1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of report (Date of earliest event reported): December 31, 1997 AMEREN CORPORATION (Exact name of registrant as specified in its charter) Missouri 43-1723446 (State or other jurisdiction (Commission (I.R.S. Employer of incorporation) File Number) Identification 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

2 ITEM 2. ACQUISITION OR DISPOSITION OF ASSETS On December 31, 1997, following the receipt of all required State and Federal regulatory approvals, Union Electric Company ("UE") and CIPSCO Incorporated ("CIPSCO"), parent company of Central Illinois Public Service Company ("CIPS"), combined to form Ameren Corporation ("Ameren") with the result that the common shareholders of UE and CIPSCO became the common shareholders of Ameren and Ameren became the owner of 100% of the common stock of CIPS and UE. Pursuant to an Agreement and Plan of Merger dated as of August 11, 1995 between (among others) UE, CIPSCO and Ameren, each outstanding share of UE common stock is to be exchanged for one share of Ameren common stock and each outstanding share of CIPSCO common stock is to be exchanged for 1.03 shares of Ameren common stock. Pursuant to Rule 12g-3(c) promulgated under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), as a result of consummation of the foregoing transactions, Ameren common stock shall be deemed to be registered under Section 12(b) of the Exchange Act. A copy of the press release with respect to completion of the transaction is attached as Exhibit 99-1 to this report. ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS The following documents, previously filed with the Securities and Exchange Commission by Union Electric Company (File No. 1-2967), CIPSCO Incorporated (File No. 1-10628), or Central Illinois Public Service Company (File No. 1-3672) pursuant to the Securities Exchange Act of 1934, as amended, are hereby incorporated by reference: 1. Union Electric Company's Annual Report on Form 10-K for the year ended December 31, 1996. 2. Union Electric Company's Quarterly Reports on Form 10-Q for the quarters ended March 31, 1997, June 30, 1997, and September 30, 1997. 3. Union Electric Company's Current Reports on Form 8-K dated December 16, and December 31, 1997. 4. CIPSCO Incorporated/Central Illinois Public Service Company's Annual Report on Form 10-K for the year ended December 31, 1996. 5. CIPSCO Incorporated/Central Illinois Public Service Company's Quarterly Reports on Form 10-Q for the quarters ended March 31, 1997, June 30, 1997, and September 30, 1997. 6. Central Illinois Public Service Company's Current Reports on Form 8-K, dated March 20, June 1, November 24, December 16, and December 31, 1997. 7. CIPSCO Incorporated's Current Reports on Form 8-K, dated March 20, November 24, December 16, and December 31, 1997. Exhibits: All exhibits are listed in the Exhibit Index on Page 4. - 2 -

3 SIGNATURES Pursuant to the requirements 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) By /s/ Donald E. Brandt ------------------------------ Donald E. Brandt Senior Vice President, Finance Date: January 2, 1998 - 3 -

4 Exhibit Index <TABLE> <CAPTION> Exhibit No. Description ----------- ----------- <S> <C> 2 Agreement and Plan of Merger dated as of August 11, 1995, by and between UE, CIPSCO, the Company and Arch Merger, Inc. (incorporated by reference to Form S-4, Annex A, dated November 13, 1995 (File No. 33-64165). 27-1 Financial Data Schedule - Period ending December 31, 1996. 27-2 Financial Data Schedule - Period ending September 30, 1997. 99-1 News Release of Ameren Corporation, dated December 31, 1997. 99-2 Supplemental Consolidated Financial Statements. 99-3 Supplemental Consolidated Condensed Quarterly Financial Statements. </TABLE> - 4 -

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1 EXHIBIT 99-1 AMEREN NEWS RELEASE CONTACT: MEDIA: Susan Gallagher (314) 554-2175 INVESTOR: Lynn Barnes (314) 554-4829 UNION ELECTRIC COMPANY AND CIPSCO INCORPORATED COMPLETE MERGER TO CREATE AMEREN CORPORATION St. Louis, MO, and Springfield, IL, Dec. 31, 1997---Union Electric Company and CIPSCO Incorporated -- two financially strong Midwest utilities--today announced the completion of their merger. The combination creates Ameren Corporation (NYSE: AEE). With assets of approximately $9 billion, Ameren is parent of Union Electric (now known as AmerenUE) and Central Illinois Public Service Company (now known as AmerenCIPS). Ameren companies serve 1.5 million electric customers and 300,000 natural gas customers in a 44,500-square mile area of Missouri and Illinois. The new holding company and AmerenUE are based in St. Louis; the headquarters of AmerenCIPS remains in Springfield, IL. With the completion of the merger, shares of the new company began trading on the New York Stock Exchange. The two companies signed a definitive merger agreement in 1995 in a transaction valued now at approximately $1.4 billion. The market capitalization of Ameren is approximately $5.3 billion. "It is an understatement to say that we are extremely pleased our merger has been approved. Our employees have demonstrated creativity and dedication to make this merger a reality," said Charles W. Mueller, chairman, president and chief executive officer of Ameren Corporation. "As we said two years ago and we believe even more firmly today, this merger brings together two high quality, low-cost energy providers who have customer-focused philosophies and a solid position in their respective markets." --more--

2 CIPSCO President and Chief Executive Officer Clifford L. Greenwalt, who retires Dec. 31, 1997, cited the two companies' focus on their core energy business and the $759 million in merger savings expected over the next 10 years as strengths in an increasingly competitive environment. Holders of Union Electric common stock receive one share of the new holding company common stock (AEE) for each Union Electric share (NYSE: UEP) they hold. Holders of CIPSCO common stock (NYSE: CIP) receive 1.03 shares of the holding company common stock. (CIPSCO Incorporated was the parent company of Central Illinois Public Service Company.) Upon completion of the merger, Ameren has approximately 137 million common shares outstanding. Ameren is expected to adopt Union Electric's annual common share dividend payment level (UE's current annual dividend is $2.54 per share). The new holding company's 15-member board of directors includes 10 members from Union Electric, with Mueller as chairman of the board, and five from CIPSCO, including Greenwalt. The final of six regulatory approvals for the merger came from the Securities and Exchange Commission on Dec. 31, 1997. Other regulatory approvals were obtained from the Federal Energy Regulatory Commission, the Illinois Commerce Commission, the Missouri Public Service Commission, Hart-Scott-Rodino Filing/Federal Trade Commission and Department of Justice, and the Nuclear Regulatory Commission. Shareholders of both companies approved the agreement Dec. 20, 1995. The preferred stock of Union Electric Company and Central Illinois Public Service Company remains outstanding.

1 EXHIBIT 99-2 SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Ameren Corporation (Ameren) is a newly created holding company which will be 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 wholly-owned subsidiaries of Ameren (the Merger). In addition, Ameren, as a result of the Merger, has a 60 percent ownership interest in Electric Energy, Inc. (EEI), which is consolidated for financial reporting purposes. Upon consummation of the Merger, the common stockholders of AmerenUE and CIPSCO received one and 1.03 shares, respectively, of Ameren common stock, par value $.01 per share, and became common stockholders of Ameren. The Merger is accounted for as a pooling-of-interests, and the Supplemental Consolidated Financial Statements included in this Form 8-K, in lieu of pro forma financial statements as required by Article ll, "Pro Forma Financial Information" of Regulation S-X, are presented as if the Merger were consummated as of the beginning of the earliest period presented. However, the Supplemental 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 1996, 1995, and 1994 were $372 million ($2.71 per share), $373 million ($2.72 per share), and $391 million ($2.85 per share), respectively. Earnings and earnings per share fluctuated due to many conditions, primarily: weather variations, electric rate reductions, competitive market forces, credits to electric customers, sales growth, fluctuating operating costs, including the Callaway Plant nuclear refueling outages, merger-related expenses, changes in interest expense and changes in income and property taxes. ELECTRIC OPERATIONS The impacts of the more significant items affecting electric revenues and operating expenses during the past three years are analyzed and discussed below: <TABLE> <CAPTION> Electric Revenues Variations from Prior Year ----------------------------------------------------------------------------------------------------- (Millions of Dollars) 1996 1995 1994 ----------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Rate variations $(20) $(14) $ -- Credit to customers (15) (33) -- Effect of abnormal weather (68) 63 (45) Growth and other 107 51 50 Interchange sales 51 (13) (11) EEI (2) (76) 25 ----------------------------------------------------------------------------------------------------- $ 53 $(22) $ 19 ----------------------------------------------------------------------------------------------------- </TABLE> The increase in 1996 electric revenues was primarily due to a 4 percent increase in kilowatthour sales over the prior year, partly offset by the 1.8 percent rate decrease for Missouri electric customers and the net increase in Missouri electric customer credits recorded in 1996 versus 1995. See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Financial Statements for further information. The kilowatthour sales increase reflected strong economic growth in the service area and increased interchange sales opportunities, partially offset by milder weather during the period. Residential and industrial sales each rose 2 percent over 1995, while commercial sales grew 3 percent and interchange sales increased 9 percent.

2 The decrease in 1995 electric revenues was primarily the result of decreased sales to the Department of Energy by EEI, a one-time $30 million credit to Missouri electric customers, a rate decrease in Missouri, and a 13 percent decline in interchange sales due to decreased interchange sales opportunities. See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Financial Statements for further information. This decrease was partially offset by increased retail kilowatthour sales, mainly due to the unusually hot weather in the third quarter of 1995, compared to 1994, and sales growth reflecting the Company's healthy service area economy. Weather-sensitive residential and commercial sales increased 6 percent and 3 percent, respectively, over 1994, and industrial sales grew 2 percent. The increase in 1994 electric revenues reflected growth in sales to commercial and industrial customers of 3 percent each, partially offset by reduced sales to residential customers of 3 percent, primarily due to milder weather in the first and third quarters of 1994, compared to 1993. <TABLE> <CAPTION> Fuel and Purchased Power Variations from Prior Year ---------------------------------------------------------------------------------------------------------- (Millions of Dollars) 1996 1995 1994 ---------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Fuel: Variation in generation $ 43 $(10) $ 58 Price (14) 2 (73) Generation efficiencies and other 2 3 (2) Purchased power variation 2 9 (47) EEI 23 (42) (3) ---------------------------------------------------------------------------------------------------------- $ 56 $(38) $(67) ---------------------------------------------------------------------------------------------------------- </TABLE> The increase in 1996 fuel and purchased power costs was driven mainly by higher kilowatthour sales, partially offset by lower fuel prices due to the use of lower cost coal. The decrease in 1995 fuel and purchased power costs reflected decreased sales by EEI, partly offset by greater retail kilowatthour sales during the hot 1995 summer and the need for replacement power during the Callaway Plant's spring nuclear refueling outage. The decrease in 1994 fuel and purchased power costs reflected lower fuel prices, resulting from the increased use of low-sulfur coal at the Company's fossil-fueled power plants. Higher generation, due largely to the availability of the Callaway Plant resulting from the absence of a refueling outage in 1994, was offset in part by reduced purchased power costs. GAS OPERATIONS The increase in 1996 gas revenues of $37 million was primarily the result of higher gas prices and increased sales due to colder weather. Residential, commercial, and industrial dekatherm sales increased 13 percent, 17 percent and 7 percent, respectively, in 1996 versus 1995. Gas revenues decreased $7 million in 1995 as a result of lower prices and lower commercial and industrial dekatherm sales of 3 percent and 25 percent, respectively, partly offset by a 2 percent increase in weather-sensitive residential dekatherm sales from colder weather in 1995 versus 1994. In 1994, gas revenues decreased $21 million primarily as a result of decreased sales due to milder weather and lower gas prices. Dekatherm sales to residential and commercial customers decreased 8 percent and 6 percent, respectively, compared to 1993, while industrial sales remained unchanged. The $35 million increase in 1996 gas costs was primarily the result of a combination of increased demand due to colder weather, coupled with an increase in the price paid for gas in 1996 versus 1995. The decrease in 1995 gas costs of $20 million was predominantly due to lower gas prices in 1995, compared to 1994. In 1994, gas costs decreased $12 million primarily due to milder weather and lower gas prices in 1994 versus 1993. OTHER OPERATING EXPENSES Other operating expense variations in 1994 through 1996 reflected recurring factors such as growth, inflation, labor and benefit increases. In 1996, other operations expenses increased $2 million primarily due to increases in employee benefits, injuries and damages, and consulting expenses. In 1995, other operations expenses increased $7 million mainly due to increases in labor and material and supplies expenses, as well as the occurrence of several one-time costs, including costs relating to a voluntary separation program and write-offs of system development costs. These increases were partly offset by decreases in employee benefits, injuries and damages and insurance expenses. The decrease of $24 2

3 million in other operations expenses in 1994 is primarily the result of EEI electing to record in 1993 a $25 million one-time charge in conjunction with its adoption of SFAS No. 106, "Employers Accounting for Postretirement Benefits Other than Pensions." In 1996, maintenance expenses decreased $5 million primarily due to lower scheduled power plant maintenance, partly offset by increased labor expenses at Callaway and fossil plants. In 1995, maintenance expenses increased $26 million, mainly due to scheduled power plant maintenance expenses partially offset by reduced distribution system maintenance expenses. Callaway Plant's maintenance expenses increased $17 million primarily due to the spring 1995 nuclear refueling outage. Maintenance expenses at other power plants increased primarily due to scheduled maintenance outages. In 1994, maintenance expenses increased $12 million, mainly caused by additional maintenance expenses at fossil plants and greater tree-trimming expenses, partly offset by lower Callaway Plant maintenance expenses (no refueling outage in 1994) and reduced labor expenses. Depreciation and amortization expense increased $12 million in 1996, $11 million in 1995 and $16 million in 1994, due to increased depreciable property. TAXES Income tax expense from operations decreased $9 million in 1996 principally due to lower pretax income. Income tax expense decreased $2 million in 1995 primarily due to lower pretax income partially offset by a higher effective income tax rate. In 1994 income tax expense increased $26 million as a result of higher pretax income. In 1996, other taxes charged to operating expenses increased $2 million due to increased property and payroll taxes. In 1995, other taxes charged to operating expenses increased $2 million due to increased gross receipts taxes from greater electric revenues and increased property taxes. In 1994, other taxes charged to operating expenses rose $5 million due to increased property taxes and greater corporate franchise taxes. OTHER INCOME AND DEDUCTIONS Miscellaneous, net increased $1 million for 1996, primarily due to reduced merger-related expenses. Miscellaneous, net decreased $11 million for 1995, primarily due to increased merger-related expenses. Merger-related expenses totaled $13 million and $14 million in 1996 and 1995, respectively. See Note 1 - Summary of Significant Accounting Policies under Notes to Supplemental Consolidated Financial Statements for further information. Miscellaneous, net decreased $9 million for 1994, primarily due to increased charitable contributions. INTEREST Interest expense increased $2 million for 1996 primarily due to a greater amount of short-term debt outstanding, offset by lower rates on variable-rate long-term debt. In 1995, interest expense declined $5 million as decreases in other interest expense were partly offset by higher interest rates on variable long-term debt. In 1994, interest expense increased $13 million generally due to a greater amount of total debt outstanding and overall higher interest rates on variable-rate debt. BALANCE SHEET The $51 million increase in other current liabilities at December 31, 1996, compared to December 31, 1995, was primarily due to the timing of the payments of the $47 million Missouri electric customer credit. See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Financial Statements for further information. LIQUIDITY AND CAPITAL RESOURCES Cash provided by operating activities totaled $786 million for 1996, compared to $792 million and $708 million in 1995 and 1994, respectively. Cash flows used in investing activities totaled $481 million, $468 million, and $485 million for the years ended December 31, 1996, 1995 and 1994, respectively. Expenditures in 1996 for constructing new or to improve existing facilities, purchasing rail cars and complying with the Clean Air Act were $436 million. In addition, the Company spent $51 million to acquire nuclear fuel. 3

4 The Company's need for additional base load electric generating capacity is not anticipated until after the year 2013. Under Title IV of the Clean Air Act Amendments of 1990, the Company is required to reduce total sulfur dioxide emissions significantly by the year 2000. Significant reductions in nitrogen oxide are also required. By switching to low-sulfur coal and early banking of emissions credits, the Company anticipates that it can comply with the requirements of the law without significant revenue increases because the related capital costs are largely offset by lower fuel costs. As of year-end 1996, estimated remaining capital costs expected to be incurred pertaining to Clean Air Act-related projects totaled $76 million. Construction expenditures are expected to be about $370 million in 1997. For the five-year period 1997-2001, construction expenditures are estimated at $1.7 billion. This estimate does not include any construction expenditures which may be incurred by the Company to meet new air quality standards for ozone and particulate matter, as discussed below. In July 1997, the United States Environmental Protection Agency (EPA) issued final regulations revising the National Ambient Air Quality Standards for ozone and particulate matter. Although specific emission control requirements are still being developed, it is believed that the revised standards will require significant additional reductions in nitrogen oxide and sulfur dioxide emissions from coal-fired boilers. In October 1997, the EPA announced that Missouri and Illinois are included in the area targeted for nitrogen oxide emissions reductions as part of their regional control program. Reduction requirements in nitrogen oxide emissions from the Company's coal-fired boilers could exceed 80 percent from 1990 levels by the year 2002. Reduction requirements in sulfur dioxide emissions may be up to 50 percent beyond that already required by Phase II acid rain control provisions of the 1990 Clean Air Act Amendments and are anticipated to be required by 2007. Because of the magnitude of these additional reductions, the Company could be required to incur significantly higher capital costs to meet future compliance obligations for its coal-fired boilers or purchase power from other sources, either of which could have significantly higher operating and maintenance expenditures associated with compliance. At this time the Company is unable to determine the impact of the revised air quality standards on the Company's future financial condition, results of operations or liquidity. The United States and other countries are discussing possibilities for an international treaty to address the issue of "global warming." The Company is unable to predict what agreements, if any, will be adopted. However, most of the proposals under discussion could result in significantly higher capital costs and operations and maintenance expenditures 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 11 - Callaway Nuclear Plant under Notes to Supplemental Consolidated Financial Statements for a discussion of Callaway Plant decommissioning costs. Cash flows used in financing activities were $296 million for 1996, compared to $325 million and $226 million for 1995 and 1994, respectively. The Company's principal financing activities during 1996 included the redemption of $35 million of first mortgage bonds and $18 million of short-term debt bank loans and the payment of dividends. In addition, on December 16, 1996, AmerenUE issued $66 million of Subordinated Deferrable Interest Debentures, 7.69 percent Series, due 2036. AmerenUE used the proceeds to redeem certain series of preferred stock in January 1997. The Company plans to continue utilizing short-term debt to support normal operations and other temporary requirements. AmerenUE and AmerenCIPS are authorized by the Federal Energy Regulatory Commission (FERC) to have up to $600 million and $150 million, respectively, 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, 1996, the Company had committed bank lines of credit aggregating $257 million (of which $246 million were unused 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. At year-end, the Company had $69 million of short-term borrowings. AmerenCIPS has registration statements covering $200 million of first mortgage bonds and medium-term notes filed with the Securities and Exchange Commission (SEC). AmerenCIPS' mortgage indenture 4

5 limits the amount of first mortgage bonds which may be issued. At December 31, 1996, AmerenCIPS could have issued about $480 million of additional first mortgage bonds under the indenture, assuming an annual interest rate of 7.75 percent. Additionally, AmerenCIPS' articles of incorporation limit amounts of preferred stock which may be issued. Assuming a preferred dividend rate of 6.50 percent, the utility could have issued all $185 million of authorized but unissued preferred stock as of year-end. AmerenUE has registration statements covering $160 million of long-term debt filed with the SEC. In addition, AmerenUE has registration statements filed with the SEC covering $100 million of preferred stock. AmerenUE also has bank credit agreements due 1999 which permit the borrowing of up to $300 million and $200 million on a long-term basis. At December 31, 1996, no such borrowings were outstanding. Additionally, AmerenUE has a lease agreement which provides for the financing of nuclear fuel. At December 31, 1996, the maximum amount which could be financed under the agreement was $120 million. Cash provided from financing for 1996 included issuances under the lease for nuclear fuel of $44 million offset in part by $35 million of redemptions. At December 31, 1996, $106 million was financed under the lease. See Note 3 - Nuclear Fuel Lease under Notes to Supplemental Consolidated Financial Statements for further information. RATE MATTERS See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Financial Statements for further information. CONTINGENCIES Subsequent to the completion of a contract restructuring with a major coal supplier by AmerenCIPS, a group of industrial customers filed with the Illinois Third District Appellate Court (the Court) in February 1997 an appeal of the December 1996 order of the Illinois Commerce Commission (ICC) which approved, among other things, recovery of the restructuring payment and associated carrying costs (Restructuring Charges), incurred as a result of the restructuring, through the retail fuel adjustment clause (FAC). 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, AmerenCIPS classified the $72 million of the Restructuring Charges made to the coal supplier in February 1997 as a regulatory asset and, through October 1997, recovered approximately $9.5 million of the Restructuring Charges through the retail FAC and from wholesale customers. On November 24, 1997, the Court reversed the ICC's order, finding that the Restructuring Charges were not direct costs of fuel that may be recovered through the retail FAC, but rather should be considered as a part of a review of AmerenCIPS' aggregate revenue requirements in a full rate case. Restructuring Charges allocated to wholesale customers (approximately 16 percent of the total) are not in question as a result of the opinion of the Court. On December 8, 1997, AmerenCIPS requested a rehearing by the Court. The Company is evaluating the impact of the Court decision on its financial statements. The Company cannot predict the ultimate outcome of this matter. If the Court's decision should ultimately prevail, AmerenCIPS will be required to cease recovery of the Restructuring Charges through the retail FAC, and could be required to refund any portion of those charges that had been collected through the retail FAC. The Company is also exploring other alternatives for recovery of the Restructuring Charges. The Company is currently evaluating the unamortized retail portion of the Restructuring Charges, which is currently classified as a regulatory asset, to determine if it continues to meet the criteria for the existence of an asset under Generally Accepted Accounting Principles (GAAP). If it is determined that such criteria are not met, the unamortized balance of the Restructuring Charges, approximately $36 million, net of tax, could be charged to earnings. The Company is also evaluating the revenues previously recovered in 1997 through the retail FAC to determine if a loss contingency, as defined under GAAP, is required. Such loss contingency ($5 million, net of tax) could also be charged to earnings. See Note 10 - Commitments and Contingencies under Notes to Supplemental Consolidated Financial Statements for further information. 5

6 See Note 10 - Commitments and Contingencies under Notes to Supplemental Consolidated Financial Statements for other material issues existing at December 31, 1996. DIVIDENDS Common stock dividends paid in 1996 resulted in a payout rate of 88% of the Company's earnings to common stockholders. Dividends paid to common stockholders in relation to net cash provided by operating activities for the same period were 42%. 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 increases at other utilities; return on investments with similar risk characteristics; and overall business considerations. It is currently anticipated that the Company will initially pay dividends on its common stock at AmerenUE's historical payment level, which was $2.54 per share on an annual basis prior to the consummation of the Merger. ELECTRIC INDUSTRY RESTRUCTURING Changes enacted and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation, as well as 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 stranded 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 addition, certain states are considering proposals that would 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 Act) providing for utility restructuring in Illinois. This legislation introduces price-based competition into the supply of electric energy in Illinois and will provide a less regulated structure for Illinois electric utilities. The Act includes a 5 percent residential electric rate decrease for the Company's Illinois electric customers, effective August 1, 1998. The Company may be subject to additional 5 percent 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. The Company estimates that the initial 5 percent rate decrease will result in a decrease in annual electric revenues of about $13 million, based on estimated levels of sales and assuming normal weather conditions. Retail direct access, which allows customers to choose their electric generation supplier, 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. The Act also relieves the Company of the requirement in the ICC's Order issued in September 1997 (which approved the Merger), requiring AmerenUE and AmerenCIPS to file electric rate cases or alternative regulatory plans in Illinois following consummation of the Merger to reflect the effects of net merger savings. Other provisions of the Act include (1) potential recovery of a portion of a utility's stranded costs through a transition charge collected from customers who choose another electric supplier, 6

7 (2) the option for certain utilities, including the Company, to eliminate the retail FAC applicable to their rates and to roll into base rates a historical level of fuel expense and (3) a mechanism to securitize certain future revenues related to stranded costs. At this time, the Company is assessing the impact that the Act will have on its operations. The potential negative consequences resulting from the Act could be significant and include the impairment and writedown of certain assets, including generation-related plant and regulatory assets, related to the Company's Illinois jurisdictional assets. The provisions of the Act could also result in lower revenues, reduced profit margins and increased costs of capital. At this time, the Company is unable to determine the impact of the Act on the Company's future financial condition, results of operations or liquidity. (See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Financial Statements.) In Missouri, where 72 percent of the Company's retail electric revenues are derived, a task force appointed by the Missouri Public Service Commission (MoPSC) is investigating industry restructuring and competition and is scheduled to issue a report to the MoPSC in 1998. A joint legislative committee is also conducting hearings on these issues. Currently, retail wheeling has not been allowed in Missouri; however, the joint agreement approved by the MoPSC in February 1997 as part of its merger authorization includes a provision that required AmerenUE to file a proposal for a 100-megawatt experimental retail wheeling pilot program in Missouri. AmerenUE filed its proposal with the MoPSC in September 1997. This proposal is still subject to review and approval by the MoPSC. The Company is unable to predict the timing or ultimate outcome of the electric industry restructuring initiatives being considered in the state of Missouri. In the state of Missouri, the potential negative consequences of industry restructuring could be significant and include the impairment and writedown of certain assets, including generation-related plant and regulatory assets, lower revenues, reduced profit margins and increased costs of capital. At this time, the Company is unable to predict the impact of potential electric industry restructuring matters in the state of Missouri on the Company's future financial condition, results of operations or liquidity. (See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Financial Statements for further information.) INFORMATION SYSTEMS The Year 2000 issue relates to computer systems and applications which currently use two-digit date fields to designate a year. As the century date change occurs, date-sensitive systems will recognize the year 2000 as 1900, or not at all. This inability to recognize or properly treat the year 2000 may cause systems to process critical financial and operational information incorrectly. The Company continues to assess the impact of the Year 2000 issue on its operations, including the development of final cost estimates for, and the extent of programming changes required to address this issue. At this time, the Company believes that the Year 2000 issue will not have a material adverse effect on its financial condition, results of operations or liquidity. OUTLOOK The Company's management and Board of Directors recognize that competition will continue to increase in the future, especially in the energy supply portion of our business. The introduction of competition into the markets, coupled with the impact of the revised air quality standards on the Company's operations, will result in numerous challenges and uncertainties for Ameren and the utility industry. At this time, the Company cannot predict the timing or impact of these matters on its future financial condition, results of operations or liquidity. ACCOUNTING MATTERS In October 1996, the American Institute of Certified Public Accountants issued Statement of Position 96-1, "Environmental Remediation Liabilities" (SOP 96-1). This statement establishes standards for the recognition, measurement, display and disclosure of environmental remediation liabilities. In October 1997, the American Institute of Certified Public Accountants issued Statement of Position 97-2, "Software Revenue Recognition" (SOP 97-2). This statement establishes standards for recognizing revenue on software transactions. SOP 96-1 is effective January 1, 1997, and SOP 97-2 is effective for transactions 7

8 entered into in fiscal years beginning after December 15, 1997. SOP 96-1 and SOP 97-2 are not expected to have a material effect on the Company's financial position or results of operations upon adoption. In February 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share" and SFAS No. 129, "Disclosure of Information about Capital Structure". SFAS 128 establishes standards for computing and presenting earnings per share. SFAS 129 establishes standards for disclosing information about an entity's capital structure. In June 1997, the Financial Accounting Standards Board issued SFAS No. 130, "Reporting Comprehensive Income" and SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information". SFAS 130 establishes standards for reporting and displaying of comprehensive income. SFAS 131 establishes standards for reporting information about operating segments in annual financial statements and interim reports to shareholders. SFAS 128 and SFAS 129 are effective for financial statements issued for periods ending after December 15, 1997. SFAS 130 and SFAS 131 are effective for fiscal years beginning after December 15, 1997. SFAS 128, SFAS 129, SFAS 130 and SFAS 131 are not expected to have a material effect on the Company's financial position or results of operations upon adoption. EFFECTS OF INFLATION AND CHANGING PRICES The Company's rates for retail electric and gas service are 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 may not be adequate to replace plant in future years. However, existing regulatory practice may be modified for the Company's generation portion of its business (see Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Financial Statements). 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 Illinois, changes in the cost of fuel for electric generation and gas costs are generally reflected in billings to customers on a timely basis through fuel and purchased gas adjustment clauses. However, existing regulatory practice may be modified in Illinois for changes in the cost of fuel for electric generation (see Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Financial Statements). In Missouri, 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. Changes in gas costs in Missouri are generally reflected in billings to customers on a timely basis 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 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, legislation, events, conditions, financial performance and dividends. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Company is providing the following cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. Factors include, but are not limited to, the effects of: regulatory actions; changes in laws and other governmental actions; competition; business and economic conditions; weather conditions; fuel prices and availability; generation plant performance; monetary and fiscal policies; and legal and administrative proceedings. 8

9 Report of Independent Accountants To the Stockholders and Board of Directors of Ameren Corporation In our opinion, based upon our audits and the reports of other auditors, the accompanying supplementary consolidated balance sheets and the related supplementary consolidated statements of income, of cash flows and retained earnings present fairly, in all material respects, the financial position of Ameren Corporation and its subsidiaries at December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. 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, which combined statements reflect total assets of $1,871,656,000 and $1,827,911,000 at December 31, 1996 and 1995, respectively, and total revenues of $896,715,000, $842,262,000 and $844,615,000 for the three years in the period ended December 31, 1996, respectively. Those statements were audited by other auditors whose reports thereon have 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, is based solely on the reports of the other auditors. We conducted our audits of these statements in accordance with generally accepted auditing standards 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 reports of other auditors provide a reasonable basis for the opinion expressed above. /s/ PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP St. Louis, Missouri December 17, 1997 9

10 AMEREN CORPORATION SUPPLEMENTAL CONSOLIDATED BALANCE SHEET (Thousands of Dollars, Except Shares) <TABLE> <CAPTION> December 31, December 31, ASSETS 1996 1995 ------ ---- ---- <S> <C> <C> Property and plant, at original cost: Electric $11,252,095 $10,991,058 Gas 428,531 403,349 Other 35,965 35,033 ----------- ----------- 11,716,591 11,429,440 Less accumulated depreciation and amortization 5,024,046 4,848,740 ----------- ----------- 6,692,545 6,580,700 Construction work in progress: Nuclear fuel in process 96,147 85,916 Other 162,414 199,600 ----------- ----------- Total property and plant, net 6,951,106 6,866,216 ----------- ----------- Investments and other assets: Investments 113,310 105,081 Nuclear decommissioning trust fund 96,601 73,838 Other 64,655 55,983 ----------- ----------- Total investments and other assets 274,566 234,902 ----------- ----------- Current assets: Cash and cash equivalents 11,899 2,378 Accounts receivable - trade (less allowance for doubtful accounts of $5,795 and $7,525, respectively) 268,839 256,309 Unbilled revenue 106,316 109,332 Other accounts and notes receivable 55,256 39,302 Materials and supplies, at average cost - Fossil fuel 106,153 107,366 Other 137,953 139,116 Other 42,759 42,023 ----------- ----------- Total current assets 729,175 695,826 ----------- ----------- Regulatory assets: Deferred income taxes 734,206 777,613 Other 243,514 213,494 ----------- ----------- Total regulatory assets 977,720 991,107 ----------- ----------- Total Assets $ 8,932,567 $ 8,788,051 =========== =========== CAPITAL AND LIABILITIES Capitalization: Common stock, $.01 par value, authorized 400,000,000 shares - outstanding 137,215,462 shares $ 1,372 $ 1,372 Other paid-in capital, principally premium on common stock 1,583,728 1,583,728 Retained earnings 1,431,295 1,385,629 ----------- ----------- Total common stockholders' equity 3,016,395 2,970,729 Preferred stock not subject to mandatory redemption (see 298,497 298,497 Note 4) Preferred stock subject to mandatory redemption (see Note 4) 624 650 Long-term debt (see Note 6) 2,335,454 2,372,539 ----------- ----------- Total capitalization 5,650,970 5,642,415 ----------- ----------- Minority interest in consolidated subsidiary 3,534 3,534 Current liabilities: Current maturity of long-term debt 146,410 69,462 Short-term debt (see Note 5) 69,068 77,521 Accounts and wages payable 297,017 289,715 Accumulated deferred income taxes 43,933 27,429 Taxes accrued 65,245 58,988 Other 194,239 143,029 ----------- ----------- Total current liabilities 815,912 666,144 ----------- ----------- Accumulated deferred income taxes 1,653,095 1,677,146 Accumulated deferred investment tax credits 209,227 218,758 Regulatory liability 304,172 329,708 Other deferred credits and liabilities 295,657 250,346 ----------- ----------- Total Capital and Liabilities $ 8,932,567 $ 8,788,051 =========== =========== </TABLE> See Notes to Supplemental Consolidated Financial Statements 10

11 AMEREN CORPORATION SUPPLEMENTAL CONSOLIDATED STATEMENT OF INCOME (Thousands of Dollars, Except Shares and Per Share Amounts) <TABLE> <CAPTION> December 31, December 31, December 31, For the year ended 1996 1995 1994 ---- ---- ---- <S> <C> <C> <C> OPERATING REVENUES: Electric $ 3,013,527 $ 3,066,940 $ 3,035,512 Gas 254,412 217,420 224,527 Other 12,153 9,976 9,432 ------------- ------------- ------------- Total operating revenues 3,333,505 3,240,923 3,269,471 OPERATING EXPENSES: Operations Fuel and purchased power 880,204 823,951 862,417 Gas costs 160,776 125,305 145,139 Other 543,998 542,386 535,590 ------------- ------------- ------------- 1,584,978 1,491,642 1,543,146 Maintenance 302,203 307,546 282,012 Depreciation and amortization 344,360 332,247 320,920 Income taxes 258,327 267,229 269,673 Other taxes 273,034 270,670 268,422 ------------- ------------- ------------- Total operating expenses 2,762,902 2,669,334 2,684,173 OPERATING INCOME 570,603 571,589 585,298 OTHER INCOME AND DEDUCTIONS: Allowance for equity funds used during construction 6,870 7,716 6,397 Miscellaneous, net (15,907) (16,686) (5,515) ------------- ------------- ------------- Total other income and deductions, net (9,037) (8,970) 882 INCOME BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS 561,566 562,619 586,180 INTEREST CHARGES AND PREFERRED DIVIDENDS: Interest 180,402 178,826 183,761 Allowance for borrowed funds used during construction (7,490) (6,179) (5,802) Preferred dividends of subsidiaries 16,970 17,100 16,762 ------------- ------------- ------------- Net interest charges and preferred dividends 189,882 189,747 194,721 NET INCOME $ 371,684 $ 372,872 $ 391,459 ============= ============= ============= EARNINGS PER SHARE OF COMMON STOCK (BASED ON AVERAGE SHARES OUTSTANDING) $ 2.71 $ 2.72 $ 2.85 ============= ============= ============= AVERAGE COMMON SHARES OUTSTANDING 137,215,462 137,215,462 137,253,617 ============= ============= ============= </TABLE> See Notes to Supplemental Consolidated Financial Statements 11

12 AMEREN CORPORATION SUPPLEMENTAL CONSOLIDATED STATEMENT OF CASH FLOWS (Thousands of Dollars) <TABLE> <CAPTION> December 31, December 31 December 31, For the year ended 1996 1995 1994 ---- ---- ---- <S> <C> <C> <C> Cash Flows From Operating: Net income $ 371,684 $ 372,872 $ 391,459 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 327,859 315,515 338,649 Amortization of nuclear fuel 37,792 35,140 44,267 Allowance for funds used during construction (14,360) (13,895) (12,199) Postretirement benefit accrued 11,923 24,680 Deferred income taxes, net 12,665 4,003 1,021 Deferred investment tax credits, net (9,531) (9,542) (9,549) Changes in assets and liabilities: Receivables, net (25,468) (21,229) 13,494 Materials and supplies 2,376 (174) (13,006) Accounts and wages payable 7,302 105,042 (104,378) Taxes accrued 6,259 (7,085) 10,366 Other, net 58,732 (13,258) 46,384 --------- --------- --------- Net cash provided by operating activities 786,100 791,656 708,054 Cash Flows From Investing: Construction expenditures (435,904) (429,839) (455,965) Allowance for funds used during construction 14,360 13,895 12,199 Nuclear fuel expenditures (51,176) (42,444) (30,458) Other (7,784) (10,047) (10,560) --------- --------- --------- Net cash used in investing activities (480,504) (468,435) (484,784) Cash Flows From Financing: Dividends on common stock (326,855) (319,875) (312,460) Environmental bond funds 4,443 12,583 Redemptions - Nuclear fuel lease (34,819) (70,420) (32,137) Short-term debt (18,300) (6,100) (84,100) Long-term debt (35,000) (54,000) (45,000) Common stock (1,020) Preferred stock (26) (26) (26) Issuances - Nuclear fuel lease 43,884 49,134 51,386 Short-term debt 9,847 52,536 14,985 Long-term debt 65,194 19,766 170,000 --------- --------- --------- Net cash used in financing activities (296,075) (324,542) (225,789) Net change in cash and cash equivalents 9,521 (1,321) (2,519) Cash and cash equivalents at beginning of year 2,378 3,699 6,218 --------- --------- --------- Cash and cash equivalents at end of year $ 11,899 $ 2,378 $ 3,699 ======================================================================================== Cash paid during the periods: ---------------------------------------------------------------------------------------- Interest (net of amount capitalized) $ 167,433 $ 173,569 $ 148,508 Income taxes $ 248,096 $ 274,820 $ 262,321 ---------------------------------------------------------------------------------------- </TABLE> See Notes to Supplemental Consolidated Financial Statements 12

13 AMEREN CORPORATION SUPPLEMENTAL CONSOLIDATED STATEMENT OF RETAINED EARNINGS (Thousands of Dollars) <TABLE> <CAPTION> ------------------------------------------------------------------------------------------------------------ Year Ended December 31, 1996 1995 1994 ------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> Balance at Beginning of Period $1,385,629 $1,331,567 $1,254,920 ------------------------------------------------------------------------------------------------------------ Add: Net income 371,684 372,872 391,459 Other 837 1,065 ------------------------------------------------------------------------------------------------------------ 1,758,150 1,705,504 1,646,379 ------------------------------------------------------------------------------------------------------------ Deduct: Common stock cash dividends 326,855 319,875 312,460 Other 2,352 ------------------------------------------------------------------------------------------------------------ 326,855 319,875 314,812 ------------------------------------------------------------------------------------------------------------ $1,431,295 $1,385,629 $1,331,567 ------------------------------------------------------------------------------------------------------------ </TABLE> Under mortgage indentures as amended, $34,435 of total retained earnings was restricted against payment of common dividends - except those payable in common stock, leaving $1,396,860 of free and unrestricted retained earnings at December 31, 1996. SELECTED QUARTERLY INFORMATION (Unaudited) (Thousands of Dollars, Except Per Share Amounts) <TABLE> <CAPTION> ------------------------------------------------------------------------------------------------ Operating Operating Net Earnings Per Revenues Income Income Common QUARTER ENDED Share ------------------------------------------------------------------------------------------------ <S> <C> <C> <C> <C> March 31, 1996 $778,528 $106,393 $57,946 $.42 March 31, 1995 731,621 100,938 47,479 .35 June 30, 1996 786,500 123,668 72,616 .53 June 30, 1995 777,269 141,629 85,608 .62 September 30, 1996 1,019,589 267,812 217,073 1.58 September 30, 1995 1,024,849 242,567 211,026 1.54 December 31, 1996 748,888 72,730 24,049 .18 December 31, 1995 707,184 86,455 28,759 .21 ------------------------------------------------------------------------------------------------ </TABLE> The first and second quarters of 1996 included credits to Missouri electric customers which reduced net income approximately $8 million and $20 million, or 6 cents per share and 15 cents per share, respectively. In addition, a 1.8% 1995 rate decrease for Missouri electric customers reduced net income for the first, second and third quarters of 1996 by $4 million, $5 million and $3 million, or 3 cents per share, 4 cents per share and 2 cents per share, respectively. Fourth quarter 1996 included Callaway Plant refueling expenses which decreased net income approximately $18 million, or 13 cents per share. First quarter 1995 included expenses related to a voluntary separation program which decreased net income by $4 million, or 3 cents per share. Second quarter 1995 included Callaway Plant refueling expenses which decreased net income approximately $20 million, or 15 cents per share. Third quarter 1995 reflected a one-time credit to Missouri electric customers which reduced net income approximately $18 million, or 13 cents per share. In addition, the 1995 rate decrease reduced net income $4 million, or 3 cents per share, in both third and fourth quarters of 1995. Also, in the third and fourth quarters of 1995, merger-related expenses reduced net income approximately $9 million and $5 million, or 7 cents per share and 3 cents per share, respectively. Fourth quarter 1995 also included a write-off of system development costs which decreased net income by $4 million, or 3 cents per share. 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 Supplemental Consolidated Financial Statements 13

14 AMEREN CORPORATION NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996 NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES MERGER AND SUPPLEMENTAL FINANCIAL STATEMENTS (BASIS OF PRESENTATION) Effective December 31, 1997, following the receipt of all required state and federal regulatory approvals, Union Electric Company (AmerenUE) and CIPSCO Incorporated (CIPSCO) combined to form Ameren Corporation (Ameren)(the Merger). The accompanying supplemental 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 financial statements reflect the conversion of each outstanding share of AmerenUE common stock into one share of Ameren common stock, and each outstanding share of CIPSCO common stock into 1.03 shares of Ameren common stock in accordance with the terms of the merger agreement. The outstanding preferred stock of AmerenUE and Central Illinois Public Service Company (AmerenCIPS), a subsidiary of CIPSCO, 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 in the states of Missouri and Illinois. The Company also has a non-regulated investing subsidiary, CIPSCO Investment Company (CIC). The Company has a 60% interest in Electric Energy, Inc. (EEI). EEI owns and operates an electric generating 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. Operating revenues and net income for each of the years in the three year period ended December 31, 1996, were as follows (in millions): <TABLE> <CAPTION> AmerenUE CIPSCO OTHER AMEREN -------- ------ ----- ------ <S> <C> <C> <C> <C> Year ended December 31, 1996: Operating revenues $2,260 $897 $177 $3,334 Net income 292 80 372 Year ended December 31, 1995: Operating revenues $2,242 $842 $157 $3,241 Net income 301 72 373 Year ended December 31, 1994: Operating revenues $2,224 $845 $200 $3,269 Net income 307 84 391 </TABLE> REGULATION Ameren will be a registered holding company and therefore subject to regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA). AmerenUE and AmerenCIPS are also regulated by the Missouri Public Service Commission (MoPSC), Illinois Commerce Commission (ICC), and the Federal Energy Regulatory Commission (FERC). The accounting policies of the Company are in accordance with the ratemaking practices of the regulatory 14

15 authorities having jurisdiction and, as such, conform to Generally Accepted Accounting Principles (GAAP), as applied to regulated public utilities. 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, plus an allowance for funds used during construction. 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, 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 1996, 1995 and 1994 was approximately 3% of the average depreciable cost. FUEL AND GAS COSTS In Illinois, the Company adjusts fuel expense to recognize over- or under- recoveries from customers of allowable fuel costs through the uniform fuel adjustment clause (FAC). The FAC provides for the current recovery of changes in the cost of fuel for electric generation in billings to customers. The purchased gas adjustment clauses provide a matching of gas costs with revenues in Illinois and in Missouri. The state of Missouri does not have a FAC. 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 kilowatthours sold. CASH AND CASH EQUIVALENTS Cash and cash equivalents include cash on hand and temporary investments purchased with a 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 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 rate-making 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 during 1996, 1995 and 1994 were 7.7% - 9.0%, 9.0% - 9.3% and 8.9% - 9.0%, respectively. 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. 15

16 STOCK COMPENSATION PLANS The Company applies Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25) in accounting for its plans. LONG-LIVED ASSETS 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" became effective on January 1, 1996. SFAS 121 prescribes general standards for the recognition and measurement of impairment losses. SFAS 121 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 discussion). SFAS 121 did not have an impact on the financial position, results of operations or liquidity of the Company upon adoption. USE OF ESTIMATES The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions may 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. NOTE 2 - REGULATORY MATTERS In July 1995, the MoPSC approved an agreement involving the Company's Missouri electric rates. The agreement decreased rates 1.8% for all classes of Missouri retail electric customers, effective August 1, 1995, reducing annual revenues by about $30 million and reducing annual earnings by approximately 13 cents per share. In addition, a one-time $30 million credit to retail Missouri electric customers reduced 1995 earnings approximately 13 cents per share. Also included is a three-year experimental alternative regulation plan that provides that earnings in any future years in excess of a 12.61% regulatory return on equity (ROE) will be shared equally between customers and stockholders, and earnings above a 14% ROE will be credited to customers. The formula for computing the credit uses twelve-month results ending June 30, rather than calendar year earnings. The agreement also provides that no party shall file for a general increase or decrease in the Company's Missouri retail electric rates prior to July 1, 1998, except that the Company may file for an increase if certain adverse events occur. During 1996, the Company recorded a $47 million credit for the first year of the plan, which reduced earnings by $28 million, or 21 cents per share. This credit was reflected as a reduction in electric revenues. Included in the joint agreement approved by the MoPSC in its February 1997 order authorizing the Merger, is a new three-year experimental alternative regulation plan that will run from July 1, 1998, through June 30, 2001. Like the current plan, the new plan provides that earnings over a 12.61% ROE up to a 14% ROE will be shared equally between customers and shareholders. The new three-year plan will also return to customers 90% of all earnings above a 14% ROE up to a 16% ROE. Earnings above a 16% ROE would be credited entirely to customers. Other agreement provisions include: recovery over a 10-year period of the Missouri portion of merger-related expenses; a Missouri electric rate decrease, effective September 1, 1998, based on the weather-adjusted average annual credits to customers under the current experimental alternative regulation plan; and an experimental retail wheeling pilot program for 100 megawatts of electric power. Also, as part of the agreement, the Company will not seek to recover in Missouri the merger premium. The exclusion of the merger premium from rates did not result in a charge to earnings. In September 1997, the ICC approved the Merger subject to certain conditions. The conditions included the requirement for AmerenUE and AmerenCIPS to file electric and gas rate cases or alternative regulatory plans within six months after the Merger is final to determine how net merger savings would be shared between the ratepayers and stockholders. In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Act) providing for utility restructuring in Illinois. This legislation introduces price-based competition into the supply of electric energy in Illinois and will provide a less regulated structure for Illinois electric utilities. The Act includes a 5 percent residential electric rate decrease for the Company's Illinois electric customers, effective August 1, 1998. The Company may be subject to additional 5 percent 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 16

17 utility average. The Company estimates that the initial 5 percent rate decrease will result in a decrease in annual electric revenues of about $13 million, based on estimated levels of sales and assuming normal weather conditions. Retail direct access, which allows customers to choose their electric generation supplier, 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. The Act also relieves the Company of the requirement in the ICC's Order issued in September 1997 (which approved the Merger), requiring AmerenUE and AmerenCIPS to file electric rate cases or alternative regulatory plans in Illinois following consummation of the Merger to reflect the effects of net merger savings. Other provisions of the Act include (1) potential recovery of a portion of a utility's stranded costs through a transition charge collected from customers who choose another electric supplier, (2) the option for certain utilities, including the Company, to eliminate the retail FAC applicable to their rates and to roll into base rates a historical level of fuel expense and (3) a mechanism to securitize certain future revenues related to stranded costs. 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 No. 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) which 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 applicable portion of the business. At its July 24, 1997 meeting, the Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) 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), and can therefore continue to be carried on the regulated entity's balance sheet to the extent such assets are recovered. In addition, SFAS 121 establishes accounting standards for the impairment of long lived assets (see Note 1 - Summary of Significant Accounting Policies for further information). Due to the enactment of the Act, prices for the supply of electric generation are expected to transition from cost-based, regulated rates to rates determined by competitive market forces in the state of Illinois. As a result, the Company will discontinue application of SFAS 71 for the Illinois 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. At this time, the Company is assessing the impact that the Act will have on its operations. The potential negative consequences resulting from the Act could be significant and include the impairment and writedown of certain assets, including generation-related plant and regulatory assets, related to the Company's Illinois jurisdictional assets. At September 30, 1997, the Company's net investment in generation facilities related to its Illinois jurisdiction approximated $826 million and was included in electric plant-in service on the Company's balance sheet. In addition, at September 30, 1997, the Company's Illinois generation-related net regulatory assets approximated $166 million. The provisions of the Act could also result in lower revenues, reduced profit margins and increased costs of capital. At this time, the Company is unable to determine the impact of the Act on the Company's future financial condition, results of operations or liquidity. In the state of Missouri, where approximately 72 percent of the Company's retail electric revenues are derived, a task force appointed by the MoPSC is conducting studies of electric industry restructuring and competition and will issue a report to the MoPSC in April 1998. A joint legislative committee is also conducting studies and will report its findings and recommendations to the Missouri General Assembly after reviewing the results of the MoPSC task force. 17

18 The Company is unable to predict the timing or ultimate outcome of the electric industry restructuring initiatives being considered in the state of Missouri. In the state of Missouri, the potential negative consequences of industry restructuring could be significant and include the impairment and writedown of certain assets, including generation-related plant and regulatory assets, lower revenues, reduced profit margins and increased costs of capital. At September 30, 1997, the Company's net investment in generation facilities related to its Missouri jurisdiction approximated $2.7 billion and was included in electric plant-in service on the Company's balance sheet. In addition, at September 30, 1997, the Company's Missouri generation-related regulatory assets approximated $435 million. At this time, the Company is unable to predict the impact of potential electric industry restructuring matters in the state of Missouri on the Company's future financial condition, results of operations or liquidity. In April 1996, the FERC issued Order 888 and Order 889 related to the industry's wholesale electric business. The Company filed an open access tariff under Order 888 as part of the merger case and in July 1997, the case was settled. In March 1997, the FERC issued Order 888A which required the Company to refile a tariff by July 1997. The terms were not significantly different from those filed in the original tariff under Order 888. 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. <TABLE> <CAPTION> At December 31, the Company had recorded the following regulatory assets and regulatory liability: ------------------------------------------------------------------------------------------ (in millions) 1996 1995 ------------------------------------------------------------------------------------------ <S> <C> <C> REGULATORY ASSETS: Income taxes $734 $778 Callaway costs 111 115 Undepreciated plant costs 41 -- Unamortized loss on reacquired debt 42 47 Contract termination costs 20 26 DOE decommissioning assessment 18 19 Other 12 6 ------------------------------------------------------------------------------------------ Regulatory Assets $978 $991 ------------------------------------------------------------------------------------------ REGULATORY LIABILITY: Income taxes $304 $330 ------------------------------------------------------------------------------------------ Regulatory Liability $304 $330 ------------------------------------------------------------------------------------------ </TABLE> INCOME TAXES: See Note 7 - Income Taxes CALLAWAY COSTS: Represents the 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). UNDEPRECIATED PLANT COSTS: Represents the unamortized cost of the Newton Power Plant Unit 1 scrubber plus costs of removal. These costs are being amortized over six years beginning in 1997. 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. CONTRACT TERMINATION COSTS: Represents costs incurred for terminating a nuclear fuel purchase contract. These costs are being amortized over the remaining life of the terminated contract (through 2001). DEPARTMENT OF ENERGY (DOE) DECOMMISSIONING ASSESSMENT: Represents fees assessed by the DOE to decommission its uranium enrichment facility. These costs are being amortized through 2007 as payments are made to the DOE. 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. 18

19 NOTE 3 - NUCLEAR FUEL LEASE The Company has a lease agreement which provides for the financing of nuclear fuel. At December 31, 1996, 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 $37 million during 1996, $34 million during 1995 and $34 million during 1994. The Company has capitalized the cost, including certain interest costs, of the leased nuclear fuel and has recorded the related lease obligation. During the year 1996, 1995 and 1994, the total interest charges under the lease were $6 million, $6 million and $5 million, respectively (based on average interest rates of 5.7%, 6.1% and 4.7%, respectively) of which $3 million was capitalized in each respective year. NOTE 4 - PREFERRED STOCK OF SUBSIDIARIES At December 31, 1996 and 1995, AmerenUE and AmerenCIPS had 25 million shares and 4.6 million shares, respectively, of authorized preferred stock. AmerenUE retired 260 shares, $6.30 Series preferred stock in each of the years 1996, 1995, and 1994. On January 21, 1997, AmerenUE redeemed $64 million of preferred stock (see note (b) in table below). <TABLE> <CAPTION> Outstanding preferred stock is redeemable at the redemption prices shown below: --------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------- December 31, 1996 1995 (in millions) (in millions) --------------------------------------------------------------------------------------------------------------- PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION: --------------------------------------------------------------------------------------------------------------- Preferred stock outstanding without par value (entitled to cumulative dividends) Redemption Price (per share) <S> <C> <C> <C> <C> Stated value of $100 per share-- $7.64 Series - 330,000 shares $103.82 - note (a) $33 $ 33 $7.44 Series - 330,001 shares 101.00 - note (b) 33 33 $6.40 Series - 300,000 shares 101.50 - note (b) 30 30 $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 (c) 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 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 - note (d) 100.00 30 30 </TABLE> 19

20 <TABLE> <S> <C> <C> <C> 6.625% - 125,000 shares 100.00 - note (e) 13 13 Stated value of $25.00 per share-- $1.735 Series - 1,657,000 shares 25.00 - note (f) 41 41 -------------------------------------------------------------------------------------------------------------- TOTAL PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION $298 $298 -------------------------------------------------------------------------------------------------------------- PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION: -------------------------------------------------------------------------------------------------------------- Preferred stock outstanding without par value (entitled to cumulative dividends) Stated value of $100 per share-- $6.30 Series - 6,240 and 6,500 shares at respective dates, due 2020 $100.00 - note (b) $ 1 $ 1 -------------------------------------------------------------------------------------------------------------- TOTAL PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION $ 1 $ 1 -------------------------------------------------------------------------------------------------------------- </TABLE> (a) Beginning February 15, 2003, eventually declining to $100 per share. (b) AmerenUE redeemed this series on January 21, 1997. (c) In the event of voluntary liquidation, $105.50. (d) Dividend rate for each dividend period (currently every 49 days) is set at a then current market rate according to an auction procedure. The rate at December 31, 1996 was 3.87%. (e) Not redeemable prior to October 1, 1998. (f) On or after August 1, 1998. NOTE 5 - 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, 1996, $69 million of short-term borrowings were outstanding. The weighted average interest rates on borrowings outstanding at December 31, 1996 and 1995, were 7.2% and 6.0%, respectively. At December 31, 1996, the Company had committed bank lines of credit aggregating $257 million (of which $246 million were unused) 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. NOTE 6 - LONG-TERM DEBT OF SUBSIDIARIES Long-term debt outstanding at December 31, was: <TABLE> <CAPTION> -------------------------------------------------------------------------------------------- (in millions) 1996 1995 -------------------------------------------------------------------------------------------- First Mortgage Bonds - note (a) -------------------------------------------------------------------------------------------- <S> <C> <C> 5 1/2% Series due 1997 $ 40 $ 40 6 3/4% Series due 1999 100 100 8.33% Series due 2002 75 75 7.65% Series due 2003 100 100 6 7/8% Series due 2004 188 188 7 3/8% Series due 2004 85 85 6 3/4% Series due 2008 148 148 7.40% Series due 2020 - note (b) 60 60 8 3/4% Series due 2021 125 125 8% Series due 2022 85 85 8 1/4% Series due 2022 104 104 7.15% Series due 2023 75 75 </TABLE> 20

21 <TABLE> <S> <C> <C> 7% Series due 2024 100 100 5.45% Series due 2028 - note (b) 44 44 Series W 7 1/8% due 5/15/1999 50 50 Series X 6 1/8% due 7/01/1997 43 43 Series X 7 1/2% due 7/01/2007 50 50 Series Z 6 3/8% due 4/01/2003 40 40 Other 121 156 ---------------------------------------------------------------------------------------------- 1,633 1,668 ---------------------------------------------------------------------------------------------- Missouri Environmental Improvement ---------------------------------------------------------------------------------------------- Revenue bonds 1984 Series A due 2014 - note (c) 80 80 1984 Series B due 2014 - note (c) 80 80 1985 Series A due 2015 - note (d) 70 70 1985 Series B due 2015 - note (d) 57 57 1991 Series due 2020 - note (d) 43 43 1992 Series due 2022 - note (d) 47 47 ---------------------------------------------------------------------------------------------- 377 377 ---------------------------------------------------------------------------------------------- Pollution Control Loan Obligations ---------------------------------------------------------------------------------------------- 1990 Series B 7.60% due 9/01/2013 32 32 1993 Series A 6 3/8% due 1/01/2028 35 35 1993 Series C-1 4.20% due 8/15/2026 - note (e) 35 35 Other 80 80 ---------------------------------------------------------------------------------------------- 182 182 ---------------------------------------------------------------------------------------------- Subordinated Deferrable Interest Debentures ---------------------------------------------------------------------------------------------- 7.69% Series A due 2036 - note (f) 66 -- ---------------------------------------------------------------------------------------------- Unsecured Loans - notes (g) (h) -- -- ---------------------------------------------------------------------------------------------- Nuclear Fuel Lease 106 97 ---------------------------------------------------------------------------------------------- 1991 Medium Term Notes 60 60 ---------------------------------------------------------------------------------------------- 1994 Medium Term Notes 70 70 ---------------------------------------------------------------------------------------------- Unamortized Discount and Premium on Debt (13) (12) ---------------------------------------------------------------------------------------------- Maturities Due Within One Year (146) (69) ---------------------------------------------------------------------------------------------- Total Long-Term Debt $2,335 $2,373 ---------------------------------------------------------------------------------------------- </TABLE> (a) At December 31, 1996, 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) On June 1 of each year, the interest rate is established for the following year, or alternatively at the option of the Company, may be fixed until maturity. A per annum rate of 3.65% is effective for the year ended May 31, 1997. Thereafter, the interest rates will depend on market conditions and the selection of an annual versus remaining life rate by the Company. The average interest rate for the year ended December 31, 1996, was 3.80%. (d) 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 1996, for 1985 Series A, 1985 Series B, 1991 Series and 1992 Series bonds were 3.45%, 3.52%, 3.68%, and 3.67%, respectively. (e) Interest rates on the 1993 Series C-1 bonds will be adjusted to a then-current market rate on August 15, 1998. (f) During the terms of the debentures, the Company may, under certain circumstances, defer the payment of interest for up to five years. (g) A bank credit agreement due 1999 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, 1996, no such borrowings were outstanding. (h) A bank credit agreement due 1999 permits the Company to borrow or to support commercial paper borrowings up to $300 million. Interest rates will vary depending on market conditions. At December 31, 1996, no such borrowings were outstanding. <TABLE> <CAPTION> Maturities of long-term debt through 2001 are as follows: -------------------------------------------------------------------------- (in millions) Principal Amount -------------------------------------------------------------------------- <S> <C> <C> 1997 $146 1998 43 1999 164 2000 39 2001 14 -------------------------------------------------------------------------- </TABLE> Amounts for years subsequent to 1998 do not include nuclear fuel lease payments since the amounts of such payments are not currently determinable. 21

22 NOTE 7 - INCOME TAXES Total income tax expense for 1996 resulted in an effective tax rate of 40% on earnings before income taxes (40% in 1995 and 39% in 1994). <TABLE> <CAPTION> Principal reasons such rates differ from the statutory federal rate: ------------------------------------------------------------------------------------------------- 1996 1995 1994 ------------------------------------------------------------------------------------------------- <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 Miscellaneous, net (1) ------------------------------------------------------------------------------------------------- EFFECTIVE INCOME TAX RATE 40% 40% 39% ------------------------------------------------------------------------------------------------- </TABLE> <TABLE> <CAPTION> Income tax expense components: ---------------------------------------------------------------------------------------- (in millions) 1996 1995 1994 ---------------------------------------------------------------------------------------- <S> <C> <C> <C> TAXES CURRENTLY PAYABLE (PRINCIPALLY FEDERAL): Included in operating expenses $261 $273 $281 Included in other income-- Miscellaneous, net (6) (7) (9) ---------------------------------------------------------------------------------------- 255 266 272 DEFERRED TAXES (PRINCIPALLY FEDERAL): Included in operating expenses-- Depreciation differences 2 10 6 Postretirement benefits (9) (10) Other 5 2 2 Included in other income-- Depreciation differences 1 1 1 Other 1 ---------------------------------------------------------------------------------------- 8 4 -- DEFERRED INVESTMENT TAX CREDITS, AMORTIZATION Included in operating expenses (9) (9) (9) ---------------------------------------------------------------------------------------- TOTAL INCOME TAX EXPENSE $254 $261 $263 ---------------------------------------------------------------------------------------- </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. <TABLE> <CAPTION> Temporary differences gave rise to the following deferred tax assets and deferred tax liabilities at December 31: -------------------------------------------------------------------------------------------------------------- (in millions) 1996 1995 -------------------------------------------------------------------------------------------------------------- <S> <C> <C> ACCUMULATED DEFERRED INCOME TAXES: Depreciation $1,070 $1,060 Regulatory assets, net 488 516 Capitalized taxes and expenses 199 210 Deferred benefit costs (48) (52) Disallowed plant costs (14) (13) Regulatory liabilities, net (46) (54) Leveraged leases 35 31 Other 13 7 -------------------------------------------------------------------------------------------------------------- TOTAL NET ACCUMULATED DEFERRED INCOME TAX LIABILITIES $1,697 $1,705 -------------------------------------------------------------------------------------------------------------- </TABLE> 22

23 NOTE 8 - RETIREMENT BENEFITS The Company has defined-benefit retirement plans covering substantially all of its employees. Benefits are based on the employees' years of service and compensation. The Company's plans are funded in compliance with income tax regulations and federal funding requirements. Pension costs for the years 1996, 1995 and 1994, were $32 million, $32 million and $36 million, respectively. Following is the pension plan information related to AmerenUE plans as of December 31: <TABLE> <CAPTION> Funded Status of Pension Plans ------------------------------------------------------------------------------------------------------------- (in millions) 1996 1995 1994 ------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> ACTUARIAL PRESENT VALUE OF BENEFIT OBLIGATION: Vested benefit obligation $661 $679 $552 ------------------------------------------------------------------------------------------------------------- Accumulated benefit obligation $752 $758 $622 ------------------------------------------------------------------------------------------------------------- Projected benefit obligation for service rendered to date $919 $913 $779 Plan assets at fair value (*) 924 847 706 ------------------------------------------------------------------------------------------------------------- (Excess) Deficiency of plan assets versus projected benefit obligation (5) 66 73 Unrecognized net gain 96 22 18 Unrecognized prior service cost (76) (82) (89) Unrecognized net assets at transition 8 9 10 ------------------------------------------------------------------------------------------------------------- ACCRUED PENSION COST AT DECEMBER 31 $ 23 $ 15 $ 12 ------------------------------------------------------------------------------------------------------------- </TABLE> (*) Plan assets consist principally of common stocks and fixed income securities. <TABLE> <CAPTION> Components of Net Pension Expense ------------------------------------------------------------------------------------------------------------- (in millions) 1996 1995 1994 ------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Service cost - benefits earned during the period $ 22 $ 19 $ 21 Interest cost on projected benefit obligation 65 66 60 Actual return on plan assets (107) (166) 8 Net amortization and deferral 48 107 (58) ------------------------------------------------------------------------------------------------------------- PENSION COST $ 28 $ 26 $ 31 ------------------------------------------------------------------------------------------------------------- </TABLE> <TABLE> <CAPTION> Assumptions for Actuarial Present Value of Projected Benefit Obligations: ------------------------------------------------------------------------------------------------------------- 1996 1995 1994 ------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Discount rate at measurement date 7.5% 7.25% 8.5% Increase in future compensation 4.5% 4.25% 5.5% Plan assets long-term rate of return 8.5% 8.5% 8.5% ------------------------------------------------------------------------------------------------------------- </TABLE> AmerenCIPS uses a September 30 measurement date for its valuation of pension plan assets and liabilities. Following is the pension plan information related to AmerenCIPS plans as of December 31: 23

24 <TABLE> <CAPTION> Funded Status of Pension Plans ------------------------------------------------------------------------------------------------------------- (in millions) 1996 1995 1994 ------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> ACTUARIAL PRESENT VALUE OF BENEFIT OBLIGATION: Vested benefit obligation $148 $121 $120 ------------------------------------------------------------------------------------------------------------- Accumulated benefit obligation $171 $142 $124 ------------------------------------------------------------------------------------------------------------- Projected benefit obligation for service rendered to date $211 $181 $163 Plan assets at fair value (*) 253 221 188 ------------------------------------------------------------------------------------------------------------- (Excess) Deficiency of plan assets versus projected benefit obligation (42) (40) (25) Unrecognized net gain 40 33 23 Unrecognized prior service cost (11) (5) (6) Unrecognized net assets at transition 3 4 4 ------------------------------------------------------------------------------------------------------------- Prepaid pension costs at September 30 (10) (8) (4) Expense, net of funding October to December (1) -- -- ------------------------------------------------------------------------------------------------------------- PREPAID PENSION COST AT DECEMBER 31 $(11) $ (8) $ (4) ------------------------------------------------------------------------------------------------------------- </TABLE> (*) Plan assets consist principally of common and preferred stocks, bonds, money market instruments and real estate. <TABLE> <CAPTION> Components of Net Pension Expense ------------------------------------------------------------------------------------------------------------ (in millions) 1996 1995 1994 ------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> Service cost - benefits earned during the period $ 7 $ 7 $ 8 Interest cost on projected benefit obligation 13 12 11 Actual return on plan assets (30) (34) (7) Net amortization and deferral 14 21 (7) ------------------------------------------------------------------------------------------------------------ PENSION COST $ 4 $ 6 $ 5 ------------------------------------------------------------------------------------------------------------ </TABLE> <TABLE> <CAPTION> Assumptions for Actuarial Present Value of Projected Benefit Obligations ---------------------------------------------------------------------------------------------------------- 1996 1995 1994 ---------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Discount rate at measurement date 7.5% 7.5% 7.75% Increase in future compensation 4.5% 4.5% 4.8% Plan assets long-term rate of return 8.5% 8.0% 8.0% ---------------------------------------------------------------------------------------------------------- </TABLE> In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees. Substantially all of the Company's employees may become eligible for those benefits if they reach retirement age while working for the Company. The Company accrues the expected postretirement benefit costs during employees' years of service. The following is information related to AmerenUE postretirement benefit plans as of December 31: AmerenUE's funding policy is to contribute to a Voluntary Employee Beneficiary Association trust (VEBA) annually the net periodic cost. Postretirement benefit costs were $44 million for each of the years 1996 and 1995 and $46 million for 1994, of which approximately 19% was charged to construction accounts in each of the three years. AmerenUE's transition obligation at December 31, 1996, is being amortized over the next 16 years. In August 1994, the MoPSC authorized the recovery of postretirement benefit costs in rates to the extent that such costs are funded. In December 1995, the Company established two external trust funds for retiree healthcare and life insurance benefits. For both 1995 and 1994, actual claims paid were approximately $15 million. In 1996, claims were paid out of the plan trust funds. 24

25 <TABLE> <CAPTION> Funded Status of the Plans ------------------------------------------------------------------------------------------------------------ (in millions) 1996 1995 1994 ------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> ACCUMULATED POSTRETIREMENT BENEFIT OBLIGATION Active employees eligible for benefits $ 38 $ 74 $ 42 Retired employees 193 211 188 Other active employees 80 32 60 ------------------------------------------------------------------------------------------------------------ Total benefit obligation 311 317 290 Plan assets at fair market value (*) 47 14 -- ------------------------------------------------------------------------------------------------------------ Accumulated postretirement benefit obligation in excess of plan assets 264 303 290 Unrecognized - transition obligation (200) (213) (225) - gain/(loss) 19 (7) 4 ------------------------------------------------------------------------------------------------------------ POSTRETIREMENT BENEFIT LIABILITY AT DECEMBER 31 $ 83 $ 83 $ 69 ------------------------------------------------------------------------------------------------------------ </TABLE> (*) Plan assets consist principally of common stocks and fixed income securities. <TABLE> <CAPTION> Components of Postretirement Benefit Cost ------------------------------------------------------------------------------------------------------------- (in millions) 1996 1995 1994 ------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Service cost - benefits earned during the period $ 12 $ 10 $ 11 Interest cost on projected benefit obligation 22 24 21 Actual return on plan assets (4) -- -- Amortization - transition obligation 12 12 13 - unrecognized (1) (2) 1 (gain)/loss Deferred gain 3 -- -- ------------------------------------------------------------------------------------------------------------- NET PERIODIC COST $ 44 $ 44 $ 46 ------------------------------------------------------------------------------------------------------------- </TABLE> <TABLE> <CAPTION> Assumptions for the Obligation Measurements ------------------------------------------------------------------------------------------------------------- 1996 1995 1994 ------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Discount rate at measurement date 7.5% 7.25% 8.5% Plan assets long-term rate of return 8.5% 8.5% -- Medical cost trend rate - initial 8.25% 9.25% 11.0% - ultimate 5.25% 5.25% 6.0% Ultimate medical cost trend rate expected in year 2000 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 by approximately $3 million and $23 million, respectively. 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 no more than the actual annual postretirement medical benefit obligation as determined by actuarial calculation and no less than the revenue provided in AmerenCIPS' utility rate structure for the obligation. AmerenCIPS uses a September 30 measurement date for its valuation of postretirement assets and liabilities. Postretirement benefit costs were $16 million for 1996 and $17 million for each of the years 1995 and 1994, of which approximately 15% was charged to construction accounts in each of the three years. AmerenCIPS' transition obligation at December 31, 1996, is being amortized over 20 years. 25

26 <TABLE> <CAPTION> Funded Status of the Plans -------------------------------------------------------------------------------------------------------------- (in millions) 1996 1995 1994 -------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> ACCUMULATED POSTRETIREMENT BENEFIT OBLIGATION Active employees eligible for benefits $ 20 $ 17 $ 15 Retired employees 54 50 48 Other active employees 65 76 64 -------------------------------------------------------------------------------------------------------------- Total benefit obligation 139 143 127 Plan assets at fair market value (*) 71 49 27 -------------------------------------------------------------------------------------------------------------- Accumulated postretirement benefit obligation in excess of plan assets 68 94 100 Unrecognized - transition obligation (89) (99) (104) - gain/(loss) 38 24 21 -------------------------------------------------------------------------------------------------------------- Accrued postretirement benefit cost at September 30 17 19 17 Expense, net of funding, October to December (14) (15) (15) -------------------------------------------------------------------------------------------------------------- POSTRETIREMENT BENEFIT LIABILITY AT DECEMBER 31 $ 3 $ 4 $ 2 -------------------------------------------------------------------------------------------------------------- </TABLE> (*) Plan assets consist principally of common and preferred stocks, bonds, money market instruments and real estate. <TABLE> <CAPTION> Components of Postretirement Benefit Cost -------------------------------------------------------------------------------------------------------------- (in millions) 1996 1995 1994 -------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> Service cost - benefits earned during the period $4 $4 $4 Interest cost on projected benefit obligation 11 10 9 Actual return on plan assets (9) (8) -- Amortization of transition obligation 6 6 6 Deferred gains (losses) 4 5 (2) -------------------------------------------------------------------------------------------------------------- NET PERIODIC COST $16 $17 $17 -------------------------------------------------------------------------------------------------------------- </TABLE> <TABLE> <CAPTION> Assumptions for the Obligation Measurements ------------------------------------------------------------------------------------------------------------ 1996 1995 1994 ------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> Discount rate at measurement date 7.5% 7.5% 8.25% Plan assets long-term rate of return 8.5% 8.0% 8.0% Medical cost trend rate - initial 9.8% 10.6% 11.4% - ultimate 4.5% 4.0% 4.0% Ultimate medical cost trend rate expected in year 2005 2007 2007 ------------------------------------------------------------------------------------------------------------ </TABLE> A 1% increase in the medical cost trend rate is estimated to increase the net periodic cost and the accumulated postretirement benefit obligation as of September 30, 1996 by approximately $3 million and $23 million, respectively. NOTE 9 - STOCK OPTION PLANS AmerenUE has a long-term incentive plan (the Plan) for eligible employees. 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 2006. Under the Plan, subject to adjustment as provided in the Plan, 2.5 million shares have been authorized to be issued or delivered. As of merger effective date, AmerenUE shares under the Plan were converted to Ameren shares. 26

27 <TABLE> <CAPTION> Summary of stock options: ------------------------------------------------------------------------------------------------------------ 1995 ------------------------------------------------------------------------------------------------------------ <S> <C> Options outstanding at beginning of the year -- Options granted during the year 142,500 Options exercised during the year -- Options expired/canceled during the year -- ------------------------------------------------------------------------------------------------------------ Options outstanding at end of the year 142,500 ------------------------------------------------------------------------------------------------------------ Options exercisable at end of the year 9,800 ------------------------------------------------------------------------------------------------------------ Exercise price range of options granted $35 1/2 - $35 7/8 ------------------------------------------------------------------------------------------------------------ </TABLE> <TABLE> <CAPTION> ------------------------------------------------------------------------------------------------------------ 1996 ------------------------------------------------------------------------------------------------------------ <S> <C> Options outstanding at beginning of the year 142,500 Options granted during the year 165,590 Options exercised during the year -- Options expired/canceled during the year 700 ------------------------------------------------------------------------------------------------------------ Options outstanding at end of the year 307,390 ------------------------------------------------------------------------------------------------------------ Options exercisable at end of the year 39,710 ------------------------------------------------------------------------------------------------------------ Exercise price of options granted $43 ------------------------------------------------------------------------------------------------------------ </TABLE> In accordance with APB 25, no compensation cost has been recognized for the Company's stock compensation plans. In 1996, the Company adopted the disclosure-only method 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 1996 and 1995 net income and earnings per share would have been immaterial. NOTE 10 - COMMITMENTS AND CONTINGENCIES The Company is engaged in a construction program under which expenditures averaging approximately $340 million, including AFC, are anticipated during each of the next five years. This estimate does not include any construction expenditures which may be incurred by the Company to meet new air quality standards for ozone and particulate matter, as discussed later in this Note. AmerenUE has commitments for the purchase of coal under long-term contracts. Coal contract commitments, including transportation costs, for 1997 through 2001 are estimated to total $789 million (excluding contract escalation provisions). Total coal purchases, including transportation costs, for 1996, 1995 and 1994 were $270 million, $293 million and $268 million, respectively. AmerenUE also has existing contracts with pipeline and natural gas suppliers to provide natural gas for distribution and electric generation. Gas-related contracted cost commitments for 1997 through 2001 are estimated to total $99 million. Total delivered natural gas costs for 1996, 1995 and 1994 were $64 million, $60 million and $63 million, respectively. AmerenUE's nuclear fuel commitments for 1997 through 2001, including uranium concentrates, conversion, enrichment and fabrication, are expected to total $151 million, and are expected to be financed under the nuclear fuel lease. Nuclear fuel expenditures for 1996, 1995 and 1994 were $51 million, $42 million, and $30 million, respectively. Additionally, AmerenUE has long-term contracts with other utilities to purchase electric capacity. These commitments for 1997 through 2001 are estimated to total $201 million. During 1996, 1995 and 1994, electric capacity purchases were $44 million, $42 million and $38 million, respectively. AmerenCIPS also has commitments for the purchase of coal under long-term contracts. Total coal commitments, including transportation costs, for 1997 through 2001 are estimated to total $788 million (excluding contract escalation provisions). Total coal purchases for AmerenCIPS, including transportation costs, for 1996, 1995 and 1994 were $217 million, $189 million, and $193 million, respectively. AmerenCIPS also has existing contracts with pipeline and natural gas suppliers to provide natural gas for distribution. Gas-related contract commitments for 1997 through 2001 are estimated at $148 million. Total delivered natural gas costs for 1996, 1995 and 1994 were $97 million, $67 million and $85 million, respectively. 27

28 During 1996, AmerenCIPS restructured its contract with one of its major coal suppliers. In 1997, AmerenCIPS paid a $70 million restructuring payment to the supplier, which allows them to purchase at market prices low-sulfur, out-of-state coal through the supplier (in substitution for the high-sulfur Illinois coal AmerenCIPS was obligated to purchase under the original contract); and would receive options for future purchases of low-sulfur, out-of-state coal from the supplier through 1999 at set negotiated prices. By switching to low-sulfur coal, AmerenCIPS was able to discontinue operating the Newton Power Plant Unit 1 scrubber. The benefits of the 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 over the next 10 years. In December 1996, the ICC entered an order approving the switch to out-of-state coal, recovery of the restructuring payment plus associated carrying costs (Restructuring Charges) through the retail FAC over six years, and continued recovery in rates of the undepreciated scrubber investment plus costs of removal. A group of industrial customers filed with the Illinois Third District Appellate Court (the Court) in February 1997 an appeal of the December 1996 order of the ICC which approved, among other things, recovery of the Restructuring Charges through the retail FAC. 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, AmerenCIPS classified the $72 million of the Restructuring Charges made to the coal supplier in February 1997 as a regulatory asset and, through October 1997, recovered approximately $9.5 million of the Restructuring Charges through the retail FAC and from wholesale customers. On November 24, 1997, the Court reversed the ICC's order, finding that the Restructuring Charges were not direct costs of fuel that may be recovered through the retail FAC, but rather should be considered as a part of a review of AmerenCIPS' aggregate revenue requirements in a full rate case. Restructuring Charges allocated to wholesale customers (approximately 16 percent of the total) are not in question as a result of the opinion of the Court. On December 8, 1997, AmerenCIPS requested a rehearing by the Court. The Company is evaluating the impact of the Court decision on its financial statements. The Company cannot predict the ultimate outcome of this matter. If the Court's decision should ultimately prevail, AmerenCIPS will be required to cease recovery of the Restructuring Charges through the retail FAC, and could be required to refund any portion of those charges that had been collected through the retail FAC. The Company is also exploring other alternatives for recovery of the Restructuring Charges. The Company is currently evaluating the unamortized retail portion of the Restructuring Charges, which is currently classified as a regulatory asset, to determine if it continues to meet the criteria for the existence of an asset under GAAP. If it is determined that such criteria are not met, the unamortized balance of the Restructuring Charges, approximately $36 million, net of tax, could be charged to earnings. The Company is also evaluating the revenues previously recovered in 1997 through the retail FAC to determine if a loss contingency, as defined under GAAP, is required. Such loss contingency ($5 million, net of tax) could also be charged to earnings. The Company's insurance coverage for its Callaway Nuclear Plant at December 31, 1996 was as follows: <TABLE> <CAPTION> TYPE AND SOURCE OF COVERAGE -------------------------------------------------------------------------------------------------------- (in millions) Maximum Maximum Coverages Assessments for Single Incidents -------------------------------------------------------------------------------------------------------- <S> <C> <C> Public Liability: American Nuclear Insurers $ 200 $ -- Pool Participation 8,720 79 (a) -------------------------------------------------------------------------------------------------------- $ 8,920 (b) $ 79 -------------------------------------------------------------------------------------------------------- Nuclear Worker Liability: American Nuclear Insurers $ 200 (c) $ 3 -------------------------------------------------------------------------------------------------------- </TABLE> 28

29 <TABLE> <S> <C> <C> Property Damage: American Nuclear Insurers $ 500 $ -- Nuclear Electric Insurance Ltd. 2,250 (d) 13 -------------------------------------------------------------------------------------------------------- $ 2,750 $ 13 -------------------------------------------------------------------------------------------------------- Replacement Power: Nuclear Electric Insurance Ltd. $ 419 (e) $ 3 -------------------------------------------------------------------------------------------------------- </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. (b) Limit of liability for each incident under Price-Anderson. (c) Total industry potential liability from workers claiming exposure to the hazard of nuclear radiation. The policy includes an automatic reinstatement thereby providing total coverage of $400 million. (d) Includes premature decommissioning costs. (e) Weekly indemnity of $3 million, for 52 weeks which commences after the first 21 weeks of an outage, plus $3 million per week for 104 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 the Callaway Plant 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 the Clean Air Act Amendments of 1990, the Company is required to reduce total annual sulfur dioxide emissions significantly by the year 2000. Significant reductions in nitrogen oxide are also required. By switching to low-sulfur coal and early banking of emission credits, the Company anticipates that it can comply with the requirements of the law without significant revenue increases because the related capital costs are largely offset by lower fuel costs. As of year-end 1996, estimated remaining capital costs expected to be incurred pertaining to Clean Air Act-related projects totaled $76 million. In July 1997, the United States Environmental Protection Agency (EPA) issued final regulations revising the National Ambient Air Quality Standards for ozone and particulate matter. Although specific emission control requirements are still being developed, it is believed that the revised standards will require significant additional reductions in nitrogen oxide and sulfur dioxide emissions from coal-fired boilers. In October 1997, the EPA announced that Missouri and Illinois are included in the area targeted for nitrogen oxide emissions reductions as part of their regional control program. Reduction requirements in nitrogen oxide emissions from the Company's coal-fired boilers could exceed 80 percent from 1990 levels by the year 2002. Reduction requirements in sulfur dioxide emissions may be up to 50 percent beyond that already required by Phase II acid rain control provisions of the 1990 Clean Air Act Amendments and are anticipated to be required by 2007. Because of the magnitude of these additional reductions, the Company could be required to incur significantly higher capital costs to meet future compliance obligations for its coal-fired boilers or purchase power from other sources, either of which could have significantly higher operating and maintenance expenditures associated with compliance. At this time the Company is unable to determine the impact of the revised air quality standards on the Company's future financial condition, results of operations or liquidity. The United States and other countries are discussing possibilities for an international treaty to address the issue of "global warming." The Company is unable to predict what agreements, if any, will be adopted. However, most of the proposals under discussion could result in significantly higher capital costs and operations and maintenance expenditures 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, 1996, AmerenUE was designated a potentially responsible party (PRP) by federal and state environmental protection agencies at four hazardous waste sites. Other hazardous waste sites have been identified for which AmerenUE may be responsible but has not been designated a PRP. AmerenCIPS has identified 13 sites where it and certain of its predecessors and other affiliates previously 29

30 operated facilities that manufactured gas from coal. This manufacturing produced various potentially harmful by-products which may remain on some sites. One site was added to the EPA Superfund list in 1990. Costs relating to studies and remediation at the 13 AmerenCIPS' sites and associated legal and litigation expenses are being accrued and deferred rather than expensed currently, pending recovery through rates or from insurers. Through December 31, 1996, the total of the costs deferred, net of recoveries from insurers and through environmental adjustment clause rate riders approved by the ICC, was $11 million. The ICC has instituted a reconciliation proceeding to review AmerenCIPS' environmental remediation activities in 1993, 1994 and 1995 and to determine whether the revenues collected under the riders in 1993 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. In mid-1997, AmerenCIPS and the ICC Staff submitted a stipulation with regard to all matters at issue. Under the stipulation, as of December 31, 1995, the aggregate amount of (i) revenues received under the riders, insurance proceeds (and related interest) exceeded (ii) rider-related costs (and related carrying costs) by approximately $4 million. If this stipulation is approved by the ICC, this amount would be applied to cover a portion of future remediation costs. Also, if the stipulation is approved, insurance proceeds of approximately $3 million would be applied to cover non-rider related costs incurred. During 1997, the accumulated balance of recoverable environmental remediation costs exceeded the balance of available insurance proceeds and rider revenues; therefore, AmerenCIPS began to again collect revenue under the riders beginning November 1, 1997. 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 lockout by AmerenCIPS of both unions during 1993. The NLRB has issued complaints against AmerenCIPS concerning its lockout. Both unions seek, among other things, back pay and other benefits for the period of the lockout. The Company estimates the amount of back pay and other benefits for both unions to be less than $17 million. An administrative law judge of the NLRB has ruled that the lockout was unlawful. On July 23, 1996, the Company appealed to the NLRB. The Company believes the lockout was both lawful and reasonable and that the final resolution of the disputes will not have a material adverse effect on financial position, results of operations or liquidity of the Company. 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 discussion. The Company is involved in other 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. NOTE 11 - CALLAWAY NUCLEAR PLANT Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. 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. 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 2005 and has viable storage alternatives under consideration. Each alternative will likely require Nuclear Regulatory Commission approval and may require other regulatory approvals. The delayed availability of DOE's disposal facility is not expected to adversely affect the continued operation of Callaway Plant. 30

31 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 $451 million in current year dollars and are expected to escalate approximately 4% per year through the end of decommissioning activity in 2033. Decommissioning cost is charged to depreciation expense over Callaway's service life and amounted to $7 million in each of the years 1996, 1995 and 1994. Every three years, the MoPSC requires 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 study was performed in 1996. Costs collected from customers are deposited in an external trust fund to provide for Callaway's decommissioning. Fund earnings are expected to average 9.25% annually through the date of decommissioning. If the assumed return on trust assets is not earned, the Company believes it is probable that such earnings deficiency will be recovered in rates. Trust fund earnings, net of expenses, appear on the balance sheet as increases in nuclear decommissioning trust fund and in the accumulated provision for nuclear decommissioning. The staff of the SEC has questioned certain of the 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 12 - 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. FINANCIAL DERIVATIVES The fair value is estimated using market values of options, calls and futures contracts on organized exchanges. NUCLEAR DECOMMISSIONING TRUST FUND The fair value of the Company's nuclear decommissioning trust fund 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 OF SUBSIDIARIES 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. Carrying amounts and estimated fair values of the Company's financial instruments at December 31: <TABLE> <CAPTION> 1996 1995 ------------------------------------------------------------------------------------------------------- (in millions) Carrying Fair Carrying Fair Amount Value Amount Value ------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> Marketable securities $ 51 $ 51 $ 46 $ 46 Preferred stock 299 257 299 254 Long-term debt (including current portion) 2,482 2,545 2,442 2,583 ------------------------------------------------------------------------------------------------------- </TABLE> 31

32 The Company has investments in debt and equity securities that are held in trust funds for the purpose of funding the nuclear decommissioning of the Callaway Nuclear Plant (see Note 11 - 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, 1996 and 1995. In 1996, 1995 and 1994, the proceeds from the sale of investments were $20 million, $9 million and $22 million, respectively. Using the specific identification method to determine cost, the gross realized gains on those sales were approximately $1 million each for 1996, 1995, and 1994. Net realized and unrealized gains and losses are reflected in accumulated provision for nuclear decommissioning on the Balance Sheet, which is consistent with the method used by the Company to account for the decommissioning costs recovered in rates. <TABLE> <CAPTION> Costs and fair values of investments in debt and equity securities in the nuclear decommissioning trust fund at December 31 were as follows: ------------------------------------------------------------------------------------------------------------- 1996 (in millions) Gross Unrealized Security Type Cost Gain (Loss) Fair Value ------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> Debt Securities $29 $ 2 $ -- $31 Equity Securities 40 22 -- 62 Cash equivalents 4 -- -- 4 ------------------------------------------------------------------------------------------------------------- $73 $24 $ -- $97 ------------------------------------------------------------------------------------------------------------- </TABLE> <TABLE> <CAPTION> ------------------------------------------------------------------------------------------------------------- 1995 (in millions) Gross Unrealized Security Type Cost Gain (Loss) Fair Value ------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> Debt Securities $22 $ 3 $ -- $25 Equity Securities 38 9 -- 47 Cash equivalents 2 -- -- 2 ------------------------------------------------------------------------------------------------------------- $62 $12 $ -- $74 ------------------------------------------------------------------------------------------------------------- </TABLE> <TABLE> <CAPTION> The contractual maturities of investments in debt securities at December 31, 1996: ------------------------------------------------------------------------------------------------------------ (in millions) Cost Fair Value ------------------------------------------------------------------------------------------------------------ <S> <C> <C> 1 year to 5 years $ 2 $ 2 5 years to 10 years 3 3 Due after 10 years 24 25 ------------------------------------------------------------------------------------------------------------ $29 $30 ------------------------------------------------------------------------------------------------------------ </TABLE> 32

1 EXHIBIT 99-3 SUPPLEMENTAL CONSOLIDATED CONDENSED FINANCIAL STATEMENTS MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Ameren Corporation (Ameren) is a newly created holding company which will be 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 wholly-owned subsidiaries of Ameren (the Merger). In addition, Ameren, as a result of the Merger, has a 60 percent ownership interest in Electric Energy, Inc. (EEI), which is consolidated for financial reporting purposes. Upon consummation of the Merger, the common stockholders of AmerenUE and CIPSCO received one and 1.03 shares, respectively, of Ameren common stock, par value $.01 per share, and became common stockholders of Ameren. The Merger is accounted for as a pooling-of-interests, and the Supplemental Consolidated Condensed Financial Statements included in this Form 8-K, in lieu of pro forma financial statements as required by Article ll, "Pro Forma Financial Information" of Regulation S-X, are presented as if the Merger were consummated as of the beginning of the earliest period presented. However, the Supplemental Consolidated Condensed 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 Common stock earnings for the nine months ended September 30, 1997 totaled $340 million, or $2.48 per share, compared to earnings of $348 million or $2.53 per share for the same period in 1996. Earnings and earnings per share fluctuated due to many conditions, primarily: weather variations, competitive market forces, credits to electric customers, sales growth, fluctuating operating expenses, and merger-related expenses. ELECTRIC OPERATIONS The impacts of the more significant items affecting electric revenues and operating expenses during the nine month period ended September 30, 1997 compared to 1996 are detailed below: <TABLE> <CAPTION> Electric Revenues -------------------------------------------------------------------- (millions of dollars) Variation for period ended September 30, 1997 from comparable prior year period -------------------------------------------------------------------- Nine Months ------ <S> <C> Rate variations $ (4) Credits to customers 26 Effect of abnormal weather (3) Growth and other (3) Interchange sales (6) EEI 5 -------------------------------------------------------------------- $ 15 -------------------------------------------------------------------- </TABLE> Electric revenues for the nine months ended September 30, 1997 increased $15 million compared to the same period last year primarily due to a lower customer credit (see Note 2 - Regulatory Matters under 1

2 Notes to the Supplemental Consolidated Condensed Financial Statements), partly offset by decreases in interchange revenues and lower revenues attributable to one less day in the period due to leap year in 1996. For the nine month period ended September 30, 1997, residential sales decreased 2 percent while commercial sales remained relatively flat compared to the same periods in 1996. Industrial sales increased 1 percent while interchange sales decreased 1 percent compared to the year-ago periods. <TABLE> <CAPTION> Fuel and Purchased Power ---------------------------------------------------------------------------- (Millions of dollars) Variation for period ended September 30, 1997 from comparable prior period ---------------------------------------------------------------------------- Nine Months ------ <S> <C> Fuel: Variation in generation $ 26 Price (20) Generation efficiencies and other -- Purchased power variation (37) EEI 9 ---------------------------------------------------------------------------- $(22) ---------------------------------------------------------------------------- </TABLE> The decline in fuel and purchased power costs for the nine months ended September 30, 1997, versus the comparable prior-year period was primarily due to decreased purchased power costs, resulting from relatively flat native load sales coupled with greater generation, as well as lower fuel prices. GAS OPERATIONS The decrease in gas revenues of $2 million for the nine months ended September 30, 1997 compared to the comparable year-ago period was primarily due to milder weather. Dekatherm sales to residential and commercial customers decreased 12 percent and 17 percent, respectively, in the nine month period ended September 30, 1997 over the same period in 1996, offset in part by increased dekatherm sales to industrial customers by 19 percent. In addition to traditional sales to its end customers, AmerenCIPS makes off-system sales of gas to others. Such off-system sales in 1997 continued to offset above mentioned declines, whereas such sales were minimal in 1996. The $4 million increase in gas costs for the nine months ended September 30, 1997 when compared to the same period in 1996 was primarily the result of increased dekatherms purchased for resale to wholesale customers. OTHER OPERATING EXPENSES Other operating expense variations reflect recurring conditions such as growth, inflation and wage increases. For the nine months ended September 30, 1997, other operating expenses increased $34 million versus the comparable prior year period primarily due to increased consultant expenses, computer related expenses, and injuries and damages expenses. Depreciation and amortization expense for the nine months ended September 30, 1997 increased $7 million compared to the comparable 1996 period primarily due to increases in depreciable property. Income taxes charged to operating expenses for the nine months ended September 30, 1997 decreased $11 million compared to the same period in 1996 primarily as the result of lower pretax income. OTHER INCOME AND DEDUCTIONS Miscellaneous, net for the nine months ended September 30, 1997 decreased $3 million compared to the nine month period ended September 30, 1996 due to an increase in merger-related expenses. INTEREST Interest charges for the nine months ended September 30, 1997 increased $5 million compared to the same period in 1996 primarily due to increased debt outstanding. 2

3 LIQUIDITY AND CAPITAL RESOURCES Cash provided by operating activities totaled $625 million for the nine months ended September 30, 1997, compared to $662 million during the same 1996 period. Cash flows used in investing activities totaled $293 million and $333 million for the nine months ended September 30, 1997 and 1996, respectively. Construction expenditures for the nine months ended September 30, 1997 of $287 million were for constructing new or improving existing facilities, purchasing railroad coal cars and complying with the Clean Air Act. In addition, the Company expended $13 million for the acquisition of nuclear fuel. Capital requirements for the remainder of 1997 are expected to be principally for construction expenditures and the acquisition of nuclear fuel. Cash flows used in financing activities were $285 million for the nine months ended September 30, 1997, compared to $297 million of cash flows used for financing activities during the same 1996 period. The Company's principal financing activities for the nine months ended September 30, 1997, were the redemption of $106 million of long-term debt and $64 million of preferred stock and the payment of dividends. The Company plans to utilize short-term debt as support for normal operations and other temporary requirements. AmerenUE and AmerenCIPS are authorized by the Federal Energy Regulatory Commission (FERC) to have up to $600 million and $150 million, respectively, 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 September 30, 1997, the Company had committed bank lines of credit aggregating $259 million (of which $252 million were unused at that 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. As of September 30, 1997, the Company had $43 million of short-term borrowings. As of September 30, 1997, AmerenCIPS has registration statements covering $75 million of first mortgage bonds and medium-term notes filed with the Securities and Exchange Commission (SEC). AmerenCIPS' mortgage indenture limits the amount of first mortgage bonds which may be issued. At September 30, 1997, AmerenCIPS could have issued about $677 million of additional first mortgage bonds under the indenture, assuming an annual interest rate of 7.5 percent. Additionally, AmerenCIPS' articles of incorporation limit amounts of preferred stock which may be issued. Assuming a preferred dividend rate of 7.38 percent, the utility could have issued all $185 million of authorized but unissued preferred stock as of September 30, 1997. AmerenUE has registration statements covering $160 million of long-term debt filed with the SEC. In addition, AmerenUE has registration statements filed with the SEC covering $100 million of preferred stock. AmerenUE also has bank credit agreements due 1999 which permit the borrowing of up to $300 million and $200 million on a long-term basis. At September 30, 1997, no such borrowings were outstanding. Additionally, AmerenUE has a lease agreement which provides for the financing of nuclear fuel. At September 30, 1997, the maximum amount which could be financed under the agreement was $120 million. Cash provided from financing for the nine months ended September 30, 1997, included issuances under the lease for nuclear fuel of $28 million offset in part by $21 million of redemptions. At September 30, 1997, $114 million was financed under the lease. RATE MATTERS See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Condensed Financial Statements for further information. CONTINGENCIES Subsequent to the completion of a contract restructuring with a major coal supplier by AmerenCIPS, a group of industrial customers filed with the Illinois Third District Appellate Court (the Court) in February 1997 an appeal of the December 1996 order of the ICC which approved, among other things, recovery of the restructuring payment and associated carrying costs (Restructuring Charges), incurred as a result of 3

4 the restructuring, through the retail fuel adjustment clause (FAC). 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, AmerenCIPS classified the $72 million of the Restructuring Charges made to the coal supplier in February 1997 as a regulatory asset and, through October 1997, recovered approximately $9.5 million of the Restructuring Charges through the retail FAC and from wholesale customers. On November 24, 1997, the Court reversed the ICC's order, finding that the Restructuring Charges were not direct costs of fuel that may be recovered through the retail FAC, but rather should be considered as a part of a review of AmerenCIPS' aggregate revenue requirements in a full rate case. Restructuring Charges allocated to wholesale customers (approximately 16 percent of the total) are not in question as a result of the opinion of the Court. On December 8, 1997, AmerenCIPS requested a rehearing by the Court. The Company is evaluating the impact of the Court decision on its financial statements. The Company cannot predict the ultimate outcome of this matter. If the Court's decision should ultimately prevail, AmerenCIPS will be required to cease recovery of the Restructuring Charges through the retail FAC, and could be required to refund any portion of those charges that had been collected through the retail FAC. The Company is also exploring other alternatives for recovery of the Restructuring Charges. The Company is currently evaluating the unamortized retail portion of the Restructuring Charges, which is currently classified as a regulatory asset, to determine if it continues to meet the criteria for the existence of an asset under Generally Accepted Accounting Principles (GAAP). If it is determined that such criteria are not met, the unamortized balance of the Restructuring Charges, approximately $36 million, net of tax, could be charged to earnings. The Company is also evaluating the revenues previously recovered in 1997 through the retail FAC to determine if a loss contingency, as defined under GAAP, is required. Such loss contingency ($5 million, net of tax) could also be charged to earnings. See Note 3 - Commitments and Contingencies under Notes to Supplemental Consolidated Condensed Financial Statements for further information. See Note 3 - Commitments and Contingencies under Notes to Supplemental Consolidated Condensed Financial Statements for other material issues existing at September 30, 1997. DIVIDENDS 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 increases at other utilities; return on investments with similar risk characteristics; and overall business considerations. It is currently anticipated that the Company will initially pay dividends on its common stock at AmerenUE's historical payment level, which was $2.54 per share on an annual basis prior to the consummation of the Merger. ELECTRIC INDUSTRY RESTRUCTURING Certain states are considering proposals that would promote competition in the retail electric market. In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Act) providing for utility restructuring in Illinois. This legislation introduces price-based competition into the supply of electric energy in Illinois and will provide a less regulated structure for Illinois electric utilities. The Act includes a 5 percent residential electric rate decrease for the Company's Illinois electric customers, effective August 1, 1998. The Company may be subject to additional 5 percent 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. The Company estimates that the initial 5 percent rate decrease will result in a decrease in annual electric revenues of about $13 million, based on estimated levels of sales and assuming normal weather conditions. Retail direct access, which allows customers to choose their electric generation supplier, 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. The Act also relieves the Company of the requirement in the ICC's Order issued in September 1997 (which approved the Merger), requiring AmerenUE and AmerenCIPS to file electric rate 4

5 cases or alternative regulatory plans in Illinois following consummation of the Merger to reflect the effects of net merger savings. Other provisions of the Act include (1) potential recovery of a portion of a utility's stranded costs through a transition charge collected from customers who choose another electric supplier, (2) the option for certain utilities, including the Company, to eliminate the retail FAC applicable to their rates and to roll into base rates a historical level of fuel expense and (3) a mechanism to securitize certain future revenues related to stranded costs. At this time, the Company is assessing the impact that the Act will have on its operations. The potential negative consequences resulting from the Act could be significant and include the impairment and writedown of certain assets, including generation-related plant and regulatory assets, related to the Company's Illinois jurisdictional assets. The provisions of the Act could also result in lower revenues, reduced profit margins and increased costs of capital. At this time, the Company is unable to determine the impact of the Act on the Company's future financial condition, results of operations or liquidity. (See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Condensed Financial Statements.) In Missouri, where 72 percent of the Company's retail electric revenues are derived, a task force appointed by the Missouri Public Service Commission (MoPSC) is investigating industry restructuring and competition and is scheduled to issue a report to the MoPSC in 1998. A joint legislative committee is also conducting hearings on these issues. Currently, retail wheeling has not been allowed in Missouri; however, the joint agreement approved by the MoPSC in February 1997 as part of its merger authorization includes a provision that required AmerenUE to file a proposal for a 100-megawatt experimental retail wheeling pilot program in Missouri. AmerenUE filed its proposal with the MoPSC in September 1997. This proposal is still subject to review and approval by the MoPSC. The Company is unable to predict the timing or ultimate outcome of the electric industry restructuring initiatives being considered in the state of Missouri. In the state of Missouri, the potential negative consequences of industry restructuring could be significant and include the impairment and writedown of certain assets, including generation-related plant and regulatory assets, lower revenues, reduced profit margins and increased costs of capital. At this time, the Company is unable to predict the impact of potential electric industry restructuring matters in the state of Missouri on the Company's future financial condition, results of operations or liquidity. (See Note 2 - Regulatory Matters under Notes to Supplemental Consolidated Condensed Financial Statements.) AIR QUALITY STANDARDS In July 1997, the United States Environmental Protection Agency (EPA) issued final regulations revising the National Ambient Air Quality Standards for ozone and particulate matter. Although specific emission control requirements are still being developed, it is believed that the revised standards will require significant additional reductions in nitrogen oxide and sulfur dioxide emissions from coal-fired boilers. In October 1997, the EPA announced that Missouri and Illinois are included in the area targeted for nitrogen oxide emissions reductions as part of their regional control program. Reduction requirements in nitrogen oxide emissions from the Company's coal-fired boilers could exceed 80 percent from 1990 levels by the year 2002. Reduction requirements in sulfur dioxide emissions may be up to 50 percent beyond that already required by Phase II acid rain control provisions of the 1990 Clean Air Act Amendments and are anticipated to be required by 2007. Because of the magnitude of these additional reductions, the Company could be required to incur significantly higher capital costs to meet future compliance obligations for its coal-fired boilers or purchase power from other sources, either of which could have significantly higher operating and maintenance expenditures associated with compliance. At this time the Company is unable to determine the impact of the revised air quality standards on the Company's future financial condition, results of operations or liquidity. The United States and other countries are discussing possibilities for an international treaty to address the issue of "global warming." The Company is unable to predict what agreements, if any, will be adopted. However, most of the proposals under discussion could result in significantly higher capital costs and operations and maintenance expenditures 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. 5

6 INFORMATION SYSTEMS The Year 2000 issue relates to computer systems and applications which currently use two-digit date fields to designate a year. As the century date change occurs, date-sensitive systems will recognize the year 2000 as 1900, or not at all. This inability to recognize or properly treat the year 2000 may cause systems to process critical financial and operational information incorrectly. The Company continues to assess the impact of the Year 2000 issue on its operations, including the development of final cost estimates for, and the extent of programming changes required to address this issue. At this time, the Company believes that the Year 2000 issue will not have a material adverse effect on its financial condition, results of operations or liquidity. OUTLOOK The Company's management and Board of Directors recognize that competition will continue to increase in the future, especially in the energy supply portion of our business. The introduction of competition into the markets, coupled with the impact of the revised air quality standards on the Company's operations, will result in numerous challenges and uncertainties for Ameren and the utility industry. At this time, the Company cannot predict the timing or impact of these matters on its future financial condition, results of operations or liquidity. SAFE HARBOR STATEMENT 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, legislation, events, conditions, financial performance and dividends. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Company is providing the following cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. Factors include, but are not limited to, the effects of: regulatory actions; changes in laws and other governmental actions; competition; business and economic conditions; weather conditions; fuel prices and availability; generation plant performance; monetary and fiscal policies; and legal and administrative proceedings. 6

7 AMEREN CORPORATION SUPPLEMENTAL CONSOLIDATED CONDENSED BALANCE SHEET SEPTEMBER 30, 1997 (UNAUDITED) (Thousands of Dollars, Except Shares) <TABLE> <S> <C> ASSETS Property and plant, at original cost: Electric $11,487,890 Gas 442,537 Other 35,960 ----------- 11,966,387 Less accumulated depreciation and amortization 5,228,270 ----------- 6,738,117 Construction work in progress: Nuclear fuel in process 108,882 Other 128,861 ----------- Total property and plant, net 6,975,860 ----------- Investments and other assets: Investments 116,008 Nuclear decommissioning trust fund 119,333 Other 61,307 ----------- Total investments and other assets 296,648 ----------- Current assets: Cash and cash equivalents 58,092 Accounts receivable - trade (less allowance for doubtful accounts of $5,202) 312,228 Unbilled revenue 84,142 Other accounts and notes receivable 62,098 Materials and supplies, at average cost - Fossil fuel 92,374 Other 137,608 Other 35,240 ----------- Total current assets 781,782 ----------- Regulatory assets: Deferred income taxes 695,782 Other 295,770 ----------- Total regulatory assets 991,552 ----------- Total Assets $ 9,045,842 =========== CAPITAL AND LIABILITIES Capitalization: Common stock, $.01 par value, authorized 400,000,000 shares - outstanding 137,215,462 shares $ 1,372 Other paid-in capital, principally premium on common stock 1,582,938 Retained earnings 1,523,429 ----------- Total common stockholders' equity 3,017,739 Preferred stock not subject to mandatory redemption 235,197 Long-term debt 2,492,741 ----------- Total capitalization 5,835,677 ----------- Minority interest in consolidated subsidiary 3,534 Current liabilities: Current maturity of long-term debt 43,193 Short-term debt 43,358 Accounts and wages payable 184,248 Accumulated deferred income taxes 35,160 Taxes accrued 249,822 Other 180,373 ----------- Total current liabilities 736,154 ----------- Accumulated deferred income taxes 1,635,289 Accumulated deferred investment tax credits 202,099 Regulatory liability 285,612 Other deferred credits and liabilities 347,477 =========== Total Capital and Liabilities $ 9,045,842 =========== </TABLE> See Notes to Supplemental Consolidated Condensed Financial Statements 7

8 AMEREN CORPORATION SUPPLEMENTAL CONSOLIDATED CONDENSED STATEMENTS OF INCOME NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996 (UNAUDITED) (Thousands of Dollars, Except Shares and Per Share Amounts) <TABLE> <CAPTION> 1997 1996 ------------- ------------- <S> <C> <C> OPERATING REVENUES: Electric $ 2,421,692 $ 2,406,283 Gas 167,899 169,557 Other 9,771 8,776 ------------- ------------- Total operating revenues 2,599,362 2,584,616 OPERATING EXPENSES: Operations Fuel and purchased power 638,297 660,732 Gas costs 106,909 102,682 Other 434,067 400,522 ------------- ------------- 1,179,273 1,163,936 Maintenance 219,795 216,150 Depreciation and amortization 263,608 256,252 Income taxes 227,735 238,934 Other taxes 211,905 211,471 ------------- ------------- Total operating expenses 2,102,316 2,086,743 OPERATING INCOME 497,046 497,873 OTHER INCOME AND DEDUCTIONS: Allowance for equity funds used during construction 3,395 5,156 Miscellaneous, net (15,141) (12,523) ------------- ------------- Total other income and deductions, net (11,746) (7,367) INCOME BEFORE INTEREST CHARGES AND PREFERRED DIVIDENDS 485,300 490,506 INTEREST CHARGES AND PREFERRED DIVIDENDS: Interest 141,262 136,060 Allowance for borrowed funds used during construction (5,443) (5,919) Preferred dividends of subsidiaries 9,395 12,730 ------------- ------------- Net interest charges and preferred dividends 145,214 142,871 NET INCOME $ 340,086 $ 347,635 ============= ============= EARNINGS PER SHARE OF COMMON STOCK (BASED ON AVERAGE SHARES OUTSTANDING) $ 2.48 $ 2.53 ============= ============= AVERAGE COMMON SHARES OUTSTANDING 137,215,462 137,215,462 ============= ============= </TABLE> See Notes to Supplemental Consolidated Condensed Financial Statements 8

9 AMEREN CORPORATION SUPPLEMENTAL CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996 (UNAUDITED) (Thousands of Dollars) <TABLE> <CAPTION> 1997 1996 --------- --------- <S> <C> <C> Cash Flows From Operating: Net income $ 340,086 $ 347,635 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 259,371 252,350 Amortization of nuclear fuel 28,737 32,198 Allowance for funds used during construction (8,838) (11,075) Deferred income taxes, net (4,479) 11,675 Deferred investment tax credits, net (7,128) (7,150) Coal contract restructuring charge (71,795) Changes in assets and liabilities: Receivables, net (22,722) (18,210) Materials and supplies 14,124 (22,862) Accounts and wages payable (112,839) (110,215) Taxes accrued 184,585 150,258 Other, net 25,865 37,763 --------- --------- Net cash provided by operating activities 624,967 662,367 Cash Flows From Investing: Construction expenditures (286,952) (312,528) Allowance for funds used during construction 8,838 11,075 Nuclear fuel expenditures (12,594) (26,001) Long-term investments (2,698) (5,282) --------- --------- Net cash used in investing activities (293,406) (332,736) Cash Flows From Financing: Dividends on common stock (248,376) (244,291) Redemptions - Nuclear fuel lease (21,011) (25,659) Short-term debt (25,710) (29,600) Long-term debt (106,000) (35,000) Preferred stock (63,924) (26) Issuances - Nuclear fuel lease 27,653 31,581 Short-term debt 6,070 Long-term debt 152,000 --------- --------- Net cash used in financing activities (285,368) (296,925) Net change in cash and cash equivalents 46,193 32,706 Cash and cash equivalents at beginning of period 11,899 2,378 ========= ========= Cash and cash equivalents at end of period $ 58,092 $ 35,084 ========= ========= Cash paid during the periods: --------- --------- Interest (net of amount capitalized) $ 108,910 $ 115,340 Income taxes $ 120,829 $ 146,942 --------- --------- </TABLE> See Notes to Supplemental Consolidated Condensed Financial Statements 9

10 AMEREN CORPORATION NOTES TO SUPPLEMENTAL CONSOLIDATED CONDENSED FINANCIAL STATEMENTS SEPTEMBER 30, 1997 NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES MERGER AND SUPPLEMENTAL FINANCIAL STATEMENTS (BASIS OF PRESENTATION) Effective December 31, 1997, following the receipt of all required state and federal regulatory approvals, Union Electric Company (AmerenUE) and CIPSCO Incorporated (CIPSCO) combined to form Ameren Corporation (Ameren)(the Merger). The accompanying supplemental consolidated condensed 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 financial statements reflect the conversion of each outstanding share of AmerenUE common stock into one share of Ameren common stock, and each outstanding share of CIPSCO common stock into 1.03 shares of Ameren common stock in accordance with the terms of the merger agreement. The outstanding preferred stock of AmerenUE and Central Illinois Public Service Company (AmerenCIPS), a subsidiary of CIPSCO, 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 in the states of Missouri and Illinois. The Company also has a non-regulated investing subsidiary, CIPSCO Investment Company (CIC). The Company has a 60% interest in Electric Energy, Inc. (EEI). EEI owns and operates an electric generating 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. Financial statement note disclosures, normally included in financial statements prepared in conformity with generally accepted accounting principles, have been omitted in these financial statements. However, in the opinion of the Company, the disclosures contained in the financial statements are adequate to make the information presented not misleading. See Notes to Supplemental Consolidated Financial Statements as of December 31, 1996, included in this Form 8-K for information relevant to the accompanying financial statements, including information as to the significant accounting policies of the Company. In the opinion of the Company, the financial statements filed as a part of this Form 8-K reflect all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of the results for the periods presented. Due to the effect of weather on sales and other factors which are characteristic of public utility operations, financial results for the periods ended September 30, 1997 and 1996 are not necessarily indicative of trends for any nine-month period. Operating revenues and net income for the nine months ended September 30, 1997 and September 30, 1996, were as follows (in millions): <TABLE> <CAPTION> AmerenUE CIPSCO OTHER AMEREN -------- ------ ------ ------ <S> <C> <C> <C> <C> Nine months ended September 30, 1997: Operating revenues $1,812 $ 649 $ 138 $2,599 Net income 278 62 340 Nine months ended September 30, 1996: Operating revenues $1,785 $ 669 $ 131 $2,585 Net income 279 69 348 </TABLE> 10

11 REGULATION Ameren will be a registered holding company and therefore subject to regulation by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (PUHCA). AmerenUE and AmerenCIPS are also regulated by the Missouri Public Service Commission (MoPSC), Illinois Commerce Commission (ICC), and the Federal Energy Regulatory Commission (FERC). The accounting policies of the Company are in accordance with the ratemaking practices of the regulatory authorities having jurisdiction and, as such, conform to Generally Accepted Accounting Principles (GAAP), as applied to regulated public utilities. NOTE 2 - REGULATORY MATTERS In July 1995, the MoPSC approved an agreement involving the Company's Missouri electric rates. The agreement decreased rates 1.8% for all classes of Missouri retail electric customers, effective August 1, 1995, reducing annual revenues by about $30 million and reducing annual earnings by approximately 13 cents per share. In addition, a one-time $30 million credit to retail Missouri electric customers reduced 1995 earnings approximately 13 cents per share. Also included is a three-year experimental alternative regulation plan that provides that earnings in any future years in excess of a 12.61% regulatory return on equity (ROE) will be shared equally between customers and stockholders, and earnings above a 14% ROE will be credited to customers. The formula for computing the credit uses twelve-month results ending June 30, rather than calendar year earnings. The agreement also provides that no party shall file for a general increase or decrease in the Company's Missouri retail electric rates prior to July 1, 1998, except that the Company may file for an increase if certain adverse events occur. During the nine months ended September 30, 1997, the Company recorded an estimated $20 million credit for the second year of the plan compared to the $47 million credit recorded for the first year of the plan in 1996. This credit, which the Company expects to pay to customers in 1998, was reflected as a reduction in revenues. Included in the joint agreement approved by the MoPSC in its February 1997 order authorizing the Merger, is a new three-year experimental alternative regulation plan that will run from July 1, 1998, through June 30, 2001. Like the current plan, the new plan provides that earnings over a 12.61% ROE up to a 14% ROE will be shared equally between customers and shareholders. The new three-year plan will also return to customers 90% of all earnings above a 14% ROE up to a 16% ROE. Earnings above a 16% ROE would be credited entirely to customers. Other agreement provisions include: recovery over a 10-year period of the Missouri portion of merger-related expenses; a Missouri electric rate decrease, effective September 1, 1998, based on the weather-adjusted average annual credits to customers under the current experimental alternative regulation plan; and an experimental retail wheeling pilot program for 100 megawatts of electric power. Also, as part of the agreement, the Company will not seek to recover in Missouri the merger premium. The exclusion of the merger premium from rates did not result in a charge to earnings. In September 1997, the ICC approved the Merger subject to certain conditions. The conditions included the requirement for AmerenUE and AmerenCIPS to file electric and gas rate cases or alternative regulatory plans within six months after the Merger is final to determine how net merger savings would be shared between the ratepayers and stockholders. In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Act) providing for utility restructuring in Illinois. This legislation introduces price-based competition into the supply of electric energy in Illinois and will provide a less regulated structure for Illinois electric utilities. The Act includes a 5 percent residential electric rate decrease for the Company's Illinois electric customers, effective August 1, 1998. The Company may be subject to additional 5 percent 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. The Company estimates that the initial 5 percent rate decrease will result in a decrease in 11

12 annual electric revenues of about $13 million, based on estimated levels of sales and assuming normal weather conditions. Retail direct access, which allows customers to choose their electric generation supplier, 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. The Act also relieves the Company of the requirement in the ICC's Order issued in September 1997 (which approved the Merger), requiring AmerenUE and AmerenCIPS to file electric rate cases or alternative regulatory plans in Illinois following consummation of the Merger to reflect the effects of net merger savings. Other provisions of the Act include (1) potential recovery of a portion of a utility's stranded costs through a transition charge collected from customers who choose another electric supplier, (2) the option for certain utilities, including the Company, to eliminate the retail FAC applicable to their rates and to roll into base rates a historical level of fuel expense and (3) a mechanism to securitize certain future revenues related to stranded costs. 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 No. 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) which 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 applicable portion of the business. At its July 24, 1997 meeting, the Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) 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), and can therefore continue to be carried on the regulated entity's balance sheet to the extent such assets are recovered. In addition, SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" establishes accounting standards for the impairment of long-lived assets (i.e., determining whether the costs of such assets are recoverable in future revenues.) SFAS 121 also requires that regulatory assets, which are no longer probable of recovery through future revenue, be charged to earnings. Due to the enactment of the Act, prices for the supply of electric generation are expected to transition from cost-based, regulated rates to rates determined by competitive market forces in the state of Illinois. As a result, the Company will discontinue application of SFAS 71 for the Illinois 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. At this time, the Company is assessing the impact that the Act will have on its operations. The potential negative consequences resulting from the Act could be significant and include the impairment and writedown of certain assets, including generation-related plant and regulatory assets, related to the Company's Illinois jurisdictional assets. At September 30, 1997, the Company's net investment in generation facilities related to its Illinois jurisdiction approximated $826 million and was included in electric plant-in service on the Company's balance sheet. In addition, at September 30, 1997, the Company's Illinois generation-related net regulatory assets approximated $166 million. The provisions of the Act could also result in lower revenues, reduced profit margins and increased costs of capital. At this time, the Company is unable to determine the impact of the Act on the Company's future financial condition, results of operations or liquidity. In the state of Missouri, where approximately 72 percent of the Company's retail electric revenues are derived, a task force appointed by the MoPSC is conducting studies of electric industry restructuring and competition and will issue a report to the MoPSC in April 1998. A joint legislative committee is also 12

13 conducting studies and will report its findings and recommendations to the Missouri General Assembly after reviewing the results of the MoPSC task force. The Company is unable to predict the timing or ultimate outcome of the electric industry restructuring initiatives being considered in the state of Missouri. In the state of Missouri, the potential negative consequences of industry restructuring could be significant and include the impairment and writedown of certain assets, including generation-related plant and regulatory assets, lower revenues, reduced profit margins and increased costs of capital. At September 30, 1997, the Company's net investment in generation facilities related to its Missouri jurisdiction approximated $2.7 billion and was included in electric plant-in service on the Company's balance sheet. In addition, at September 30, 1997, the Company's Missouri generation-related regulatory assets approximated $435 million. At this time, the Company is unable to predict the impact of potential electric industry restructuring matters in the state of Missouri on the Company's future financial condition, results of operations or liquidity. In April 1996, the FERC issued Order 888 and Order 889 related to the industry's wholesale electric business. The Company filed an open access tariff under Order 888 as part of the merger case and in July 1997, the case was settled. In March 1997, the FERC issued Order 888A which required the Company to refile a tariff by July 14, 1997. The terms were not significantly different from those filed in the original tariff under Order 888. 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. The Company had recorded the following regulatory assets and regulatory liability as of September 30, 1997 and December 31, 1996: <TABLE> <CAPTION> ------------------------------------------------------------------------------- (in millions) September 30, 1997 December 31, 1996 ------------------------------------------------------------------------------- <S> <C> <C> REGULATORY ASSETS: Income taxes $696 $734 Callaway costs 108 111 Coal contract restructuring charge 66 -- Undepreciated plant costs 37 41 Unamortized loss on reacquired debt 40 42 Contract termination costs 14 20 DOE decommissioning assessment 17 18 Other 14 12 ------------------------------------------------------------------------------- Regulatory Assets $992 $978 ------------------------------------------------------------------------------- REGULATORY LIABILITY: Income taxes $286 $304 ------------------------------------------------------------------------------- Regulatory Liability $286 $304 ------------------------------------------------------------------------------- </TABLE> 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 - COMMITMENTS AND CONTINGENCIES During 1996, AmerenCIPS restructured its contract with one of its major coal suppliers. In 1997, AmerenCIPS paid a $70 million restructuring payment to the supplier, which allows them to purchase at market prices low-sulfur, out-of-state coal through the supplier (in substitution for the high-sulfur Illinois coal AmerenCIPS was obligated to purchase under the original contract); and would receive options for future purchases of low-sulfur, out-of-state coal from the supplier through 1999 at set negotiated prices. By switching to low-sulfur coal, AmerenCIPS was able to discontinue operating the Newton Power Plant Unit 1 scrubber. The benefits of the 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 over the next 10 years. In December 1996, the ICC entered an order approving the switch to out-of-state 13

14 coal, recovery of the restructuring payment plus associated carrying costs (Restructuring Charges) through the retail FAC over six years, and continued recovery in rates of the undepreciated scrubber investment plus costs of removal. A group of industrial customers filed with the Illinois Third District Appellate Court (the Court) in February 1997 an appeal of the December 1996 order of the ICC which approved, among other things, recovery of the Restructuring Charges through the retail FAC. 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, AmerenCIPS classified the $72 million of the Restructuring Charges made to the coal supplier in February 1997 as a regulatory asset and, through October 1997, recovered approximately $9.5 million of the Restructuring Charges through the retail FAC and from wholesale customers. On November 24, 1997, the Court reversed the ICC's order, finding that the Restructuring Charges were not direct costs of fuel that may be recovered through the retail FAC, but rather should be considered as a part of a review of AmerenCIPS' aggregate revenue requirements in a full rate case. Restructuring Charges allocated to wholesale customers (approximately 16 percent of the total) are not in question as a result of the opinion of the Court. On December 8, 1997, AmerenCIPS requested a rehearing by the Court. The Company is evaluating the impact of the Court decision on its financial statements. The Company cannot predict the ultimate outcome of this matter. If the Court's decision should ultimately prevail, AmerenCIPS will be required to cease recovery of the Restructuring Charges through the retail FAC, and could be required to refund any portion of those charges that had been collected through the retail FAC. The Company is also exploring other alternatives for recovery of the Restructuring Charges. The Company is currently evaluating the unamortized retail portion of the Restructuring Charges, which is currently classified as a regulatory asset, to determine if it continues to meet the criteria for the existence of an asset under GAAP. If it is determined that such criteria are not met, the unamortized balance of the Restructuring Charges, approximately $36 million, net of tax, could be charged to earnings. The Company is also evaluating the revenues previously recovered in 1997 through the retail FAC to determine if a loss contingency, as defined under GAAP, is required. Such loss contingency ($5 million, net of tax) could also be charged to earnings. Under the Clean Air Act Amendments of 1990, the Company is required to reduce total annual sulfur dioxide emissions significantly by the year 2000. Significant reductions in nitrogen oxide are also required. By switching to low-sulfur coal and early banking of emission credits, the Company anticipates that it can comply with the requirements of the law without significant revenue increases because the related capital costs are largely offset by lower fuel costs. As of year-end 1996, estimated remaining capital costs expected to be incurred pertaining to Clean Air Act-related projects totaled $76 million. In July 1997, the United States Environmental Protection Agency (EPA) issued final regulations revising the National Ambient Air Quality Standards for ozone and particulate matter. Although specific emission control requirements are still being developed, it is believed that the revised standards will require significant additional reductions in nitrogen oxide and sulfur dioxide emissions from coal-fired boilers. In October 1997, the EPA announced that Missouri and Illinois are included in the area targeted for nitrogen oxide emissions reductions as part of their regional control program. Reduction requirements in nitrogen oxide emissions from the Company's coal-fired boilers could exceed 80 percent from 1990 levels by the year 2002. Reduction requirements in sulfur dioxide emissions may be up to 50 percent beyond that already required by Phase II acid rain control provisions of the 1990 Clean Air Act Amendments and are anticipated to be required by 2007. Because of the magnitude of these additional reductions, the Company could be required to incur significantly higher capital costs to meet future compliance obligations for its coal-fired boilers or purchase power from other sources, either of which could have significantly higher operating and maintenance expenditures associated with compliance. At this time the Company is unable to determine the impact of the revised air quality standards on the Company's future financial condition, results of operations or liquidity. The United States and other countries are discussing possibilities for an international treaty to address the issue of "global warming." The Company is unable to predict what agreements, if any, will be adopted. However, most of the proposals under discussion could result in significantly higher capital costs and 14

15 operations and maintenance expenditures 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 September 30, 1997, AmerenUE was designated a potentially responsible party (PRP) by federal and state environmental protection agencies at four hazardous waste sites. Other hazardous waste sites have been identified for which AmerenUE may be responsible but has not been designated a PRP. AmerenCIPS has identified 13 sites where it and certain of its predecessors and other affiliates previously operated facilities that manufactured gas from coal. This manufacturing produced various potentially harmful by-products which may remain on some sites. One site was added to the EPA Superfund list in 1990. Costs relating to studies and remediation at the 13 AmerenCIPS' sites and associated legal and litigation expenses are being accrued and deferred rather than expensed currently, pending recovery through rates or from insurers. Through December 31, 1996, the total of the costs deferred, net of recoveries from insurers and through environmental adjustment clause rate riders approved by the ICC, was $11 million. The ICC has instituted a reconciliation proceeding to review AmerenCIPS' environmental remediation activities in 1993, 1994 and 1995 and to determine whether the revenues collected under the riders in 1993 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. In mid-1997, AmerenCIPS and the ICC Staff submitted a stipulation with regard to all matters at issue. Under the stipulation, as of December 31, 1995, the aggregate amount of (i) revenues received under the riders, insurance proceeds (and related interest) exceeded (ii) rider-related costs (and related carrying costs) by approximately $4 million. If this stipulation is approved by the ICC, this amount would be applied to cover a portion of future remediation costs. Also, if the stipulation is approved, insurance proceeds of approximately $3 million would be applied to cover non-rider related costs incurred. During 1997, the accumulated balance of recoverable environmental remediation costs exceeded the balance of available insurance proceeds and rider revenues; therefore, AmerenCIPS began to again collect revenue under the riders beginning November 1, 1997. 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 lockout by AmerenCIPS of both unions during 1993. The NLRB has issued complaints against AmerenCIPS concerning its lockout. Both unions seek, among other things, back pay and other benefits for the period of the lockout. The Company estimates the amount of back pay and other benefits for both unions to be less than $17 million. An administrative law judge of the NLRB has ruled that the lockout was unlawful. On July 23, 1996, the Company appealed to the NLRB. The Company believes the lockout was both lawful and reasonable and that the final resolution of the disputes will not have a material adverse effect on financial position, results of operations or liquidity of the Company. 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 discussion. The Company is involved in other 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. 15