primarily due to increased power plant maintenance and tree-trimming activity. The expenses incurred for the 35-day refueling outage in the fall of 1999 at the Callaway Nuclear Plant were comparable to those for the 31-day spring 1998 refueling outage. No refueling outage is scheduled for 2000. Maintenance expenses increased $2 million in 1998, compared to 1997, due to the refueling outage at the Callaway Nuclear Plant, partially offset by less scheduled fossil power plant maintenance. Maintenance expenses for 1997 increased $8 million, primarily resulting from increased scheduled fossil plant maintenance, partly offset by decreased expenses at the Callaway Plant due to the absence of a refueling outage in 1997. Depreciation and amortization expense was relatively flat in 1999 and 1998, compared to the prior year periods. Depreciation and amortization expense increased $7 million in 1997, due to increased depreciable property. TAXES Income tax expense from operations decreased $9 million in 1999, compared to 1998, due to lower pretax income. Income tax expense from operations increased $33 million in 1998, compared to 1997, due to higher pretax income and a higher effective tax rate. Income tax expense from operations decreased $19 million in 1997, principally due to lower pretax income and a lower effective tax rate. Other tax expense decreased $26 million in 1999, compared to 1998, primarily due to a decrease in gross receipts taxes related to the Company's Illinois jurisdiction. This decrease is the result of the restructuring of the Illinois public utility tax whereby gross receipts taxes are no longer recorded as electric revenues and gross receipts tax expense. OTHER INCOME AND DEDUCTIONS Miscellaneous, net increased $8 million, compared to 1998, primarily due to the write-off of certain nonregulated investments in 1999 and gains on the sale of property realized in 1998 but not in 1999. Miscellaneous, net decreased $8 million for 1998, compared to 1997, due to increased interest income and gains on the sale of property. Miscellaneous, net decreased $11 million for 1997, compared to 1996, primarily due to the capitalization of certain merger-related costs in 1997 (see Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information). INTEREST Interest expense decreased $13 million in 1999, primarily due to a lower amount of debt outstanding throughout the year. Interest expense decreased $4 million in 1998, compared to 1997, due to lower interest rates and a decrease in other interest expense, partially offset by an increase in interest on a higher amount of debt outstanding. Interest expense increased $5 million in 1997, primarily due to higher debt outstanding during the year at higher interest rates. BALANCE SHEET The $22 million increase in trade accounts receivable and unbilled revenue was due primarily to higher sales and revenues in November and December 1999, compared to the same 1998 period. The $20 million decrease in accounts receivable and unbilled revenues at December 31, 1998, compared to 1997, was due to lower sales and revenues in November and December 1998, compared to the same 1997 time period, due to mild winter weather. The $84 million increase in other current liabilities was primarily due to the timing of credit payments to electric customers in the Company's Missouri and Illinois jurisdictions, as well as an increase in a liability for an estimated rate reduction for Missouri electric customers retroactive to September 1, 1998 (see Note 2-Regulatory Matters under Notes to Consolidated Financial Statements for further information). The remaining variance is a result of the timing of various payments to suppliers. LIQUIDITY AND CAPITAL RESOURCES Cash provided by operating activities totaled $918 million for 1999, compared to $803 million for 1998 and $708 million for 1997. Cash flows used in investing activities totaled $558 million, $323 million and $387 million, for the years ended December 31, 1999, 1998 and 1997, respectively. Expenditures in 1999 for constructing new or improving existing facilities and purchasing rail cars were $571 million. In addition, the Company spent $22 million to acquire nuclear fuel. Capital expenditures are expected to approximate $749 million in 2000. For the five-year period 2000 through 2004, construction expenditures are estimated at $3.3 billion. This estimate includes capital expenditures of approximately $1 billion for the purchase of new combustion turbines (CTs) (see Note 12-Commitments and Contingencies under Notes to Consolidated Financial Statements for further information), as well as expenditures that will be incurred by the Company to meet new air quality standards for ozone and particulate matter, as discussed below. Title IV of the Clean Air Act Amendments of 1990 requires the Company to significantly reduce total annual sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions by the year 2000. By switching to low-sulfur coal, early banking of emission credits and installing advanced NOx reduction combustion technology, the Company is meeting these requirements.

5 page 18 Ameren Corporation 1999 Annual Report In July 1997, the United States Environmental Protection Agency (EPA) issued regulations revising the National Ambient Air Quality Standards for ozone and particulate matter. In May 1999, the U.S. Court of Appeals for the District of Columbia remanded the regulations back to the EPA for review. Litigation regarding appeals of these regulations is ongoing. New ambient standards may result in significant additional reductions in SO2 and NOx emissions from the Company's power plants by 2007. At this time, the Company is unable to predict the ultimate impact of these revised air quality standards on its future financial condition, results of operations or liquidity. In an attempt to lower ozone levels across the eastern United States, the EPA issued the implementation of regulations in September 1998 to reduce NOx emissions from coal-fired boilers and other sources in 22 states, including Missouri and Illinois (where all of the Company's coal-fired power plant boilers are located). The implementation of these regulations has been delayed by the U.S. Court of Appeals for the District of Columbia until a legal challenge brought by various industries and states has been resolved. The proposed regulations mandate a 75% reduction from 1990 levels by the year 2003 and require states to develop plans to reduce NOx emissions to help alleviate ozone problem areas. The NOx emissions reductions already achieved on several of the Company's coal-fired power plants will help to reduce the costs of compliance with these regulations. However, preliminary analysis of the regulations indicate that selective catalytic reduction technology may be required for some of the Company's units, as well as other additional controls. Currently, the Company estimates that its additional capital expenditures to comply with the final NOx regulations could range from $250 million to $300 million over the period from 1999 to 2003. Associated operations and maintenance expenditures could increase $10 million to $15 million annually, beginning in 2003. The Company is exploring alternatives to comply with these new regulations in order to minimize, to the extent possible, its capital costs and operating expenses. The Company is unable to predict the ultimate impact of these standards on its future financial condition, results of operations or liquidity. In November 1998, the United States signed an agreement with numerous other countries (the Kyoto Protocol) containing certain environmental provisions, which would require decreases in greenhouse gases in an effort to address the "global warming" issue. The Kyoto Protocol has not been ratified by the United States Senate. Implementation of the Kyoto Protocol in its present form would likely result in significantly higher capital costs and operations and maintenance expenses by the Company. At this time, the Company is unable to determine the impact of these proposals on the Company's future financial condition, results of operations or liquidity. See Note 13 - Callaway Nuclear Plant under Notes to Consolidated Financial Statements for a discussion of Callaway Plant decommissioning costs. Cash flows used in financing activities were $241 million for 1999, compared to $446 million for 1998 and $302 million for 1997. The Company's principal financing activities during 1999 included the issuance of $210 million of long-term debt, the redemption of $174 million of long-term debt and the payment of dividends. The Company plans to continue utilizing short-term debt to support normal operations and other temporary requirements. The Company and its subsidiaries are authorized by the Securities and Exchange Commission (SEC) under PUHCA to have up to an aggregate $2.8 billion of short-term unsecured debt instruments outstanding at any one time. Short-term borrowings consist of bank loans (maturities generally on an overnight basis) and commercial paper (maturities generally within 10 to 45 days). At December 31, 1999, the Company had committed bank lines of credit aggregating $180 million, all of which was unused and available at such date, which make available interim financing at various rates of interest based on LIBOR, the bank certificate of deposit rate or other options. The lines of credit are renewable annually at various dates throughout the year. The Company has bank credit agreements, expiring at various dates between 2000 and 2003, that support commercial paper programs totaling $800 million, $500 million of which is available for the Company's own use and for the use of its subsidiaries. The remaining $300 million is available for the use of the Company's regulated subsidiaries. At December 31, 1999, $520 million was unused and available. The Company had $80 million of short-term borrowings outstanding at year-end. AmerenUE also has a lease agreement that provides for the financing of nuclear fuel. At December 31, 1999, the maximum amount that could be financed under the agreement was $120 million. Cash used in financing for 1999 included issuances under the lease for nuclear fuel of $65 million, offset in part by $15 million of redemptions. At December 31, 1999, $116 million was financed under the lease. See Note 5 - Nuclear Fuel Lease under Notes to Consolidated Financial Statements for further information. The Company, in the ordinary course of business, explores opportunities to reduce its costs in order to remain competitive in the marketplace. Areas where the Company focuses its review include, but are not limited to, labor costs and fuel supply costs. In the labor area, the Company has recently reached agreements with many of the Company's major collective bargaining units which will permit it to manage its labor costs and practices effectively in the future. The Company also explores alternatives to effectively manage the size of its workforce. These alternatives include utilizing hiring freezes, outsourcing and offering employee separation packages. In the fuel supply area, the Company explores alternatives to effectively manage its overall fuel costs. These alternatives include diversifying fuel sources for use at the Company's fossil power plants (e.g. utilizing low-sulfur versus high-sulfur coal), as well as restructuring or terminating existing contracts with suppliers. Certain of these reduction alternatives could result in additional investments being made at the Company's power plants in order to utilize different types of coal, or could require nonrecurring payments of employee separation benefits or nonrecurring payments to restructure or terminate existing fuel contracts with a supplier. Management is unable to predict which (if any), and to what extent, these alternatives to reduce its overall cost structure will be executed. Management is unable to determine the impact of these actions on the Company's future financial position, results of operations or liquidity.

6 www.ameren.com page 19 DIVIDENDS Common stock dividends paid in 1999 resulted in a payout rate of 90% of the Company's net income. Dividends paid to common stockholders in relation to net cash provided by operating activities for the same period were 38%. The Board of Directors does not set specific targets or payout parameters for dividend payments; however, the Board considers various issues including the Company's historic earnings and cash flow; projected earnings, cash flow and potential cash flow requirements; dividend payout rates at other utilities; return on investments with similar risk characteristics; and overall business considerations. On February 11, 2000, the Ameren Board of Directors declared a quarterly common stock dividend of 63.5 cents per share, payable March 31, 2000. RATE MATTERS See Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for a discussion of rate matters. ELECTRIC INDUSTRY RESTRUCTURING Steps taken and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation, and encourage increased competition. At the federal level, the Energy Policy Act of 1992 reduced various restrictions on the operation and ownership of independent power producers and gave the FERC the authority to order electric utilities to provide transmission access to third parties. In April 1996, the FERC issued Order 888 and Order 889, which are intended to promote competition in the wholesale electric market. The FERC requires transmission-owning public utilities, such as AmerenUE and AmerenCIPS, to provide transmission access and service to others in a manner similar and comparable to that which the utilities have by virtue of ownership. Order 888 requires that a single tariff be used by the utility in providing transmission service. Order 888 also provides for the recovery of strandable costs, under certain conditions, related to the wholesale business. Order 889 established the standards of conduct and information requirements that transmission owners must adhere to in doing business under the open access rule. Under Order 889, utilities must obtain transmission service for their own use in the same manner their customers will obtain service, thus mitigating market power through control of transmission facilities. In addition, under Order 889, utilities must separate their merchant function (buying and selling wholesale power) from their transmission and reliability functions. The Company believes that Order 888 and Order 889, which relate to its wholesale business, will not have a material adverse effect on its financial condition, results of operations or liquidity. In 1998, Ameren's operating utility subsidiaries joined a group of companies that support the formation of the Midwest Independent System Operator (Midwest ISO). An ISO operates, but does not own, electric transmission systems and maintains system reliability and security, while alleviating pricing issues associated with the "pancaking" of rates. The Midwest ISO would be regulated by the FERC. Thirteen transmission-owning utilities have joined the Midwest ISO as of December 31, 1999. The FERC conditionally approved the formation of the Midwest ISO in September 1998, and it is expected to be operational during the year 2001. The MoPSC and the Illinois Commerce Commission (ICC) have authorized AmerenUE and AmerenCIPS to join the Midwest ISO and to transfer control of their transmission facilities to the Midwest ISO. The Midwest ISO covers 14 states, represents portions of 60,000 miles of transmission line and controls $8 billion of assets. The Company believes that the operation of the Midwest ISO will not have a material adverse effect on its financial condition, results of operations or liquidity. In December 1999, the FERC issued Order 2000 relating to Regional Transmission Organizations (RTOs) that would meet certain characteristics such as size and independence. Order 2000 calls on all transmission owners to join RTOs. In particular, all public utilities that own, operate, or control interstate transmission facilities must file with the FERC by October 15, 2000, a proposal for an RTO, or alternatively a description of efforts by the utility to join an RTO. The Company expects that its participation in the Midwest ISO will satisfy the requirements of Order 2000. ILLINOIS Certain states are considering proposals or have adopted legislation that will promote competition at the retail level. In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Illinois Law) providing for electric utility restructuring in Illinois. This legislation introduces competition into the supply of electric energy at retail in Illinois. Major provisions of the Illinois Law include the phasing-in through 2002 of retail direct access, which allows customers to choose their electric generation suppliers. The phase-in of retail direct access began on October 1, 1999, with large commercial and industrial customers principally comprising the initial group. The customers in this group represent approximately 10% of the Company's total sales. As of December 31, 1999, the impact of retail direct access on the Company's financial condition, results of operations or liquidity was immaterial. Retail direct access will be offered to the remaining commercial and industrial customers on December 31, 2000, and to residential customers on May 1, 2002. In addition, the Illinois Law included a 5% rate decrease for residential customers that became effective in August 1998. This rate decrease reduced electric revenues $8 million in 1999 compared to 1998 and is expected to impact electric revenues by approximately $14 million annually, based on estimated levels of sales and assuming normal weather conditions. (See Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information). In 1998, the Company eliminated its Uniform Fuel Adjustment Clauses (FACs) as allowed by the Illinois Law, which benefited shareholders in 1998 and 1999 and is expected to benefit shareholders in the future (see Note 1 - Summary of Significant Accounting Policies under Notes to Consolidated Financial Statements for further information). The Illinois Law contains a provision allowing for the potential recovery of a portion of strandable costs, which

7 page 20 Ameren Corporation 1999 Annual Report represent costs that would not be recoverable in a restructured environment, through a transition charge collected from customers who choose an alternate electric supplier. In addition, the Illinois Law contains a provision requiring a portion of excess earnings (as defined under the Illinois Law) for the years 1998 through 2004 to be refunded to customers. As of December 31, 1999, the Company recorded an estimated $5 million credit it expects to return to its Illinois customers under the Illinois Law for the two-year period ended December 31, 1999. See Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information. In December 1997, after evaluating the impact of the Illinois Law, the Company determined that it was necessary to write-off the generation-related regulatory assets and liabilities of its Illinois retail electric business. This extraordinary charge reduced 1997 earnings $52 million, net of income taxes, or 38 cents per share. The Company has also concluded that its remaining net generation-related assets are not impaired for financial reporting purposes and that no plant writedowns are necessary at this time. See Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information. In conjunction with another provision of the Illinois Law, in July 1999, AmerenCIPS filed a notice with the ICC that it intends to transfer AmerenCIPS' generating facilities (all in Illinois) to a new nonregulated subsidiary of Ameren. The formation of the new generating subsidiary, as well as the transfer of AmerenCIPS' generating assets and liabilities (at historical net book value) and certain power sales contracts, is subject to various regulatory proceedings. Certain regulatory approvals were received from the ICC, the FERC, and the MoPSC. An additional PUHCA-related determination that will permit the new generating subsidiary to operate as an Exempt Wholesale Generator will be sought from the FERC. The generating subsidiary will include most of the new combustion turbine generators being acquired by Ameren, in addition to the AmerenCIPS facilities (see Note 2-Regulatory Matters and Note 12 - Commitments and Contingencies under Notes to Consolidated Financial Statements for further information). The new subsidiary is expected to be operational in mid-2000, subject to the outcome of these regulatory proceedings. Once the transfer is completed, a power sales agreement would be in place between the new generating subsidiary and a nonregulated marketing affiliate for all generation. The marketing affiliate would have a power sales agreement with AmerenCIPS to supply it sufficient generation to meet native load requirements over the term of the agreement. Power will continue to be jointly dispatched between AmerenUE and the new generating subsidiary. The proposed transfer of AmerenCIPS' generating assets and liabilities had no effect on the Company's financial statements as of December 31, 1999. MISSOURI In Missouri, where approximately 73% of the Company's retail electric revenues are derived, a task force appointed by the MoPSC investigated electric industry restructuring and competition. In 1998 the task force issued a report to the MoPSC that addressed many of the restructuring issues, but did not provide a specific recommendation or approach to restructure the industry. In addition, in 1998, the MoPSC staff issued a proposed plan for restructuring Missouri's electric industry. The staff's plan addressed a number of issues of concern if the industry is restructured in Missouri. It also included a proposal for less than full recovery of strandable costs. The staff's plan has not been addressed by the MoPSC. A joint committee of the Missouri legislature is also conducting hearings on these issues. Several restructuring bills were introduced by the Missouri legislature in 1999 and 2000. The Company is unable to predict the timing or ultimate outcome of electric industry restructuring in the state of Missouri. SUMMARY In summary, the potential negative consequences associated with electric industry restructuring could be significant and could include the impairment and writedown of certain assets, including generation-related plant and net regulatory assets, lower revenues, reduced profit margins and increased costs of capital and operations expenses. The Company is actively taking steps to mitigate these potential negative consequences. Most importantly, the Company will continue to focus on cost control to ensure that it maintains a competitive cost structure, which includes the recent termination of high-cost coal supply contracts (see Note 12 - Commitments and Contingencies under Notes to Consolidated Financial Statements for further information). Also, in Illinois, the Company's actions include establishing a nonregulated generating subsidiary and expanding its generation assets, strengthening the Company's trading and marketing operations to maintain its current customers and obtain new customers, and enhancing its information systems. The Company believes that these actions will position the Company well in the competitive Illinois marketplace. In Missouri, the Company is actively involved in all major deliberations taking place surrounding electric industry restructuring in an effort to ensure that restructuring legislation, if any, contains an orderly transition and is equitable to the Company's shareholders. The Company is also actively involved in shaping the policies of the Midwest ISO to protect its shareholders' interests. At this time, the Company is unable to predict the ultimate impact of electric industry restructuring on the Company's future financial condition, results of operations or liquidity. YEAR 2000 ISSUE The Year 2000 Issue relates to how dates are stored and used in computer systems, applications, and embedded systems. As the century date change occurred, certain date-sensitive systems had to recognize the year as 2000 and not as 1900. This inability to recognize and properly treat the year as 2000 could have caused these systems to process critical financial and operational information incorrectly. Management implemented a Year 2000 plan and briefed Ameren's Board of Directors about the Year 2000 Issue and how it might have affected the Company. The Company encountered no significant problems associated with the Year

8 www.ameren.com page 21 2000 Issue at year-end. In addressing the Year 2000 Issue, the Company incurred internal labor costs as well as external consulting and other expenses to prepare for the new century. As of December 31, 1999, the Company had expended approximately $8 million in external costs (consulting fees and related costs). The impact of the Year 2000 Issue on the Company's financial condition, results of operations or liquidity was immaterial. The Company will continue to monitor date-sensitive systems as certain key dates occur throughout the year. CONTINGENCIES See Note 2 - Regulatory Matters, Note 12 - Commitments and Contingencies and Note 13 - Callaway Nuclear Plant under Notes to Consolidated Financial Statements for material issues existing at December 31, 1999. MARKET RISK RELATED TO FINANCIAL INSTRUMENTS AND COMMODITY INSTRUMENTS Market risk represents the risk of changes in value of a financial instrument, derivative or non-derivative, caused by fluctuations in market variables (e.g., interest rates, equity prices, commodity prices, etc.). The following discussion of the Company's risk management activities includes "forward-looking" statements that involve risks and uncertainties. Actual results could differ materially from those projected in the "forward-looking" statements. The Company handles market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, the Company also faces risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, operational, and credit risk and are not represented in the following analysis. INTEREST RATE RISK The Company is exposed to market risk through changes in interest rates through its issuance of both long-term and short-term variable-rate debt, fixed-rate debt, commercial paper and auction market preferred stock. The Company manages its interest rate exposure by controlling the amount of these instruments it holds within its total capitalization portfolio and by monitoring the effects of market changes in interest rates. If interest rates increase 1% in 2000, as compared to 1999, the Company's interest expense would increase by approximately $9 million, and net income would decrease by approximately $5 million. This amount has been determined using the assumptions that the Company's outstanding variable-rate debt, commercial paper and auction market preferred stock, as of December 31, 1999, continued to be outstanding throughout 2000, and that the average interest rates for these instruments increased 1% over 1999. The model does not consider the effects of the reduced level of potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate its exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no change in the Company's financial structure. COMMODITY PRICE RISK The Company is exposed to changes in market prices for natural gas, fuel and electricity. With regard to its natural gas utility business, the Company's exposure to changing market prices is in large part mitigated by the fact that the Company has Purchased Gas Adjustment Clauses (PGAs) in place in both its Missouri and Illinois jurisdictions. The PGAs allow the Company to pass on to its customers its prudently incurred costs of natural gas. With approval of the MoPSC, AmerenUE participated in an experimental program to control the volatility of gas prices paid by its Missouri customers in the 1998-1999 winter months through the purchase of financial instruments. This program concluded in April 1999. Since the Company does not have a provision similar to the PGA for its electric operations, the Company has entered into several long-term contracts with various suppliers to purchase coal and nuclear fuel to manage its exposure to fuel prices. (See Note 12 - Commitments and Contingencies under Notes to Consolidated Financial Statements for further information). With regard to the Company's exposure to commodity price risk for purchased power and excess electricity sales, the Company has established a subsidiary, AmerenEnergy, whose primary responsibility includes managing market risks associated with changing market prices for electricity purchased and sold on behalf of the Company's operating subsidiaries, AmerenUE and AmerenCIPS. AmerenEnergy utilizes several techniques to mitigate its market risk for electricity, including utilizing derivative financial instruments. A derivative is a contract whose value is dependent on or derived from the value of some underlying asset. The derivative financial instruments that AmerenEnergy is allowed to utilize (which include forward contracts, futures contracts, and option contracts) are dictated by a risk management policy, which has been reviewed with the Auditing Committee of Ameren's Board of Directors. Compliance with the risk management policy is the responsibility of a risk management steering committee, consisting of Company officers and an independent risk management officer at AmerenEnergy. As of December 31, 1999, the fair value of derivative financial instruments exposed to commodity price risk was immaterial. AmerenEnergy's primary use of derivatives has been limited to transactions that are either risk-neutral or that reduce price risk exposure of the Company. EQUITY PRICE RISK The Company maintains trust funds, as required by the Nuclear Regulatory Commission and Missouri and Illinois state laws, to fund certain costs of nuclear decommissioning (see Note 13 - Callaway Nuclear Plant under Notes to Consolidated Financial Statements for further information). As of December 31, 1999, these funds were invested primarily in domestic equity securities, fixed-rate, fixed-income securities, and cash and cash equivalents. By maintaining a portfolio that includes long-term equity investments, the Company is seeking to maximize the returns to be utilized to fund nuclear decommissioning costs. However, the

9 page 22 Ameren Corporation 1999 Annual Report equity securities included in the Company's portfolio are exposed to price fluctuations in equity markets, and the fixed-rate, fixed-income securities are exposed to changes in interest rates. The Company actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, established target allocation percentages of the assets of its trusts to various investment options. The Company's exposure to equity price market risk is in large part mitigated due to the fact that the Company is currently allowed to recover its decommissioning costs in its rates. ACCOUNTING MATTERS In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities and requires recognition of all derivatives as either assets or liabilities on the balance sheet measured at fair value. The intended use of the derivatives and their designation as either a fair value hedge, a cash flow hedge, or a foreign currency hedge will determine when the gains or losses on the derivatives are to be reported in earnings and when they are to be reported as a component of other comprehensive income. In June 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133," which delayed the effective date of SFAS 133 to all fiscal quarters of all fiscal years, beginning after June 15, 2000. Earlier application is still encouraged. The Company expects to adopt SFAS 133 in the first quarter of 2001. The Company is currently evaluating the impact of SFAS 133 on its financial position and results of operations upon adoption. The Company's evaluation includes reviewing existing derivative instruments and contracts to determine the appropriate accounting for these items under SFAS 133. At this time, management believes that adoption of SFAS 133 will not have a material impact on the Company's financial position or results of operations upon adoption based on the derivative instruments which existed as of December 31, 1999. However, changing market conditions, the volume of future transactions which may fall within the scope of SFAS 133, and potential amendments to SFAS 133 could change management's current assessment. As a result, SFAS 133 could increase the volatility of the Company's future earnings and could be material to the Company's financial position and results of operations upon adoption. EFFECTS OF INFLATION AND CHANGING PRICES The Company's rates for retail electric and gas utility service are generally regulated by the MoPSC and the ICC. Non-retail electric rates are regulated by the FERC. The current replacement cost of the Company's utility plant substantially exceeds its recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical costs through depreciation might not be adequate to replace plants in future years. Regulatory practice has been modified for the Company's generation portion of its business in its Illinois jurisdiction and may be modified in the future for the Company's Missouri jurisdiction (see Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information). In addition, the impact on common stockholders is mitigated to the extent depreciable property is financed with debt that is repaid with dollars of less purchasing power. In the Illinois retail jurisdiction, the cost of fuel for electric generation, which was previously reflected in billings to customers through Uniform Fuel Adjustment Clauses, has been added to base rates as provided for in the Illinois Law (see Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information). In the Missouri retail jurisdiction, the cost of fuel for electric generation is reflected in base rates with no provision for changes to be made through a fuel adjustment clause. In Illinois and Missouri, changes in gas costs are generally reflected in billings to customers through Purchased Gas Adjustment Clauses. Inflation continues to be a factor affecting operations, earnings, stockholders' equity and financial performance. SAFE HARBOR STATEMENT Statements made in this annual report to stockholders which are not based on historical facts, are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, financial performance and the Year 2000 Issue. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Company is providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in subsequent securities filings, could cause results to differ materially from management expectations as suggested by such "forward-looking" statements: the effects of regulatory actions; changes in laws and other governmental actions; the impact on the Company of current regulations related to the phasing-in of the opportunity for some customers to choose alternative energy suppliers in Illinois; the effects of increased competition in the future due to, among other things, deregulation of certain aspects of the Company's business at both the state and Federal levels; future market prices for fuel and purchased power, electricity, and natural gas, including the use of financial instruments; average rates for electricity in the Midwest; business and economic conditions; interest rates; weather conditions; fuel prices and availability; generation plant performance; the impact of current environmental regulations on utilities and generating companies and the expectation that more stringent requirements will be introduced over time, which could potentially have a negative financial effect; monetary and fiscal policies; future wages and employee benefits costs; and legal and administrative proceedings.

10 www.ameren.com page 23 CONSOLIDATED STATEMENT OF INCOME <TABLE> <CAPTION> Thousands of Dollars, Except Share and Per Share Amounts Year Ended December 31, 1999 1998 1997 ------------------------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> OPERATING REVENUES: Electric $ 3,287,590 $ 3,094,211 $ 3,064,177 Gas 228,298 216,681 249,815 Other 7,743 7,316 12,551 -------------------------------------------------------- TOTAL OPERATING REVENUES 3,523,631 3,318,208 3,326,543 -------------------------------------------------------- OPERATING EXPENSES: Operations Fuel and purchased power 973,277 780,123 836,445 Gas 131,449 118,846 160,679 Other 629,482 647,157 585,214 -------------------------------------------------------- 1,734,208 1,546,126 1,582,338 -------------------------------------------------------- Maintenance 370,873 312,011 310,241 Depreciation and amortization 350,539 348,403 346,000 Income taxes 258,870 267,673 234,179 Other taxes 246,592 272,774 271,711 -------------------------------------------------------- TOTAL OPERATING EXPENSES 2,961,082 2,746,987 2,744,469 -------------------------------------------------------- OPERATING INCOME 562,549 571,221 582,074 -------------------------------------------------------- OTHER INCOME AND (DEDUCTIONS): Allowance for equity funds used during construction 7,161 5,001 5,244 Miscellaneous, net (10,813) (2,609) (10,344) -------------------------------------------------------- TOTAL OTHER INCOME AND (DEDUCTIONS) (3,652) 2,392 (5,100) -------------------------------------------------------- INCOME BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS 558,897 573,613 576,974 -------------------------------------------------------- INTEREST CHARGES AND PREFERRED DIVIDENDS: Interest 168,275 181,580 185,368 Allowance for borrowed funds used during construction (7,123) (7,026) (7,462) Preferred dividends of subsidiaries 12,650 12,562 12,532 -------------------------------------------------------- NET INTEREST CHARGES AND PREFERRED DIVIDENDS 173,802 187,116 190,438 -------------------------------------------------------- INCOME BEFORE EXTRAORDINARY CHARGE 385,095 386,497 386,536 EXTRAORDINARY CHARGE, NET OF INCOME TAXES (NOTE 2) -- -- (51,820) -------------------------------------------------------- NET INCOME $ 385,095 $ 386,497 $ 334,716 -------------------------------------------------------- EARNINGS PER COMMON SHARE - BASIC AND DILUTED (BASED ON AVERAGE SHARES OUTSTANDING) Income before extraordinary charge $ 2.81 $ 2.82 $ 2.82 Extraordinary charge -- -- (.38) -------------------------------------------------------- NET INCOME $ 2.81 $ 2.82 $ 2.44 -------------------------------------------------------- AVERAGE COMMON SHARES OUTSTANDING 137,215,462 137,215,462 137,215,462 -------------------------------------------------------- </TABLE> See Notes to Consolidated Financial Statements.

11 page 24 Ameren Corporation 1999 Annual Report CONSOLIDATED BALANCE SHEET <TABLE> <CAPTION> Thousands of Dollars December 31, 1999 1998 ------------------------------------------------------------------------------------------------------------------------------------ <S> <C> <C> ASSETS PROPERTY AND PLANT, AT ORIGINAL COST: Electric $12,053,411 $11,761,306 Gas 491,708 469,216 Other 92,696 44,646 ----------------------------------- 12,637,815 12,275,168 Less accumulated depreciation and amortization 5,891,340 5,602,816 ----------------------------------- 6,746,475 6,672,352 Construction work in progress: Nuclear fuel in process 88,830 108,294 Other 329,880 147,393 ----------------------------------- TOTAL PROPERTY AND PLANT, NET 7,165,185 6,928,039 ----------------------------------- INVESTMENTS AND OTHER ASSETS: Investments 66,476 86,694 Nuclear decommissioning trust fund 186,760 161,877 Other 80,737 78,091 ----------------------------------- TOTAL INVESTMENTS AND OTHER ASSETS 333,973 326,662 ----------------------------------- CURRENT ASSETS: Cash and cash equivalents 194,882 76,863 Accounts receivable - trade (less allowance for doubtful accounts of $7,136 and $8,393, respectively) 216,344 198,193 Unbilled revenue 154,097 150,481 Other accounts and notes receivable 20,668 76,919 Materials and supplies, at average cost: Fossil fuel 123,143 112,908 Other 130,081 132,884 Other 39,791 22,912 ----------------------------------- TOTAL CURRENT ASSETS 879,006 771,160 ----------------------------------- REGULATORY ASSETS: Deferred income taxes 622,520 633,529 Other 176,931 188,049 ----------------------------------- TOTAL REGULATORY ASSETS 799,451 821,578 ----------------------------------- TOTAL ASSETS $ 9,177,615 $ 8,847,439 ----------------------------------- </TABLE> See Notes to Consolidated Financial Statements.

12 www.ameren.com page 25 <TABLE> <CAPTION> Thousands of Dollars, Except Share and Per Share Amounts December 31, 1999 1998 ------------------------------------------------------------------------------------------------------------------------------------ <S> <C> <C> CAPITAL AND LIABILITIES CAPITALIZATION: Common stock, $.01 par value, 400,000,000 shares authorized - 137,215,462 shares outstanding (Note 6) $ 1,372 $ 1,372 Other paid-in capital, principally premium on common stock 1,582,501 1,582,548 Retained earnings (see accompanying statement) 1,505,827 1,472,200 -------------------------------- Total Common Stockholders' Equity 3,089,700 3,056,120 Preferred stock not subject to mandatory redemption (Note 6) 235,197 235,197 Long-term debt (Note 8) 2,448,448 2,289,424 -------------------------------- TOTAL CAPITALIZATION 5,773,345 5,580,741 -------------------------------- MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES 4,010 3,534 -------------------------------- CURRENT LIABILITIES: Current maturity of long-term debt (Note 8) 128,867 201,713 Short-term debt 80,165 58,528 Accounts and wages payable 341,274 284,818 Accumulated deferred income taxes 70,719 66,299 Taxes accrued 155,396 114,106 Other 300,747 216,889 -------------------------------- TOTAL CURRENT LIABILITIES 1,077,168 942,353 -------------------------------- Commitments and Contingencies (Notes 2, 12 and 13) Accumulated deferred income taxes 1,493,634 1,521,417 Accumulated deferred investment tax credits 170,834 178,832 Regulatory liability 188,404 198,937 Other deferred credits and liabilities 470,220 421,625 -------------------------------- TOTAL CAPITAL AND LIABILITIES $9,177,615 $8,847,439 ================================ </TABLE> See Notes to Consolidated Financial Statements.

13 page 26 Ameren Corporation 1999 Annual Report CONSOLIDATED STATEMENT OF CASH FLOWS <TABLE> <CAPTION> Thousands of Dollars Year Ended December 31, 1999 1998 1997 ------------------------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> CASH FLOWS FROM OPERATING: Income before extraordinary charge $ 385,095 $ 386,497 $ 386,536 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 340,329 338,488 340,079 Amortization of nuclear fuel 36,068 36,855 37,126 Allowance for funds used during construction (14,284) (12,027) (12,706) Deferred income taxes, net (22,578) (24,849) (24,499) Deferred investment tax credits, net (7,998) (11,428) (18,967) Changes in assets and liabilities: Receivables, net 34,484 (6,658) 11,476 Materials and supplies (7,432) (18,209) 16,523 Accounts and wages payable 56,456 (8,573) (3,626) Taxes accrued 41,290 3,540 45,321 Other 76,145 119,608 (68,820) -------------------------------------------------- NET CASH PROVIDED BY OPERATING ACTIVITIES 917,575 803,244 708,443 -------------------------------------------------- CASH FLOWS FROM INVESTING: Construction expenditures (570,807) (324,905) (380,593) Allowance for funds used during construction 14,284 12,027 12,706 Nuclear fuel expenditures (21,901) (20,432) (35,432) Other 20,218 10,494 16,122 -------------------------------------------------- NET CASH USED IN INVESTING ACTIVITIES (558,206) (322,816) (387,197) -------------------------------------------------- CASH FLOWS FROM FINANCING: Dividends on common stock (348,527) (348,527) (331,282) Redemptions: Nuclear fuel lease (15,138) (67,720) (28,292) Short-term debt -- (27,738) -- Long-term debt (174,444) (273,444) (123,444) Preferred stock -- -- (63,924) Issuances: Nuclear fuel lease 64,972 16,439 40,337 Short-term debt 21,637 -- 17,198 Long-term debt 210,150 255,000 187,000 -------------------------------------------------- NET CASH USED IN FINANCING ACTIVITIES (241,350) (445,990) (302,407) -------------------------------------------------- NET CHANGE IN CASH AND CASH EQUIVALENTS 118,019 34,438 18,839 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 76,863 42,425 23,586 -------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF YEAR $ 194,882 $ 76,863 $ 42,425 ================================================== Cash paid during the periods: Interest (net of amount capitalized) $ 162,705 $ 175,168 $ 162,459 Income taxes $ 247,428 $ 298,589 $ 249,477 </TABLE> SUPPLEMENTAL DISCLOSURE OF NONCASH TRANSACTION An extraordinary charge to earnings was recorded in the fourth quarter of 1997 for the write-off of generation-related regulatory assets and liabilities of the Company's Illinois retail electric business as a result of electric industry restructuring legislation enacted in Illinois in December 1997. The write-off reduced earnings $52 million, net of income taxes. See Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information. See Notes to Consolidated Financial Statements.

14 www.ameren.com page 27 CONSOLIDATED STATEMENT OF RETAINED EARNINGS <TABLE> <CAPTION> Thousands of Dollars Year Ended December 31, 1999 1998 1997 --------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> BALANCE AT BEGINNING OF PERIOD $1,472,200 $1,434,658 $1,431,295 Add: Net income 385,095 386,497 334,716 Deduct: Dividends 351,468 348,955 331,353 ------------------------------------------- BALANCE AT CLOSE OF PERIOD $1,505,827 $1,472,200 $1,434,658 =========================================== </TABLE> SELECTED QUARTERLY INFORMATION (Unaudited) <TABLE> <CAPTION> Thousands of Dollars, Except Per Share Amounts ------------------------------------------------------------------------------------------------------------------------- Quarter Ended Operating Operating Net Income Earnings (Loss) Revenues Income (Loss) Per Common Share <S> <C> <C> <C> <C> MARCH 31, 1999 (a) $ 735,902 $ 99,687 $ 54,359 $ .40 March 31, 1998 (a) 700,810 90,432 39,927 .29 ------------------------------------------------------------------------------- JUNE 30, 1999 859,884 130,512 86,519 .63 June 30, 1998 (b) 821,777 128,158 83,632 .61 ------------------------------------------------------------------------------- SEPTEMBER 30, 1999 1,193,462 296,727 249,819 1.82 September 30, 1998 (c) 1,117,118 283,652 236,657 1.73 ------------------------------------------------------------------------------- DECEMBER 31, 1999 (d) 734,383 35,623 (5,602) (.04) December 31, 1998 678,503 68,979 26,281 .19 =============================================================================== </TABLE> (a) The first quarter of 1999 and 1998 included credits to Missouri electric customers that reduced net income approximately $11 million, or 8 cents per share, and $6 million, or 4 cents per share, respectively. (b) The second quarter of 1998 included credits to Missouri electric customers that reduced net income approximately $18 million, or 14 cents per share. Callaway Plant refueling expenses, which decreased net income approximately $18 million, or 13 cents per share, were also included in the second quarter of 1998. (c) The third quarter of 1998 included a nonrecurring charge related to the targeted employee separation plan that reduced net income $15 million, or 11 cents per share. (See Note 3 - Targeted Separation Plan under Notes to Consolidated Financial Statements for further information). (d) The fourth quarter of 1999 included adjustments that increased earnings $9 million, or 6 cents per share, as a result of a Report and Order received from the Missouri Public Service Commission relating to the Company's alternative regulation plan. (See Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for further information). The fourth quarter of 1999 also included a charge of $31 million, or 23 cents per share, for coal supply contract terminations. (See Note 12 - Commitments and Contingencies under Notes to Consolidated Financial Statements for further information). In addition, Callaway Plant refueling expenses, which decreased net income approximately $22 million, or 16 cents per share, were included in the fourth quarter of 1999. Other changes in quarterly earnings are due to the effect of weather on sales and other factors that are characteristic of public utility operations. See Notes to Consolidated Financial Statements.

15 page 28 Ameren Corporation 1999 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION Ameren Corporation (Ameren) is a holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA). In December 1997, Union Electric Company (AmerenUE) and CIPSCO Incorporated (CIPSCO) combined to form Ameren, with AmerenUE and CIPSCO's subsidiaries, Central Illinois Public Service Company (AmerenCIPS) and CIPSCO Investment Company (CIC), becoming subsidiaries of Ameren (the Merger). The accompanying consolidated financial statements (the financial statements) reflect the accounting for the Merger as a pooling of interests and are presented as if the companies were combined as of the earliest period presented. However, the financial information is not necessarily indicative of the results of operations, financial position or cash flows that would have occurred had the Merger been consummated for the periods for which it is given effect, nor is it necessarily indicative of future results of operations, financial position or cash flows. The outstanding preferred shares of AmerenUE and AmerenCIPS were not affected by the Merger. The accompanying financial statements include the accounts of Ameren and its consolidated subsidiaries (collectively the Company). All subsidiaries for which the Company owns directly or indirectly more than 50% of the voting stock are included as consolidated subsidiaries. Ameren's primary operating companies, AmerenUE and AmerenCIPS, are engaged principally in the generation, transmission, distribution and sale of electric energy and the purchase, distribution, transportation and sale of natural gas. The operating companies serve 1.5 million electric and 300,000 natural gas customers in a 44,500-square-mile area of Missouri and Illinois. The Company's nonregulated subsidiaries include CIC, an investing subsidiary; AmerenEnergy, Inc., an energy marketing subsidiary; Ameren Development Company, a nonregulated products and services subsidiary; Ameren Intermediate Holding Company, a holding company for the proposed Illinois nonregulated generating subsidiary and its proposed marketing affiliate (see Note 2 - Regulatory Matters for further information); and Ameren Services Company, a shared support services subsidiary. The Company also has a 60% interest in Electric Energy, Inc. (EEI). EEI owns and operates an electric generation and transmission facility in Illinois that supplies electric power primarily to a uranium enrichment plant located in Paducah, Kentucky. All significant intercompany balances and transactions have been eliminated from the consolidated Financial statements. REGULATION Ameren is subject to regulation by the Securities and Exchange Commission (SEC). AmerenUE is also regulated by the Missouri Public Service Commission (MoPSC), Illinois Commerce Commission (ICC) and the Federal Energy Regulatory Commission (FERC). AmerenCIPS is also regulated by the ICC and the FERC. The accounting policies of the Company conform to U.S. generally accepted accounting principles (GAAP). See Note 2 - Regulatory Matters for further information. PROPERTY AND PLANT The cost of additions to, and betterments of, units of property and plant is capitalized. Cost includes labor, material, applicable taxes and overheads. An allowance for funds used during construction is also added for the Company's regulated assets, and interest during construction is added for nonregulated assets. Maintenance expenditures and the renewal of items not considered units of property are charged to income, as incurred. When units of depreciable property are retired, the original cost and removal cost, less salvage value, are charged to accumulated depreciation. DEPRECIATION Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis. The provision for depreciation in 1999, 1998 and 1997 was approximately 3% of the average depreciable cost. FUEL AND GAS COSTS In the Missouri and Illinois retail electric jurisdictions, the cost of fuel for electric generation is reflected in base rates with no provision for changes to be made through fuel adjustment clauses. (See Note 2 - Regulatory Matters for further information.) In the Illinois jurisdiction in 1997, changes in fuel costs were generally reflected in billings to electric customers through fuel adjustment clauses. In the Illinois and Missouri retail gas jurisdictions, changes in gas costs are generally reflected in billings to gas customers through purchased gas adjustment clauses. NUCLEAR FUEL The cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is charged to expense based on net kilowatthours generated and sold. CASH AND CASH EQUIVALENTS Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less. INCOME TAXES The Company and its subsidiaries file a consolidated federal tax return. Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes, measured using statutory tax rates. Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the related properties. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION Allowance for funds used during construction (AFC) is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds (preferred and common stockholders' equity) applicable to the Company's regulated construction program are capitalized as a cost of construction. AFC does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials. Under accepted ratemaking practice, cash recovery of AFC, as well as other construction costs, occurs when completed projects are placed in service and reflected in customer rates. The AFC ranges of rates used were 5% - 10% during 1999, 6% - 9% during 1998, and 8% - 9% during 1997. UNAMORTIZED DEBT DISCOUNT, PREMIUM AND EXPENSE Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues. REVENUE The Company accrues an estimate of electric and gas revenues for service rendered, but unbilled, at the end of each accounting period.

16 www.ameren.com page 29 ENERGY CONTRACTS The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) Issue 98-10, "Accounting for Energy Trading and Risk Management Activities" became effective on January 1, 1999. EITF 98-10 provides guidance on the accounting for energy contracts entered into for the purchase or sale of electricity, natural gas, capacity and transportation. The EITF reached a consensus in EITF 98-10 that sales and purchase activities being performed need to be classified as either trading or nontrading. Furthermore, transactions that are determined to be trading activities would be recognized on the balance sheet measured at fair value, with gains and losses included in earnings. AmerenEnergy, Inc., an energy marketing subsidiary of Ameren, enters into contracts for the sale and purchase of energy on behalf of AmerenUE and AmerenCIPS. Currently, virtually all of AmerenEnergy's transactions are considered nontrading activities and are accounted for using the accrual or settlement method, which represents industry practice. EITF 98-10 did not have a material impact on the Company's financial position or results of operations upon adoption. SOFTWARE Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use" became effective on January 1, 1999. SOP 98-1 provides guidance on accounting for the costs of computer software developed or obtained for internal use. Under SOP 98-1, certain costs may be capitalized and amortized over some future period. SOP 98-1 did not have a material impact on the Company's financial position or results of operations upon adoption. EVALUATION OF ASSETS FOR IMPAIRMENT Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" prescribes general standards for the recognition and measurement of impairment losses. The Company determines if long-lived assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount. An impairment loss is recognized if the undiscounted expected future cash flows are less than the carrying amount of the asset. SFAS 121 also requires that regulatory assets which are no longer probable of recovery through future revenues be charged to earnings (see Note 2 - Regulatory Matters for further information). As of December 31, 1999, no impairment was identified. STOCK COMPENSATION PLANS The Company applies Accounting Principles Board Opinion (APB) 25, "Accounting for Stock Issued to Employees" in accounting for its plans. See Note 11 - Stock Option Plans for further information. EARNINGS PER SHARE The Company's calculation of basic and diluted earnings per share resulted in the same earnings per share amounts for each of the years 1999, 1998 and 1997. The reconciling item in each of the years is comprised of assumed stock option conversions which increased the number of shares outstanding in the diluted earnings per share calculation by 38,786 shares, 29,787 shares and 7,318 shares in 1999, 1998 and 1997, respectively. USE OF ESTIMATES The preparation of Financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from those estimates. RECLASSIFICATIONS Certain reclassifications have been made to prior-years' financial statements to conform with 1999 reporting. NOTE 2 REGULATORY MATTERS MISSOURI ELECTRIC In July 1995, the MoPSC approved an agreement establishing contractual obligations involving the Company's Missouri retail electric rates. Included was a three-year experimental alternative regulation plan (the Original Plan) that ran from July 1, 1995, through June 30, 1998, which provided that earnings in those years in excess of a 12.61% regulatory return on equity (ROE) be shared equally between customers and stockholders, and earnings above a 14% ROE be credited to customers. The formula for computing the credit used twelve-month results ending June 30, rather than calendar year earnings. In 1996, the Company recorded a $47 million credit for the first year of the Original Plan. This credit reduced earnings $28 million, or 20 cents per share. During 1997, the Company recorded a $20 million credit for the second year of the Original Plan, which reduced earnings $11 million, or 8 cents per share. In 1998, the Company recorded an estimated $43 million credit for the final year of the Original Plan, which reduced earnings $26 million, or 18 cents per share. Included in the joint agreement approved by the MoPSC in its February 1997 order authorizing the Merger, was a new three-year experimental alternative regulation plan (the New Plan) that runs from July 1, 1998, through June 30, 2001. Like the Original Plan, the New Plan requires that earnings over a 12.61% ROE up to a 14% ROE be shared equally between customers and shareholders. The New Plan also returns to customers 90% of all earnings above a 14% ROE up to a 16% ROE. Earnings above a 16% ROE are credited entirely to customers. In addition, the joint agreement provides for a Missouri electric rate decrease, retroactive to September 1, 1998, based on the weather-adjusted average annual credits to customers under the Original Plan. The Company estimated that its Missouri electric rate decrease should approximate $20 million on an annualized basis and reduced revenues accordingly since September 1998. In November 1998, the MoPSC staff proposed adjustments to the customer credit for the third year of the Original Plan. In addition, the MoPSC staff proposed adjustments to the Company's estimated Missouri electric rate decrease based upon their methodology of calculating the weather-adjusted credits. The determination of the credit for the third year of the Original Plan, as well as the determination of the Missouri electric rate decrease, were subject to regulatory proceedings before the MoPSC in 1999. On December 23, 1999, the MoPSC issued a Report and Order (Order) related to the customer credit for the third year of the Original Plan. Certain of the MoPSC staff's proposed adjustments were accepted by the MoPSC in the Order. In addition, the Order requires the Company to capitalize and amortize certain costs (including computer software costs) that had previously been expensed for its Missouri electric operations.

17 page 30 Ameren Corporation 1999 Annual Report Based on the provisions of the Order, the Company estimates that the credit for the third year of the Original Plan will approximate $31 million. In addition, with regard to the Missouri electric rate decrease, the Company, the MoPSC staff, and other parties reached a settlement related to the calculation of the weather-adjusted credits. As a result, the Company estimates that the annualized Missouri electric rate decrease will approximate $17 million. Both of these estimates are subject to final approval of the MoPSC. The provisions of the Order also have an impact on the estimated credit to electric customers recorded by the Company for the first year of the New Plan. As a result, the Company recorded an estimated credit of $25 million for the plan year ended June 30, 1999. In addition, the Company recorded an estimated $20 million credit for the 1999 portion of the second year of the New Plan. Also, the provision of the Order which requires the Company to capitalize and amortize certain costs (including computer software costs) that had been previously expensed resulted in the capitalization of approximately $20 million of costs in the fourth quarter of 1999. In summary, the provisions of the Order and the resulting changes in the Company's estimates of credits and Missouri electric rate decrease for the open years under the Original Plan and the New Plan resulted in an increase in earnings of approximately $9 million, or 6 cents per share in the fourth quarter of 1999. On December 30, 1999, the Company filed a request for rehearing with the MoPSC, asking that it reconsider its decision to adopt certain of the MoPSC staff's adjustments. On January 25, 2000, the MoPSC denied the Company's request. The Company plans to file an appeal with the courts. GAS In February 1999, the ICC approved a $9 million total annual rate increase for natural gas service in AmerenUE's and AmerenCIPS' Illinois jurisdictions. The increase became effective in February 1999. In December 1997, the MoPSC approved a $12 million annual rate increase for natural gas service in AmerenUE's Missouri jurisdiction. The rate increase became effective in February 1998. MIDWEST ISO In 1998, Ameren's operating subsidiaries joined a group of companies that support the formation of the Midwest Independent System Operator (Midwest ISO). An ISO operates, but does not own, electric transmission systems and maintains system reliability and security while alleviating pricing issues associated with the "pancaking" of rates. The Midwest ISO would be regulated by the FERC. Thirteen transmission-owning utilities have joined the Midwest ISO, as of December 31, 1999. The FERC conditionally approved the formation of the Midwest ISO in September 1998, and it is expected to be operational during the year 2001. The MoPSC and the ICC have authorized AmerenUE and AmerenCIPS to join the Midwest ISO and to transfer control of their transmission facilities to the Midwest ISO. The Midwest ISO covers 14 states, represents portions of 60,000 miles of transmission line and controls $8 billion in assets. The Company believes that the operation of the Midwest ISO will not have a material adverse effect on its financial condition, results of operations or liquidity. In December 1999, the FERC issued its Order 2000 relating to Regional Transmission Organizations (RTOs) that would meet certain characteristics such as size and independence. Order 2000 calls on all transmission owners to join RTOs. In particular, all public utilities that own, operate, or control interstate transmission facilities must file with the FERC by October 15, 2000, a proposal for an RTO, or alternatively a description of efforts by the utility to join an RTO. The Company expects that its participation in the Midwest ISO will satisfy the requirements of Order 2000. ILLINOIS ELECTRIC RESTRUCTURING Certain states are considering proposals or have adopted legislation that will promote competition at the retail level. In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Illinois Law) providing for electric utility restructuring in Illinois. This legislation introduces competition into the supply of electric energy at retail in Illinois. Under the Illinois Law, retail direct access, which allows customers to choose their electric generation suppliers, will be phased in over several years. Access for commercial and industrial customers will occur over a period from October 1999 to December 2000, and access for residential customers will occur after May 1, 2002. As a requirement of the Illinois Law, in March 1999, AmerenUE and AmerenCIPS filed delivery service tariffs with the ICC. These tariffs would be used by electric customers who choose to purchase their power from alternate suppliers. On August 25, 1999, the ICC issued an order approving the delivery services tariffs, with an allowed rate of return on equity of 10.45%. AmerenUE and AmerenCIPS filed a joint petition for rehearing of that order requesting the ICC to alter its conclusions on a number of issues. On October 13, 1999, the ICC granted a rehearing on certain issues. An order on this reopened proceeding is expected in early 2000. The Illinois Law included a 5% residential electric rate decrease for the Company's Illinois electric customers, effective August 1, 1998. This rate decrease reduced electric revenues approximately $8 million in 1999. The Company may be subject to additional 5% residential electric rate decreases in each of 2000 and 2002, to the extent its rates exceed the Midwest utility average at that time. The Company's rates are currently below the Midwest utility average. As a result of the Illinois Law, AmerenUE and AmerenCIPS filed proposals with the ICC to eliminate their electric fuel adjustment clauses for Illinois retail customers, thereby including historical levels of fuel costs in base rates. The ICC approved AmerenUE's and AmerenCIPS' filings in early 1998. The Illinois Law also contains a provision requiring that one-half of excess earnings from the Illinois jurisdiction for the years 1998 through 2004 be refunded to Ameren's Illinois customers. Excess earnings are defined as the portion of the two-year average annual rate of return on common equity in excess of 1.5% of the two-year average of an Index, as defined in the Illinois Law. The Index is defined as the sum of the average for the twelve months ended September 30 of the average monthly yields of the 30-year US Treasury bonds, plus prescribed percentages ranging from 4% to 7%. Filings must be made with the ICC on, or before, March 31 of each year 2000 through 2005. As of December 31, 1999, the Company recorded an estimated $5 million credit it expects to return to its customers under the Illinois Law for the two-year period ended December 31, 1999. In conjunction with another provision of the Illinois Law, in July 1999, AmerenCIPS filed a notice with the ICC that it intends to transfer AmerenCIPS' generating facilities (all in Illinois) to a new nonregulated subsidiary of Ameren. The formation of the new generating subsidiary, as well as the transfer of AmerenCIPS' generating assets and liabilities (at historical

18 www.ameren.com page 31 net book value) and certain power sales contracts, are subject to various regulatory proceedings. Certain regulatory approvals were received from the ICC, the FERC, and the MoPSC. An additional PUHCA-related determination that will permit the new generating subsidiary to operate as an Exempt Wholesale Generator will be sought from the FERC. The generating subsidiary will include most of the new combustion turbine generators being acquired by Ameren in addition to the AmerenCIPS facilities. (See Note 12 - Commitments and Contingencies for further information.) The new generating subsidiary is expected to be operational in mid-2000, subject to the outcome of these regulatory proceedings. The proposed transfer of AmerenCIPS' generating assets and liabilities had no effect on Ameren's financial statements as of December 31, 1999. Once the transfer is completed, a power sales agreement would be in place between the new generating subsidiary and a nonregulated marketing affiliate for all generation. The marketing affiliate would have a power sales agreement with AmerenCIPS to supply it sufficient generation to meet native load requirements over the term of the agreement. Power will continue to be jointly dispatched between AmerenUE and the new generating subsidiary. Other provisions of the Illinois Law include (1) potential recovery of a portion of strandable costs, which represent costs which would not be recoverable in a restructured environment, through a transition charge collected from customers who choose another electric supplier; (2) a mechanism to securitize certain future revenues; and (3) a provision relieving the Company of the requirement to file electric rate cases or alternative regulatory plans in Illinois, following the consummation of the Merger to reflect the effects of net merger savings. The Company's accounting policies and financial statements conform to GAAP applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Such effects concern mainly the time at which various items enter into the determination of net income in order to follow the principle of matching costs and revenues. For example, SFAS 71 allows the Company to record certain assets and liabilities (regulatory assets and regulatory liabilities) that are expected to be recovered or settled in future rates and would not be recorded under GAAP for nonregulated entities. In addition, reporting under SFAS 71 allows companies whose service obligations and prices are regulated to maintain assets on their balance sheets representing costs they reasonably expect to recover from customers, through inclusion of such costs in future rates. SFAS 101, "Accounting for the Discontinuance of Application of FASB Statement No. 71," specifies how an enterprise that ceases to meet the criteria for application of SFAS 71 for all or part of its operations should report that event in its financial statements. In general, SFAS 101 requires that the enterprise report the discontinuance of SFAS 71 by eliminating from its balance sheet all regulatory assets and liabilities related to the portion of the business that no longer meets the SFAS 71 criteria. The EITF has concluded that application of SFAS 71 accounting should be discontinued once sufficiently detailed deregulation legislation is issued for a separable portion of a business for which a plan of deregulation has been established. However, the EITF further concluded that regulatory assets associated with the deregulated portion of the business, which will be recovered through tariffs charged to customers of a regulated portion of the business, should be associated with the regulated portion of the business from which future cash recovery is expected (not the portion of the business from which the costs originated). Those assets can therefore continue to be carried on the regulated entity's balance sheet to the extent such assets are recoverable. In addition, SFAS 121 establishes accounting standards for the impairment of long-lived assets. Due to the enactment of the Illinois Law, prices for the retail supply of electric generation are expected to transition from cost-based, regulated rates to rates determined in large part by competitive market forces in the state of Illinois. As a result, the Company discontinued application of SFAS 71 for the Illinois retail portion of its generating business (i.e., the portion of the Company's business related to the supply of electric energy in Illinois) in the fourth quarter of 1997. The Company evaluated the impact of the Illinois Law on the future recoverability of its regulatory assets and liabilities related to the generation portion of its business and determined that it was not probable that such assets and liabilities would be recovered through the cash flows from the regulated portion of its business. Accordingly, the Company's generation-related regulatory assets and liabilities of its Illinois retail electric business were written off in the fourth quarter of 1997, resulting in an extraordinary charge to earnings of $52 million, net of income taxes, or 38 cents per share. These regulatory assets and liabilities included previously incurred costs originally expected to be collected/refunded in future revenues, such as coal contract restructuring costs, deferred charges related to a generating plant, costs associated with an abandoned scrubber at a generating plant, and income tax-related regulatory assets and liabilities. In addition, the Company has evaluated whether the recoverability of the costs associated with its remaining net generation-related assets has been impaired as defined under SFAS 121. The Company has concluded that impairment, as defined under SFAS 121, does not exist and that no plant writedowns are necessary at this time. At December 31, 1999, the Company's net investment in generation facilities related to its Illinois retail jurisdiction approximated $861 million and was included in electric plant in-service on the Company's consolidated balance sheet. In August 1999, the Company filed a transmission system rate case with the FERC. This filing was primarily designed to implement rates, terms and conditions for transmission service for those retail customers in Illinois who choose other suppliers as allowed under the Illinois Law. On October 14, 1999, the FERC issued an order suspending the proposed rates until March 25, 2000. In January 2000, a settlement in principle was reached with the FERC trial staff and other interested parties. The settlement establishes the rates for transmission service that are to go into effect in the first quarter of 2000. The settlement is subject to approval by the FERC. The Company expects that the FERC will approve the settlement in 2000. The provisions of the Illinois Law could also result in lower revenues, reduced profit margins and increased costs of capital and operations expense. At this time, the Company is unable to determine the impact of the Illinois Law on the Company's future financial condition, results of operations or liquidity. MISSOURI ELECTRIC RESTRUCTURING In Missouri, where approximately 73% of the Company's retail electric revenues are derived, a task force appointed by the MoPSC investigated electric industry restructuring and competition. In 1998, the task force issued a report to the MoPSC that addressed many of the restructuring issues but did not provide a specific recommendation or approach to restructure the industry. In addition, in 1998, the MoPSC staff issued a proposed plan for restructuring Missouri's electric industry. The staff's plan addressed a number of issues of

19 page 32 Ameren Corporation 1999 Annual Report concern if the industry is restructured in Missouri. It also included a proposal for less than full recovery of strandable costs. The staff's plan has not been addressed by the MoPSC. A joint committee of the Missouri legislature is also conducting hearings on these issues. Several restructuring bills were introduced by the Missouri legislature in 1999 and 2000. The Company is unable to predict the timing or ultimate outcome of electric industry restructuring in the state of Missouri, as well as the impact of potential electric industry restructuring matters on the Company's future financial condition, results of operations or liquidity. The potential negative consequences of electric industry restructuring could be significant and include the impairment and write-down of certain assets, including generation-related plant and net regulatory assets, lower revenues, reduced profit margins and increased costs of capital and operations expense. At December 31, 1999, the Company's net investment in generation facilities related to its Missouri jurisdiction approximated $2.6 billion and was included in electric plant in-service on the Company's balance sheet. In addition, at December 31, 1999, the Company's Missouri net generation-related regulatory assets approximated $454 million. REGULATORY ASSETS AND LIABILITIES In accordance with SFAS 71, the Company has deferred certain costs pursuant to actions of its regulators, and is currently recovering such costs in electric rates charged to customers. At December 31, the Company had recorded the following regulatory assets and regulatory liability: <TABLE> <CAPTION> In Millions 1999 1998 ---------------------------------------------------------------------------- <S> <C> <C> REGULATORY ASSETS: Income taxes $623 $634 Callaway costs 92 95 Unamortized loss on reacquired debt 31 33 Merger costs 27 24 Other 26 36 ----------------- Regulatory Assets $799 $822 ----------------- REGULATORY LIABILITY: Income taxes $188 $199 ----------------- Regulatory Liability $188 $199 ----------------- </TABLE> Income Taxes: See Note 9 - Income Taxes. Callaway Costs: Represents Callaway Nuclear Plant operations and maintenance expenses, property taxes and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the plant (through 2024). Unamortized Loss on Reacquired Debt: Represents losses related to refunded debt. These amounts are being amortized over the lives of the related new debt issues or the remaining lives of the old debt issues if no new debt was issued. Merger Costs: Represents the portion of merger-related expenses applicable to the Missouri retail jurisdiction. These costs are being amortized within 10 years, based on a MoPSC order. The Company continually assesses the recoverability of its regulatory assets. Under current accounting standards, regulatory assets are written off to earnings when it is no longer probable that such amounts will be recovered through future revenues. However, as noted in the above paragraphs, electric industry restructuring legislation may impact the recoverability of regulatory assets in the future. NOTE 3 TARGETED SEPARATION PLAN In July 1998, the Company offered separation packages to employees whose positions were eliminated through a targeted separation plan (TSP). During the third quarter of 1998, a nonrecurring, pretax charge of $25 million was recorded, reducing earnings $15 million, or 11 cents per share. This represented costs incurred to implement the TSP. NOTE 4 CONCENTRATION OF RISK MARKET RISK The Company engages in price risk management activities related to electricity and fuel. In addition to buying and selling these commodities, the Company uses derivative financial instruments to manage market risks and reduce exposure resulting from fluctuations in interest rates and the prices of electricity and fuel. Derivative instruments used include futures, forward contracts and options. The use of these types of contracts allows the Company to manage and hedge its contractual commitments and reduce exposure related to the volatility of commodity market prices. CREDIT RISK Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. New York Mercantile Exchange (NYMEX) traded futures contracts are guaranteed by NYMEX and have nominal credit risk. On all other transactions, the Company is exposed to credit risk in the event of nonperformance by the counterparties in the transaction. The Company's financial instruments subject to credit risk consist primarily of trade accounts receivables and forward contracts. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups comprising the Company's customer base. The Company's revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. For each counterparty in forward contracts, the Company analyzes the counterparty's financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis through a credit risk management program. NOTE 5 NUCLEAR FUEL LEASE The Company has a lease agreement that provides for the financing of nuclear fuel. At December 31, 1999, the maximum amount that could be financed under the agreement was $120 million. Pursuant to the terms of the lease, the Company has assigned to the lessor certain contracts for purchase of nuclear fuel. The lessor obtains, through the issuance of commercial paper or from direct loans under a committed revolving credit agreement from commercial banks, the necessary funds to purchase the fuel and make interest payments when due. The Company is obligated to reimburse the lessor for all expenditures for nuclear fuel, interest and related costs. Obligations under this lease become due as the nuclear fuel is consumed at the Company's Callaway Nuclear Plant. The Company reimbursed the lessor $16 million in 1999, $23 million during 1998 and $31 million during 1997.

20 www.ameren.com page 33 The Company has capitalized the cost, including certain interest costs, of the leased nuclear fuel and has recorded the related lease obligation. Total interest charges under the lease were $5 million in 1999 and 1998 and $6 million in 1997. Interest charges for these years were based on average interest rates of approximately 6%. Interest charges of $4 million were capitalized in 1999 and $3 million were capitalized in 1998 and 1997. NOTE 6 SHAREHOLDER RIGHTS PLAN AND PREFERRED STOCK OF SUBSIDIARIES In October 1998, the Company's Board of Directors approved a share purchase rights plan designed to assure shareholders of fair and equal treatment in the event of a proposed takeover. The rights will be exercisable only if a person or group acquires 15% or more of Ameren's common stock or announces a tender offer, the consummation of which would result in ownership by a person or group of 15% or more of the common stock. Each right will entitle the holder to purchase one one-hundredth of a newly issued preferred stock at an exercise price of $180. If a person or group acquires 15% or more of Ameren's outstanding common stock, each right will entitle its holder (other than such person or members of such group) to purchase, at the right's then-current exercise price, a number of Ameren's common shares having a market value of twice such price. In addition, if Ameren is acquired in a merger or other business combination transaction after a person or group has acquired 15% or more of the Company's outstanding common stock, each right will entitle its holder to purchase, at the right's then-current exercise price, a number of the acquiring company's common shares having a market value of twice such price. The acquiring person or group will not be entitled to exercise these rights. The SEC approved the plan under PUHCA in December 1998. The rights were issued as a dividend payable January 8, 1999, to shareholders of record on that date; these rights expire in 2008. One right will accompany each new share of Ameren common stock issued prior to such expiration date. At December 31, 1999 and 1998, AmerenUE and AmerenCIPS had 25 million shares and 4.6 million shares respectively, of authorized preferred stock. Outstanding preferred stock is entitled to cumulative dividends and is redeemable at the prices shown in the following table: PREFERRED STOCK OUTSTANDING NOT SUBJECT TO MANDATORY REDEMPTION: <TABLE> <CAPTION> Redemption Price December 31, Dollars In Millions (per share) 1999 1998 -------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> Without par value and stated value of $100 per share -- $7.64 Series - 330,000 shares $103.82 - note(a) $ 33 $ 33 $5.50 Series A - 14,000 shares 110.00 1 1 $4.75 Series - 20,000 shares 102.176 2 2 $4.56 Series - 200,000 shares 102.47 20 20 $4.50 Series - 213,595 shares 110.00 - note(b) 21 21 $4.30 Series - 40,000 shares 105.00 4 4 $4.00 Series - 150,000 shares 105.625 15 15 $3.70 Series - 40,000 shares 104.75 4 4 $3.50 Series - 130,000 shares 110.00 13 13 </TABLE> <TABLE> <CAPTION> Redemption Price December 31, Dollars In Millions (per share) 1999 1998 -------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> With par value of $100 per share -- 4.00% Series - 150,000 shares 101.00 15 15 4.25% Series - 50,000 shares 102.00 5 5 4.90% Series - 75,000 shares 102.00 8 8 4.92% Series - 50,000 shares 103.50 5 5 5.16% Series - 50,000 shares 102.00 5 5 1993 Auction - 300,000 shares 100.00 - note(c) 30 30 6.625% Series - 125,000 shares 100.00 12 12 Without par value and stated value of $25 per share -- $1.735 Series - 1,657,500 shares 25.00 42 42 ------------------ TOTAL PREFERRED STOCK OUTSTANDING NOT SUBJECT TO MANDATORY REDEMPTION $235 $235 ================== </TABLE> (a) Beginning February 15, 2003, eventually declining to $100 per share. (b) In the event of voluntary liquidation, $105.50. (c) Dividend rates, and the periods during which such rates apply, vary depending on the Company's selection of certain defined dividend period lengths. The average dividend rate during 1999 was 3.89%. NOTE 7 SHORT-TERM BORROWINGS Short-term borrowings of the Company consist of bank loans (maturities generally on an overnight basis) and commercial paper (maturities generally within 10-45 days). At December 31, 1999 and 1998, $80 million and $59 million, respectively, of short-term borrowings were outstanding. The weighted average interest rates on borrowings outstanding at December 31, 1999 and 1998, were 6.3% and 4.9%, respectively. At December 31, 1999, the Company had committed bank lines of credit aggregating $180 million (all of which was unused and available at such date) which make available interim financing at various rates of interest based on LIBOR, the bank certificate of deposit rate, or other options. These lines of credit are renewable annually at various dates throughout the year. The Company also has a $300 million, short-term, bank credit agreement due in 2000, which permits the Company to borrow or to support a portion of the Company's commercial paper program. At December 31, 1999, all was unused and $240 million of such borrowing was available. The Company has money pool agreements among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained between regulated and nonregulated businesses. Interest is calculated at varying rates of interest depending on the composition of internal and external funds in the money pools. This debt and the related interest represent intercompany balances, which are eliminated at the Ameren Corporation consolidated level.

21 page 34 Ameren Corporation 1999 Annual Report NOTE 8 LONG-TERM DEBT <TABLE> <CAPTION> December 31, In Millions 1999 1998 ------------------------------------------------------------------ <S> <C> <C> FIRST MORTGAGE BONDS - note(a) 6 3/4% Series paid in 1999 $ - $ 100 7 1/8% Series W paid in 1999 - 50 8.33% Series due 2002 75 75 6 3/8% Series Z due 2003 40 40 7.65% Series due 2003 100 100 6 7/8% Series due 2004 188 188 7 3/8% Series due 2004 85 85 7 1/2% Series X due 2007 50 50 6 3/4% Series due 2008 148 148 7.61% 1997 Series due 2017 40 40 7.40% Series due 2020 - note(b) 60 60 8 3/4% Series due 2021 125 125 8 1/4% Series due 2022 104 104 8% Series due 2022 85 85 7.15% Series due 2023 75 75 7% Series due 2024 100 100 6.125% Series due 2028 60 60 5.45% Series due 2028 - note(b) 44 44 Other 5.375% - 7.05% due 2000 through 2008 158 168 ------------------- 1,537 1,697 ------------------- </TABLE> ENVIRONMENTAL IMPROVEMENT/POLLUTION CONTROL REVENUE BONDS <TABLE> <S> <C> <C> 1985 Series A due 2015 - note(c) 70 70 1985 Series B due 2015 - note(c) 57 57 1990 Series B 7.60% due 2013 32 32 1991 Series due 2020 - note(c) 43 43 1992 Series due 2022 - note(c) 47 47 1993 Series A 6 3/8% due 2028 35 35 1993 Series C-1 due 2026 - note(c) 35 35 1998 Series A due 2033 - note(c) 60 60 1998 Series B due 2033 - note(c) 50 50 1998 Series C due 2033 - note(c) 50 50 Other 5.40% - 7.60% due 2014 through 2028 80 80 ------------------- 559 559 ------------------- </TABLE> <TABLE> <S> <C> <C> SUBORDINATED DEFERRABLE INTEREST DEBENTURES 7.69% Series A due 2036 - note(d) 66 66 UNSECURED LOANS Commercial paper - note(e) 152 - Credit agreements - note(f) 68 10 1991 Senior Medium Term Notes 8.60% due through 2005 41 47 1994 Senior Medium Term Notes 6.61% due through 2005 46 54 --------------------- 307 111 --------------------- NUCLEAR FUEL LEASE 116 66 --------------------- UNAMORTIZED DISCOUNT AND PREMIUM ON DEBT (8) (8) --------------------- MATURITIES DUE WITHIN ONE YEAR (129) (202) --------------------- TOTAL LONG-TERM DEBT $ 2,448 $ 2,289 --------------------- </TABLE> (a) At December 31, 1999, substantially all of the property and plant was mortgaged under, and subject to liens of, the respective indentures pursuant to which the bonds were issued. (b) Environmental Improvement Series (c) Interest rates, and the periods during which such rates apply, vary depending on the Company's selection of certain defined rate modes. The average interest rates for the year 1999 are as follows: 1985 Series A 3.21% 1985 Series B 3.29% 1991 Series 3.65% 1992 Series 3.55% 1993 Series 3.34% 1998 Series A 3.49% 1998 Series B 3.48% 1998 Series C 3.46% (d) During the terms of the debentures, the Company may, under certain circumstances, defer the payment of interest for up to five years. (e) A bank credit agreement, due 2002, permits AmerenUE to borrow or to support commercial paper borrowings up to $300 million. Interest rates will vary depending on market conditions. (f) A bank credit agreement, due 2002, permits the Company to borrow up to $200 million. Interest rates will vary depending on market conditions and the Company's selection of various options under the agreement. At December 31, 1999, the average annualized interest rate was 6.4%. Maturities of long-term debt through 2004 are as follows: <TABLE> <CAPTION> In Millions Principal Amount -------------------------------- <S> <C> 2000 $129 2001 45 2002 275 2003 160 2004 288 </TABLE> Amounts for years subsequent to 2000 do not include nuclear fuel lease payments since the amounts of such payments are not currently determinable. NOTE 9 INCOME TAXES Total income tax expense for 1999 resulted in an effective tax rate of 39% on earnings before income taxes (40% in 1998 and 38% in 1997). Principal reasons such rates differ from the statutory federal rate: <TABLE> <CAPTION> 1999 1998 1997 ------------------------------------------------------------------- <S> <C> <C> <C> STATUTORY FEDERAL INCOME TAX RATE: 35% 35% 35% Increases (Decreases) from: Depreciation differences 1 1 1 State tax 4 4 4 Other (1) - (2) ------------------------ EFFECTIVE INCOME TAX RATE 39% 40% 38% ------------------------ </TABLE> Income tax expense components: <TABLE> <CAPTION> In Millions 1999 1998 1997 ------------------------------------------------------------------- <S> <C> <C> <C> TAXES CURRENTLY PAYABLE (PRINCIPALLY FEDERAL): Included in operating expenses $287 $303 $261 Included in other income - Miscellaneous, net (3) (6) - ----------------------- 284 297 261 ----------------------- </TABLE>

22 www.ameren.com page 35 Income tax expense components (continued): <TABLE> <CAPTION> In Millions 1999 1998 1997 ------------------------------------------------------------------- <S> <C> <C> <C> DEFERRED TAXES (PRINCIPALLY FEDERAL): Included in operating expenses - Depreciation differences 3 (10) (11) Other (23) (17) (7) Included in other income- Other (2) 2 10 ----------------------- (22) (25) (8) ----------------------- DEFERRED INVESTMENT TAX CREDIT AMORTIZATION: Included in operating expenses (8) (8) (9) ----------------------- TOTAL INCOME TAX EXPENSE $254 $264 $244 ----------------------- </TABLE> In accordance with SFAS 109, "Accounting for Income Taxes," a regulatory asset, representing the probable recovery from customers of future income taxes, which is expected to occur when temporary differences reverse, was recorded along with a corresponding deferred tax liability. Also, a regulatory liability, recognizing the lower expected revenue resulting from reduced income taxes associated with amortizing accumulated deferred investment tax credits, was recorded. Investment tax credits have been deferred and will continue to be credited to income over the lives of the related property. The Company adjusts its deferred tax liabilities for changes enacted in tax laws or rates. Recognizing that regulators will probably reduce future revenues for deferred tax liabilities initially recorded at rates in excess of the current statutory rate, reductions in the deferred tax liability were credited to the regulatory liability. Temporary differences gave rise to the following deferred tax assets and deferred tax liabilities at December 31: <TABLE> <CAPTION> In Millions 1999 1998 -------------------------------------------------------------------------------- <S> <C> <C> NET ACCUMULATED DEFERRED INCOME TAX LIABILITIES: Depreciation $1,038 $1,036 Regulatory assets, net 433 433 Capitalized taxes and expenses 130 155 Deferred benefit costs (58) (48) Other 21 12 ------------------- TOTAL NET ACCUMULATED DEFERRED INCOME TAX LIABILITIES $1,564 $1,588 ------------------- </TABLE> NOTE 10 RETIREMENT BENEFITS The Company has a defined-benefit retirement plan covering substantially all of its employees. Benefits are based on the employees' years of service and compensation. The Company's plan is funded in compliance with income tax regulations and federal funding requirements. On January 1, 1999, the AmerenUE and the AmerenCIPS pension plans combined to form the Ameren Retirement Plan. The AmerenUE and AmerenCIPS pension plans' information for 1998 and 1997 is presented separately. The Ameren plan covers qualified employees of the Company. Following is the pension plan information related to Ameren's plan as of December 31, 1999: Pension costs for 1999 were $24 million, of which approximately 18% was charged to construction accounts. FUNDED STATUS OF AMEREN'S PENSION PLAN: <TABLE> <CAPTION> In Millions 1999 ----------------------------------------------------------- <S> <C> CHANGE IN BENEFIT OBLIGATION Net benefit obligation at beginning of year $1,321 Service cost 33 Interest cost 91 Actuarial gain (95) Benefits paid (93) ------ Net benefit obligation at end of year 1,257 ------ CHANGE IN PLAN ASSETS* Fair value of plan assets at beginning of year 1,372 Actual return on plan assets 146 Employer contributions 2 Benefits paid (93) ------ Fair value of plan assets at end of year 1,427 ------ Funded status - excess (170) Unrecognized net actuarial gain 310 Unrecognized prior service cost (62) Unrecognized net transition asset 7 ------ ACCRUED PENSION COST AT DECEMBER 31 $ 85 ====== </TABLE> * Plan assets consist principally of common stocks and fixed income securities. COMPONENTS OF AMEREN'S NET PERIODIC BENEFIT COST: <TABLE> <CAPTION> In Millions 1999 ---------------------------------------------------------- <S> <C> Service cost $ 33 Interest cost 91 Expected return on plan assets (104) Amortization of: Transition asset (1) Prior service cost 7 Actuarial gain (2) ----- NET PERIODIC BENEFIT COST $ 24 ===== </TABLE> WEIGHTED-AVERAGE ASSUMPTIONS FOR ACTUARIAL PRESENT VALUE OF PROJECTED BENEFIT OBLIGATIONS: <TABLE> <CAPTION> 1999 ---------------------------------------------------------- <S> <C> Discount rate at measurement date 7.75% Expected return on plan assets 8.50% Increase in future compensation 4.75% </TABLE> AmerenUE's plan covers qualified employees of AmerenUE as well as certain employees of Ameren Services Company. Following is the pension plan information related to AmerenUE's plan as of December 31: Pension costs for the years 1998 and 1997, were $28 million and $24 million, respectively, of which approximately 19% and 17%, respectively, was charged to construction accounts.

23 page 36 Ameren Corporation 1999 Annual Report FUNDED STATUS OF AMERENUE'S PENSION PLAN: <TABLE> <CAPTION> In Millions 1998 ----------------------------------------------------------- <S> <C> CHANGE IN BENEFIT OBLIGATION Net benefit obligation at beginning of year $ 999 Service cost 24 Interest cost 70 Amendments 10 Actuarial loss 38 Special termination benefit charge 7 Benefits paid (88) ----- Net benefit obligation at end of year 1,060 ----- CHANGE IN PLAN ASSETS* Fair value of plan assets at beginning of year 1,006 Actual return on plan assets 122 Employer contributions 1 Benefits paid (88) ----- Fair value of plan assets at end of year 1,041 ----- Funded status - deficiency 19 Unrecognized net actuarial gain 121 Unrecognized prior service cost (73) Unrecognized net transition asset 6 ----- ACCRUED PENSION COST AT DECEMBER $ 73 ----- </TABLE> * Plan assets consist principally of common stocks and fixed income securities. COMPONENTS OF AMERENUE'S NET PERIODIC BENEFIT COST: <TABLE> <CAPTION> In Millions 1998 1997 ------------------------------------------------------------ <S> <C> <C> Service cost $ 24 $ 22 Interest cost 70 69 Expected return on plan assets (75) (71) Amortization of: Transition asset (1) (1) Prior service cost 6 7 Actuarial gain (3) (2) Special termination benefit charge 7 - ------------- NET PERIODIC BENEFIT COST $ 28 $ 24 ============= </TABLE> WEIGHTED-AVERAGE ASSUMPTIONS FOR ACTUARIAL PRESENT VALUE OF PROJECTED BENEFIT OBLIGATIONS: <TABLE> <CAPTION> 1998 ------------------------------------------------------------ <S> <C> Discount rate at measurement date 6.75% Expected return on plan assets 8.5% Increase in future compensation 4% </TABLE> AmerenCIPS' plan covers substantially all employees of AmerenCIPS as well as certain employees of Ameren Services Company. In 1998, AmerenCIPS changed its measurement date for valuation of plan assets and liabilities to December 31. Following is the pension plan information related to AmerenCIPS' plan as of December 31: Pension costs for the years 1998 and 1997 were $9 million and $5 million, respectively, of which approximately 19% in 1998 and 15% in 1997 was charged to construction accounts. FUNDED STATUS OF AMERENCIPS' PENSION PLAN: <TABLE> <CAPTION> In Millions 1998 ----------------------------------------------------------- <S> <C> CHANGE IN BENEFIT OBLIGATION Net benefit obligation at beginning of year $249 Service cost 8 Interest cost 17 Amendments 5 Actuarial loss 8 Special termination benefit charge 5 Benefits paid (31) ---- Net benefit obligation at end of year 261 ---- CHANGE IN PLAN ASSETS* Fair value of plan assets at beginning of year 319 Actual return on plan assets 38 Employer contributions 5 Benefits paid (31) ---- Fair value of plan assets at end of year 331 ---- Funded status - excess (70) Unrecognized net actuarial gain 73 Unrecognized prior service cost (13) Unrecognized net transition asset 2 ---- PREPAID PENSION COST AT DECEMBER 31 $ (8) ==== </TABLE> * Plan assets consist principally of common and preferred stocks, bonds, money market instruments and real estate. COMPONENTS OF AMERENCIPS' NET PERIODIC BENEFIT COST: <TABLE> <CAPTION> In Millions 1998 1997 ----------------------------------------------------------- <S> <C> <C> Service cost $ 8 $ 7 Interest cost 17 16 Expected return on plan assets (22) (19) Amortization of prior service cost 1 1 Special termination benefit charge 5 - -------------- NET PERIODIC BENEFIT COST $ 9 $ 5 -------------- </TABLE> WEIGHTED-AVERAGE ASSUMPTIONS FOR ACTUARIAL PRESENT VALUE OF PROJECTED BENEFIT OBLIGATIONS: <TABLE> <CAPTION> 1998 ----------------------------------------------------------- <S> <C> Discount rate at measurement date 6.75% Expected return on plan assets 8.5% Increase in future compensation 4% </TABLE> In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees. The Company accrues the expected postretirement benefit costs during employees' years of service. AmerenUE's plans cover qualified employees of AmerenUE as well as certain employees of Ameren Services Company. The following is information related to AmerenUE's postretirement benefit plans as of December 31: AmerenUE's funding policy is to annually contribute the net periodic cost to a Voluntary Employee Beneficiary Association trust (VEBA). Postretirement benefit costs were $46 million for 1999, $43 million in 1998 and $44 million

24 www.ameren.com page 37 in 1997, of which approximately 18% in 1999 and 17% in 1998 and 1997 were charged to construction accounts. AmerenUE's transition obligation at December 31, 1999, is being amortized over the next 13 years. The MoPSC and the ICC allow the recovery of postretirement benefit costs in rates to the extent that such costs are funded. In December 1995, AmerenUE established two external trust funds for retiree health care and life insurance benefits. In 1999, 1998 and 1997, claims were paid out of the plan trust funds. FUNDED STATUS OF AMERENUE'S POSTRETIREMENT PLANS: <TABLE> <CAPTION> In Millions 1999 1998 --------------------------------------------------------------------- <S> <C> <C> CHANGE IN BENEFIT OBLIGATION Net benefit obligation at beginning of year $ 360 $ 333 Service cost 15 14 Interest cost 25 24 Actuarial (gain)/loss (20) 9 Benefits paid (26) (20) ---------------- Net benefit obligation at end of year 354 360 ---------------- CHANGE IN PLAN ASSETS* Fair value of plan assets at beginning of year 110 81 Actual return on plan assets 4 8 Employer contributions 46 44 Unincorporated business income tax - (3) Benefits paid (26) (20) ---------------- Fair value of plan assets at end of year 134 110 ---------------- Funded status - deficiency 220 250 Unrecognized net actuarial gain 29 11 Unrecognized prior service cost (3) (3) Unrecognized net transition obligation (162) (175) ---------------- POSTRETIREMENT BENEFIT LIABILITY AT DECEMBER 31 $ 84 $ 83 ================ </TABLE> * Plan assets consist principally of common stocks and fixed income securities. COMPONENTS OF AMERENUE'S NET PERIODIC BENEFIT COST: <TABLE> <CAPTION> In Millions 1999 1998 1997 ------------------------------------------------------------------ <S> <C> <C> <C> Service cost $ 15 $ 14 $ 12 Interest cost 25 24 23 Expected return on plan assets (6) (5) (2) Amortization of: Transition obligation 12 12 12 Actuarial gain - (2) (1) --------------------- NET PERIODIC BENEFIT COST $ 46 $ 43 $ 44 ===================== </TABLE> ASSUMPTIONS FOR THE OBLIGATION MEASUREMENTS: <TABLE> <CAPTION> 1999 1998 ----------------------------------------------------------------- <S> <C> <C> Discount rate at measurement date 7.75% 6.75% Expected return on plan assets 8.5% 8.5% Medical cost trend rate - initial - 5.75% - ultimate 5.25% 4.75% Ultimate medical cost trend rate expected in year 2000 2000 </TABLE> A 1% increase in the medical cost trend rate is estimated to increase the net periodic cost and the accumulated postretirement benefit obligation approximately $4 million and $31 million, respectively. A 1% decrease in the medical cost trend rate is estimated to decrease the net periodic cost and the accumulated postretirement benefit obligation approximately $4 million and $31 million, respectively. AmerenCIPS' plans cover substantially all employees of AmerenCIPS as well as certain employees of Ameren Services Company. The following is information related to AmerenCIPS' postretirement benefit plans as of December 31: AmerenCIPS' funding policy is to fund the two VEBAs and the 401(h) account established within the AmerenCIPS retirement income trust with the lesser of the net periodic cost or the amount deductible for federal income tax purposes. In 1998, AmerenCIPS changed its measurement date for valuation of plan assets and liabilities to December 31. Postretirement benefit costs were $3 million for 1999, $6 million for 1998 and $12 million for 1997, of which approximately 10% was charged to construction accounts in 1999, 20% in 1998, and 17% in 1997. AmerenCIPS' transition obligation at December 31, 1999 is being amortized over the next 13 years. The ICC allows the recovery of postretirement benefit costs in rates to the extent that such costs are funded. FUNDED STATUS OF AMERENCIPS' POSTRETIREMENT PLANS: <TABLE> <CAPTION> In Millions 1999 1998 ------------------------------------------------------------------- <S> <C> <C> CHANGE IN BENEFIT OBLIGATION Net benefit obligation at beginning of year $ 152 $ 140 Service cost 3 3 Interest cost 9 10 Actuarial (gain)/loss (22) 4 Benefits paid (4) (5) ------------- Net benefit obligation at end of year 138 152 ------------- CHANGE IN PLAN ASSETS* Fair value of plan assets at beginning of year 128 115 Actual return on plan assets 10 16 Employer contributions 1 4 401(h) transfer - (2) Benefits paid (4) (5) ------------- Fair value of plan assets at end of year 135 128 ------------- Funded status - deficiency 3 24 Unrecognized net actuarial gain 75 58 Unrecognized net transition obligation (71) (76) ------------- POSTRETIREMENT BENEFIT LIABILITY AT DECEMBER 31 $ 7 $ 6 ============= </TABLE> * Plan assets consist principally of common and preferred stocks, bonds, money market instruments and real estate. COMPONENTS OF AMERENCIPS' NET PERIODIC BENEFIT COST: <TABLE> <CAPTION> In Millions 1999 1998 1997 ------------------------------------------------------------ <S> <C> <C> <C> Service cost $ 3 $ 3 $ 4 Interest cost 9 10 10 Expected return on plan assets (9) (8) (5) Amortization of: Transition obligation 6 5 5 Actuarial gain (6) (4) (2) --------------------- NET PERIODIC BENEFIT COST $ 3 $ 6 $ 12 ===================== </TABLE>

25 page 38 Ameren Corporation 1999 Annual Report ASSUMPTIONS FOR THE OBLIGATION MEASUREMENTS: <TABLE> <CAPTION> 1999 1998 ----------------------------------------------------------------- <S> <C> <C> Discount rate at measurement date 7.75% 6.75% Expected return on plan assets 8.5% 8.5% Medical cost trend rate - initial - 5.75% - ultimate 5.25% 4.75% Ultimate medical cost trend rate expected in year 2000 2000 </TABLE> A 1% increase in the medical cost trend rate is estimated to increase the net periodic cost and the accumulated postretirement benefit obligation approximately $2 million and $20 million, respectively. A 1% decrease in the medical cost trend rate is estimated to decrease the net periodic cost and the accumulated postretirement benefit obligation approximately $2 million and $20 million, respectively. NOTE 11 STOCK OPTION PLANS In 1998, the Company adopted a long-term incentive plan (the Plan) for eligible employees, replacing the plan previously in place at AmerenUE. The Plan provides for the grant of options, performance awards, restricted stock, dividend equivalents and stock appreciation rights. Under the terms of the Plan, options may be granted at a price not less than the fair market value of the common shares at the date of grant. Granted options vest over a period of five years, beginning at the date of grant, and provide for acceleration of exercisability of the options upon the occurrence of certain events, including retirement. Outstanding options expire on various dates through 2009. Under the Plan, subject to adjustment as provided in the Plan, four million shares have been authorized to be issued or delivered under the Company's Plan. In accordance with APB 25, no compensation cost has been recognized for the Company's stock compensation plans. The Company has adopted the disclosure-only method of fair value data under SFAS 123, "Accounting for Stock-Based Compensation." If the fair value-based accounting method under this statement had been used to account for stock-based compensation cost, the effects on 1999, 1998, and 1997 net income and earnings per share would have been immaterial. The following table summarizes stock option activity during 1999, 1998 and 1997: <TABLE> <CAPTION> 1999 ---------------------- Weighted Average Exercise Shares Price ------------------------------------------------------------- <S> <C> <C> Outstanding at beginning of year 1,095,180 $39.41 Granted 768,100 36.63 Exercised 11,162 37.20 Cancelled or expired 18,010 42.45 --------------------- Outstanding at end of year 1,834,108 38.22 Exercisable at end of year 391,456 39.06 --------------------- </TABLE> <TABLE> <CAPTION> 1998 1997 ----------------------------------- Weighted Weighted Average Average Exercise Exercise Shares Price Shares Price ------------------------------------------------------------------- <S> <C> <C> <C> <C> Outstanding at beginning of year 496,070 $ 39.24 307,390 $ 39.71 Granted 700,600 39.25 195,880 38.50 Exercised 72,390 36.81 - - Cancelled or expired 29,100 39.28 7,200 39.56 -------------------------------------- Outstanding at end of year 1,095,180 39.41 496,070 39.24 Exercisable at end of year 173,653 39.91 134,785 38.55 ====================================== </TABLE> Additional information about stock options outstanding at December 31, 1999: <TABLE> <CAPTION> Weighted Average Exercise Price Outstanding Shares Life (Years) Exercisable Shares ----------------------------------------------------------------------------- <S> <C> <C> <C> $ 35.50 800 5.6 600 35.875 79,225 4.8 59,375 36.625 768,100 8.5 60,700 38.50 175,853 6.0 68,701 39.25 662,500 7.2 111,150 39.8125 5,300 8.5 - 43.00 142,330 4.8 90,930 ============================================================================= </TABLE> The fair values of stock options were estimated using a binomial option-pricing model with the following assumptions: <TABLE> <CAPTION> Grant Risk-free Expected Expected Date Interest Rate Option Term Volatility Dividend Yield ------------------------------------------------------------------------- <S> <C> <C> <C> <C> 2/12/99 5.44% 10 years 18.80% 6.51% 6/16/98 5.63% 10 years 17.68% 6.55% 4/28/98 6.01% 10 years 17.63% 6.55% 2/10/97 5.70% 10 years 13.17% 6.53% 2/7/96 5.87% 10 years 13.67% 6.32% ------------------------------------------------------------------------- </TABLE> NOTE 12 COMMITMENTS AND CONTINGENCIES The Company is engaged in a capital program under which expenditures averaging approximately $653 million, including AFC, are anticipated during each of the next five years. This estimate includes capital expenditures for the purchase of new combustion turbine generators, as well as expenditures that will be incurred by the Company to meet new air quality standards for ozone and particulate matter, as discussed later in this Note. The Company has committed to purchase combustion turbine generators (CTs), which will add more than 2,700 megawatts to its net peaking capacity and are expected to cost approximately $1.2 billion. CTs with a total capacity of approximately 590 megawatts are planned to be installed in 2000, 560 megawatts in 2001, 590 megawatts in 2002, and 325 megawatts each in 2003 through 2005. Except for nearly 200 megawatts, the new capacity is expected to be operated by the Company's proposed new nonregulated generating subsidiary (see Note 2 - Regulatory Matters for further information).

26 www.ameren.com page 39 The Company has commitments for the purchase of coal under long-term contracts. Coal contract commitments, including transportation costs, for 2000 through 2004 are estimated to total $2.1 billion. Total coal purchases, including transportation costs, for 1999, 1998 and 1997 were $603 million, $567 million and $547 million, respectively. The Company also has existing contracts with pipeline and natural gas suppliers to provide, transport and store natural gas for distribution and electric generation. Gas-related contract cost commitments for 2000 through 2004 are estimated to total $122 million. Total delivered natural gas costs were $131 million for 1999, $119 million for 1998, and $161 million for 1997. The Company's nuclear fuel commitments for 2000 through 2004, including uranium concentrates, conversion, enrichment and fabrication, are expected to total $73 million, and are expected to be substantially financed under the nuclear fuel lease. Nuclear fuel expenditures for 1999, 1998 and 1997, were $22 million, $20 million and $35 million, respectively. Additionally, the Company has long-term contracts with other utilities to purchase electric capacity. These commitments for 2000 through 2004 are estimated to total $241 million. During 1999, 1998 and 1997, electric capacity purchases were $44 million, $38 million and $36 million, respectively. In the fourth quarter 1999, AmerenCIPS and two of its coal suppliers executed agreements to terminate their existing coal supply contracts, effective December 31, 1999. Under these agreements, AmerenCIPS has made termination payments to the suppliers totaling approximately $52 million. These termination payments were recorded as a nonrecurring charge in the fourth quarter of 1999, equivalent to $31 million, after income taxes, or 23 cents per share. Total pretax fuel cost savings from these termination agreements are estimated to be $183 million (or $131 million net of the termination payments) through 2010, which is the maximum period that would have remained on any of the terminated coal supply contracts. Approximately $66 million of pretax fuel cost savings is expected to be realized over the next three years. During 1996, AmerenCIPS restructured its contract with one of its major coal suppliers. In 1997, the Company paid a $70 million restructuring payment to the supplier, which allowed it to purchase at market prices low-sulfur, non-Illinois coal through the supplier (in substitution for the high-sulfur Illinois coal AmerenCIPS was obligated to purchase under the original contract). Under the 1997 restructuring, the Company received options for future purchases of low-sulfur, non-Illinois coal from the supplier through 1999 at set negotiated prices. By switching to low-sulfur coal, the Company was able to discontinue operating a generating plant scrubber. The benefits of the 1999 restructuring include lower cost coal, avoidance of significant capital expenditures to renovate the scrubber, and elimination of scrubber operating and maintenance costs (offset by scrubber retirement expenses). The net benefits of restructuring are expected to exceed $100 million through 2007. In December 1996, the ICC entered an order approving the switch to non-Illinois coal, recovery of the restructuring payment plus associated carrying costs (Restructuring Charges) through the retail Fuel Adjustment Clause (FAC) over six years, and continued recovery in rates of the undepreciated scrubber investment, plus costs of removal. Additionally, in May 1997 the FERC approved recovery of the wholesale portion of the Restructuring Charges through the wholesale FAC. As a result of the ICC and FERC orders, the Company classified $72 million of the Restructuring Charges as a regulatory asset and, through December 1997, recovered approximately $10 million of the Restructuring Charges through the retail FAC and from wholesale customers. In November 1997, the ICC order was reversed on appeal by the Illinois Third District Appellate Court. The Illinois Supreme Court issued a final decision in December 1998 reversing the Appellate Court's opinion and affirming the ICC's order allowing the recovery of the Restructuring Charges through the retail FAC. The recoverability of the Restructuring Charges under the retail FAC in Illinois was impacted by the Illinois Law. Among other things, the Illinois Law provides utilities with the option to eliminate the retail FAC and limits the ability of utilities to file a full rate case for its aggregate revenue requirements. After evaluating the impact of the Illinois Law on the future recoverability of the Company's Restructuring Charges through future rates, the Company wrote off the unamortized balance of the Illinois retail portion of its Restructuring Charges as of December 31, 1997 ($34 million, net of income taxes). See Note 2 - Regulatory Matters for further information. The Company's insurance coverage for Callaway Nuclear Plant at December 31, 1999 was as follows: TYPE AND SOURCE OF COVERAGE <TABLE> <CAPTION> Maximum Assessments Maximum for Single In Millions Coverages Incidents -------------------------------------------------------------- <S> <C> <C> Public Liability: American Nuclear Insurers $ 200 $ - Pool Participation 9,338 88(a) ------------------------ $9,538(b) $88 ------------------------ Nuclear Worker Liability: American Nuclear Insurers $ 200(c) $ 3 ------------------------ Property Damage: Nuclear Electric Insurance Ltd. $2,750(d) $11 ------------------------ Replacement Power: Nuclear Electric Insurance Ltd. $ 490(e) $ 2 ------------------------ </TABLE> (a) Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended, (Price-Anderson). Subject to retrospective assessment with respect to loss from an incident at any U.S. reactor, payable at $10 million per year. Price-Anderson expires in 2002. (b) Limit of liability for each incident under Price-Anderson. (c) Industry limit for potential liability from workers claiming exposure to the hazard of nuclear radiation. (d) Includes premature decommissioning costs. (e) Weekly indemnity of $3.5 million, for 52 weeks which commences after the first 12 weeks of an outage, plus $2.8 million per week for 110 weeks thereafter. Price-Anderson limits the liability for claims from an incident involving any licensed U.S. nuclear facility. The limit is based on the number of licensed reactors and is adjusted at least every five years based on the Consumer Price Index. Utilities owning a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by Price-Anderson. If losses from a nuclear incident at Callaway exceed the limits of, or are not subject to, insurance, or if coverage is not available, the Company will self-insure the risk. Although the Company has no reason to anticipate a serious nuclear incident, if one did occur, it could have a material, but indeterminable, adverse effect on the Company's financial position, results of operations or liquidity. Under Title IV of the Clean Air Act Amendments of 1990, the Company is required to significantly reduce total annual sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions by the year 2000. By switching to low-sulfur coal, early

27 page 40 Ameren Corporation 1999 Annual Report banking of emissions credits and installing advanced NOx reduction combustion technology, the Company is meeting these requirements. In July 1997, the United States Environmental Protection Agency (EPA) issued regulations revising the National Ambient Air Quality Standards for ozone and particulate matter. In May 1999, the U.S. Court of Appeals for the District of Columbia remanded the regulations back to the EPA for review. Litigation regarding appeals of these regulations is ongoing. New ambient standards may result in additional significant reductions in SO2 and NOx emissions from the Company's power plants by 2007. At this time, the Company is unable to predict the ultimate impact of these revised air quality standards on its future financial condition, results of operations or liquidity. In an attempt to lower ozone levels across the eastern United States, the EPA issued the implementation of regulations in September 1998 to reduce NOx emissions from coal-fired boilers and other sources in 22 states, including Missouri and Illinois (where all of the Company's coal-fired power plant boilers are located). The implementation of these regulations has been delayed by the U.S. Court of Appeals for the District of Columbia until a legal challenge brought by various industries and states has been resolved. The proposed regulations mandate a 75% reduction from 1990 levels by the year 2003 and require states to develop plans to reduce NOx emissions to help alleviate ozone problem areas. The NOx emissions reductions already achieved on several of the Company's coal-fired power plants will help to reduce the costs of compliance with these regulations. However, preliminary analysis of the regulations indicate that selective catalytic reduction technology may be required for some of the Company's units, as well as other additional controls. Currently, the Company estimates that its additional capital expenditures to comply with the final NOx regulations could range from $250 million to $300 million over the period from 1999 to 2003. Associated operations and maintenance expenditures could increase $10 million to $15 million annually, beginning in 2003. The Company is exploring alternatives to comply with these new regulations in order to minimize, to the extent possible, its capital costs and operating expenses. The Company is unable to predict the ultimate impact of these standards on its future financial condition, results of operations or liquidity. In November 1998, the United States signed an agreement with numerous other countries (the Kyoto Protocol) containing certain environmental provisions, which would require decreases in greenhouse gases in an effort to address the "global warming" issue. The Kyoto Protocol has not been ratified by the United States Senate. Implementation of the Kyoto Protocol in its present form would likely result in significantly higher capital costs and operations and maintenance expenses by the Company. At this time, the Company is unable to determine the impact of these proposals on the Company's future financial condition, results of operations or liquidity. As of December 31, 1999, the Company's utility operating subsidiaries were designated as potentially responsible parties (PRP) by federal and state environmental protection agencies at seven hazardous waste sites. Other hazardous waste sites have been identified for which the Company may be responsible but has not been designated a PRP. Costs relating to studies and remediation and associated legal and litigation expenses at the former manufactured gas plant sites located in Illinois are being accrued and deferred rather than expensed currently, pending recovery through environmental adjustment clause rate riders approved by the ICC. Through December 31, 1999, the total of the costs deferred, net of recoveries from insurers and through environmental adjustment clause riders, was $13 million. The ICC has instituted reconciliation proceedings to review the Company's environmental remediation activities to determine whether the revenues collected from customers under its environmental adjustment clause rate riders were consistent with the amount of remediation costs prudently and properly incurred. Amounts found to have been incorrectly included under the riders would be subject to refund. Rulings from the ICC are pending with respect to these proceedings applicable to the years 1993 through 1998. The reconciliation proceedings relating to the Company's 1999 environmental remediation activities will commence by the ICC in 2000. The Company continually reviews remediation costs that may be required for all of these sites. Any unrecovered environmental costs are not expected to have a material adverse effect on the Company's financial position, results of operations or liquidity. The International Union of Operating Engineers Local 148 and the International Brotherhood of Electrical Workers Local 702 filed unfair labor practice charges with the National Labor Relations Board (NLRB), relating to the legality of the 1993 lockout of both unions by AmerenCIPS. The NLRB issued complaints against AmerenCIPS concerning its lockout. Both unions sought, among other things, back pay and other benefits for the period of the lockout. At that time, the Company estimated the amount of back pay and other benefits for both unions to be approximately $17 million. In August 1998, a three-member panel of the NLRB reversed the May 1996 decision of its administrative law judge and ruled in favor of AmerenCIPS holding that the lockout was lawful. In April 1999, the unions filed petitions for review with the U.S. Court of Appeals for the District of Columbia Circuit of the NLRB's August 1998 decision. This appeal is pending. The Company continues to believe that the lockout was both lawful and reasonable and that the final resolution of the dispute will not have a material adverse effect on its financial position, results of operations or liquidity. Certain employees of the Company are represented by the International Brotherhood of Electrical Workers and the International Union of Operating Engineers. These employees comprise approximately 70% of the Company's workforce. New contracts with collective bargaining units representing approximately 60% of these employees were ratified in 1999 with terms expiring in 2002. Negotiations with collective bargaining units representing approximately 38% of those union employees are currently underway. The current collective bargaining agreements which expired in July 1999 have been extended to facilitate those negotiations. At this time, the Company is unable to predict the impact of these negotiations on its future financial condition, results of operations or cash flows. The collective bargaining agreement covering the remaining 2% of represented employees expires in 2000. Regulatory changes enacted and being considered at the federal and state levels continue to change the structure of the utility industry and utility regulation, as well as encourage increased competition. At this time, the Company is unable to predict the impact of these changes on the Company's future financial condition, results of operations or liquidity. See Note 2 - Regulatory Matters for further information. The Company is involved in other legal and administrative proceedings before various courts and agencies with respect to matters arising in the

28 www.ameren.com page 41 ordinary course of business, some of which involve substantial amounts. The Company believes that the final disposition of these proceedings will not have a material adverse effect on its financial position, results of operations or liquidity. NOTE 13 CALLAWAY NUCLEAR PLANT Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill per nuclear-generated kilowatthour sold for future disposal of spent fuel. Electric rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. The Company has sufficient storage capacity at the Callaway Plant site until 2020 and has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE's disposal facility is not expected to adversely affect the continued operation of the Callaway Plant. Electric rates charged to customers provide for recovery of Callaway Plant decommissioning costs over the life of the plant, based on an assumed 40-year life, ending with expiration of the plant's operating license in 2024. The Callaway site is assumed to be decommissioned using the DECON (immediate dismantlement) method. Decommissioning costs, including decontamination, dismantling and site restoration, are estimated to be $509 million in current year dollars and are expected to escalate approximately 4% per year through the end of decommissioning activity in 2033. Decommissioning costs are charged to depreciation expense over Callaway's service life and amounted to approximately $7 million in each of the years 1999, 1998 and 1997. Every three years, the MoPSC and ICC require the Company to file updated cost studies for decommissioning Callaway, and electric rates may be adjusted at such times to reflect changed estimates. The latest studies were filed in 1999. Costs collected from customers are deposited in an external trust fund to provide for Callaway's decommissioning. Fund earnings are expected to average approximately 9% annually through the date of decommissioning. If the assumed return on trust assets is not earned, the Company believes it is probable that any such earnings deficiency will be recovered in rates. Trust fund earnings, net of expenses, appear on the consolidated balance sheet as increases in the nuclear decommissioning trust fund and in the accumulated provision for nuclear decommissioning. The staff of the SEC has questioned certain current accounting practices of the electric utility industry, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In response to these questions, the Financial Accounting Standards Board has agreed to review the accounting for removal costs, including decommissioning. The Company does not expect that changes in the accounting for nuclear decommissioning costs will have a material effect on its financial position, results of operations or liquidity. NOTE 14 FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: CASH AND TEMPORARY INVESTMENTS/ SHORT-TERM BORROWINGS The carrying amounts approximate fair value because of the short-term maturity of these instruments. MARKETABLE SECURITIES The fair value is based on quoted market prices obtained from dealers or investment managers. NUCLEAR DECOMMISSIONING TRUST FUND The fair value is estimated based on quoted market prices for securities. PREFERRED STOCK OF SUBSIDIARIES The fair value is estimated based on the quoted market prices for the same or similar issues. LONG-TERM DEBT The fair value is estimated based on the quoted market prices for same or similar issues or on the current rates offered to the Company for debt of comparable maturities. DERIVATIVE FINANCIAL INSTRUMENTS Market prices used to determine fair value are based on management's estimates, which take into consideration factors like closing exchange prices, over-the-counter prices, time value of money and volatility factors. Carrying amounts and estimated fair values of the Company's financial instruments at December 31: <TABLE> <CAPTION> 1999 1998 -------------------------------------- Carrying Fair Carrying Fair In Millions Amount Value Amount Value ----------------------------------------------------------------------- <S> <C> <C> <C> <C> Marketable securities $ - $ - $ 14 $ 14 Preferred stock 235 192 235 235 Long-term debt (including current portion) 2,577 2,552 2,491 2,659 -------------------------------------- </TABLE> The Company has investments in debt and equity securities that are held in trust funds for the purpose of funding the nuclear decommissioning of Callaway Nuclear Plant (see Note 13 - Callaway Nuclear Plant). The Company has classified these investments in debt and equity securities as available for sale and has recorded all such investments at their fair market value at December 31, 1999 and 1998. In 1999, 1998 and 1997, the proceeds from the sale of investments were $83 million, $29 million and $24 million, respectively. Using the specific identification method to determine cost, the gross realized gains on those sales were approximately $11 million for 1999, and $2 million for 1998 and 1997. Net realized and unrealized gains and losses are reflected in the accumulated provision for nuclear decommissioning on the consolidated balance sheet, which is consistent with the method used by the Company to account for the decommissioning costs recovered in rates. Costs and fair values of investments in debt and equity securities in the nuclear decommissioning trust fund at December 31 were as follows:

29 page 42 Ameren Corporation 1999 Annual Report <TABLE> <CAPTION> Gross Unrealized 1999 In Millions ---------------- Security Type Cost Gain (Loss) Fair Value ----------------------------------------------------------------- <S> <C> <C> <C> <C> Debt securities $ 67 $ - $ - $ 67 Equity securities 45 73 - 118 Cash equivalents 2 - - 2 --------------------------------- $114 $73 $ - $187 --------------------------------- <CAPTION> Gross Unrealized 1998 In Millions ---------------- Security Type Cost Gain (Loss) Fair Value ----------------------------------------------------------------- <S> <C> <C> <C> <C> Debt securities $ 48 $ 4 $ - $ 52 Equity securities 46 62 - 108 Cash equivalents 2 - - 2 --------------------------------- $ 96 $66 $ - $162 --------------------------------- </TABLE> The contractual maturities of investments in debt securities at December 31, 1999 were as follows: <TABLE> <CAPTION> In Millions Cost Fair Value ------------------------------------------------------------ <S> <C> <C> 1 year to 5 years $ 6 $ 6 5 years to 10 years 30 30 Due after 10 years 31 31 ------------- $67 $ 67 ------------- </TABLE> NOTE 15 SEGMENT INFORMATION In 1998, the Company adopted SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." Ameren's principal business segment is comprised of the two regulated utility operating companies that provide electric and gas service in portions of Missouri and Illinois. The other reportable segment includes the nonregulated subsidiaries, as well as the Company's 60% interest in Electric Energy, Inc. The accounting policies of the segments are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data includes intersegment revenues, as well as a charge allocating costs of administrative support services to each of the operating companies. These costs are accumulated in a separate subsidiary, Ameren Services Company, which provides a variety of support services to Ameren and its subsidiaries. The Company evaluates the performance of its segments and allocates resources to them, based on revenues, operating income and net income. The table below presents information about the reported revenues, operating income, net income, and total assets of Ameren for the years ended December 31: <TABLE> <CAPTION> Regulated Reconciling 1999 In Millions Utilities All Other Items Total ------------------------------------------------------------------------ <S> <C> <C> <C> <C> Revenues $ 3,455 $243 $(174)* $3,524 Net income 384 1 - 385 Total assets 8,825 435 (82) 9,178 ---------------------------------------------- </TABLE> <TABLE> <CAPTION> Regulated Reconciling 1998 In Millions Utilities All Other Items Total ------------------------------------------------------------------------ <S> <C> <C> <C> <C> Revenues $3,230 $190 $(102)* $3,318 Net income 380 6 - 386 Total assets 8,594 237 16 8,847 ---------------------------------------------- </TABLE> <TABLE> <CAPTION> 1997 In Millions ------------------------------------------------------------------------ <S> <C> <C> <C> <C> Revenues $3,139 $243 $ (55)* $3,327 Net income 321 14 - 335 Total assets 8,591 243 (6) 8,828 ---------------------------------------------- </TABLE> *Elimination of intercompany revenues. Specified items included in segment profit/loss for the year ended December 31: <TABLE> <CAPTION> 1999 In Millions Regulated Utilities All Other Total -------------------------------------------------------------------------- <S> <C> <C> <C> Interest expense $163 $ 9 $172 Depreciation, depletion and amortization expense 337 12 349 Income tax expense 261 (2) 259 ------------------------------------------ </TABLE> <TABLE> <CAPTION> 1998 In Millions -------------------------------------------------------------------------- <S> <C> <C> <C> Interest expense $170 $ 9 $179 Depreciation, depletion and amortization expense 334 14 348 Income tax expense 263 5 268 ------------------------------------------- </TABLE> <TABLE> <CAPTION> 1997 In Millions -------------------------------------------------------------------------- <S> <C> <C> <C> Interest expense $168 $10 $178 Depreciation, depletion and amortization expense 331 15 346 Income tax expense 226 8 234 Extraordinary items (52) - (52) ------------------------------------------- </TABLE> Specified items related to segment assets as of December 31: <TABLE> <CAPTION> 1999 In Millions Regulated Utilities All Other Total ----------------------------------------------------------------------------- <S> <C> <C> <C> Expenditures for additions to long-lived assets $342 $179 $521 -------------------------------------- <CAPTION> 1998 In Millions ----------------------------------------------------------------------------- <S> <C> <C> <C> Expenditures for additions to long-lived assets $290 $ 31 $321 -------------------------------------- <CAPTION> 1997 In Millions ----------------------------------------------------------------------------- <S> <C> <C> <C> Expenditures for additions to long-lived assets $375 $ 6 $381 -------------------------------------- </TABLE>

30 www.ameren.com page 43 SELECTED CONSOLIDATED FINANCIAL INFORMATION <TABLE> <CAPTION> Millions of Dollars Except Share and Per Share Amounts and Ratios 1999 1998 1997 1996 1995 1994 ------------------------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> <C> <C> <C> RESULTS OF OPERATIONS Year ended December 31, Operating revenues $3,524 $3,318 $3,327 $3,328 $3,236 $3,270 Operating expenses 2,961 2,747 2,744 2,752 2,658 2,685 Operating income 563 571 582 576 578 585 Income before extraordinary charge 385 386 387 372 373 391 Extraordinary charge, net of income taxes - - 52 - - - Net income 385 386 335 372 373 391 Average common shares outstanding 137,215,462 137,215,462 137,215,462 137,215,462 137,215,462 137,253,617 -------------------------------------------------------------------------------- ASSETS, OBLIGATIONS AND EQUITY CAPITAL DECEMBER 31, Total assets $9,178 $8,847 $8,828 $8,933 $8,788 $8,629 Long-term debt obligations 2,448 2,289 2,506 2,335 2,373 2,413 Preferred stock subject to mandatory redemption - - - 1 1 1 Preferred stock not subject to mandatory redemption 235 235 235 298 298 298 Common equity 3,090 3,056 3,019 3,016 2,971 2,917 -------------------------------------------------------------------------------- FINANCIAL INDICES Year ended December 31, Earnings per share of common stock before extraordinary charge $2.81 $2.82 $2.82 $2.71 $2.72 $2.85 Extraordinary charge, net of income taxes - - $(.38) - - - Earnings per share of common stock (based on average shares outstanding) $2.81 $2.82 $2.44 $2.71 $2.72 $2.85 Dividend payout ratio 90% 90% 99% 88% 86% 80% Return on average common stock equity 12.56% 12.82% 11.14% 12.51% 12.76% 13.69% Ratio earnings to fixed charges AmerenUE 5.64 4.99 4.70 4.68 4.78 4.68 AmerenCIPS 2.98 4.13 3.64 4.30 4.41 4.93 Book value per common share $22.52 $22.27 $22.00 $21.98 $21.65 $21.25 -------------------------------------------------------------------------------- CAPITALIZATION RATIOS DECEMBER 31, Common equity 53.5% 54.8% 52.4% 53.4% 52.6% 51.8% Preferred stock 4.1 4.2 4.1 5.3 5.3 5.3 Long-term debt 42.4 41.0 43.5 41.3 42.1 42.9 -------------------------------------------------------------------------------- 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% </TABLE>

31 page 44 Ameren Corporation 1999 Annual Report ELECTRIC OPERATING STATISTICS <TABLE> <CAPTION> Year Ended December 31, 1999 1998 1997 1996 1995 1994 ------------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> ELECTRIC OPERATING REVENUES Millions Residential $1,097 $1,125 1,064 $1,070 $1,073 $1,014 Commercial 956 966 927 920 906 884 Industrial 50 511 500 500 496 487 Wholesale 90 91 91 91 87 84 Other 24 23 24 28 28 22 -------------------------------------------------------------------------------------- Native 2,672 2,716 2,606 2,609 2,590 2,491 Interchange 417 240 224 280 230 243 EEI 177 152 207 198 201 276 Miscellaneous 60 29 47 22 20 20 Credit to customers (38) (43) (20) (47) (33) -- ------------------------------------------------------------------------------------- TOTAL ELECTRIC OPERATING REVENUES $3,288 $3,094 $3,064 $3,062 $3,008 $3,030 ------------------------------------------------------------------------------------- KILOWATTHOUR SALES Millions Residential 14,863 15,188 14,325 14,418 14,086 13,282 Commercial 15,418 15,555 14,990 14,872 14,464 14,043 Industrial 11,549 11,582 11,404 11,191 10,971 10,728 Wholesale 2,492 2,446 2,323 2,328 2,248 2,137 Other 303 303 317 305 316 301 -------------------------------------------------------------------------------------- Native 44,625 45,074 43,359 43,114 42,085 40,491 Interchange 12,881 8,075 9,402 10,768 8,176 8,080 EEI 9,270 8,296 11,220 10,554 10,850 14,594 -------------------------------------------------------------------------------------- TOTAL KILOWATTHOUR SALES 66,776 61,445 63,981 64,436 61,111 63,165 -------------------------------------------------------------------------------------- ELECTRIC CUSTOMERS End of Year Residential 1,298,008 1,289,548 1,282,042 1,275,534 1,267,976 1,258,757 Commercial 188,503 181,678 180,206 176,621 173,810 171,072 Industrial 6,188 5,926 6,554 6,660 6,782 6,750 Wholesale 20 20 21 20 21 21 Miscellaneous 2,388 2,193 2,381 2,398 2,434 2,406 -------------------------------------------------------------------------------------- TOTAL ELECTRIC CUSTOMERS 1,495,107 1,479,365 1,471,204 1,461,233 1,451,023 1,439,006 -------------------------------------------------------------------------------------- RESIDENTIAL CUSTOMER DATA Average Kilowatthours used 11,827 11,986 11,215 11,354 11,152 10,606 Annual electric bill $859.53 $873.28 $833.34 $842.82 $849.62 $809.27 Revenue per kilowatthour 7.27(cent) 7.29(cent) 7.38(cent) 7.30(cent) 7.62(cent) 7.63(cent) ----------------------------------------------------------------------------------------- GROSS INSTANTANEOUS PEAK DEMAND Megawatts AmerenUE 8,831 8,429 8,055 8,085 7,965 7,430 AmerenCIPS 2,217 2,163 1,923 1,892 1,940 1,854 ---------------------------------------------------------------------------------------- CAPABILITY AT TIME OF PEAK, INCLUDING NET PURCHASES AND SALES Megawatts AmerenUE 9,141 9,027 8,950 9,120 8,714 8,469 AmerenCIPS 2,556 2,417 2,491 2,519 2,489 2,510 ---------------------------------------------------------------------------------------- GENERATING CAPABILITY AT TIME OF PEAK Megawatts AmerenUE 8,352 8,282 8,279 8,244 8,184 8,057 AmerenCIPS 3,027 3,040 3,033 3,033 3,018 3,018 ---------------------------------------------------------------------------------------- COAL BURNED Tons 23,638,000 22,959,000 21,392,000 20,062,000 17,715,000 16,885,000 ---------------------------------------------------------------------------------------- PRICE PER TON OF COAL Average $20.34 $21.29 $23.54 $25.25 $26.86 $28.02 ---------------------------------------------------------------------------------------- SOURCE OF ENERGY SUPPLY Coal 85.4% 83.5% 83.8% 79.6% 76.3% 76.2% Nuclear 17.9 17.7 19.3 19.2 18.3 23.0 Hydro 3.1 3.8 2.7 2.8 3.6 3.9 Purchased and interchanged, net (6.4) (5.0) (5.8) (1.6) 1.8 (3.1) --------------------------------------------------------------------------------------- 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% --------------------------------------------------------------------------------------- </TABLE>

32 Ameren Corporation 1999 Annual Report page 45 GAS OPERATING STATISTICS <TABLE> <CAPTION> Year Ended December 31 1999 1998 1997 1996 1995 1994 ---------------------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> <C> NATURAL GAS OPERATING REVENUES Millions Residential $146 $135 $150 $161 $137 $138 Commercial 52 50 55 61 51 53 Industrial 18 19 22 21 18 24 Off system sales 4 3 13 - - - Miscellaneous 8 10 10 11 11 10 ----------------------------------------------------------------------------------- TOTAL NATURAL GAS OPERATING REVENUES $228 $217 $250 $254 $217 $225 =================================================================================== MMBtu SALES Millions Residential 21 21 23 27 24 23 Commercial 8 8 9 11 10 10 Industrial 4 6 6 5 5 6 Off system sales 1 1 5 - - - ----------------------------------------------------------------------------------- TOTAL MMBTU SALES 34 36 43 43 39 39 =================================================================================== NATURAL GAS CUSTOMERS End of Year Residential 267,086 265,405 263,588 260,989 257,848 254,328 Commercial 29,247 30,245 30,147 29,911 29,446 29,037 Industrial 436 407 412 402 378 351 ----------------------------------------------------------------------------------- TOTAL NATURAL GAS CUSTOMERS 296,769 296,057 294,147 291,302 287,672 283,716 =================================================================================== PEAK DAY THROUGHPUT Thousands of MMBtus AmerenCIPS 247 229 281 302 270 303 AmerenUE 184 157 181 189 159 179 ----------------------------------------------------------------------------------- TOTAL PEAK DAY THROUGHPUT 431 386 462 491 429 482 =================================================================================== </TABLE>

33 INVESTOR INFORMATION COMMON STOCK AND DIVIDEND INFORMATION Ameren's common stock is listed on the New York Stock Exchange (ticker symbol: AEE). AEE began trading on January 2, 1998, following the merger of Union Electric Company and CIPSCO Incorporated on December 31, 1997. Common stockholders of record totaled 116,922 for Ameren at December 31, 1999. The following includes the price ranges and dividends paid per common share for AEE during 1999 and 1998. <TABLE> <CAPTION> AEE 1999 Quarter Ended High Low Close Dividends Paid -------------------------------------------------------------------------------- <S> <C> <C> <C> <C> March 31 $42 15/16 $ 36 3/16 $ 36 3/16 63 1/2(cent) June 30 40 15/16 35 13/16 38 3/8 63 1/2 September 30 40 3/4 36 7/8 37 13/16 63 1/2 December 31 39 7/8 32 32 3/4 63 1/2 AEE 1998 Quarter Ended High Low Close Dividends Paid -------------------------------------------------------------------------------- March 31 $43 1/8 $ 35 9/16 $42 1/8 63 1/2(cent) June 30 42 9/16 37 5/8 39 3/4 63 1/2 September 30 42 1/4 37 41 15/16 63 1/2 December 31 44 5/16 39 1/16 42 11/16 63 1/2 -------------------------------------------------------------------------------- </TABLE> ANNUAL MEETING The annual meeting of Ameren, Union Electric Company and Central Illinois Public Service Company stockholders will convene at 9 a.m., Tuesday, April 25, 2000, at Powell Symphony Hall, 718 North Grand Boulevard, St. Louis, Missouri. -------------------------------------------------------------------------------- DRPLUS Through DRPlus -- Ameren's dividend reinvestment and stock purchase plan -- stockholders, customers and employees of Ameren and its subsidiaries can: - make cash investments by check or automatic direct debit to their bank accounts to purchase Ameren common stock, totalling up to $120,000 annually. - reinvest their dividends in Ameren common stock -- or receive Ameren dividends in cash. - place Ameren common stock certificates in safekeeping and receive regular account statements. If you have not yet exchanged your Union Electric Company or CIPSCO Incorporated common stock certificates for Ameren stock certificates, please contact the Investor Services Department. This is not an offer to sell, or a solicitation of an offer to buy, any securities. -------------------------------------------------------------------------------- DIRECT DEPOSIT OF DIVIDENDS All registered Ameren common and Union Electric Company and Central Illinois Public Service Company preferred stockholders can have their cash dividends automatically credited to their bank accounts. This service gives stockholders immediate access to their dividend on the dividend payment date and eliminates the possibility of lost or stolen dividend checks. -------------------------------------------------------------------------------- AMEREN'S WEB SITE To obtain AEE's daily stock price, recent financial statistics and other information about the company, visit Ameren's home page on the Internet. Ameren's web site address is: http://www.ameren.com -------------------------------------------------------------------------------- INVESTOR SERVICES The company's Investor Services representatives are available to help you each business day from 7:30 a.m. to 4:30 p.m. (central standard time). Please write or call: Ameren Services Company Investor Services Department P.O. Box 66887 St. Louis, MO 63166-6887 St. Louis area 314-554-3502 Toll-free 1-800-255-2237 -------------------------------------------------------------------------------- TRANSFER AGENT, REGISTRAR AND PAYING AGENT The Transfer Agent, Registrar and Paying Agent for Ameren Corporation Common Stock and Union Electric Company and Central Illinois Public Service Company Preferred Stock is Ameren Services Company. -------------------------------------------------------------------------------- OFFICE One Ameren Plaza 1901 Chouteau Avenue St. Louis, MO 63103 314-621-3222 --------------------------------------------------------------------------------

1 Exhibit 21 SUBSIDIARIES OF AMEREN CORPORATION AT DECEMBER 31, 1999 <TABLE> <CAPTION> State or Jurisdiction Name of Incorporation ---------------------------------------------------- ----------------------- <S> <C> Ameren Corporation Missouri Ameren Development Company Missouri Ameren Energy Communications, Inc. Missouri Ameren ERC, Inc. Missouri Missouri Central Railroad(1) Delaware Ameren Energy, Inc. Missouri Ameren Energy Resources Co. Illinois Ameren Services Company Missouri Central Illinois Public Service Company (CIPS) Illinois CIPSCO Investment Company Illinois CIPSCO Securities Company Illinois CIPSCO Leasing Company Illinois CLC Aircraft Leasing Company Illinois CLC Leasing Company A Illinois CLC Leasing Company B Illinois CLC Leasing Company C Illinois CIPSCO Energy Company Illinois CEC-PGE-G Co. Illinois CEC-PGE-L Co. Illinois CEC-APL-G Co. Illinois CEC-APL-L Co. Illinois CEC-PSPL-G Co. Illinois CEC-PSPL-L Co. Illinois CEC-MPS-G Co. Illinois CEC-MPS-L Co. Illinois CEC-ACE-G Co. Illinois CEC-ACE-L Co. Illinois CEC-ACLP Co. Illinois CIPSCO Venture Company Illinois Union Electric Company (UE) Missouri Electric Energy, Inc.(2) Illinois </TABLE> ---------------------- (1) Ameren ERC owns 95% of the common stock. (2) Ameren owns 60% of the common stock.

1 EXHIBIT 23 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Prospectus constituting part of the Registration Statement on Form S-3 (No. 33-43721) and the Registration Statement on Form S-8 (No. 333-43737 and No. 333-50793) of Ameren Corporation of our report dated February 2, 2000, which appears on Page 14 of Ameren Corporation's 1999 Annual Report to Shareholders, which is incorporated by reference in this Annual Report on Form 10-K. We also consent to the incorporation by reference of our report on the Financial Statements Schedule, which appears on Page 14 of this Form 10-K. /s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP St. Louis, Missouri March 30, 2000

1 EXHIBIT 24 POWER OF ATTORNEY WHEREAS, AMEREN CORPORATION, a Missouri corporation (herein referred to as the "Company"), is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 1999; and WHEREAS, each of the below undersigned holds the office or offices in the Company set opposite his or her name; NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Charles W. Mueller and/or Donald E. Brandt and/or Steven R. Sullivan the true and lawful attorneys-in-fact of the undersigned, for and in the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto, and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact may do by virtue hereof. IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 11th day of February 2000: <TABLE> <S> <C> Charles W. Mueller, Chairman, President, Chief Executive Officer and Director (Principal Executive Officer) /s/ Charles W. Mueller ---------------------------------------------- William E. Cornelius, Director /s/ William E. Cornelius ---------------------------------------------- Clifford L. Greenwalt, Director /s/ Clifford L. Greenwalt ---------------------------------------------- Thomas A. Hays, Director /s/ Thomas A. Hays ---------------------------------------------- Richard A. Liddy, Director /s/ Richard A. Liddy ---------------------------------------------- Gordon R. Lohman, Director /s/ Gordon R. Lohman ---------------------------------------------- Richard A. Lumpkin, Director /s/ Richard A. Lumpkin ---------------------------------------------- John Peters MacCarthy, Director /s/ John Peters MacCarthy ---------------------------------------------- Hanne M. Merriman, Director ---------------------------------------------- Paul L. Miller, Jr., Director /s/ Paul L. Miller, Jr. ---------------------------------------------- Robert H. Quenon, Director /s/ Robert H. Quenon ---------------------------------------------- Harvey Saligman, Director /s/ Harvey Saligman ---------------------------------------------- Janet McAfee Weakley, Director /s/ Janet McAfee Weakley ---------------------------------------------- James W. Wogsland, Director ---------------------------------------------- Donald E. Brandt, Senior Vice President (Principal Financial Officer) /s/ Donald E. Brandt ---------------------------------------------- Warner L. Baxter, Vice President and Controller (Principal Accounting Officer) /s/ Warner L. Baxter ---------------------------------------------- </TABLE>

2 EXHIBIT 24 STATE OF MISSOURI ) ) SS. CITY OF ST. LOUIS ) On this 11th day of February, 2000, before me, the undersigned Notary Public in and for said State, personally appeared the above-named officers and directors of Ameren Corporation, known to me to be the persons described in and who executed the foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated. IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal. /s/ K. A. Bell ---------------------------------------- K. A. BELL Notary Public - Notary Seal STATE OF MISSOURI St. Louis County My Commission Expires: October 13, 2002

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