10-Q 1 amc10-qcomb063004.txt 2Q 2004 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-Q (X) Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended June 30, 2004 OR ( ) Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from __________ to __________.

~~UNITED STATES~~Exact ~~SECURITIES~~Name ~~AND~~of ~~EXCHANGE~~Registrant ~~COMMISSION~~as specified in its charter; Commission State of Incorporation; IRS Employer File Number Address and Telephone Number Identification No. ---------- ---------------------------- ------------------ 1-14756 Ameren Corporation 43-1723446 (Missouri Corporation) 1901 Chouteau Avenue St. Louis, Missouri 63103 (314) 621-3222 1-2967 Union Electric Company 43-0559760 (Missouri Corporation) 1901 Chouteau Avenue St. Louis, Missouri 63103 (314) 621-3222 1-3672 Central Illinois Public Service Company 37-0211380 (Illinois Corporation) 607 East Adams Street Springfield, Illinois 62739 (217) 523-3600 333-56594 Ameren Energy Generating Company 37-1395586 (Illinois Corporation) 1901 Chouteau Avenue St. Louis, Missouri 63103 (314) 621-3222 2-95569 CILCORP Inc. 37-1169387 (Illinois Corporation) 300 Liberty Street Peoria, Illinois 61602 (309) 677-5230 1-2732 Central Illinois Light Company 37-0211050 (Illinois Corporation) 300 Liberty Street Peoria, Illinois 61602 (309) 677-5230

Indicate by check mark whether the Registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes (X) No ( ) Indicate by check mark whether each Registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Ameren Corporation Yes (X) No ( ) Union Electric Company Yes ( ) No (X) Central Illinois Public Service Company Yes ( ) No (X) Ameren Energy Generating Company Yes ( ) No (X) CILCORP Inc. Yes ( ) No (X) Central Illinois Light Company Yes ( ) No (X) The number of shares outstanding of each Registrant's classes of common stock as of July 30, 2004, was as follows:

~~Washington~~Ameren Corporation Common stock, ~~DC 20549~~ $.01 par value - 194,274,842 Union Electric Company Common stock, $5 par value, held by Ameren Corporation (parent company of the Registrant) - 102,123,834 Central Illinois Public Service Company Common stock, no par value, held by Ameren Corporation (parent company of the Registrant) - 25,452,373 Ameren Energy Generating Company Common stock, no par value, held by Ameren Energy Development Company (parent company of the Registrant and indirect subsidiary of Ameren Corporation) - 2,000 CILCORP Inc. Common stock, no par value, held by Ameren Corporation (parent company of the Registrant) - 1,000 Central Illinois Light Company Common stock, no par value, held by CILCORP Inc. (parent company of the Registrant and subsidiary of Ameren Corporation) - 13,563,871

This combined Form 10-Q is separately filed by Ameren Corporation, Union Electric Company, Central Illinois Public Service Company, Ameren Energy Generating Company, CILCORP Inc. and Central Illinois Light Company. Each Registrant hereto is filing on its own behalf all of the information contained in this quarterly report that relates to such Registrant. Each Registrant hereto is not filing any information that does not relate to such Registrant, and therefore makes no representation as to any such information. Prior to the quarterly report on Form 10-Q for the period ended September 30, 2003, separate filings were made by each Registrant, except CILCORP Inc. and Central Illinois Light Company, which made a combined filing. Ameren Corporation and its subsidiaries changed to a combined filing in order to improve disclosure and to simplify administrative processes. OMISSION OF CERTAIN INFORMATION Ameren Energy Generating Company and CILCORP Inc. meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format allowed under that General Instruction.

~~FORM~~TABLE OF CONTENTS Page Glossary of Terms and Abbreviations................................................................................. 5 Forward-looking Statements.......................................................................................... 8 PART I. Financial Information ITEM 1. Financial Statements (Unaudited) Ameren Corporation Consolidated Statement of Income................................................................... 9 Consolidated Balance Sheet......................................................................... 10 Consolidated Statement of Cash Flows............................................................... 11 Union Electric Company Consolidated Statement of Income................................................................... 12 Consolidated Balance Sheet......................................................................... 13 Consolidated Statement of Cash Flows............................................................... 14 Central Illinois Public Service Company Statement of Income................................................................................ 15 Balance Sheet...................................................................................... 16 Statement of Cash Flows............................................................................ 17 Ameren Energy Generating Company Statement of Income................................................................................ 18 Balance Sheet...................................................................................... 19 Statement of Cash Flows............................................................................ 20 CILCORP Inc. Consolidated Statement of Income................................................................... 21 Consolidated Balance Sheet......................................................................... 22 Consolidated Statement of Cash Flows............................................................... 23 Central Illinois Light Company Consolidated Statement of Income................................................................... 24 Consolidated Balance Sheet......................................................................... 25 Consolidated Statement of Cash Flows............................................................... 26 3 Combined Notes to Financial Statements............................................................. 27 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.............. 53 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk......................................... 77 ITEM 4. Controls and Procedures............................................................................ 81 PART II. Other Information ITEM 1. Legal Proceedings.................................................................................. 81 ITEM 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities................... 82 ITEM 4. Submission of Matters to a Vote of Security Holders................................................ 82 ITEM 5. Other Information.................................................................................. 84 ITEM 6. Exhibits and Reports on Form 8-QK................................................................... 84 SIGNATURES.......................................................................................................... 86

This Form 10-Q contains "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q under the heading Forward-looking Statements. Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts," "projects" and similar expressions. 4 GLOSSARY OF TERMS AND ABBREVIATIONS When we refer to our, we or us, it indicates that the referred information relates to all Ameren Companies. When we refer to financing or acquisition activities, we are defining Ameren as the parent holding company. When appropriate, subsidiaries of Ameren are specifically referenced in order to distinguish among their different business activities. AERG - AmerenEnergy Resources Generating Company, a subsidiary of CILCO, which operates a non rate-regulated electric generation business in Illinois and which was formerly known as Central Illinois Generation, Inc. AES - The AES Corporation. AFS - Ameren Energy Fuels and Services Company, a subsidiary of Resources Company, which procures fuel and gas and manages the related risks for the Ameren Companies. Ameren - Ameren Corporation and its subsidiaries on a consolidated basis. When referring to financing or acquisition activities, Ameren is defined as Ameren Corporation, the parent. Ameren Companies - The individual Registrants within the Ameren consolidated group. Ameren Energy - Ameren Energy, Inc., a subsidiary of Ameren Corporation, which serves as a power marketing and risk management agent for UE and Genco for transactions of primarily less than one year. Ameren Services - Ameren Services Company, a subsidiary of Ameren Corporation, which provides a variety of support services to Ameren and its subsidiaries. Capacity factor - A measure that indicates the percent of an electric power generating unit's(s') capacity that was used during a period. CILCO - Central Illinois Light Company, a subsidiary of CILCORP, which operates a rate-regulated transmission and distribution business, a primarily non rate-regulated electric generation business, and a rate-regulated natural gas distribution business in Illinois as AmerenCILCO. CILCO owns all of the common stock of AERG. CILCORP - CILCORP Inc., a subsidiary of Ameren Corporation, which operates as a holding company for CILCO. CIPS - Central Illinois Public Service Company, a subsidiary of Ameren Corporation, which operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS. Cooling degree days - The summation of positive differences between the mean daily temperature and the 65 degrees Fahrenheit base. This statistic is useful as an indicator of demand for electricity for summer space cooling for residential and commercial customers. CT - Combustion turbine generation equipment. Development Company - Ameren Energy Development Company, a subsidiary of Resources Company and parent of Genco, which develops and constructs generating facilities for Genco. DOE - Department of Energy, a governmental agency of the United States of America. DOJ - Department of Justice, a governmental agency of the United States of America. DRPlus - Ameren Corporation's dividend reinvestment and stock purchase plan. Dynegy - Dynegy Inc., the indirect parent company of Illinois Power. 5 EEI - Electric Energy, Inc., a 60%-owned subsidiary of Ameren Corporation, which is 40% owned by UE and 20% owned by Resources Company, and which operates electric generation and transmission facilities in Illinois. EPA - Environmental Protection Agency, a governmental agency of the United States of America. Equivalent availability factor - A measure that indicates the percent of time an electric power generating unit(s) was available for service during a period. ERISA - Employee Retirement Income Security Act of 1974, as amended. Exchange Act - Securities Exchange Act of 1934, as amended. FASB - Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States of America. FCC - Federal Communications Commission, a governmental agency of the United States of America. FERC - Federal Energy Regulatory Commission, a governmental agency of the United States of America that, among other things, regulates interstate transmission and wholesale sales of electricity and natural gas and related matters and hydroelectric facilities. FIN - FASB Interpretation intended to clarify accounting pronouncements previously issued by the FASB. Fitch - Fitch Ratings, a credit rating agency. FTC - Federal Trade Commission, a governmental agency of the United States of America. GAAP - Generally accepted accounting principles in the United States of America. Genco - Ameren Energy Generating Company, a subsidiary of Development Company, which operates a non rate-regulated electric generation business in Illinois and Missouri. GridAmerica Companies - UE, CIPS, American Transmission Systems, Inc., a subsidiary of FirstEnergy Corp., and Northern Indiana Public Service Company, a subsidiary of NiSource, Incorporated. Hart-Scott-Rodino Act - Hart-Scott-Rodino Antitrust Improvements Act of 1976, which establishes procedures for companies involved in transactions that meet certain criteria to file a premerger notification with the FTC and the DOJ Antitrust Division and establishes prescribed time periods for government review prior to completing their transaction. Heating degree days - The summation of negative differences between the mean daily temperature and the 65 degrees Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter space heating for residential and commercial customers. IBEW - International Brotherhood of Electrical Workers. ICC - Illinois Commerce Commission, a state agency that regulates the Illinois utility businesses and operations of UE, CIPS, CILCO and Illinois Power. Illinois Customer Choice Law - Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which provides for electric utility restructuring and introduces competition into the retail supply of electric energy in Illinois. Illinois Power - Illinois Power Company, a wholly owned subsidiary of Illinova Corporation, which is a subsidiary of Dynegy. IUOE - International Union of Operating Engineers. 6 MAIN - Mid-America Interconnected Network, Inc., one of the regional electric reliability councils organized for coordinating the planning and operation of the nation's bulk power supply. Marketing Company - Ameren Energy Marketing Company, a subsidiary of Resources Company, which markets power for periods primarily over one year. Medina Valley - AmerenEnergy Medina Valley Cogen (No. 4), LLC and its subsidiaries, which are subsidiaries of Resources Company, which indirectly own a 40 megawatt, gas-fired electric generation plant. Midwest ISO - Midwest Independent Transmission System Operator Inc. Missouri Environmental Authority - State Environmental Improvement and Energy Resources Authority of the State of Missouri, a governmental instrumentality that is authorized to finance environmental projects through the issuance of tax exempt bonds and notes. Money pool - Borrowing arrangements with and among the Ameren Companies to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained between rate-regulated and non rate-regulated businesses referred to as the utility money pool and the non-state regulated subsidiary money pool, respectively. Moody's - Moody's Investors Service, Inc., a credit rating agency. MoPSC - Missouri Public Service Commission, a state agency that regulates the Missouri utility business and operations of UE. NRC - Nuclear Regulatory Commission, a governmental agency of the United States of America. NOx - Nitrogen oxide. NYMEX - New York Mercantile Exchange. OATT - Open Access Transmission Tariff. OCI - Other Comprehensive Income (Loss) as defined by GAAP. PJM - PJM Interconnection LLC. PUHCA - Public Utility Holding Company Act of 1935, as amended. Resources Company - Ameren Energy Resources Company, a subsidiary of Ameren Corporation, which consists of non rate-regulated operations, including Development Company, Genco, Marketing Company, AFS and Medina Valley. RRO - Regional Reliability Organization. RTO - Regional Transmission Organization. S&P - Standard and Poor's Inc., a credit rating agency. SEC - Securities and Exchange Commission, a governmental agency of the United States of America. SFAS - Statement of Financial Accounting Standards, the accounting and financial reporting rules issued by the FASB. SO2 - Sulfur dioxide. UE - Union Electric Company, a subsidiary of Ameren Corporation, which operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas distribution business in Missouri and Illinois as AmerenUE. 7 FORWARD-LOOKING STATEMENTS Statements made in this report, which are not based on historical facts, are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in past and subsequent filings with the SEC, could cause actual results to differ materially from management expectations as suggested by such "forward-looking" statements: o the closing and timing of Ameren's acquisition of Illinois Power and the impact of any conditions imposed by regulators in connection with their approval thereof; o the effects of the stipulation and agreement relating to the UE Missouri electric excess earnings complaint case and other regulatory actions, including changes in regulatory policies; o changes in laws and other governmental actions, including monetary and fiscal policies; o the impact on the company of current regulations related to the opportunity for customers to choose alternative energy suppliers in Illinois; o the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at both the state and federal levels; o the effects of participation in a FERC-approved RTO, including activities associated with the Midwest ISO; o the availability of fuel for the production of electricity, such as coal and natural gas, and purchased power and natural gas for distribution, and the level and volatility of future market prices for such commodities, including the ability to recover any increased costs; o the use of financial and derivative instruments; o average rates for electricity in the Midwest; o business and economic conditions; o the impact of the adoption of new accounting standards and the application of appropriate technical accounting rules and guidance; o interest rates and the availability of capital; o actions of ratings agencies and the effects of such actions; o weather conditions; o generation plant construction, installation and performance; o operation of nuclear power facilities, including planned and unplanned outages, and decommissioning costs; o the effects of strategic initiatives, including acquisitions and divestitures; o the impact of current environmental regulations on utilities and generating companies and the expectation that more stringent requirements will be introduced over time, which could potentially have a negative financial effect; o future wages and employee benefits costs, including changes in returns on benefit plan assets; o disruptions of the capital markets or other events making the Ameren Companies' access to necessary capital more difficult or costly; o competition from other generating facilities, including new facilities that may be developed; o difficulties in integrating CILCO and Illinois Power, if consummated, with Ameren's other businesses; o changes in the energy markets, environmental laws or regulations, interest rates or other factors adversely impacting assumptions in connection with the CILCORP and Illinois Power, if consummated, acquisitions; o cost and availability of transmission capacity for the energy generated by the Ameren Companies' generating facilities or required to satisfy energy sales made by the Ameren Companies; and legal and administrative proceedings. Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 8

~~ý QUARTERLY~~PART ~~REPORT~~I. ~~PURSUANT~~FINANCIAL TOINFORMATION ~~SECTION~~ITEM 131. ORFINANCIAL 15STATEMENTS. AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (dUnaudited) OF ~~THE~~(In ~~SECURITIES~~millions, ~~EXCHANGE~~except ~~ACT~~per OFshare ~~1934~~amounts) Three Months Ended Six Months Ended June 30, June 30, ---------------------- ---------------------- 2004 2003 2004 2003 ---------- ---------- ----------- ---------- Operating Revenues: Electric $ 1,032 $ 968 $ 1,945 $ 1,824 Gas 119 118 420 368 Other 1 2 3 4 ---------- ---------- ---------- ---------- Total operating revenues 1,152 1,088 2,368 2,196 ---------- ---------- ---------- ---------- Operating Expenses: Fuel and purchased power 282 239 553 471 Gas purchased for resale 75 83 288 264 Other operations and maintenance 343 307 649 599 Depreciation and amortization 132 132 262 256 Taxes other than income taxes 74 77 154 155 ---------- ---------- ---------- ---------- Total operating expenses 906 838 1,906 1,745 ---------- ---------- ---------- ---------- Operating Income 246 250 462 451 Other Income and (Deductions): Miscellaneous income 4 5 12 11 Miscellaneous expense (4) (7) (5) (10) ---------- ---------- ---------- ---------- Total other income and (deductions) - (2) 7 1 ---------- ---------- ---------- ---------- Interest Charges and Preferred Dividends: Interest 66 69 130 135 Preferred dividends of subsidiaries 2 2 5 5 ---------- ---------- ---------- ---------- Net interest charges and preferred dividends 68 71 135 140 ---------- ---------- ---------- ---------- Income Before Income Taxes and Cumulative Effect of Change in Accounting Principle 178 177 334 312 Income Taxes 60 67 119 119 ---------- ---------- ---------- ---------- Income Before Cumulative Effect of Change in Accounting Principle 118 110 215 193 Cumulative Effect of Change in Accounting Principle, Net of Income Taxes of $-, $-, $- and $12 - - - 18 ---------- ---------- ---------- ---------- Net Income $ 118 $ 110 $ 215 $ 211 ========== ========== ========== ========== Earnings per Common Share - Basic and Diluted: Income before cumulative effect of change in accounting principle $ 0.65 $ 0.68 $ 1.20 $ 1.21 Cumulative effect of change in accounting principle, net of income taxes - - - 0.11 ---------- ---------- ---------- ---------- Earnings per Common Share - Basic and Diluted $ 0.65 $ 0.68 $ 1.20 $ 1.32 ========== ========== ========== ========== Dividends per Common Share $ 0.635 $ 0.635 $ 1.27 $ 1.27 Average Common Shares Outstanding 182.7 161.2 178.5 160.1 The accompanying notes are an integral part of these consolidated financial statements.

~~For~~AMEREN ~~the Quarterly~~CORPORATION ~~period~~CONSOLIDATED ~~ended~~BALANCE ~~September~~SHEET (Unaudited) (In millions, except per share amounts) June 30, ~~2002~~December 31, 2004 2003 ----------- ------------ ASSETS Current Assets: Cash and cash equivalents $ 511 $ 111 Accounts receivables - trade (less allowance for doubtful accounts of $12 and $13, respectively) 343 326 Unbilled revenue 258 221 Miscellaneous accounts and notes receivable 47 126 Materials and supplies, at average cost 458 487 Other current assets 35 46 ------------ ------------ Total current assets 1,652 1,317 ------------ ------------ Property and Plant, Net 11,052 10,920 Investments and Other Non-Current Assets: Investments in leveraged leases 153 164 Nuclear decommissioning trust fund 219 212 Goodwill and other intangibles, net 565 574 Other assets 354 320 ------------ ------------ Total investments and other non-current assets 1,291 1,270 ------------ ------------ Regulatory Assets 682 729 ------------ ------------ TOTAL ASSETS $ 14,677 $ 14,236 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Current maturities of long-term debt $ 291 $ 498 Short-term debt 35 161 Accounts and wages payable 273 480 Taxes accrued 220 103 Other current liabilities 215 215 ------------ ------------ Total current liabilities 1,034 1,457 ------------ ------------ Long-term Debt, Net 4,051 4,070 Preferred Stock of Subsidiary Subject to Mandatory Redemption 21 21 Deferred Credits and Other Non-Current Liabilities: Accumulated deferred income taxes, net 1,775 1,853 Accumulated deferred investment tax credits 145 151 Regulatory liabilities 862 824 Asset retirement obligations 425 413 Accrued pension liabilities 744 699 Other deferred credits and liabilities 175 190 ------------ ------------ Total deferred credits and other non-current liabilities 4,126 4,130 ------------ ------------ Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption 182 182 Minority Interest in Consolidated Subsidiaries 25 22 Commitments and Contingencies (Note 9) Stockholders' Equity: Common stock, $.01 par value, 400.0 shares authorized - shares outstanding of 183.3 and 162.9 respectively 2 2 Other paid-in capital, principally premium on common stock 3,456 2,552 Retained earnings 1,835 1,853 Accumulated other comprehensive income (loss) (41) (44) Other (14) (9) ------------ ------------ Total stockholders' equity 5,238 4,354 ------------ ------------ TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 14,677 $ 14,236 ============ ============ The accompanying notes are an integral part of these consolidated financial statements.

ORAMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) (In millions) Six Months Ended June 30, ------------------------- 2004 2003 ---------- ----------- Cash Flows From Operating Activities: Net income $ 215 $ 211 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of change in accounting principle - (18) Depreciation and amortization 262 256 Amortization of nuclear fuel 13 16 Amortization of debt issuance costs and premium/discounts 5 5 Deferred income taxes, net (5) (9) Deferred investment tax credits, net (6) (6) Coal contract settlement 18 - Other 1 (11) Changes in assets and liabilities, excluding the effects of the acquisitions: Receivables, net (23) 6 Materials and supplies 29 (14) Accounts and wages payable (162) (149) Taxes accrued 117 99 Assets, other (57) 17 Liabilities, other 29 27 ---------- ----------- Net cash provided by operating activities 436 430 ---------- ----------- Cash Flows From Investing Activities: Construction expenditures (379) (332) Acquisitions, net of cash acquired - (489) Nuclear fuel expenditures (5) (1) Other 17 6 ---------- ----------- Net cash used in investing activities (367) (816) ---------- ----------- Cash Flows From Financing Activities: Dividends on common stock (232) (205) Capital issuance costs (23) (11) Redemptions, repurchases, and maturities: Nuclear fuel lease (67) (20) Short-term debt (126) (91) Long-term debt (260) (420) Issuances: Common stock 935 308 Long-term debt 104 298 ---------- ----------- Net cash provided by (used in) financing activities 331 (141) ---------- ----------- Net change in cash and cash equivalents 400 (527) Cash and cash equivalents at beginning of year 111 - ---------- ----------- Cash and cash equivalents at end of period $ 511 $ (527) ========== =========== Cash Paid During the Periods: Interest $ 145 $ 133 Income taxes, net 71 100 The accompanying notes are an integral part of these consolidated financial statements.

~~o TRANSITION~~UNION ~~REPORT~~ELECTRIC ~~PURSUANT~~COMPANY TOCONSOLIDATED ~~SECTION~~STATEMENT OF INCOME (Unaudited) (In millions) Three Months Ended Six Months Ended June 30, June 30, ----------------------------- ----------------------------- 2004 2003 2004 2003 ------------- ------------- ------------- ------------- Operating Revenues: Electric $ 658 $ 616 $ 1,206 $ 1,171 Gas 25 20 97 85 ------------- ------------- ------------- ------------- Total operating revenues 683 636 1,303 1,256 ------------- ------------- ------------- ------------- Operating Expenses: Fuel and purchased power 139 123 282 265 Gas purchased for resale 14 13 OR58 1552 Other operations and maintenance 207 187 400 372 Depreciation and amortization 74 71 146 141 Taxes other than income taxes 56 54 111 107 ------------- ------------- ------------- ------------- Total operating expenses 490 448 997 937 ------------- ------------- ------------- ------------- Operating Income 193 188 306 319 Other Income and (dDeductions) OF: ~~THE~~Miscellaneous ~~SECURITIES~~income ~~EXCHANGE~~4 ~~ACT~~8 OF9 ~~1934~~9 Miscellaneous expense (4) (2) (5) (3) ------------- ------------- ------------- ------------- Total other income and (deductions) - 6 4 6 ------------- ------------- ------------- ------------- Interest Charges 26 26 51 51 ------------- ------------- ------------- ------------- Income Before Income Taxes 167 168 259 274 Income Taxes 58 61 92 99 ------------- ------------- ------------- ------------- Net Income 109 107 167 175 Preferred Stock Dividends 2 2 3 3 ------------- ------------- ------------- ------------- Net Income Available to Common Stockholder $ 107 $ 105 $ 164 $ 172 ============= ============= ============= ============= The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.

~~For~~UNION ~~the Transition~~ELECTRIC ~~period~~COMPANY CONSOLIDATED BALANCE SHEET (Unaudited) (In millions, except per share amounts) June 30, December 31, 2004 2003 ------------- ------------- ASSETS Current Assets: Cash and cash equivalents $ 15 $ 15 Accounts receivable - trade (less allowance for doubtful accounts of $5 and $6, respectively) 187 172 Unbilled revenue 170 111 Miscellaneous accounts and notes receivable 44 117 Materials and supplies, at average cost 182 175 Other current assets 12 26 ------------- ------------- Total current assets 610 616 ------------- ------------- Property and Plant, Net 6,904 6,758 Investments and Other Non-Current Assets: Nuclear decommissioning trust fund 219 212 Other assets 259 246 ------------- ------------- Total investments and other non-current assets 478 458 ------------- ------------- Regulatory Assets 637 685 ------------- ------------- TOTAL ASSETS $ 8,629 $ 8,517 ============= ============= LIABILITIES AND STOCKHOLDER'S EQUITY Current Liabilities: Current maturities of long-term debt $ 277 $ 344 Short-term debt - 150 Borrowings from money pool 342 - Accounts and wages payable 175 314 Taxes accrued 181 66 Other current liabilities 98 102 ------------- ------------- Total current liabilities 1,073 976 ------------- ------------- Long-term Debt, Net 1,762 1,758 Deferred Credits and Other Non-Current Liabilities: Accumulated deferred income taxes, net 1,214 1,289 Accumulated deferred investment tax credits 111 114 Regulatory liabilities 684 652 Asset retirement obligations 420 408 Accrued pension and other postretirement benefits 339 317 Other deferred credits and liabilities 81 80 ------------- ------------- Total deferred credits and other non-current liabilities 2,849 2,860 ------------- ------------- Commitments and Contingencies (Note 9) Stockholder's Equity: Common stock, $5 par value, 150.0 shares authorized - 102.1 shares outstanding 511 511 Preferred stock not subject to mandatory redemption 113 113 Other paid-in capital, principally premium on common stock 702 702 Retained earnings 1,649 1,630 Accumulated other comprehensive income (loss) (30) (33) ------------- ------------- Total stockholder's equity 2,945 2,923 ------------- ------------- TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 8,629 $ 8,517 ============= ============= The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.
1-8946	CILCORP Inc.	37-1169387
	(An Illinois Corporation)
	300 Liberty Street Peoria, Illinois 61602 (309) 677-5230
1-2732	CENTRAL ILLINOIS LIGHT COMPANY	37-0211050
	(An Illinois Corporation)
	300 Liberty Street Peoria, Illinois 61602 (309) 677-5230

~~Indicate~~CENTRAL byILLINOIS ~~check~~PUBLIC ~~mark~~SERVICE ~~whether~~COMPANY ~~the~~STATEMENT ~~Registrants~~OF INCOME (1Unaudited) ~~have~~(In ~~filed~~millions) ~~all reports~~Three ~~required~~Months toEnded beSix ~~filed~~Months byEnded ~~Section~~June 30, June 30, ---------------------------- ------------------------ 2004 2003 2004 2003 ----------- ----------- ----------- ----------- Operating Revenues: Electric $ 139 $ 137 $ 266 $ 269 Gas 28 30 113 107 ----------- ----------- ----------- ----------- Total operating revenues 167 167 379 376 ----------- ----------- ----------- ----------- Operating Expenses: Purchased power 79 82 159 168 Gas purchased for resale 16 18 72 71 Other operations and maintenance 35 38 72 80 Depreciation and amortization 13 or13 ~~15(d)~~26 of26 ~~the~~Taxes ~~Securities~~other ~~Exchange Act~~than ofincome ~~1934~~taxes ~~during~~5 ~~the~~7 ~~preceding~~14 1216 ~~months~~----------- ----------- ----------- ----------- Total operating expenses 148 158 343 361 ----------- ----------- ----------- ----------- Operating Income 19 9 36 15 Other Income and (orDeductions): ~~for~~Miscellaneous ~~such~~income ~~shorter~~6 ~~period~~7 ~~that~~13 ~~the Registrants~~14 ~~were~~Miscellaneous ~~required~~expense to(1) ~~file~~(1) ~~such~~(1) ~~reports~~(2), ----------- ----------- ----------- ----------- Total other income and (2deductions) ~~have~~5 ~~been~~6 ~~subject~~12 12 ----------- ----------- ----------- ----------- Interest Charges 8 9 16 18 ----------- ----------- ----------- ----------- Income Before Income Taxes 16 6 32 9 Income Taxes 8 3 14 4 ----------- ----------- ----------- ----------- Net Income 8 3 18 5 Preferred Stock Dividends - - 1 1 ----------- ----------- ----------- ----------- Net Income Available to ~~such~~ ~~filing~~Common ~~requirements~~Stockholder ~~for~~$ ~~the~~8 ~~past~~$ 903 ~~days~~$ 17 $ 4 =========== =========== =========== =========== The accompanying notes as they relate to CIPS are an integral part of these financial statements.

~~Yes ý No o~~CENTRAL ILLINOIS PUBLIC SERVICE COMPANY BALANCE SHEET (Unaudited) (In millions) June 30, December 31, 2004 2003 ------------- ------------- ASSETS Current Assets: Cash and cash equivalents $ 3 $ 16 Accounts receivable - trade (less allowance for doubtful accounts of $2 and $1, respectively) 51 48 Unbilled revenue 61 64 Miscellaneous accounts and notes receivable 22 22 Current portion of intercompany note receivable - Genco 324 49 Current portion of intercompany tax receivable - Genco 12 12 Materials and supplies, at average cost 42 51 Other current assets 12 6 ------------- ------------- Total current assets 527 268 ------------- ------------- Property and Plant, Net 951 955 Investments and Other Non-Current Assets: Intercompany note receivable - Genco - 324 Intercompany tax receivable - Genco 144 150 Other assets 23 17 ------------- ------------- Total investments and other non-current assets 167 491 ------------- ------------- Regulatory Assets 31 28 ------------- ------------- TOTAL ASSETS $ 1,676 $ 1,742 ============= ============= LIABILITIES AND STOCKHOLDER'S EQUITY Current Liabilities: Accounts and wages payable $ 74 $ 71 Borrowings from money pool 47 121 Taxes accrued 31 19 Other current liabilities 26 27 ------------- ------------- Total current liabilities 178 238 ------------- ------------- Long-term Debt, Net 485 485 Deferred Credits and Other Non-Current Liabilities: Accumulated deferred income taxes, net 269 269 Accumulated deferred investment tax credits 11 11 Regulatory liabilities 146 145 Other deferred credits and liabilities 63 62 ------------- ------------- Total deferred credits and other non-current liabilities 489 487 ------------- ------------- Commitments and Contingencies (Note 9) Stockholder's Equity: Common stock, no par value, 45.0 shares authorized - 25.5 shares outstanding 120 120 Preferred stock not subject to mandatory redemption 50 50 Retained earnings 358 369 Accumulated other comprehensive income (loss) (4) (7) ------------- ------------- Total stockholder's equity 524 532 ------------- ------------- TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 1,676 $ 1,742 ============= ============= The accompanying notes as they relate to CIPS are an integral part of these financial statements.

~~Indicate~~CENTRAL ~~the~~ILLINOIS ~~number~~PUBLIC ofSERVICE ~~shares~~COMPANY ~~outstanding~~STATEMENT ofOF ~~each~~CASH ~~of the~~FLOWS ~~issuer’s~~(Unaudited) ~~classes~~(In ofmillions) Six Months Ended June 30, -------------------------- 2004 2003 ------------ ----------- Cash Flows From Operating Activities: Net income $ 18 $ 5 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 26 26 Deferred income taxes, net (12) (11) Deferred investment tax credits, net - (1) Other 3 (2) Changes in assets and liabilities: Receivables, net - 21 Materials and supplies 9 8 Accounts and wages payable 3 (1) Taxes accrued 12 - Assets, other (7) 7 Liabilities, other 10 5 ------------ ----------- Net cash provided by operating activities 62 57 ------------ ----------- Cash Flows From Investing Activities: Construction expenditures (21) (22) Intercompany note receivable - Genco 49 62 ------------ ----------- Net cash provided by investing activities 28 40 ------------ ----------- Cash Flows From Financing Activities: Dividends on common stock (28) (39) Dividends on preferred stock (1) (1) Repayments to money pool (74) - Redemptions, asrepurchases, and maturities: Long-term debt - (95) Borrowings from money pool - 39 ------------ ----------- Net cash used in financing activities (103) (96) ------------ ----------- Net change in cash and cash equivalents (13) 1 Cash and cash equivalents at beginning of ~~the~~year ~~latest~~16 ~~practicable~~17 ~~date~~------------ ----------- Cash and cash equivalents at end of period $ 3 $ 18 ============ =========== Cash Paid During the Periods: Interest $ 16 $ 20 Income taxes, net 15 14 The accompanying notes as they relate to CIPS are an integral part of these financial statements.

CILCORP Inc.	Common stock, no par value,
	shares outstanding and privately
	held by The AES Corporation
	at September 30, 2002	1,000
CENTRAL ILLINOIS LIGHT COMPANY
	Common stock, no par value,
	shares outstanding and privately
	held by CILCORP Inc. at September 30, 2002	13,563,871

~~CILCORP~~AMEREN ~~INC~~ENERGY GENERATING COMPANY BALANCE SHEET (Unaudited) (In millions, except shares) June 30, December 31, 2004 2003 ------------- ------------ ASSETS Current Assets: Cash and cash equivalents $ - $ 2 Accounts receivable 79 88 Materials and supplies, at average cost 89 90 Other current assets 2 4 ------------ ------------ Total current assets 170 184 Property and Plant, Net 1,753 1,774 Other Non-Current Assets 20 19 ------------ ------------ TOTAL ASSETS $ 1,943 $ 1,977 ============ ============ LIABILITIES AND STOCKHOLDER'S EQUITY Current Liabilities: Accounts and wages payable $ 55 $ 75 Borrowings from money pool 156 124 Current portion of intercompany notes payable - CIPS and Ameren 358 53 Current portion of intercompany tax payable - CIPS 12 12 Taxes accrued 27 30 Other current liabilities 22 23 ------------ ------------ Total current liabilities 630 317 ------------ ------------ Long-term Debt, Net 698 698 Intercompany Notes Payable - CIPS and Ameren - 358 Deferred Credits and Other Non-Current Liabilities: Accumulated deferred income taxes, net 104 99 Accumulated deferred investment tax credits 13 13 Intercompany tax payable - CIPS 144 150 Accrued pension and other postretirement benefits 22 19 Other deferred credits and liabilities 2 2 ------------ ------------ Total deferred credits and other non-current liabilities 285 283 ------------ ------------ Commitments and Contingencies (Note 9) Stockholder's Equity: Common stock, no par value, 10,000 shares authorized - 2,000 shares outstanding - - Other paid-in capital 150 150 Retained earnings 181 170 Accumulated other comprehensive (loss) income (1) 1 ------------ ------------ Total stockholder's equity 330 321 ------------ ------------ TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 1,943 $ 1,977 ============ ============ The accompanying notes as they relate to Genco are an integral part of these financial statements.

~~AND~~AMEREN ENERGY GENERATING COMPANY STATEMENT OF CASH FLOWS (Unaudited) (In millions) Six Months Ended June 30, -------------------------- 2004 2003 ------------ ------------ Cash Flows From Operating Activities: Net income $ 46 $ 49 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of change in accounting principle - (18) Depreciation and amortization 38 37 Deferred income taxes, net 18 27 Other (2) - Changes in assets and liabilities: Accounts receivable 9 (2) Materials and supplies 1 (15) Taxes accrued (3) 66 Accounts and wages payable (10) (17) Assets, other 2 - Liabilities, other (17) (1) ------------ ------------ Net cash provided by operating activities 82 126 ------------ ------------ Cash Flows From Investing Activities: Construction expenditures (28) (31) ------------ ------------ Net cash used in investing activities (28) (31) ------------ ------------ Cash Flows From Financing Activities: Dividends on common stock (35) (2) Redemptions, repurchases, and maturities: Repayments to money pool - (37) Intercompany notes payable - CIPS and Ameren (53) (51) Issuances: Borrowings from money pool 32 - ------------ ------------ Net cash used in financing activities (56) (90) ------------ ------------ Net change in cash and cash equivalents (2) 5 Cash and cash equivalents at beginning of year 2 3 ------------ ------------ Cash and cash equivalents at end of period $ - $ 8 ============ ============ Cash Paid During the Periods: Interest $ 48 $ 49 Income taxes, net paid (refunded) 15 (66) The accompanying notes as they relate to Genco are an integral part of these financial statements.

~~CENTRAL ILLINOIS~~CILCORP ~~LIGHT~~INC. ~~COMPANY~~CONSOLIDATED STATEMENT OF INCOME (Unaudited) (In millions) ---------------Successor------ ---------Successor--------- | -Predecessor- Three Three Six Five | Months Months Months Months | Ended Ended Ended Ended | June 30, June 30, June 30, June 30, | January ------------ ------------ ------------ ------------ | ------------ 2004 2003 2004 2003 | 2003 ------------ ------------ ------------ ------------ | ------------ Operating Revenues: | Electric $ 89 $ 125 $ 187 $ 205 | $ 47 Gas 50 66 191 169 | 58 Other 1 1 2 2 | - ------------ ------------ ------------ ------------ | ------------ Total operating revenues 140 192 380 376 | 105 ------------ ------------ ------------ ------------ | ------------ | Operating Expenses: | Fuel and purchased power 33 65 78 107 | 24 Gas purchased for resale 31 51 138 134 | 44 Other operations and maintenance 47 35 90 57 | 14 Depreciation and amortization 17 22 33 36 | 6 Taxes other than income taxes 5 9 14 17 | 4 ------------ ------------ ------------ ------------ | ------------ Total operating expenses 133 182 353 351 | 92 ------------ ------------ ------------ ------------ | ------------ | Operating Income 7 10 27 25 | 13 | Other Income and (Deductions): | Miscellaneous expense (1) (1) (2) (1) | - ------------ ------------ ------------ ------------ | ------------ Total other income and (deductions) (1) (1) (2) (1) | - ------------ ------------ ------------ ------------ | ------------ | Interest Charges and Preferred Dividends: | Interest 14 11 26 20 | 5 Preferred dividends of subsidiaries 1 1 1 1 | - ------------ ------------ ------------ ------------ | ------------ Net interest charges and preferred dividends 15 12 27 21 | 5 ------------ ------------ ------------ ------------ | ------------ | Income Before Income Taxes and Cumulative Effect of | Change in Accounting Principle (9) (3) (2) 3 | 8 | Income Taxes (5) (3) (2) - | 3 ------------ ------------ ------------ ------------ | ------------ | Income Before Cumulative Effect of Change in | Accounting Principle (4) - - 3 | 5 | Cumulative Effect of Change in Accounting Principle, | Net of Income Taxes of $-, $-, $-, $- and $2 - - - - | 4 ------------ ------------ ------------ ------------ | ------------ | Net Income $ (4) $ - $ - $ 3 | $ 9 ============ ============ ============ ============ | ============ The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.

~~FORM~~CILCORP INC. CONSOLIDATED BALANCE SHEET (Unaudited) (In millions, except shares) ---------Successor--------- June 30, December 31, 2004 2003 ------------- ------------- ASSETS Current Assets: Cash and cash equivalents $ 5 $ 11 Accounts receivables - trade (less allowance for doubtful accounts of $4 and $6, respectively) 29 59 Unbilled revenue 22 40 Miscellaneous accounts and notes receivable 6 16 Materials and supplies, at average cost 129 154 Other current assets 4 5 ------------- ------------- Total current assets 195 285 ------------- ------------- Property and Plant, Net 1,154 1,127 Investments and Other Non-Current Assets: Investments in leveraged leases 127 130 Goodwill and other intangibles, net 558 567 Other assets 18 11 ------------- ------------- Total investments and other non-current assets 703 708 ------------- ------------- Regulatory Assets 13 16 ------------- ------------- TOTAL ASSETS $ 2,065 $ 2,136 ============= ============= LIABILITIES AND STOCKHOLDER'S EQUITY Current Liabilities: Current maturities of long-term debt $ - $ 100 Borrowings from money pool 232 145 Intercompany note payable - Ameren 57 46 Accounts and wages payable 75 108 Other current liabilities 37 38 ------------- ------------- Total current liabilities 401 437 ------------- ------------- Long-term Debt, Net 646 669 Preferred Stock of Subsidiary Subject to Mandatory Redemption 21 21 Deferred Credits and Other Non-Current Liabilities: Accumulated deferred income taxes, net 177 181 Accumulated deferred investment tax credits 11 11 Regulatory liabilities 31 24 Accrued pension and other postretirement benefits 266 259 Other deferred credits and liabilities 29 37 ------------- ------------- Total deferred credits and other non-current liabilities 514 512 ------------- ------------- Preferred Stock of Subsidiary Not Subject to Mandatory Redemption 19 19 Commitments and Contingencies (Note 9) Stockholder's Equity: Common stock, no par value, 10,000 shares authorized -Q ~~FOR~~1,000 ~~THE~~shares ~~QUARTER ENDED~~outstanding ~~SEPTEMBER~~- 30- Other paid-in capital 490 490 Retained earnings (31) (13) Accumulated other comprehensive income (loss) 5 1 ------------- ------------- Total stockholder's equity 464 478 ------------- ------------- TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 2,065 ~~2002~~$ 2,136 ============= ============= The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.

~~INDEX~~CILCORP INC. CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) (In millions) ---------Successor--------- | --Predecessor-- Six Five | Months Months | Ended Ended | June 30, June 30, | January ------------- ------------- | -------------- 2004 2003 | 2003 ------------- ------------- | -------------- Cash Flows From Operating Activities: | Net income $ - $ 3 | $ 9 Adjustments to reconcile net income to net cash | provided by operating activities: | Cumulative effect of change in accounting principle - - | (4) Depreciation and amortization 33 36 | 6 Deferred income taxes, net 3 (3) | (5) Deferred investment tax credits, net - (1) | - Other 7 (17) | - Changes in assets and liabilities: | Receivables, net 66 32 | (20) Materials and supplies 25 (8) | 13 Accounts and wages payable (26) (42) | 20 Taxes accrued 2 (3) | 11 Assets, other (3) 18 | 6 Liabilities, other (4) 4 | (5) ------------- ------------- | -------------- Net cash provided by operating activities 103 19 | 31 ------------- ------------- | -------------- | Cash Flows From Investing Activities: | Construction expenditures (73) (38) | (16) Other 4 2 | 1 ------------- ------------- | -------------- Net cash used in investing activities (69) (36) | (15) ------------- ------------- | -------------- | Cash Flows From Financing Activities: | Dividends on common stock (18) - | - Redemptions, repurchases, and maturities: | Short-term debt - - | (10) Long-term debt (120) (101) | - Issuances: | Borrowings from money pool 87 111 | - Intercompany note payable - Ameren 11 - | - ------------- ------------- | -------------- Net cash provided by (used in) financing activities (40) 10 | (10) ------------- ------------- | -------------- | Net change in cash and cash equivalents (6) (7) | 6 Cash and cash equivalents at beginning of year 11 38 | 32 ------------- ------------- | -------------- Cash and cash equivalents at end of period $ 5 $ 31 | $ 38 ============= ============= | ============== | Cash Paid During the Periods: | Interest $ 20 $ 9 | $ 5 Income taxes, net (refunded) paid (4) 9 | - The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.

PART I.	FINANCIAL INFORMATION
Item 1:	Financial Statements
	CILCORP INC.
	Consolidated Statements of Operations and Comprehensive Income
	Consolidated Balance Sheets
	Consolidated Statements of Cash Flows
	CENTRAL ILLINOIS LIGHT COMPANY
	Consolidated Statements of Income and Comprehensive Income
	Consolidated Balance Sheets
	Consolidated Statements of Cash Flows
	Statements of Segments of Business
	Notes to Consolidated Financial Statements CILCORP Inc. and Central Illinois Light Company
Item 2:	Management’s Discussion and Analysis of Financial Condition and Results of Operations CILCORP Inc. and Central Illinois Light Company
Item 3:	Quantitative and Qualitative Disclosures about Market Risk
Item 4:	Controls and Procedures
PART II.	OTHER INFORMATION
Item 1:	Legal Proceedings
Item 5:	Other Information
Item 6:	Exhibits and Reports on Form 8-K
Signatures
Certifications

2CENTRAL ILLINOIS LIGHT COMPANY CONSOLIDATED BALANCE SHEET (Unaudited) (In millions) June 30, December 31, 2004 2003 ----------- ------------ ASSETS Current Assets: Cash and cash equivalents $ 3 $ 8 Accounts receivable - trade (less allowance for doubtful accounts of $4 and $6, respectively) 28 57 Unbilled revenue 21 35 Miscellaneous accounts and notes receivable 5 14 Materials and supplies, at average cost 52 69 Other current assets 4 5 ----------- ------------ Total current assets 113 188 ----------- ------------ Property and Plant, Net 1,137 1,101 Other Non-Current Assets 26 19 Regulatory Assets 13 16 ----------- ------------ TOTAL ASSETS $ 1,289 $ 1,324 =========== ============ LIABILITIES AND STOCKHOLDER'S EQUITY Current Liabilities: Current maturities of long-term debt $ - $ 100 Borrowings from money pool 233 149 Accounts and wages payable 72 101 Taxes accrued 4 13 Other current liabilities 33 30 ----------- ------------ Total current liabilities 342 393 ----------- ------------ Long-term Debt, Net 138 138 Preferred Stock Subject to Mandatory Redemption 21 21 Deferred Credits and Other Non-Current Liabilities: Accumulated deferred income taxes, net 97 101 Accumulated deferred investment tax credits 11 11 Regulatory liabilities 172 167 Accrued pension and other postretirement benefits 145 128 Other deferred credits and liabilities 19 23 ----------- ------------ Total deferred credits and other non-current liabilities 444 430 ----------- ------------ Commitments and Contingencies (Note 9) Stockholder's Equity: Common stock, no par value, 20.0 shares authorized - 13.6 shares outstanding 186 186 Preferred stock not subject to mandatory redemption 19 19 Other paid-in capital 52 52 Retained earnings 93 95 Accumulated other comprehensive income (loss) (6) (10) ----------- ----------- Total stockholder's equity 344 342 ----------- ------------ TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 1,289 $ 1,324 =========== ============ The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.

~~PART~~CENTRAL I.ILLINOIS ~~FINANCIAL~~LIGHT ~~INFORMATION~~COMPANY CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) (In millions) Six Months Ended June 30, ------------------------ 2004 2003 ----------- ----------- Cash Flows From Operating Activities: Net income $ 8 $ 39 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of change in accounting principle - (24) Depreciation and amortization 32 37 Deferred income taxes, net 4 (5) Deferred investment tax credits, net - (1) Other 7 (2) Changes in assets and liabilities: Receivables, net 52 10 Materials and supplies 17 5 Accounts and wages payable (28) 4 Taxes accrued (9) (13) Assets, other (7) 6 Liabilities, other 18 17 ----------- ----------- Net cash provided by operating activities 94 73 ----------- ----------- Cash Flows From Investing Activities: Construction expenditures (73) (54) Other 1 1 ----------- ----------- Net cash used in investing activities (72) (53) ----------- ----------- Cash Flows From Financing Activities: Dividends on common stock (10) (21) Dividends on preferred stock (1) (1) Redemptions, repurchases, and maturities: Short-term debt - (10) Long-term debt (100) (101) Issuances: Borrowings from money pool 84 99 ----------- ----------- Net cash used in financing activities (27) (34) ----------- ----------- Net change in cash and cash equivalents (5) (14) Cash and cash equivalents at beginning of year 8 22 ----------- ----------- Cash and cash equivalents at end of period $ 3 $ 8 =========== =========== Cash Paid During the Periods: Interest $ 9 $ 14 Income taxes, net 8 11 The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.

26 AMEREN CORPORATION (CONSOLIDATED) UNION ELECTRIC COMPANY (CONSOLIDATED) CENTRAL ILLINOIS PUBLIC SERVICE COMPANY AMEREN ENERGY GENERATING COMPANY CILCORP INC. (CONSOLIDATED) CENTRAL ILLINOIS LIGHT COMPANY (CONSOLIDATED) COMBINED NOTES TO FINANCIAL STATEMENTS (UNAUDITED) June 30, 2004 NOTE 1 - Summary of Significant Accounting Policies General Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren's primary asset is the common stock of its subsidiaries. Ameren's subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas distribution businesses and non rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren's common stock are dependent on distributions made to it by its subsidiaries. Ameren's principal operating subsidiaries are listed below. Also see Glossary of Terms and Abbreviations. o UE, also known as Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas distribution business in Missouri and Illinois. UE was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the State of Missouri and supplies electric and gas service to a 24,500 square mile area located in central and eastern Missouri and west central Illinois. This area has an estimated population of 3 million and includes the greater St. Louis area. UE supplies electric service to approximately 1.2 million customers and natural gas service to approximately 130,000 customers. See Note 3 - Rate and Regulatory Matters for information regarding the proposed transfer in 2004 of UE's Illinois electric and natural gas transmission and distribution businesses to CIPS. o CIPS, also known as Central Illinois Public Service Company, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. CIPS was incorporated in Illinois in 1902. It supplies electric and gas utility service to portions of central and southern Illinois having an estimated population of 1 million in an area of approximately 20,000 square miles. CIPS supplies electric service to approximately 325,000 customers and natural gas service to approximately 170,000 customers. o Genco, also known as Ameren Energy Generating Company, operates a non rate-regulated electric generation business in Illinois and Missouri. Genco was incorporated in Illinois in March 2000, in conjunction with the Illinois Customer Choice Law. Genco commenced operations on May 1, 2000, when CIPS transferred its five coal-fired power plants and related liabilities to Genco at historical net book value. Genco is a subsidiary of Development Company, which is a subsidiary of Resources Company, which is a subsidiary of Ameren. See Note 3 - Rate and Regulatory Matters for information regarding the proposed transfer in 2004 of Genco's CTs located in Pinckneyville and Kinmundy, Illinois to UE. o CILCO, also known as Central Illinois Light Company, is a subsidiary of CILCORP (a holding company) and operates a rate-regulated electric transmission and distribution business, a primarily non rate-regulated electric generation business and a rate-regulated natural gas distribution business in Illinois. CILCO was incorporated in Illinois in 1913. It supplies electric and gas utility service to portions of central and east central Illinois in areas of approximately 3,700 and 4,500 square miles, respectively, with an estimated population of 1 million. CILCO supplies electric service to approximately 205,000 customers and natural gas service to approximately 210,000 customers. In October 2003, CILCO transferred its coal-fired plants and a CT facility, representing in the aggregate approximately 1,100 megawatts of electric generating capacity, to a wholly owned subsidiary, known as AERG, as a contribution in return for all the outstanding stock of AERG and AERG's assumption of certain liabilities. The net book value of the transferred assets was approximately $378 million and no gain or loss was recognized as the 27 transaction was accounted for as a transfer between entities under common control. The transfer was made in conjunction with the Illinois Customer Choice Law. CILCORP was incorporated in Illinois in 1985. Ameren has various other subsidiaries responsible for the short and long-term marketing of power, procurement of fuel, management of commodity risks and providing other shared services. Ameren also has a 60% ownership interest in EEI through UE, which owns 40%, and Resources Company, which owns 20%. Ameren consolidates EEI for financial reporting purposes, while UE and Resources Company report EEI under the equity method. The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. Results of CILCORP and CILCO reflected in Ameren's consolidated financial statements include the period from the acquisition date of January 31, 2003. See Note 2 - Acquisitions for further information. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated. Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results for a full year. Certain reclassifications have been made to prior year's financial statements to conform to 2004 reporting. These statements should be read in conjunction with the financial statements and the notes thereto included in the Ameren Companies' combined 2003 Annual Reports on Form 10-K and first quarter 2004 Quarterly Reports on Form 10-Q. Earnings Per Share There were no differences between the basic and diluted earnings per share amounts for the three and six month periods ended June 30, 2004 and 2003. Assumed stock option conversions increased the number of shares outstanding in the diluted earnings per share calculation by 161,665 shares for the three months ended June 30, 2004 (2003 - 306,389 shares) and 230,999 shares for the six months ended June 30, 2004 (2003 - 273,136 shares). Ameren's equity security units had no dilutive effect on earnings per share in 2003 and 2004. As only the Ameren parent company has publicly held common stock, earnings per share calculations are not relevant and are not presented for any of the subsidiaries of Ameren. Accounting Changes and Other Matters SFAS No.143 - "Accounting for Asset Retirement Obligations" We adopted the provisions of SFAS No. 143, effective January 1, 2003. SFAS No. 143 provides the accounting requirements for asset retirement obligations associated with tangible, long-lived assets. Upon adoption of the standard, Ameren and Genco recognized a net after-tax gain of $18 million in the first quarter of 2003 for the cumulative effect of change in accounting principle. Prior to Ameren's acquisition of CILCORP, predecessor CILCORP and CILCO recognized a net after-tax gain upon adoption of SFAS No. 143 in 2003 of $4 million and $24 million, respectively, for the cumulative effect of change in accounting principle. In addition, in accordance with SFAS No. 143, estimated future removal costs associated with Ameren's, UE's, CIPS', CILCORP's and CILCO's rate-regulated operations that had previously been embedded in accumulated depreciation were reclassified to a regulatory liability. Asset retirement obligations at Ameren and UE increased by approximately $6 million during the quarter ended, and $12 million during the six months ended, June 30, 2004, to reflect the accretion of obligations to their present value. Increases to Genco's, CILCORP's and CILCO's asset retirement obligations were immaterial during these periods. Substantially all of this accretion was recorded as an increase to regulatory assets. In June 2004, the FASB issued an exposure draft on a proposed interpretation of SFAS No. 143. The comment period on the exposure draft ended on August 1, 2004. The interpretation would clarify that a legal obligation to perform an asset retirement activity that is conditional on a future event is within the scope of SFAS No. 143. Accordingly, an 28 entity would be required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability's fair value can be estimated reasonably. The interpretation provides examples of conditional asset retirement obligations that may need to be recognized under the provisions of the interpretation, including asbestos removal. This proposed interpretation could require accrual of additional liabilities by the Ameren Companies and could result in increased expense, which while not yet quantifiable, could be material. This proposed interpretation would be effective for us no later than December 31, 2005. FIN No. 46 - "Consolidation of Variable Interest Entities" In January 2003, the FASB issued FIN No. 46, which changed the consolidation requirements for special purpose entities (SPEs) and non-special purpose entities (non-SPEs) that meet the criteria for designation as variable interest entities (VIEs). In December 2003, the FASB revised FIN No. 46 (FIN No. 46R) to clarify certain aspects of FIN No. 46 and modify the effective dates of the new guidance. FIN No. 46R provides guidance on the accounting for entities that are controlled through means other than voting rights by another entity. FIN No. 46R requires a VIE to be consolidated by a company if that company is designated as the primary beneficiary. The Ameren Companies do not have any interests in entities that are considered SPEs. FIN No. 46R was effective on March 31, 2004 for any interests Ameren holds in non-SPEs. The adoption of FIN No. 46R did not have a material impact on the consolidated financial statements of the Ameren Companies. However, in connection with the adoption of FIN No. 46R, we have determined that the following significant variable interests are held by the Ameren Companies: o EEI. Ameren has a 60% ownership interest in EEI through UE's 40% interest and Resources Company's 20% interest. Under the FIN No. 46R model, Ameren, UE and Resources Company have a variable interest in EEI, and Ameren is the primary beneficiary. Accordingly, Ameren will continue to consolidate EEI, and UE will continue to account for its investment in EEI under the equity method of accounting. The maximum exposure to loss as a result of these variable interests in EEI is limited to Ameren's and UE's equity investments in EEI. o Tolling agreement. CILCO has a significant variable interest in Medina Valley through a tolling agreement to purchase steam, chilled water and electricity. We have concluded that CILCO is not the primary beneficiary of Medina Valley, and accordingly, CILCO does not consolidate Medina Valley. The maximum exposure to loss as a result of this variable interest in the tolling agreement is not material. o Leveraged lease and affordable housing partnership investments. Ameren, UE and CILCORP have investments in leveraged lease and affordable housing partnership arrangements that are variable interests. We have concluded that neither Ameren, UE nor CILCORP are the primary beneficiary of any of the VIEs related to these investments. The maximum exposure to loss as a result of these variable interests is limited to the investments in these arrangements. At June 30, 2004, Ameren and CILCORP had net investments in leveraged leases of $153 million and $127 million, respectively. At June 30, 2004, Ameren, UE and CILCORP had investments in affordable housing partnerships of $19 million, $7 million and $7 million, respectively. FASB Staff Position SFAS No. 106-1 and FASB Staff Position SFAS No. 106-2 "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Prescription Drug Act) was enacted. The Prescription Drug Act introduced a prescription drug benefit to retirees under Medicare as well as a federal subsidy to sponsors of retiree healthcare benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Through its postretirement benefit plans, Ameren provides retirees with prescription drug coverage that we believe is actuarially equivalent to the Medicare prescription drug benefit. In January 2004, the FASB issued FASB Staff Position SFAS No. 106-1 (FSP SFAS 106-1), which permitted a plan sponsor of a postretirement healthcare plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Ameren made this one-time election allowed by FSP SFAS 106-1. In May 2004, the FASB issued FASB Staff Position SFAS No. 106-2 (FSP SFAS 106-2), which superceded FSP SFAS 106-1. FSP SFAS 106-2 provides guidance on accounting for the effects of the Medicare prescription drug legislation by employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Ameren elected to adopt FSP SFAS 106-2 during the second quarter ended June 30, 2004, retroactive to January 29 1, 2004. See Note 12 - Pension and other Postretirement Benefits for additional information on the impact of adoption of FSP SFAS 106-2. Interchange Revenues The following table presents the interchange revenues included in Operating Revenues - Electric for the three months and six months ended June 30, 2004 and 2003. See Note 8 - Related Party Transactions for information on sales among affiliates.

~~Item~~================================================================================================================ 1Three Months Six Months ---------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Ameren(a). ~~Financial~~.............................................. ~~Statements~~$ 81 $ 71 $ 172 $ 185 UE...................................................... 71 65 155 167 CIPS.................................................... 10 10 19 18 Genco................................................... 36 27 75 72 CILCORP(b).............................................. 9 3 21 8 CILCO................................................... 9 3 21 8 ================================================================================================================

================================================================================================================ Three Months Six Months ---------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Ameren(a)............................................... $ 80 $ 71 $ 152 $ 123 UE...................................................... 46 37 96 82 CIPS.................................................... 79 82 159 168 Genco................................................... 32 30 70 71 CILCORP(b).............................................. ~~INC~~8 47 30 87 CILCO................................................... ~~AND~~8 ~~SUBSIDIARIES~~44 30 84 ================================================================================================================

~~Consolidated Statements~~================================================================================================================ ofThree ~~Operations~~Months Six Months ---------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Ameren(a)............................................... $ 31 $ 31 $ 65 $ 62 UE...................................................... 27 25 51 47 CIPS.................................................... 2 3 7 8 Genco................................................... - - - - CILCORP(b).............................................. 2 3 7 9 CILCO................................................... 2 3 7 9 ================================================================================================================

(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) 2003 amounts include January 2003 predecessor information which was $2 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. 30 NOTE 2 - Acquisitions CILCORP and Medina Valley On January 31, 2003, Ameren completed the acquisition of all of the outstanding common stock of CILCORP from AES. CILCORP is the parent company of Peoria, Illinois-based CILCO. With the acquisition, CILCO became an indirect Ameren subsidiary, but remains a separate utility company, operating as AmerenCILCO. On February 4, 2003, Ameren also completed the acquisition from AES of Medina Valley, which indirectly owns a 40 megawatt, gas-fired electric generation plant. The results of operations for CILCORP and Medina Valley were included in Ameren's consolidated financial statements effective with the respective January and February 2003 acquisition dates. See Note 1 - Summary of Significant Accounting Policies for further information on the presentation of the results of CILCORP and CILCO in Ameren's consolidated financial statements. The purchase price allocation for the acquisition of CILCORP and Medina Valley was finalized in January 2004. As a result, goodwill decreased by $8 million since December 31, 2003, primarily due to January 2004 adjustments to property and plant, income tax accounts and accrued severance expenses. The following table presents the final estimated fair values of the assets acquired and liabilities assumed at the dates of our acquisitions of CILCORP and Medina Valley.

=================================================================================================== Current assets............................................................. $ 323 Property and ~~Comprehensive~~plant......................................................... ~~Income~~1,162 Investments and other non-current assets................................... 154 Specifically-identifiable intangible assets................................ 6 Goodwill................................................................... 560 --------------------------------------------------------------------------------------------------- Total assets acquired................................................... 2,205 --------------------------------------------------------------------------------------------------- Current liabilities........................................................ 189 Long-term debt, including current maturities............................... 937 Other non-current liabilities.............................................. 521 --------------------------------------------------------------------------------------------------- Total liabilities assumed............................................... 1,647 --------------------------------------------------------------------------------------------------- Preferred stock assumed.................................................... 41 --------------------------------------------------------------------------------------------------- Net assets acquired..................................................... $ 517 ===================================================================================================

Specifically-identifiable intangible assets of $6 million are comprised of retail customer contracts, which are subject to amortization with an average life of 10 years. Goodwill of $560 million (CILCORP - $553 million; Medina Valley - $7 million) was recognized in connection with the CILCORP and Medina Valley acquisitions. None of this goodwill is expected to be deductible for tax purposes. Illinois Power On February 2, 2004, Ameren entered into an agreement with Dynegy to purchase the stock of Decatur, Illinois-based Illinois Power and Dynegy's 20% ownership interest in EEI. Illinois Power operates a rate-regulated electric and natural gas transmission and distribution business serving approximately 600,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. The total transaction value is approximately $2.3 billion, including the assumption of approximately $1.8 billion of Illinois Power debt and preferred stock, with the balance of the purchase price to be paid in cash at closing. Ameren will place $100 million of the cash portion of the purchase price in a six-year escrow pending resolution of certain contingent environmental obligations of Illinois Power and other Dynegy affiliates for which Ameren has been provided indemnification by Dynegy. In addition, this transaction includes a firm capacity power supply contract for Illinois Power's annual purchase of 2,800 megawatts of electricity from a subsidiary of Dynegy. This contract will extend through 2006 and is expected to supply about 70% of Illinois Power's customer requirements. Ameren's financing plan for this transaction includes the issuance of new Ameren common stock. In February 2004, Ameren issued 19.1 million common shares that generated net proceeds of $853 million, and in July 2004, Ameren completed its issuance of common stock for this transaction with the issuance of 10.9 million common shares that generated net proceeds of $445 million. Proceeds from these sales are expected to be used to finance the cash portion of the purchase price, to reduce Illinois Power debt assumed as part of this transaction and to pay any related 31 premiums. Pending such use, and/or if the acquisition is not completed, we plan to use the net proceeds to reduce present or future indebtedness and/or repurchase securities of Ameren or our subsidiaries. Upon completion of the acquisition, expected by the end of 2004, Illinois Power will become an Ameren subsidiary operating as AmerenIP. The transaction remains subject to the approval of the ICC and the SEC under the PUHCA and other customary closing conditions. Ameren has received approval from the FERC and the FCC, and the waiting period under the Hart-Scott-Rodino Act has expired. In April 2004, the FCC consented to the transfer of control of FCC licenses held by Illinois Power to Ameren, and the initial 30 calendar day waiting period expired without a request by the FTC or DOJ for additional information or documents under the Hart-Scott-Rodino Act. In July 2004, the FERC issued an order approving Ameren's acquisition of Illinois Power and Dynegy's interest in EEI. The principal conditions of the FERC's approval are that Illinois Power join the Midwest ISO prior to closing the transaction and 125 megawatts of EEI's power be sold to a nonaffiliate of Ameren. A procedural schedule has been adopted in the ICC proceeding, which can permit an order to be issued by the fall of 2004. The ICC Staff and several intervenors filed testimony in early July expressing various concerns with the acquisition and objecting to parts of the application filed by Ameren and Illinois Power in March 2004. In late July, Ameren filed testimony responding to these concerns and objections. Hearings in the ICC proceeding are scheduled to be held in August 2004. However, we are unable to predict the ultimate outcome of the remaining regulatory proceedings or the timing of the final agency decisions. According to Illinois Power's Annual Report on Form 10-K for the year ended December 31, 2003, Illinois Power had revenues of $1.6 billion, operating income of $166 million, and net income applicable to its common shareholder of $115 million, and at December 31, 2003, had total assets of $2.8 billion, excluding an intercompany note receivable from its parent company of approximately $2.3 billion. Illinois Power files quarterly, annual and current reports with the SEC pursuant to the Exchange Act. NOTE 3 - Rate and Regulatory Matters Intercompany Transfer of Electric Generating Facilities and Illinois Service Territory As a part of the settlement of the Missouri electric rate case in 2002, UE committed to making certain infrastructure investments from January 1, 2002 through June 30, 2006 of $2.25 billion to $2.75 billion, including the addition of 700 megawatts of generation capacity. The new capacity requirement is expected to be satisfied by the additions in 2002 of 240 megawatts and the proposed transfer from Genco to UE, at net book value (approximately $250 million), of approximately 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois. In July 2004, the FERC approved the generation transfer, but the transfer remains subject to receipt of SEC approval under the PUHCA. Approval by the ICC is not required contingent upon prior approval and execution of UE's transfer of its generation Illinois public utility operations to CIPS as discussed below. Approval by the MoPSC is not required in order for this transfer to occur. However, the MoPSC has jurisdiction over UE's ability to recover the cost of the transferred generating facilities from its electric customers in its rates. As part of the settlement of the Missouri electric rate case in 2002, UE is subject to a rate moratorium providing for no changes in its electric rates before June 30, 2006, subject to certain statutory and other exceptions. In May 2003, UE announced its plan to limit its public utility operations to the state of Missouri and to discontinue operating as a public utility subject to ICC regulation. UE intends to accomplish this plan by transferring its Illinois-based electric and natural gas businesses, including its Illinois-based distribution assets and certain of its transmission assets, to CIPS. In 2003, UE's Illinois electric and gas service territory generated revenues of $155 million and had a net book value of $122 million at December 31, 2003. UE's electric generating facilities and a certain minor amount of its electric transmission facilities in Illinois would not be part of the transfer. The transfer was approved by the FERC in December 2003. The transfer of UE's Illinois-based utility businesses will also require the approval of the ICC, the MoPSC and the SEC under the provisions of the PUHCA. In August 2003, UE filed with the MoPSC, and in October and November 2003, filed with the ICC and the SEC, respectively, for authority to transfer UE's Illinois-based utility 32 businesses, at net book value, to CIPS. The filing with the ICC seeks approval to transfer only UE's Illinois-based natural gas utility business since the ICC authorized the transfer of UE's Illinois-based electric utility business to CIPS in 2000. UE proposes to transfer approximately one-half of the assets directly to CIPS in consideration for a CIPS subordinated promissory note, and approximately one-half of the assets by means of a dividend in kind to Ameren followed by a capital contribution by Ameren to CIPS. A filing seeking approval of both the transfer of UE' Illinois-based utility businesses and Genco's CTs was made with the SEC in October 2003. If completed, the transfers will be accounted for at book value with no gain or loss recognition, which is appropriate treatment for transactions of this type by two entities under common control. In January 2004, the MoPSC staff and the Missouri Office of Public Counsel filed rebuttal testimony with the MoPSC expressing concerns that the transfers of UE's Illinois-based utility businesses may be detrimental to the public in Missouri and recommended that the transfers be denied. Hearings occurred in late March and early April 2004 and post-hearing briefs were filed in May and in early June of 2004. The MoPSC is currently deliberating on this matter. See Note 8 - Related Party Transactions for a discussion of an amendment to the joint dispatch agreement among UE, Genco and CIPS, which was proposed to address concerns raised before the MoPSC in this proceeding. We are unable to predict the ultimate outcome of these regulatory proceedings or the timing of the final decisions of the various agencies. Federal - Electric Transmission Regional Transmission Organization In December 1999, the FERC issued Order 2000 requiring all utilities subject to FERC jurisdiction to state their intentions for joining a RTO. The MoPSC issued an order in early 2004 authorizing UE to participate in the Midwest ISO for a five year period, with participation after that period subject to further approvals by the MoPSC. Subsequently, the FERC issued a final order allowing UE's and CIPS' participation in the Midwest ISO. Under these orders, the MoPSC continues to set the transmission component of UE's rates to serve its bundled retail load. CILCO is already a member of the Midwest ISO and previously transferred functional control of its transmission system to the Midwest ISO. Genco does not own transmission assets, but pays the Midwest ISO to use the transmission system to transmit power from the Genco generating plants. On May 1, 2004, functional control, but not ownership, of the UE and CIPS transmission systems was transferred to the Midwest ISO through GridAmerica LLC, or Grid America. The transfer had no accounting impact to UE and CIPS because they continue to own the transmission system assets. The participation by UE and CIPS in the Midwest ISO is expected to increase annual costs by $10 million to $20 million in the aggregate and could result in a decrease in annual revenues of between $5 million and $10 million in the aggregate. UE and CIPS may also be required to expand their transmission systems according to decisions made by the Midwest ISO rather than their internal planning process. As a part of the transfer of functional control of UE's and CIPS' transmission systems to the Midwest ISO, Ameren received $26 million, which represented the refund of the $13 million exit fee paid by UE and the $5 million exit fee paid by CIPS, which were expensed when they left the Midwest ISO in 2001 plus $1 million interest on the exit fees and the reimbursement of $7 million that was invested in the proposed Alliance RTO. These refunds resulted in after-tax gains of approximately $11 million, $8 million and $3 million for Ameren, UE and CIPS, respectively, which were recorded in other operations and maintenance expenses. Through orders issued during late 2003 and early 2004, the FERC had ordered the elimination of regional through-and-out rates assessed by the Midwest ISO and PJM on transmission service between the Midwest ISO and PJM regions, to be effective May 1, 2004. However, in March 2004, the FERC accepted an agreement among affected transmission owners that retains the regional through-and-out rates until December 1, 2004, and provides for continued negotiations aimed at developing a long-term transmission pricing structure to eliminate seams between the PJM and Midwest ISO regions based on specified pricing principles. Until the long-term transmission pricing structure has been established, UE, CIPS and CILCO cannot predict the ultimate impact that such structure will have on their costs and revenues. In March 2004, the Midwest ISO tendered for filing at the FERC a proposed Open Access Transmission and Energy Markets Tariff (the "Energy Markets Tariff"), which is intended to supercede its existing Open Access Transmission 33 Tariff. The Energy Markets Tariff establishes rates, terms and conditions necessary for implementation of a centralized security-constrained economic dispatch platform supported by a day-ahead and real-time energy market design, including Locational Marginal-Cost Pricing and Financial Transmission Rights for transmission service within the Midwest ISO region. The Energy Markets Tariff also establishes market monitoring and mitigation procedures and codifies existing resource adequacy requirements placed on Midwest ISO members by their states or applicable RRO. The Midwest ISO initially proposed to make the Energy Markets Tariff effective on December 1, 2004, subject to its ability to implement the Energy Markets Tariff. However, implementation of the Energy Markets Tariff is now expected to be effective on March 1, 2005. The Energy Markets Tariff has not yet been accepted for filing by the FERC. Ameren is unable to determine the full impact that the Energy Markets Tariff will have until further information is available regarding the implementation of the Energy Markets Tariff. Until UE and CIPS achieve some degree of operational experience participating in the Midwest ISO through GridAmerica, we are unable to predict the ultimate impact that such participation or ongoing RTO developments at the FERC or other regulatory authorities will have on our financial position, results of operations or liquidity. New Market Power Analysis Screen Order In an order issued in April 2004, the FERC replaced the Supply Margin Assessment Screen previously used to review applications by sellers of electricity at wholesale for authorization to sell power at market-based rates with two alternative measures of market power: (a) an uncommitted pivotal supplier analysis and (b) an uncommitted market share analysis which is to be prepared on a seasonal basis. If an applicant passes both screens, a rebuttable presumption will exist that it lacks generation market power. If the applicant fails either screen, a rebuttable presumption will exist that it has market power. Under such circumstances, the applicant may either seek to rebut the presumption by preparing a delivered price test (identifying the amount of economic capacity from neighboring areas that can be delivered to the control area) or propose mitigation measures. Unless some other mitigation measure is adopted, the applicant's authority to sell power at market-based rates in areas in which it has market power will be revoked, and the applicant will be required to sell at cost-based rates in those areas. UE, Genco, CILCO, AERG, Development Company, Marketing Company and Medina Valley currently have authorization from the FERC to continue to sell power at market-based rates. However, the FERC indicated in its April order that it would apply the new market analysis screens to pending and future market-based rate applications, including three-year market-based rate reviews. All of the aforementioned Ameren entities currently have three-year market-based rate reviews pending at the FERC. Until Ameren has evaluated the impact of the FERC's order with respect to the Ameren system, we are unable to predict the ultimate impact that the new market power analysis screens will have on Ameren's ability to sell power at market-based rates. NOTE 4 - SHORT-TERM BORROWINGS AND LIQUIDITY Short-term borrowings consist of commercial paper issuances and bank line of credit drawings with maturities generally within 1 to 45 days. As of June 30, 2004, Ameren had short-term borrowings totaling $35 million, $32 million of which was borrowed by EEI. The average short-term borrowings at EEI were $10 million for the six months ended June 30, 2004, with a weighted-average interest rate of 1.7%. Peak short-term borrowings for EEI were $44 million for the six months June 30, 2004, with a weighted-average interest rate of 1.7%. CIPS, Genco, CILCORP and CILCO had no external short-term borrowings as of June 30, 2004 and December 31, 2003. At December 31, 2003, Ameren and UE had short-term borrowings outstanding, which totaled $161 million and $150 million, respectively. At June 30, 2004, certain of the Ameren Companies had committed bank credit facilities totaling $829 million, all of which were available for use by UE, CIPS, CILCO and Ameren Services through a utility money pool arrangement. In addition, $600 million of the $829 million was available for use by Ameren directly, and by most of the non rate-regulated affiliates including, but not limited to, Resources Company, Genco, Marketing Company, AFS, AERG and Ameren Energy, through a non state-regulated subsidiary money pool agreement. We have money pool agreements with and among our subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained between rate-regulated and non rate-regulated businesses. See Note 8 - Related Party Transactions for a detailed explanation of the money pool arrangements. The committed bank credit facilities are used to support our commercial paper programs under which no amounts were outstanding at June 30, 2004 (December 34 31, 2003 - $150 million). Access to our credit facilities for any of Ameren's subsidiaries is subject to reduction based on use by affiliates. In July 2004, Ameren entered into two new credit agreements for $700 million in revolving credit facilities to be used for general corporate purposes, including support of Ameren and UE commercial paper programs. The $700 million in new facilities includes a $350 million three-year revolving credit facility and a $350 million five-year revolving credit facility. These new credit facilities replaced Ameren's existing $235 million 364-day revolving credit facility, which matured on July 14, 2004, and a $130 million multi-year revolving credit facility, which would have matured in July 2005. An existing Ameren $235 million multi-year revolving facility, which matures in July 2006, remains outstanding and available. In May 2004, UE renewed its 364-day revolving facilities totaling $154 million that were due to expire that month for an additional one-year term. EEI also has two bank credit agreements totaling $45 million with maturities through June 2005. At June 30, 2004, $32 million was borrowed and outstanding under these credit facilities. Borrowings under Ameren's non state-regulated subsidiary money pool agreement by Genco, Development Company and Medina Valley, each an "exempt wholesale generator," are considered investments for purposes of the 50% SEC aggregate investment limitation. Based on Ameren's aggregate investment in these "exempt wholesale generators" as of June 30, 2004, the maximum permissible borrowings under Ameren's non state-regulated subsidiary money pool pursuant to this limitation for these entities were $705 million. Indebtedness Provisions and Other Covenants Certain of the Ameren Companies' bank credit agreements contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets and merge with other entities. Certain of these credit agreements also contain a provision that limits Ameren's, UE's, CIPS' and/or CILCO's total indebtedness to 60% of total capitalization pursuant to a calculation defined in the related agreement. As of June 30, 2004, the ratio of total indebtedness to total capitalization (calculated in accordance with this provision) for Ameren, UE, CIPS and CILCO was 45%, 45%, 51% and 52%, respectively. In addition, certain of these credit agreements contain indebtedness cross-default provisions and material adverse change clauses which could trigger a default under these facilities in the event that any of Ameren' subsidiaries (subject to the definition in the underlying credit agreements), other than certain project finance subsidiaries, defaults in indebtedness in excess of $50 million. The credit agreements also require us to meet minimum ERISA funding rules. None of the Ameren Companies' credit agreements or financing agreements contain credit rating triggers. A $100 million CILCO bank term loan containing a credit ratings trigger was repaid in February 2004. At June 30, 2004, the Ameren Companies and EEI were in compliance with their credit agreement provisions and covenants. NOTE 5 - LONG-TERM DEBT AND EQUITY FINANCINGS Ameren In February 2004, Ameren issued, pursuant to an August 2002 Form S-3 shelf registration statement, 19.1 million shares of its common stock at $45.90 per share for net proceeds of $853 million. This issuance substantially depleted all of the capacity under the August 2002 shelf registration statement. In June 2004, the SEC declared effective a Form S-3 shelf registration statement filed by Ameren covering the offering from time to time of up to $2 billion of various forms of securities including long-term debt, trust preferred securities and equity securities. In July 2004, Ameren issued, pursuant to the June 2004 Form S-3 shelf registration statement, 10.9 million shares of its common stock at $42.00 per share for net proceeds of $445 million. The proceeds from these offerings are expected to provide funds required to pay the cash portion of the purchase price for our pending acquisition of Illinois Power and Dynegy's 20 percent interest in EEI, and to reduce Illinois Power debt, assumed as a part of this transaction, and pay related premiums. Pending such use, and/or if the acquisition is not completed, we plan to use the net proceeds to reduce present or future indebtedness 35 and/or repurchase securities of Ameren or its subsidiaries. A portion of the net proceeds may also be temporarily invested in short-term instruments. See Note 2 - Acquisitions for further information. In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of six million additional shares of its common stock under DRPlus. Shares of common stock sold under the DRPlus are, at Ameren's option, newly issued shares or treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus. For the six months ended June 30, 2004, Ameren issued 1.2 million new common shares valued at approximately $60 million under its DRPlus and its 401(k) plans to be used for general corporate purposes. UE UE had a lease agreement, which was scheduled to expire on August 31, 2031, that provided for the financing of a portion of its nuclear fuel that was processed for use or was consumed at UE's Callaway nuclear plant. In February 2004, UE terminated this lease with a final payment of $67 million. In February and March 2004, in connection with the delivery of bond insurance policies to secure the environmental improvement and pollution control revenue bonds (Series 1991, 1992, 1998A, 1998B, 1998C, 2000A, 2000B and 2000C) previously issued by the Missouri Environmental Authority, UE delivered separate series of its first mortgage bonds (which are subject to fallaway provisions, as defined in the related financing agreements, similar to those included in its first mortgage bonds which secure UE's senior secured notes) to secure its respective obligations under the existing loan agreements with the Missouri Environmental Authority relating to such environmental improvement and pollution control revenue bonds. As a result, the environmental improvement and pollution control revenue bonds were rated Aaa, AAA and AAA by Moody's, S&P's and Fitch's, respectively. In May 2004, UE issued, pursuant to a September 2003 Form S-3 shelf registration statement, $104 million of 5.50% senior secured notes due May 15, 2014, with interest payable semi-annually on May 15 and November 15 of each year beginning in November 2004. UE received net proceeds of $103 million which were used to redeem and refinance the $100 million 7.00% first mortgage bonds due 2024. The remaining proceeds were used to pay for a portion of the redemption premium and issuance costs. CILCORP and CILCO In February 2004, CILCO repaid its secured bank term loan totaling $100 million with available cash and borrowings from the utility money pool. In May 2004, CILCORP repurchased, $15 million in principal amount of its 9.375% senior bonds for approximately $20 million, which included premium and accrued interest costs. In July 2004, CILCORP repurchased $2 million in principal amount of its 9.375% senior bonds for approximately $3 million which included premium and accrued interest costs. In July 2004, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. The redemption satisfied the Company's mandatory sinking fund redemption requirement for this series of preferred stock for 2004. The amortization related to debt fair value adjustments recorded in connection with the CILCORP acquisition for the three month and six month periods ended June 30, 2004 was $2 million (2003 - $2 million) and $4 million (2003 - $3 million), respectively, and was recorded in interest expense in the Consolidated Statements of Income for Ameren and CILCORP. In conjunction with the repurchase of CILCORP's 9.375% senior bonds in May 2004, the fair value adjustment was reduced by $4 million during the second quarter of 2004. EEI In June 2004, EEI repaid its $40 million 7.61% bank term loan due 2004 with proceeds received from EEI's credit facilities. 36 Amortization of Interest-related Costs The following table presents the amortization of debt issuance costs and any premium or discounts included in interest expense for the Ameren Companies for the three months and six months ended June 30, 2004 and 2003, respectively:

=========================================================================================================== Three Months Six Months ----------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Ameren(Ina)(c)........................................ ~~thousands~~$ 5 $ 5 $ 10 $ 8 UE.................................................. 1 1 2 2 CIPS................................................ - - - - Genco............................................... 1 1 1 1 CILCORP(b)(c) ...................................... 2 2 4 3 CILCO............................................... - - - - ===========================================================================================================

==================================================================================================================== Three Months Six Months -------------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Ameren:(~~Unaudited~~a) Miscellaneous income: Interest and dividend income.......................... $ 3 $ 1 $ 5 $ 2 Allowance for equity funds used during construction... 1 - 4 - Other................................................. - 4 3 9 ------------------------------------------------------------------------------------------------------------------- Total miscellaneous income............................... $ 4 $ 5 $ 12 $ 11 ------------------------------------------------------------------------------------------------------------------- Miscellaneous expense: Minority interest in subsidiary....................... $ (2) $ (4) $ (3) $ (5) Other................................................. (2) (3) (2) (5) ------------------------------------------------------------------------------------------------------------------- Total miscellaneous expense.............................. $ (4) $ (7) $ (5) $ (10) =================================================================================================================== UE: Miscellaneous income: Interest and dividend income.......................... $ 1 $ - $ 2 $ - Equity in earnings of subsidiary...................... 2 4 3 5 Allowance for equity funds used during construction... 1 - 4 - Other................................................. - 4 - 4 ------------------------------------------------------------------------------------------------------------------- Total miscellaneous income............................... $ 4 $ 8 $ 9 $ 9 ------------------------------------------------------------------------------------------------------------------- Miscellaneous expense: Other................................................. $ (4) $ (2) $ (5) $ (3) ------------------------------------------------------------------------------------------------------------------- Total miscellaneous expense.............................. $ (4) $ (2) $ (5) $ (3) ------------------------------------------------------------------------------------------------------------------- 38 ------------------------------------------------------------------------------------------------------------------- Three Months Six Months ------------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- CIPS: Miscellaneous income: Interest and dividend income.......................... $ 6 $ 7 $ 13 $ 14 ------------------------------------------------------------------------------------------------------------------- Total miscellaneous income............................... $ 6 $ 7 $ 13 $ 14 ------------------------------------------------------------------------------------------------------------------- Miscellaneous expense: Other................................................. $ (1) $ (1) $ (1) $ (2) ------------------------------------------------------------------------------------------------------------------- Total miscellaneous expense.............................. $ (1) $ (1) $ (1) $ (2) =================================================================================================================== Genco: Miscellaneous expense: Other................................................. $ - $ - $ (1) $ - ------------------------------------------------------------------------------------------------------------------- Total miscellaneous expense.............................. $ - $ - $ (1) $ - =================================================================================================================== CILCORP:(b) Miscellaneous expense: Other................................................. $ (1) $ (1) $ (2) $ (1) ------------------------------------------------------------------------------------------------------------------- Total miscellaneous expense.............................. $ (1) $ (1) $ (2) $ (1) =================================================================================================================== CILCO: Miscellaneous expense: Other................................................. $ (2) $ (1) $ (3) $ (1) ------------------------------------------------------------------------------------------------------------------- Total miscellaneous expense.............................. $ (2) $ (1) $ (3) $ (1) ===================================================================================================================

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Revenue:
CILCO Electric	$	126,099		$	123,712		$	304,868		$	305,011
CILCO Gas	24,762			21,801			142,961			222,496
CILCO Other	40,902			36,731			91,135			76,015
Other businesses	9,971			14,359			39,998			39,844
Total	201,734			196,603			578,962			643,366
Operating expenses:
Cost of fuel and purchased power	70,467			80,276			181,701			182,073
Cost of gas	20,581			17,859			118,731			191,958
Other operations and maintenance	30,351			28,527			100,061			93,309
Depreciation and amortization	18,204			21,392			54,251			64,302
Taxes, other than income taxes	9,924			9,442			30,925			31,147
Total	149,527			157,496			485,669			562,789
Fixed charges and other:
Interest expense	16,616			17,229			49,470			52,895
Preferred stock dividends of subsidiary	540			540			1,619			1,619
Allowance for funds used during construction	(384		)	(14		)	(1,031		)	(58		)
Other	(53		)	332			614			950
Total	16,719			18,087			50,672			55,406
Income from continuing operations before income taxes	35,488			21,020			42,621			25,171
Income taxes	12,812			9,409			13,810			12,645
Income from continuing operations	22,676			11,611			28,811			12,526
Loss from operations of discontinued businesses, net of tax of $(3), $(2,813), $(11) and $(2,813)	(4		)	(4,278		)	(16		)	(4,278		)
Net income	$	22,672		$	7,333		$	28,795		$	8,248
Other comprehensive income (loss)	606			(5,828		)	5,630			(12,697		)
Comprehensive income (loss)	$	23,278		$	1,505		$	34,425		$	(4,449	)

(a) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. (b) Represents the mark-to-market loss for the hedged portion of electricity price exposure for periods generally less than one year. Certain contracts designated as hedges of electricity price exposure have terms up to five years. (c) Represents a gain associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity and the gain in OCI is amortized over a 10-year period that began in June 2002. (d) Represents a gain associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through October 2007. CILCO amount represents a gain associated with a partial hedge of natural gas requirements through October 2007. (e) Represents the mark-to-market gain of two call options to purchase coal that are accounted for as cash flow hedges. One of these options to purchase coal expires in October 2004 and the other option expires in July 2005. The pre-tax net gain or loss on power forward derivative instruments included in Other Income and Deductions at Ameren, UE and Genco, which represented the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, as well as the reversal of amounts previously recorded in OCI due to transactions going to delivery or settlement, was a $2 million gain for Ameren, $1 million gain for UE and $1 million gain for Genco for the quarter ended June 30, 2004 (2003 - less than $1 million gain for Ameren, less than $1 million gain for UE, less than $1 million gain for Genco) and was a $2 million gain for Ameren, $1 million gain for UE and $1 million gain for Genco for the six 39 months ended June 30, 2004 (2003 - $1 million loss for Ameren, less than $1 million loss for UE, less than $1 million loss for Genco). Other Derivatives The following table represents for the three months and six months ended June 30, 2004 and 2003, the net change in market value of option transactions, which are used to manage our positions in SO2 allowances, coal, heating oil and electricity or power. Certain of these transactions are treated as non-hedge transactions under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The net change in the market value of SO2 options is recorded in Operating Revenues - Electric, while the net change in the market value of coal, heating oil and electricity or power options is recorded as Operating Expenses - Fuel and Purchased Power.

~~See~~================================================================================================================= ~~Notes~~Gains ~~to Consolidated~~(Losses)(a) ~~Financial~~Three ~~Statements~~Months Six Months ----------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- SO2 options: Ameren(b)....................................... $ (1) $ - $ (2) $ (1) UE.............................................. (4) - (7) - CIPS............................................ - - - - Genco........................................... 3 - 5 (1) CILCORP(c)...................................... - - - - CILCO(c)........................................ - - - - =================================================================================================================

(a) Coal, power and heating oil option gains and losses were less than $1 million for the periods shown above. (b) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (c) January 2003 predecessor amounts were zero. NOTE 8 - Related Party Transactions The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren's financial statements. For a discussion of our material related party agreements, see Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies' combined Form 10-K for the fiscal year ended December 31, 2003. Below are updates to several related party transactions. Electric Power Supply Agreements Under two electric power supply agreements, Genco is obligated to supply to Marketing Company, and Marketing Company, in turn, is obligated to supply to CIPS, all of the energy and capacity needed by CIPS to offer service for resale to its native load customers at rates specified by the ICC and to fulfill CIPS' other obligations under all applicable federal and state tariffs or contracts. The agreement between CIPS and Marketing Company expires on December 31, 2004. The agreement between Genco and Marketing Company can be terminated by either party upon at least one year's notice, but may not be terminated prior to December 31, 2004. CIPS and Marketing Company filed in July 2004, a request with the FERC to extend their agreement through December 31, 2006. This extension was required by the ICC in its order approving Ameren's acquisition of CILCORP. In October 2003, in conjunction with CILCO's transfer to AERG of substantially all of its generating assets, AERG entered into an electric power supply agreement with CILCO to supply CILCO with sufficient power to meet its native load requirements. This agreement expires on December 31, 2004. AERG and CILCO have agreed to extend the power supply agreement through December 31, 2006. Unlike the CIPS-Marketing Company agreement, the provisions of the agreement between CILCO and AERG allow the parties to extend the term of the agreement, and Ameren believes that no further FERC action is necessary for such an extension to become effective. The ICC also required this extension in its order approving Ameren's acquisition of CILCORP. 40 Joint Dispatch Agreement UE and Genco jointly dispatch electric generation under an amended joint dispatch agreement. Under the agreement, each affiliate is required to serve its load requirements from its own generation first, and then allow access to any available generation to its affiliate. The joint dispatch agreement can be terminated by either party by giving one year's notice. To address concerns raised before the MoPSC in the proceeding relating to the transfer of UE's Illinois-based utility businesses to CIPS (see Note 3 - Rate and Regulatory Matters), UE offered to seek to amend the joint dispatch agreement so as to provide UE with a larger share of the margins on short term sales of power from the combined generation of UE and Genco. In particular, UE offered to use its best efforts to obtain all required regulatory approvals for such an amendment, but only if the MoPSC concluded that this was a necessary condition for its approval of the transfer of UE's Illinois-based utility businesses. If made, such an amendment is expected to provide to UE additional annual margins ranging from approximately $7 million to $24 million for UE's share of short term power sales. Such an amendment is expected to result in a corresponding reduction in Genco's margins from its share of short term power sales. However, this reduction is expected to be offset by margins received from additional power sales by Genco (through Marketing Company) to CIPS to serve the transferred UE Illinois-based electric utility business. Also as part of the proceeding before the MoPSC, UE offered to study alternatives to the current use of incremental costs to price system energy transfers under the joint dispatch agreement between UE and Genco, if the MoPSC concluded that this was a necessary condition for its approval. As a result of the foregoing, there is uncertainty as to the terms of the joint dispatch agreement and also as to its duration. The termination of the agreement, or modifications to it, could have a material adverse effect on UE or Genco. Modifications to, or termination of, the agreement would not have an immediate impact on Ameren due to UE's Missouri electric rate moratorium, which ends June 30, 2006. Money Pools Through the utility money pool, the pool participants can access committed credit facilities at Ameren, which totaled $600 million at June 30, 2004, and were increased to $935 million in July 2004. These facilities are in addition to UE's $154 million, CIPS' $15 million and CILCO's $60 million in committed credit facilities which are also available to the utility money pool participants. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent the pool participants have surplus funds or other external sources are used to increase the available amounts. The average interest rate for borrowing under the utility money pool for the three months ended June 30, 2004 was 1.04% (2003 - 1.19%) and for the six months ended June 30, 2004 was 1.02% (2003 - 1.25%). At June 30, 2004, $600 million was available through the non state-regulated subsidiary money pool, excluding additional funds available through excess cash balances. The average interest rate for borrowing under the non state-regulated subsidiary money pool for the three months ended June 30, 2004 was 8.84% (2003 - 8.84%) and for the six months ended June 30, 2004 was 8.84% (2003 - 8.84%). CILCORP has been granted authority by the SEC under the PUHCA to borrow up to $250 million directly from Ameren in a separate arrangement unrelated to the money pools. Intercompany Promissory Notes Genco has affiliate notes payable of $324 million and $34 million to CIPS and Ameren, respectively, which, by their current terms, have final payments of principal and interest due on May 1, 2005. The note payable to CIPS was issued in conjunction with the transfer of its electric generating assets and related liabilities to Genco. Genco and CIPS expect to renew or modify the CIPS note to extend the principal maturity, which could include continued amortization of the principal amount. Such extension could require regulatory approval. Genco and Ameren are currently evaluating various alternatives with respect to the note payable to Ameren. In the event the maturities of these notes are not extended or restructured, whether due to not obtaining any necessary regulatory approvals or otherwise, Genco may need to access other financing sources to meet the maturity obligation to the extent it does not have cash available from its operating cash flows. Such sources of financing could include borrowings under the non state-regulated subsidiary money pool, or infusion of equity capital or new direct borrowings from Ameren, all subject to applicable regulatory financing authorizations and provisions in Genco's senior note indenture. 41 UE The following tables present the impact of related party transactions on UE's Consolidated Statement of Income and Consolidated Balance Sheet, based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies' combined Form 10-K for the year ended December 31, 2003:

=================================================================================================================== Statement of Income Three Months Six Months ------------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Operating revenues from affiliates: Power supply agreement with EEI................... $ 2 $ 1 $ 2 $ 1 Joint dispatch agreement with Genco............... 28 24 58 56 Agency agreement with Ameren Energy............... 42 41 95 111 Gas transportation agreement with Genco........... - 1 - 1 ------------------------------------------------------------------------------------------------------------------- Total operating revenues......................... $ 72 $ 67 $ 155 $ 169 ------------------------------------------------------------------------------------------------------------------- Fuel and purchased power expenses from affiliates: Power supply agreements: EEI............................................. $ 17 $ 15 $ 33 $ 28 Marketing Company............................... 3 3 5 5 Joint dispatch agreement with Genco............... 12 7 24 18 Agency agreement with Ameren Energy............... 11 11 30 28 ------------------------------------------------------------------------------------------------------------------- Total fuel and purchased power expenses........... $ 43 $ 36 $ 92 $ 79 ------------------------------------------------------------------------------------------------------------------- Other operating expenses: Support service agreements: Ameren Services................................. $ 38 $ 41 $ 76 $ 86 Ameren Energy................................... 4 5 7 10 AFS............................................. 1 2 2 4 ------------------------------------------------------------------------------------------------------------------- Total other operating expenses.................... $ 43 $ 48 $ 85 $ 100 ------------------------------------------------------------------------------------------------------------------- Interest expense: Borrowings (advances) related to money pool....... $ 1 $ 1 $ 1 $ 2 =================================================================================================================== =================================================================================================================== Balance Sheet June 30, 2004 December 31, 2003 ------------------------------------------------------------------------------------------------------------------- Assets: Miscellaneous accounts and notes receivable...................... $ 11 $ 16 Advances to money pool........................................... 2 12 Liabilities: Accounts payable and wages payable............................... $ 69 $ 46 Borrowings from money pool....................................... 342 - =================================================================================================================== CIPS The following tables present the impact of related party transactions on CIPS' Statement of Income and Balance Sheet, based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies' combined Form 10-K for the year ended December 31, 2003: =================================================================================================================== Statement of Income Three Months Six Months ------------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Operating revenues from affiliates: Power supply agreements: Marketing Company............................... $ 8 $ 8 $ 16 $ 15 CILCO........................................... - 2 - 3 ------------------------------------------------------------------------------------------------------------------- Total operating revenues.......................... $ 8 $ 10 $ 16 $ 18 ------------------------------------------------------------------------------------------------------------------- Fuel and purchased power expenses from affiliates: Power supply agreements: Marketing Company............................... $ 71 $ 74 $ 143 $ 153 EEI............................................. 8 8 16 15 ------------------------------------------------------------------------------------------------------------------- Total fuel and purchased power expenses........... $ 79 $ 82 $ 159 $ 168 ------------------------------------------------------------------------------------------------------------------- 42 =================================================================================================================== Statement of Income Three Months Six Months ------------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Other operating expenses: Support service agreements: Ameren Services.................................. $ 12 $ 14 $ 24 $ 29 AFS.............................................. - 1 - 1 ------------------------------------------------------------------------------------------------------------------- Total other operating expenses.................... $ 12 $ 15 $ 24 $ 30 ------------------------------------------------------------------------------------------------------------------- Interest income: Note receivable from Genco........................ $ 6 $ 7 $ 13 $ 14 =================================================================================================================== =================================================================================================================== Balance Sheet June 30, 2004 December 31, 2003 ------------------------------------------------------------------------------------------------------------------- Assets: Miscellaneous accounts and notes receivable................... $ 10 $ 10 Promissory note receivable from Genco(a)....................... 324 373 Tax receivable from Genco(b)................................... 156 162 Liabilities: Accounts payable and wages payable............................. $ 47 $ 43 Borrowings from money pool..................................... 47 121 ====================================================================================================================

(a) Amount includes current portion of $49 million as of December 31, 2003 and $324 million as of June 30, 2004. (b) Amount includes current portion of $12 million as of December 31, 2003 and $12 million as of June 30, 2004. Genco The following tables present the impact of related party transactions on Genco's Statement of Income and Balance Sheet, based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies' combined Form 10-K for the year ended December 31, 2003:

~~CILCORP~~=================================================================================================================== ~~INC~~Statement of Income Three Months Six Months ------------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Operating revenues from affiliates: Power supply agreements: Marketing Company.................................... ~~AND~~$ ~~SUBSIDIARIES~~168 $ 143 $ 341 $ 300 EEI.................................................. 1 1 1 1 Joint dispatch agreement with UE....................... 12 7 24 18 Agency agreement with Ameren Energy.................... 22 19 49 54 Operating lease with Development Company............... 2 2 5 5 ------------------------------------------------------------------------------------------------------------------- Total operating revenues .............................. $ 205 $ 172 $ 420 $ 378 ------------------------------------------------------------------------------------------------------------------- Fuel and purchased power expenses from affiliates: Joint dispatch agreement with UE....................... $ 28 $ 24 $ 58 $ 56 Agency agreement with Ameren Energy.................... 3 6 10 15 Gas transportation agreement with UE................... - 1 - 1 ------------------------------------------------------------------------------------------------------------------- Total fuel and purchased power expenses................ $ 31 $ 31 $ 68 $ 72 ------------------------------------------------------------------------------------------------------------------- Other operating expenses: Support service agreements: Ameren Services...................................... $ 4 $ 4 $ 8 $ 9 Ameren Energy........................................ 3 2 4 5 AFS.................................................. 1 - 1 1 ------------------------------------------------------------------------------------------------------------------- Total other operating expenses......................... $ 8 $ 6 $ 13 $ 15 ------------------------------------------------------------------------------------------------------------------- Interest expense: Borrowings related to money pool....................... $ 3 $ 4 $ 6 $ 9 Note payable to CIPS................................... 6 7 13 14 Note payable to Ameren................................. - - 1 1 ===================================================================================================================

~~Consolidated~~ =================================================================================================================== Balance ~~Sheets~~Sheet June 30, 2004 December 31, 2003 ------------------------------------------------------------------------------------------------------------------- Assets: Miscellaneous accounts and notes receivable................. $ 73 $ 78 Liabilities: Accounts payable and wages payable.......................... 23 22 Interest payable............................................ 7 7 Promissory note payable to CIPS(a).......................... 324 373 Promissory note payable to Ameren(b)........................ 34 38 Tax payable to CIPS(c)...................................... 156 162 Borrowings from money pool.................................. 156 124 ===================================================================================================================

(a) Amount includes current portion of $49 million as of December 31, 2003 and $324 million as of June 30, 2004. (b) Amount includes current portion of $4 million as of December 31, 2003 and $34 million as of June 30, 2004. (c) Amount includes current portion of $12 million as of December 31, 2003 and $12 million as of June 30, 2004. CILCORP The following tables present the impact of related party transactions on CILCORP's Consolidated Statement of Income and Consolidated Balance Sheet, based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies' combined Form 10-K for the year ended December 31, 2003:

~~(In~~================================================================================================================== ~~thousands~~Statement of Income(a)(b) Three Months Six Months ------------------------------------------------------------------------------------------------------------------ 2004 2003 2004 2003 ---- ---- ---- ---- Operating revenues from affiliates: Gas supply and services agreement with Medina Valley............................................... $ - $ 3 $ - $ 10 ------------------------------------------------------------------------------------------------------------------ Total operating revenues............................... $ - $ 3 $ - $ 10 ------------------------------------------------------------------------------------------------------------------ Fuel and purchased power expenses from affiliates: Executory tolling agreement with Medina Valley......... $ 7 $ 6 $ 17 $ 15 Power purchase agreement with CIPS..................... - 2 - 3 ------------------------------------------------------------------------------------------------------------------ Total fuel and purchased power expenses................ $ 7 $ 8 $ 17 $ 18 ------------------------------------------------------------------------------------------------------------------ Other operating expenses: Support services agreements: Ameren Services...................................... $ 12 $ 1 $ 25 $ 1 AFS.................................................. 1 1 1 1 ------------------------------------------------------------------------------------------------------------------ Total other operating expenses............................ $ 13 $ 2 $ 26 $ 2 ------------------------------------------------------------------------------------------------------------------ Interest expense: Note payable to Ameren................................. $ 1 $ - $ 2 $ - Borrowings related to money pool....................... 1 - 2 - ==================================================================================================================

(a) 2003 amounts include January 2003 predecessor information which included $2 million in operating revenues and $3 million in purchased power associated with the executory tolling agreement with Medina Valley. (b) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

	September 30, 2002		December 31, 2001
	(Unaudited)
ASSETS
Current Assets:
Cash and Temporary Cash Investments	$	56,760	$	18,312
Receivables, Less Allowance for Uncollectible Accounts of $2,067 and $1,800	58,591		47,610
Accrued Unbilled Revenue	24,587		40,265
Fuel, at Average Cost	13,896		18,068
Materials and Supplies, at Average Cost	18,130		17,273
Gas in Underground Storage, at Average Cost	27,128		27,067
FAC Underrecoveries	1,255		1,255
PGA Underrecoveries	2,379		3,236
Prepayments and Other	15,646		20,533
Total Current Assets	218,372		193,619
Investments and Other Property:
Investment in Leveraged Leases	134,257		135,504
Other Investments	17,424		19,285
Total Investments and Other Property	151,681		154,789
Property, Plant and Equipment:
Utility Plant, at Original Cost
Electric	728,738		716,857
Gas	240,250		233,278
	968,988		950,135
Less-Accumulated Provision for Depreciation	170,534		126,502
	798,454		823,633
Construction Work in Progress	102,288		34,340
Other, Net of Depreciation	22		14
Total Property, Plant and Equipment	900,764		857,987
Other Assets:
Goodwill, Net of Accumulated Amortization of $33,753	579,211		579,211
Other	27,578		26,092
Total Other Assets	606,789		605,303
Total Assets	$	1,877,606	$	1,811,698

(a) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. CILCO The following tables present the impact of related party transactions on CILCO's Consolidated Statement of Income and on the Consolidated Balance Sheet, based primarily on the various agreements discussed above and in Note 14 - 44 Related Party Transactions under Part II, Item 8 of the Ameren Companies' combined Form 10-K for the year ended December 31, 2003:

~~See~~=================================================================================================================== ~~Notes~~Statement of Income Three Months Six Months ----------------------------------------------------------------------------------------------------- ------------- 2004 2003 2004 2003 ---- ---- ---- ---- Fuel and purchased power expenses from affiliates: Executory tolling agreement with Medina Valley........ $ 7 $ 6 $ 17 $ 16 Power purchase agreement with CIPS.................... - 2 - 3 ------------------------------------------------------------------------------------------------------------------- Total fuel and purchased power expenses............... $ 7 $ 8 $ 17 $ 19 ------------------------------------------------------------------------------------------------------------------- Other operating expenses: Support services agreements: Ameren Services..................................... $ 12 $ 1 $ 24 $ 1 AFS................................................. - 1 - 1 ------------------------------------------------------------------------------------------------------------------- Total other operating expenses........................ $ 12 $ 2 $ 24 $ 2 ------------------------------------------------------------------------------------------------------------------- Interest expense: Borrowings related to ~~Consolidated~~ ~~Financial~~money ~~Statements~~pool...................... $ 1 $ - $ 2 $ - =================================================================================================================== =================================================================================================================== Balance Sheet June 30, 2004 December 31, 2003 ------------------------------------------------------------------------------------------------------------------- Assets: Miscellaneous accounts and notes receivable............... $ 5 $ 6 Liabilities: Accounts payable ......................................... $ 23 $ 23 Borrowings from money pool................................ 233 149 ===================================================================================================================

NOTE 9 - Commitments and Contingencies Reference is made to Note 15 - Commitments and Contingencies under Part II, Item 8 of the Ameren Companies' combined Form 10-K for the fiscal year ended December 31, 2003. Callaway Nuclear Plant The following table presents insurance coverage at UE's Callaway nuclear plant at June 30, 2004:

=================================================================================================================== Maximum Maximum Assessments Type and Source of Coverage Coverages for Single Incidents ------------------------------------------------------------------------------------------------------------------- Public liability: American Nuclear Insurers...................... $ 300 $ - Pool participation............................. 10,461 101(a) ------------------------------------------------------------- $ 10,761(b) $ 101 Nuclear worker liability: American Nuclear Insurers...................... $ 300(c) $ 4 Property damage: Nuclear Electric Insurance Ltd................. $ 2,750(d) $ 21 Replacement power: Nuclear Electric Insurance Ltd................. $ 490(e) $ 7 ===================================================================================================================

(a) Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended (Price-Anderson). This is subject to retrospective assessment with respect to loss from an incident at any U.S. reactor, payable at $10 million per year. Price-Anderson expired in August 2002 and the temporary extension expired December 31, 2003. Until Price-Anderson is renewed, its provisions continue to apply to existing nuclear plants. (b) Limit of liability for each incident under Price-Anderson. (c) Industry limit for potential liability from workers claiming exposure to the hazards of nuclear radiation. (d) Includes premature decommissioning costs. (e) Weekly indemnity of $3.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $2.8 million per week for 110 weeks thereafter. Price-Anderson limits the liability for claims from an incident involving any licensed U.S. nuclear facility. The limit is based on the number of licensed reactors and is adjusted at least every five years based on the Consumer Price Index. Utilities owning a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson. 45 If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or if coverage is not available, we self-insure the risk. Although we have no reason to anticipate a serious nuclear incident, if one did occur, it could have a material, but indeterminable, adverse effect on our financial position, results of operations or liquidity. Environmental Matters Clean Air Act The EPA issued a rule in October 1998 requiring 22 eastern states and the District of Columbia to reduce emissions of NOx in order to reduce ozone in the eastern United States. Among other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NOx emission budget for each state, including Illinois. The EPA rule requires states to implement controls sufficient to meet their NOx budget by May 31, 2004. In February 2002, the EPA proposed similar rules for Missouri. These rules were finalized in the spring of 2004. The compliance date for the Missouri rules is May 1, 2007. UE has filed an appeal of these rules with the United States Court of Appeals. In mid-December 2003, the EPA issued proposed regulations with respect to SO2 and NOx emissions (the "Clean Air Interstate Rule") and mercury emissions from coal-fired power plants. The new rules, if adopted, will require significant additional reductions in these emissions from our power plants in phases, beginning in 2010. The rules are currently under a public review and comment period and may change before being issued as final. The following table presents preliminary estimated capital costs based on current technology on the Ameren systems to comply with the Clean Air Interstate and mercury rules, as proposed:

	September 30, 2002			December 31, 2001
	(Unaudited)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Current Portion of Long-Term Debt	$	26,750		$	1,400
Notes Payable	—			63,000
Accounts Payable	60,697			75,644
Accrued Taxes	23,022			14,879
Accrued Interest	25,206			18,392
Other	5,191			18,281
Total Current Liabilities	140,866			191,596
Long-Term Debt	791,016			717,730
Deferred Credits and Other Liabilities:
Deferred Income Taxes	213,660			202,822
Regulatory Liability of Regulated Subsidiary	34,418			45,377
Deferred Investment Tax Credit	13,357			14,553
Other	93,632			83,388
Total Deferred Credits and Other Liabilities	355,067			346,140
Preferred Stock of Subsidiary Without Mandatory Redemption	19,120			19,120
Preferred Stock of Subsidiary With Mandatory Redemption	22,000			22,000
Total Preferred Stock of Subsidiary	41,120			41,120
Stockholder’s Equity:
Common Stock, No Par Value; Authorized 10,000 Outstanding 1,000	—			—
Additional Paid-in Capital	518,833			518,833
Retained Earnings	39,100			10,305
Accumulated Other Comprehensive Loss	(8,396		)	(14,026		)
Total Stockholder’s Equity	549,537			515,112
Total Liabilities and Stockholder’s Equity	$	1,877,606		$	1,811,698

(a) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. Emission Credits Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act and NOx Budget Trading Program created marketable commodities called allowances. Each allowance gives the owner the right to emit one ton of SO2 or NOx. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. If additional allowances are needed for new generating facilities, they can be purchased from facilities having excess allowances or from allowance banks. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, the use of low sulfur fuels or through the application of pollution control technology. The NOx Budget Trading Program limits emissions of NOx during the ozone season (May through September). The NOx Budget Trading Program applies to all electric generating units in Illinois beginning in 2004 and in the eastern third of Missouri beginning in 2007. Our generating facilities are expected to comply with the NOx limits through the use and purchase of allowances or through the application of pollution control technology, including low NOx burners, over fire air systems, combustion optimization and selective catalytic reduction (SCR) systems. As of June 30, 2004, UE, Genco and CILCO held 1.7 million, 0.5 million and 0.3 million tons, respectively, of SO2 emission allowances for use between 2004 and 2012. Each company possesses additional allowances for use in periods beyond 2012. As of June 30, 2004, UE, Genco and CILCO Illinois facilities expect to hold 290, 26,200 and 8,300, respectively, of NOx emission allowances with vintages from 2004 to 2007. The Illinois EPA is still determining some NOx emission allowances allocations for this period and 2008. UE, Genco and CILCO expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. Allocations of NOx allowances for Missouri facilities are pending the finalization of rules by Missouri regulators. New environmental regulations, including the Clean Air 46 Interstate Rule, the timing of the installation of pollution control equipment and level of operations will have a significant impact on the amount of allowances actually required for ongoing operations. Noise-related Matters On October 28, 2003, Genco filed a rulemaking proceeding before the Illinois Pollution Control Board (IPCB) seeking site specific noise limitations for its CTs in Elgin, Illinois. The new limitations would allow Genco to meet Illinois noise requirements in a newly proposed residential area. On July 22, 2004, the Illinois Pollution Control Board adopted a final rule that establishes site-specific noise limitations for Genco's CTs in Elgin, Illinois so that Genco will be able to comply with Illinois noise regulations. No further litigation or rulemaking action by Genco is necessary. Asbestos-Related Litigation Ameren, UE, CIPS, Genco and CILCO have been named, along with numerous other parties, in a number of lawsuits which have been filed by certain plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The number of total defendants named in each case is significant with as many as 110 parties named in a case to as few as six. However, the average number of parties is 60 in the cases that were pending as of June 30, 2004. The claims filed against Ameren, UE, CIPS, Genco and CILCO allege injury from asbestos exposure during the plaintiffs' activities at our electric generating plants. In the case of CIPS, its former plants are now owned by Genco, and in the case of CILCO, most of its former plants are now owned by AERG. As a part of the transfer of ownership of the generating plants, the transferor (CIPS or CILCO) has contractually agreed to indemnify the transferee (Genco or AERG) for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages in excess of $50,000, which, if proved, typically would be shared among the named defendants. From April 1, 2004 through June 30, 2004, seven additional lawsuits were filed against Ameren, UE and CIPS, mostly in the Circuit Court of Madison County, Illinois, two lawsuits were dismissed and five were settled. The following table presents the status as of June 30, 2004 of the asbestos-related lawsuits that have been filed against the Ameren Companies:

~~See~~=================================================================================================================== ~~Notes~~Specifically ~~to Consolidated~~Named ~~Financial~~as ~~Statements~~Defendant ----------------------------------------------------------------------- Total(a) Ameren UE CIPS Genco CILCO ------------------------------------------------------------------------------------------------------------------- Filed.......................... 195 | 18 134 77 2 15 Settled........................ 42 | - 31 16 - 1 Dismissed...................... 72 | 3 53 22 - 2 Pending........................ 81 | 15 50 39 2 12 ===================================================================================================================

(a) Addition of the numbers in the individual columns does not equal the total column because some of the lawsuits name multiple Ameren entities as defendants. Ameren, UE, CIPS, Genco and CILCO believe that the final disposition of these proceedings will not have a material adverse effect on their financial position, results of operations or liquidity. Other Matters Enron Litigation Settlement In May 2001, CILCO and Enron Power Marketing, Inc. (EPMI), a subsidiary of Enron Corp. (Enron), entered into a master agreement for electric purchases and sales, which covered energy transactions scheduled for deliveries during the period of 2001 to 2003. In November 2001, EPMI demanded that CILCO post $28 million in collateral based on mark-to-market exposure of open transactions. Also in November 2001, CILCO notified EPMI that events of default had occurred under the master agreement and pursuant to the termination provisions of the master agreement declared the master agreement terminated effective December 20, 2001. Enron and EPMI filed Chapter 11 bankruptcy petitions in December 2001 in the U.S. Bankruptcy Court for the Southern District of New York. In December 2002, EPMI filed a complaint against AES, Constellation New Energy, Inc., formerly known as AES New Energy Inc., and CILCO in the U.S. Bankruptcy Court seeking $31 million. As a result of court ordered mediation of this matter, an agreement in 47 principal was reached among the parties in June 2004, which upon finalization and approval by the U.S. Bankruptcy Court, will settle the outstanding claim by requiring CILCO to pay approximately $21 million to Enron or its subsidiary. The settlement payment is expected to be made during the fourth quarter of 2004. The payment will also settle an unrelated dispute between CILCO and another Enron subsidiary, Enron North America Corp. (ENA) over ENA's failure to deliver natural gas to CILCO pursuant to transactions entered into in May and October 2001. AES, in conjunction with its sale of CILCORP to Ameren in 2003, agreed to indemnify Ameren against the after-tax cost of all liabilities, which will include the settlement payment, legal fees and expenses, incurred by CILCO relating to the Enron claim. Ameren assigned its indemnification rights to CILCO. As a result, this settlement will have no earnings impact on Ameren, CILCORP or CILCO. Labor-related Matters On June 18, 2003, 20 retirees and surviving spouses of retirees of various Ameren companies (the plaintiffs) filed a complaint in the U.S. District Court, Southern District of Illinois, against Ameren, UE, CIPS, Genco and Ameren Services, and against our Retiree Medical Plan (the defendants). The retirees were members of various local labor unions of the IBEW and the IUOE. The complaint, referred to as Barnett, et al. vs Ameren Corporation, et al., alleges the following: o the labor organizations which represented the plaintiffs have historically negotiated retiree medical benefits with the defendants and that pursuant to the negotiated collective bargaining agreements and other negotiated documents, the plaintiffs are guaranteed medical benefits at no cost or at a fixed maximum cost during their retirement; o Ameren has unilaterally announced that, beginning in 2004, retirees must pay a portion of their own healthcare premiums and either an increasing portion of their dependents' premiums or newly imposed dependents' premiums, and that surviving spouses will be paying increased amounts for their medical benefits; o the defendants' actions deprive the plaintiffs of vested benefits and thus violate ERISA and the Labor Management Relations Act of 1947, and constitute a breach of the defendants' fiduciary duties; and o the defendants are estopped from changing the plan benefits. (This allegation was subsequently dropped from the amended complaints referred to below). The plaintiffs filed the complaint on behalf of themselves, other similarly situated former non-management employees and their surviving spouses who retired from January 1, 1992 through October 1, 2002, and on behalf of all subsequent non-management retirees and their surviving spouses whose medical benefits are reduced or are threatened with reduction. The plaintiffs seek to have this lawsuit certified as a class action, seek injunctive relief and declaratory relief, seek actual damages for any amounts they are made to pay as a result of the defendants' actions, and seek payment of attorney fees and costs. An amended complaint that added three plaintiffs was filed July 15, 2003. In response to the Court's ruling on the defendants' motions to dismiss various counts of the complaint, a second amended complaint was filed on December 15, 2003, clarifying some of the allegations, adding two and dropping two plaintiffs, and adding the Ameren Group Medical Plan as a defendant. On April 27, 2004, the Court granted the defendants' motion to dismiss one of the counts brought in connection with the amended complaint which alleges the defendants breached their fiduciary duties under ERISA. In July 2004, the Court denied the plaintiffs' motion to certify this lawsuit as a class action. However, the plaintiffs requested reconsideration of the Court's order denying class certification. In August 2004, the defendants filed a motion for summary judgment. We are unable to predict the outcome of this lawsuit or the impact of the outcome on our financial position, results of operations or liquidity. Certain employees of CILCO are represented by the IBEW. These employees comprise 4% of Ameren's workforce. Labor agreements covering these employees expire August 29, 2004. Labor agreements covering the remaining UE and CIPS employees represented by IBEW and the IUOE expire in June 2006 and June 2007. CILCO has presented its best and final offer and we cannot predict whether negotiations concerning this offer will be accepted. Leveraged Leases Ameren owns interests in assets which have been financed as leveraged leases. One of these leveraged leases is a $10 million net investment at June 30, 2004, in an aircraft leased to Delta Air Lines. Delta Air Lines reported significant operating losses and disclosed in its Form 10-Q filing for the three months ended March 31, 2004, that there is a possibility of filing for bankruptcy if the company cannot achieve a competitive cost structure, regain sustained profitability and access the capital markets under acceptable terms. Ameren could lose all or a portion of its investment 48 in the Delta Air Lines lease in the event of a bankruptcy or default by Delta Air Lines or any voluntary restructuring of the lease. As of June 30, 2004, Delta Air Lines was current in its lease payments related to this lease. NOTE 10 - 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. The DOE currently charges one mill, or 1/10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this Act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. UE has sufficient storage capacity at its Callaway nuclear plant until 2019 and has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE's disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life. Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant's 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 nuclear plant site is assumed to be decommissioned based on immediate dismantlement method and removal from service. Decommissioning costs, including decontamination, dismantling and site restoration, are estimated to be $536 million in current year dollars and are expected to escalate approximately 3.5% per year through the end of decommissioning activity in 2033. Decommissioning costs are charged to cost of services used to establish electric rates for UE's customers and amounted to approximately $7 million in each of the years 2003, 2002 and 2001. Every three years, the MoPSC and ICC require UE to file updated cost studies for decommissioning its Callaway nuclear plant, and electric rates may be adjusted at such times to reflect changed estimates. The latest studies were filed in 2002. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant's decommissioning. Fund earnings are expected to average approximately 8.6% annually through the date of decommissioning. If the assumed return on trust assets is not earned, we believe it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for UE's Callaway nuclear plant is reported in Nuclear Decommissioning Trust Fund in Ameren's and UE's Consolidated Balance Sheets. This amount is legally restricted to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to the regulatory asset recorded in connection with the adoption of SFAS No. 143. Upon the completion of UE's transfer of its Illinois electric and gas utility businesses to CIPS, which is subject to the receipt of regulatory approvals, the assets and liabilities related to the Illinois portion of the decommissioning trust fund will be transferred to Missouri. See Note 3 - Rate and Regulatory Matters for further information. NOTE 11 - Stockholders' Equity Paid-In Capital Ameren's paid-in capital increased by $904 million as of June 30, 2004 compared to December 31, 2003. Ameren received net proceeds of $853 million from the issuance of 19.1 million shares of its common stock in February 2004. In addition, during the six months ended June 30, 2004, Ameren, pursuant to a Form S-3 registration statement, issued 1.3 million new shares of common stock valued at $60 million under its DRPlus and its 401(k) plans. Ameren's paid-in capital decreased $9 million due to the cashless exercise of stock options by its employees in the first six months of 2004. See Note 5 - Long-term Debt and Equity Financings for further information. Other Comprehensive Income Comprehensive income includes net income as reported on the statements of income and all other changes in common stockholders' equity, except those resulting from transactions with common stockholders. A reconciliation of 49 net income to comprehensive income for the three months and six months ended June 30, 2004 and 2003 is shown below for the Ameren Companies:

================================================================================================================= Three Months Ended Six Months Ended ----------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Ameren:(a) Net income................................................... $ 118 $ 110 $ 215 $ 211 Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $3, $(2), $3, $(2)............... 6 (4) 6 (5) Reclassification adjustments for gains (losses) included in net income, net of taxes (benefit) of $(1), $-, $(1), $(1) (3) - (3) (2) ----------------------------------------------------------------------------------------------------------------- Total comprehensive income, net of taxes................ $ 121 $ 106 $ 218 $ 204 ================================================================================================================= UE: Net income................................................... $ 109 $ 107 $ 167 $ 175 Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $(1), $1, $(1)................. 1 (2) 3 (2) Reclassification adjustments for gains (losses) included in net income, net of taxes (benefit) of $-, $-, $-, $-......... - - - (1) ----------------------------------------------------------------------------------------------------------------- Total comprehensive income, net of taxes................ $ 110 $ 105 $ 170 $ 172 ================================================================================================================= CIPS: Net income................................................... $ 8 $ 3 $ 18 $ 5 Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $1, $(1), $2, $(1)................. 1 (2) 4 (2) Reclassification adjustments for gains (losses) included in net income, net of taxes (benefit) of $-, $-, $-, $-......... - - (1) - ----------------------------------------------------------------------------------------------------------------- Total comprehensive income, net of taxes................ $ 9 $ 1 $ 21 $ 3 ================================================================================================================= Genco: Net income................................................... $ 17 $ 10 $ 46 $ 49 Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $-, $(1), $-................... - - (1) - Reclassification adjustments for gains (losses) included in net income, net of taxes (benefit) of $-, $-, $-, $-......... (1) - (1) - ----------------------------------------------------------------------------------------------------------------- Total comprehensive income, net of taxes................ $ 16 $ 10 $ 44 $ 49 ================================================================================================================= CILCORP: (b) Net income (loss)............................................ $ (4) $ - $ - $ 12 Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $1, $-, $2, $(1)................... 3 - 6 (1) Reclassification adjustments for gains (losses) included in net income, net of taxes (benefit) of $(1), $-, $(1), $-..... (2) - (2) - ----------------------------------------------------------------------------------------------------------------- Total comprehensive income (loss), net of taxes......... $ (3) $ - $ 4 $ 11 ================================================================================================================= CILCO: Net income................................................... $ 3 $ 5 $ 9 $ 40 Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $1, $-, $2, $(1)................... 3 - 6 (1) Reclassification adjustments for gains (losses) included in net income, net of taxes (benefit) of $(1), $-, $(1), $-..... (2) - (2) - ----------------------------------------------------------------------------------------------------------------- Total comprehensive income, net of taxes................ $ 4 $ 5 $ 13 $ 39 =================================================================================================================

(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003 and includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) 2003 amounts include January 2003 predecessor information, which was zero. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. 50 Outstanding Shares of Common Stock The following table reconciles the outstanding shares of Ameren common stock for the three months and six months ended June 30, 2004 and 2003:

~~CILCORP~~================================================================================================================ ~~INC~~Three Months Ended Six Months Ended ---------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Shares outstanding at beginning of period............. ~~AND~~182.5 ~~SUBSIDIARIES~~161.1 162.9 154.1 Shares issued......................................... 0.8 0.6 20.4 7.6 ---------------------------------------------------------------------------------------------------------------- Shares outstanding at end of period 183.3 161.7 183.3 161.7 ================================================================================================================

NOTE 12 - PENSION AND OTHER POSTRETIREMENT BENEFITS In December 2003, the FASB issued SFAS No. 132 (Revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits (SFAS No. 132R)," which retains the disclosure requirements in SFAS No. 132 and contains additional requirements. These additional requirements include disclosures about a plan sponsor's investment strategies, detailed information of plan assets, expected future cash flow requirements, and interim disclosures related to periodic benefit cost. The following table presents Ameren's net periodic benefit costs (and the components of those costs) for pension and other postretirement benefits for the three months and six months ended June 30, 2004 and 2003:

~~Consolidated Statements~~================================================================================================================== ofPension ~~Cash~~Benefits ~~Flows~~Postretirement Benefits ------------------------------------------------------------------------------------------------------------------ Three Months Six Months Three Months Six Months ------------------------------------------------------------------------ 2004 2003 2004 2003 2004 2003 2004 2003 ---- ---- ---- ---- ---- ---- ---- ---- Service cost.......................... $ 10 $ 9 $ 21 $ 19 $ 3 $ 3 $ 7 $ 6 Interest cost......................... 31 32 63 66 12 15 28 30 Expected return on plan assets........ (29) (31) (59) (64) (7) (8) (16) (16) Amortization cost: Transition obligation............... - - - - 1 1 2 2 Prior service cost.................. 3 2 6 4 (1) (1) (2) (2) Losses.............................. 6 2 12 4 7 8 17 17 ------------------------------------------------------------------------------------------------------------------ Net periodic benefit cost............. 21 14 43 29 15 18 36 37 ==================================================================================================================

The total amount of our contributions paid, and expected to be paid, do not differ significantly from amounts previously disclosed. Ameren adopted FSP SFAS 106-2 during the second quarter of 2004, retroactive to January 1, 2004, which resulted in the recognition of a federal subsidy for postretirement benefit costs related to prescription drug benefits. See Note 1 - Summary of Significant Accounting Policies. The effect of this subsidy was a reduction of various components of Ameren's, and principally UE's, net periodic postretirement benefit costs for the second quarter of 2004. Interest costs and amortization losses were reduced by $4 million each, partially offset by a reduction in the expected return on plan assets of $2 million. The subsidy-related reduction in Ameren's, and principally UE's, accumulated postretirement benefit obligation was $71 million. UE, CIPS, Genco, CILCORP and CILCO are participants in Ameren's plans and are responsible for their proportional share of the pension benefit costs. The following table presents the pension costs incurred for the three months and six months ended June 30, 2004 and 2003:

=================================================================================================================== Three Months Six Months ------------------------------------------------------------------------------------------------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- Ameren(Ina)........................................................ ~~thousands~~$ 21 $ 14 $ 43 $ 29 UE............................................................... 13 7 26 19 CIPS............................................................. 3 2 6 4 Genco............................................................ 2 1 4 3 CILCORP(b)....................................................... 2 2 4 2 CILCO............................................................ 3 4 8 6 ===================================================================================================================

(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries. (b) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. 51 UE, CIPS, Genco, CILCORP and CILCO are participants in Ameren's plans and are responsible for their proportional share of the postretirement benefit costs. The following table presents the postretirement costs incurred for the three months and six months ended June 30, 2004 and 2003:

================================================================================================================== Three Months Six Months ------------------------------------------------------------------------------------------------------------------ 2004 2003 2004 2003 ---- ---- ---- ---- Ameren(~~Unaudited~~a)........................................................ $ 15 $ 18 $ 36 $ 37 UE............................................................... 8 14 22 25 CIPS............................................................. 3 2 4 4 Genco............................................................ 1 - 2 2 CILCORP(b)....................................................... 2 2 5 5 CILCO............................................................ 4 4 9 9 ===================================================================================================================

(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries. (b) Includes predecessor information for January 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. NOTE 13 - Segment Information As discussed in the Ameren Companies combined Form 10-K for the fiscal year ended December 31, 2003, Ameren's two reportable segments are: (1) Utility Operations, which generates electricity and transmits and distributes gas and electricity; and (2) Other, which is comprised of the parent holding company, Ameren Corporation. The table below presents segment information about the reported revenues and net income of Ameren for the three months and six months ended June 30, 2004 and 2003:

	Nine Months Ended September 30,
	2002			2001
Cash flows from operating activities:
Income from continuing operations before preferred dividends of subsidiary	$	30,430		$	14,145
Adjustments to reconcile net income to net cash provided by operating activities:
Non-cash lease income and investment income	(2,740		)	(3,055		)
Out-of-market coal contract liability adjustment	—			(28,574		)
QST litigation settlement	—			(4,500		)
Non-cash FAC refund	—			(4,045		)
Intangible items	—			3,966
Other non-cash items	—			(89		)
Cash receipts in excess of debt service on leases	5,128			7,923
Depreciation and amortization	54,251			64,302
Deferred income taxes, investment tax credit and regulatory liability of subsidiary, net	5,533			(2,598		)
Changes in operating assets and liabilities:
Decrease in accounts receivable and accrued unbilled revenue	4,682			55,121
Decrease (increase) in inventories	3,254			(6,266		)
Decrease in accounts payable	(14,947		)	(29,153		)
Increase (decrease) in accrued taxes	8,152			(4,151		)
Decrease (increase) in other assets	6,214			(9,710		)
Increase in other liabilities	2,017			30,520
Total adjustments	71,544			69,691
Net cash provided by operating activities from continuing operations	101,974			83,836
Net cash (used in) provided by operating activities of discontinued operations	(11		)	6,033
Cash flows from operations	101,963			89,869
Cash flows from investing activities:
Additions to plant	(95,803		)	(38,513		)
Cost of equity funds capitalized	(14		)	—
Other	(1,679		)	(457		)
Net cash used in investing activities of continuing operations	(97,496		)	(38,970		)
Net cash used by investing activities from discontinued operations	—			—
Cash flows from investing activities	(97,496		)	(38,970		)
Cash flows from financing activities:
Net decrease in short-term debt	(63,000		)	(20,300		)
Long-term debt issued	100,000			—
Long-term debt retired	(1,400		)	(8,500		)
Common dividends paid	—			(15,000		)
Subsidiary preferred dividends paid	(1,619		)	(1,619		)
Net cash provided by (used in) financing activities of continuing operations	33,981			(45,419		)
Net cash used in financing activities of discontinued operations	—			(6,000		)
Cash flows from financing activities	33,981			(51,419		)
Net increase (decrease) in cash and temporary cash investments	38,448			(520		)
Cash and temporary cash investments at beginning of year	18,312			11,743
Cash and temporary cash investments at September 30	$	56,760		$	11,223
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	44,483		$	48,729
Income taxes	$	5,393		$	9,810

(a) Elimination of intercompany revenues. (b) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. 52 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. OVERVIEW Executive Summary Despite some challenges during the second quarter of 2004, Ameren was able to once again deliver solid financial results. The second quarter 2004 earnings were reduced by the incremental costs Ameren incurred in connection with the scheduled refueling and maintenance outage at its Callaway nuclear plant. A similar Callaway outage did not occur in 2003. In addition, the second quarter was negatively impacted by earnings per share dilution principally caused by Ameren's issuance of common shares to prefund the Illinois Power acquisition. Despite these factors, second quarter earnings benefited from solid organic growth, a return to more normal summer weather, stronger power prices, the refund of a Midwest ISO exit fee and a focus on cost control. A major effort taking place at Ameren in the first half of 2004 was the work towards completion of the Illinois Power acquisition. In early July 2004, Ameren completed the equity financing for the acquisition of Illinois Power and the additional 20% interest in EEI from Dynegy. Ameren continues to proceed through the regulatory approval process. As a result of the progress to date in the regulatory approval process, Ameren believes the Illinois Power acquisition remains on target to close by the end of this year. General Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren's primary asset is the common stock of its subsidiaries. Ameren's subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas distribution businesses and non rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren's common stock are dependent on distributions made to it by its subsidiaries. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part I, Item 1 of this report for a detailed description of our principal operating subsidiaries. Also see the Glossary of Terms and Abbreviations. o UE, also known as Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business and a rate-regulated natural gas distribution business in Missouri and Illinois. o CIPS, also known as Central Illinois Public Service Company, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. o Genco, also known as Ameren Energy Generating Company, operates a non rate-regulated electric generation business in Illinois and Missouri. o CILCO, also known as Central Illinois Light Company, is a subsidiary of CILCORP (a holding company) and was acquired on January 31, 2003. It operates a rate-regulated electric transmission and distribution business, a primarily non rate-regulated electric generation business and a rate-regulated natural gas distribution business in Illinois. The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. Results of CILCORP and CILCO reflected in Ameren's consolidated financial statements include the period from the acquisition date of January 31, 2003. See Note 2 - Acquisitions to our financial statements under Part I, Item 1 of this report for further information. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated. In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact Ameren's earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on our earnings. All references in this report of earnings per share are on the basis of diluted shares. 53 Illinois Power Acquisition On February 2, 2004, Ameren entered into an agreement with Dynegy to purchase the stock of Decatur, Illinois-based Illinois Power and Dynegy's 20% ownership interest in EEI. Illinois Power operates a rate-regulated electric and natural gas transmission and distribution business serving approximately 600,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. The total transaction value is approximately $2.3 billion, including the assumption of approximately $1.8 billion of Illinois Power debt and preferred stock, with the balance of the purchase price to be paid in cash at closing. Ameren will place $100 million of the cash portion of the purchase price in a six-year escrow pending resolution of certain contingent environmental obligations of Illinois Power and other Dynegy affiliates for which Ameren has been provided indemnification by Dynegy. In addition, this transaction includes a firm capacity power supply contract for Illinois Power's annual purchase of 2,800 megawatts of electricity from a subsidiary of Dynegy. This contract will extend through 2006 and is expected to supply about 70% of Illinois Power's customer requirements. In February 2004, Ameren issued 19.1 million common shares that generated net proceeds of $853 million, and in July 2004, Ameren issued 10.9 million common shares that generated net proceeds of $445 million. Proceeds from these sales are expected to be used to finance the cash portion of the purchase price, to reduce Illinois Power debt assumed as part of this transaction and to pay any related premiums. Pending such use, and/or if the acquisition is not completed, Ameren plans to use the net proceeds to reduce present or future indebtedness and/or repurchase securities of Ameren or its subsidiaries. However, prior to the closing of the acquisition of Illinois Power, Ameren expects the new common shares to be dilutive to earnings per share. Upon completion of the acquisition, expected by the end of 2004, Illinois Power will become an Ameren subsidiary operating as AmerenIP. The transaction remains subject to the approval of the ICC and the SEC under the PUHCA and other customary closing conditions. In April 2004, the FCC consented to the transfer of control of FCC licenses held by Illinois Power to Ameren, and the initial 30 calendar day waiting period expired without a request by the FTC or DOJ for additional information or documents under the Hart-Scott-Rodino Act. In July 2004, the FERC issued an order approving Ameren's acquisition of Illinois Power and Dynegy's interest in EEI. The principal conditions of the FERC's approval were that Illinois Power join the Midwest ISO prior to closing and 125 megawatts of EEI's power be sold to a nonaffiliate annually. A procedural schedule has been adopted in the ICC proceeding, which can permit an order to be issued by the fall of 2004. The ICC Staff and several intervenors filed testimony in early July expressing various concerns with the acquisition and objecting to parts of the application filed by Ameren and Illinois Power in March 2004. Hearings in the ICC proceeding are scheduled to be held in August 2004. As a result of progress to date in the regulatory approval processes, we believe the acquisition remains on target to close by the end of 2004. However, we are unable to predict the ultimate outcome of the remaining regulatory proceedings or the timing of the final agency decisions. According to Illinois Power's Annual Report on Form 10-K for the year ended December 31, 2003, Illinois Power had revenues of $1.6 billion, operating income of $166 million, and net income applicable to its common shareholder of $115 million, and at December 31, 2003, had total assets of $2.8 billion, excluding an intercompany note receivable from its parent company of approximately $2.3 billion. Illinois Power files quarterly, annual and current reports with the SEC pursuant to the Exchange Act. Ameren expects the acquisition of Illinois Power to be accretive to earnings in the first two years of ownership based on a variety of assumptions related to power prices, interest rates, synergies and regulatory outcomes, among other things. Although Ameren has entered into fixed price power contracts for approximately 70% of Illinois Power's energy supply needs, Ameren's expectations for Illinois Power's earnings through 2006 remain sensitive to changing energy prices for Illinois Power's entire power supply requirements as a result of purchase accounting, as well as other assumptions. 54 RESULTS OF OPERATIONS Earnings Summary Our results of operations and financial position are affected by many factors. Weather, economic conditions and the actions of key customers or competitors can significantly impact the demand for our services. Our results are also affected by seasonal fluctuations caused by winter heating and summer cooling demand. With over 90% of Ameren's revenues directly subject to regulation by various state and federal agencies, decisions by regulators can have a material impact on the price we charge for our services. Our non rate-regulated sales are subject to market conditions for power. We principally utilize coal, nuclear fuel, natural gas and oil in our operations. The prices for these commodities can fluctuate significantly due to the world economic and political environment, weather, supply and demand levels and many other factors. We do not have fuel or purchased power cost recovery mechanisms in Missouri or Illinois for our electric utility businesses, but we do have gas cost recovery mechanisms in each state for our gas delivery businesses. The electric rates for UE are set through June 2006, and are set for CIPS and CILCO through the end of 2006 such that cost decreases or increases will not be immediately reflected in rates. In addition, the gas delivery rates for UE in Missouri are set through June 2006. Fluctuations in interest rates impact our cost of borrowing and pension and postretirement benefits. We employ various risk management strategies in order to try to reduce our exposure to commodity risks and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems and the level of purchased power cost, operating and administrative costs and capital investment are key factors that we seek to control in order to optimize our results of operations, cash flows and financial position. Ameren's net income increased $8 million to $118 million, or 65 cents per share, in the second quarter of 2004 from $110 million, or 68 cents per share, in the second quarter of 2003. The change in net income between 2003 and 2004 was primarily due to organic growth in our service territory, a return to more normal early summer weather versus the mild weather of 2003 and increased margins on interchange sales, principally due to higher power prices. In addition, second quarter net income benefited from a FERC-ordered refund of $18 million in exit fees, previously paid by UE and CIPS to the Midwest ISO in May 2004, upon their re-entry into the Midwest ISO. Partially offsetting these benefits were increased fuel and purchased power and other operations and maintenance costs principally as a result of UE's Callaway nuclear plant refueling and maintenance outage. Net income for Ameren was also reduced by increased employee benefit costs and decreased sales of emission credits. Increased common shares outstanding, primarily due to a February 2004 offering in order to prefund a portion of the equity financing for the Illinois Power acquisition, reduced earnings per share in the first six months of 2004. Ameren's net income increased $4 million to $215 million, or $1.20 per share for the six months ended June 30, 2004 compared to year-ago earnings of $211 million, or $1.32 per share. In the first six months of 2003, Ameren's net income included a net cumulative effect after-tax gain of $18 million, or 11 cents per share, associated with the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." The net SFAS No. 143 gain resulted principally from the elimination of non-legal obligation costs of removal for non rate-regulated assets from accumulated depreciation. The following table presents the net cumulative effect after-tax gain recorded at each of the Ameren Companies upon adoption of SFAS No. 143:

~~See~~=================================================================================================================== ~~Notes~~Net ~~to Consolidated~~Cumulative ~~Financial~~Effect ~~Statements~~After-Tax Gain ------------------------------------------------------------------------------------------------------------------ Ameren(a)............................................................................... $ 18 UE...................................................................................... - CIPS.................................................................................... - Genco................................................................................... 18 CILCORP(b).............................................................................. 4 CILCO................................................................................... 24 ===================================================================================================================

(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) Represents predecessor information recorded in January 2003 prior to the acquisition date of January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. Excluding the net cumulative effect after-tax gain discussed above, Ameren's net income increased $22 million for the first six months of 2004 as compared to the same period in 2003. The change in net income was primarily due to 55 organic growth in revenues due to a recovering economy, favorable weather conditions in the second quarter of the current year, increased sales of emission credits, the Midwest ISO refund and results of CILCORP being included for an additional month in 2004. Partially offsetting these benefits were increased fuel and purchased power and other operations and maintenance costs as a result of the Callaway nuclear plant outage, and increased employee benefit costs. Increased common shares outstanding reduced earnings per share for the first six months of 2004 as compared to the same period in 2003 for Ameren. As a holding company, Ameren's net income and cash flows are primarily generated by its principal subsidiaries, UE, CIPS, Genco and CILCORP. The following table presents the contribution by Ameren's principal subsidiaries to Ameren's consolidated net income for the three months and six months ended June 30, 2004 and 2003:

6=================================================================================================================== Three Months Six Months ------------------------------------------------------------------------------------------------------------------ 2004 2003 2004 2003 ---- ---- ---- ---- Net income: UE(a).......................................... $ 107 $ 105 $ 164 $ 172 CIPS........................................... 8 3 17 4 Genco(a)....................................... 17 10 46 49 CILCORP(b)..................................... (4) - - 3 Other(c)....................................... (10) (8) (12) (17) ------------------------------------------------------------------------------------------------------------------ Ameren net income.................................... $ 118 $ 110 $ 215 $ 211 ===================================================================================================================

(a) Includes earnings from interchange sales by Ameren Energy that provided approximately $16 million and $33 million of UE's net income in the three and six months ended June 30, 2004, respectively, (2003 - second quarter - $11 million; year-to-date - $33 million) and approximately $8 million and $18 million of Genco's net income in the three and six months ended June 30, 2004, respectively (2003 - second quarter - $5 million; year-to-date - $17 million). (b) Excludes net income prior to the acquisition date of January 31, 2003. January 2003 predecessor amount was $9 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. (c) Includes corporate general and administrative expenses, transition costs associated with the CILCORP acquisition, and other non rate-regulated operations. Electric Operations The following table presents the favorable (unfavorable) variations in electric margins, defined as electric revenues less fuel and purchased power, for the three months and six months ended June 30, 2004, from the comparable periods in 2003. We consider electric margin to be a useful measure to analyze the change in profitability of our electric operations between periods and have included the below analysis as a complement to our financial information provided in accordance with GAAP. However, electric margin may not be a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP information we are providing. The variation for Ameren reflects the contribution from CILCORP for the January 2004 period as a separate line item, which allows other margin components to be comparable year over year as we owned CILCORP for only five months in the first six months of 2003. The variations in CILCORP and CILCO electric margins are for the three months and six months ended June 30, 2004, as compared to the same periods in 2003.

~~CENTRAL ILLINOIS~~=================================================================================================================== ~~LIGHT~~Ameren(a) ~~COMPANY~~UE CIPS Genco CILCORP(b) CILCO ------------------------------------------------------------------------------------------------------------------ Three Months Electric revenue change: Effect of weather (estimate)......... $ 32 $ 24 $ 2 $ - $ 4 $ 4 Growth and other (estimate).......... 32 22 - 26 (46) (46) Rate reductions...................... (10) (10) - - - - Interchange revenues................. 24 6 - 9 6 6 EEI.................................. (14) - - - - - ------------------------------------------------------------------------------------------------------------------ Total .................................. $ 64 $ 42 $ 2 $ 35 $ (36) $ (36) ------------------------------------------------------------------------------------------------------------------ Fuel and purchased power change: Fuel: Generation and other............. $ (20) $ 1 $ - $ (14) $ (6) $ (4) Price............................ (11) (8) - (2) (1) (1) Purchased power...................... (9) (9) 3 (2) 39 36 EEI ................................. (3) - - - - - ------------------------------------------------------------------------------------------------------------------ Total .................................. $ (43) $ (16) $ 3 $ (18) $ 32 $ 31 ------------------------------------------------------------------------------------------------------------------ Net change in electric margins.......... $ 21 $ 26 $ 5 $ 17 $ (4) $ (5) ------------------------------------------------------------------------------------------------------------------

~~Consolidated Statements~~------------------------------------------------------------------------------------------------------------------ Ameren(a) UE CIPS Genco CILCORP(b) CILCO ------------------------------------------------------------------------------------------------------------------ Six Months Electric revenue change: CILCORP - January 2004............... $ 47 $ - $ - $ - $ - $ - Effect of ~~Income~~weather (estimate)......... 18 14 - - 3 3 Growth and other (estimate).......... 87 50 (4) 42 (81) (81) Rate reductions...................... (17) (17) - - - - Interchange revenues................. (1) (12) 1 3 13 13 EEI.................................. (13) - - - - - ------------------------------------------------------------------------------------------------------------------ Total .................................. $ 121 $ 35 $ (3) $ 45 $ (65) $ (65) ------------------------------------------------------------------------------------------------------------------ Fuel and purchased power change: CILCORP - January 2004............... $ (24) $ - $ - $ - $ - $ - Fuel: Generation and other............... (21) 9 - (19) (10) (7) Price.............................. (16) (12) - (4) 6 6 Purchased power...................... (15) (14) 9 1 57 54 EEI ................................. (6) - - - - - ------------------------------------------------------------------------------------------------------------------ Total .................................. $ (82) $ (17) $ 9 $ (22) $ 53 $ 53 ------------------------------------------------------------------------------------------------------------------ Net change in electric margins.......... $ 39 $ 18 $ 6 $ 23 $ (12) $ (12) ==================================================================================================================

~~And~~=================================================================================================================== ~~Comprehensive~~Three ~~Income~~Months Six Months ------------------------------------------------------------------------------------------------------------------- Ameren(a)....................................... $ 9 $ 28 UE.............................................. 4 6 CIPS............................................ - 5 Genco........................................... - - CILCORP(b)...................................... 4 4 CILCO........................................... 4 2 ===================================================================================================================

~~(In~~=================================================================================================================== ~~thousands)~~Three Months Six Months ------------------------------------------------------------------------------------------------------------------- Ameren.......................................... $ 6 $ 15 UE.............................................. 3 6 CIPS............................................ 1 5 Genco........................................... - - CILCORP......................................... 2 4 CILCO........................................... 2 4 ===================================================================================================================

Operating Expenses and Other Statement of Income Items The following table presents the favorable (unfavorable) variations in operating and other expenses for the three months and six months ended June 30, 2004, from the comparable period in 2003:

=================================================================================================================== Ameren(~~Unaudited~~a) UE CIPS Genco CILCORP(b) CILCO ------------------------------------------------------------------------------------------------------------------ Three Months Other operations and maintenance....... $ (36) $ (20) $ 3 $ (9) $ (12) $ (9) Depreciation and amortization.......... - (3) - - 5 3 Taxes other than income taxes.......... 3 (2) 2 - 4 3 Other income and deductions............ 2 (6) (1) - - (1) Interest............................... 3 - 1 1 (3) 1 Income taxes........................... 7 3 (5) (2) 2 2 ------------------------------------------------------------------------------------------------------------------- Six Months Other operations and maintenance....... $ (50) $ (28) $ 8 $ (6) $ (19) $ (15) Depreciation and amortization.......... (6) (5) - (1) 9 5 Taxes other than income taxes.......... 1 (4) 2 2 7 7 Other income and deductions............ 6 (2) - (1) (1) (2) Interest............................... 5 - 2 4 (1) 3 Income taxes........................... - 7 (10) (6) 5 5 ===================================================================================================================

(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. Includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) Includes predecessor information for January 2003. 59 Other Operations and Maintenance Ameren's other operations and maintenance expenses increased $36 million for the three months and $50 million for the six months ended June 30, 2004, as compared to the same periods in 2003. Excluding the additional month of CILCORP results in the current year of $15 million, expenses increased $35 million for the six months ended June 30, 2004. Expenses at Ameren and UE increased primarily due to increased power plant maintenance expenses as a result of the outage at UE's Callaway nuclear plant during the second quarter of 2004. The outage lasted 64 days and resulted in incremental maintenance costs of approximately $40 million. Refueling outages occur approximately every 18 months and typically include the replacement of fuel and the performance of maintenance and inspections. The last refueling outage occurred in the fall of 2002. In addition to the Callaway outage expenses, employee benefit costs were higher at Ameren during both the quarter and the six months ended June 30, 2004. The adoption in the second quarter of 2004, retroactive to January 1, 2004, of FASB Staff Position SFAS No. 106-2 resulted in the recognition of nontaxable federal subsidies expected to be provided under the Medicare Prescription Drug, Improvement and Modernization Act, which partially offset employee benefit cost increases in the second quarter of 2004. See Note 1 - Summary of Significant Accounting Policies and Note 12 - Pension and Other Postretirement Benefits to our financial statements under Part I, Item 1 of this report for further information. UE's employee benefit costs decreased for the second quarter of 2004 as a result of the recording of the subsidy and were comparable to the prior year amounts for the six months ended June 30, 2004. Ameren, UE and CIPS benefited during the second quarter of 2004 from the refund to UE, referenced above, of previously paid exit fees upon its re-entry into the Midwest ISO. CIPS' other operations and maintenance expenses decreased in the three months and six months ended June 30, 2004, as compared to the same periods in 2003, primarily due to CIPS' portion of the Midwest ISO exit fee refund. Genco's, CILCORP's and CILCO's other operations and maintenance expenses increased in the three months and six months ended June 30, 2004, as compared to the same periods in 2003, primarily due to higher employee benefit costs. Depreciation and Amortization Ameren's depreciation and amortization expenses were comparable to the prior year for the three months and six months ended June 30, 2004, excluding the additional month of CILCORP expenses in the current year ($6 million). Depreciation and amortization expenses at CIPS and Genco were also comparable in the second quarter and first six months of 2004 to the same periods in 2003. UE's depreciation and amortization expenses increased in the second quarter and for the first six months of 2004, as compared to the same periods in 2003, primarily due to capital additions. Depreciation and amortization expenses at CILCORP and CILCO decreased in the three months and six months ended June 30, 2004, as compared to the same periods in 2003, primarily due to property retirements exceeding capital additions. Taxes Other Than Income Taxes Taxes other than income taxes decreased at Ameren and CIPS in the three months and six months ended June 30, 2004, as compared to the same periods in 2003, primarily due to decreased property taxes. UE's taxes other than income taxes increased in the three months and six months ended June 30, 2004, as compared to the same periods in 2003, primarily due to higher gross receipts taxes as a result of increased utility sales in 2004. Genco's taxes other than income taxes decreased in the first six months of 2004, as compared to 2003, primarily due to favorable property tax assessments in the current year. Taxes other than income taxes for the second quarter of 2004 were comparable to the same period in the prior year. 60 Taxes other than income taxes decreased at CILCORP and CILCO in the second quarter and first six months ended June 30, 2004, as compared to 2003, primarily due to reduced gross receipts taxes as a result of customers switching to Marketing Company. Other Income and Deductions Ameren's other income and deductions increased in the second quarter and first six months of 2004, as compared to the same periods in 2003, primarily due to increased interest income as a result of investing the proceeds from the February 2004 equity offering. Other income and deductions at UE decreased in the second quarter and first six months of 2004, as compared to the same periods in 2003, primarily due to a net decrease in earnings from UE's ownership interest in EEI and donations made in 2004. Other income and deductions at CIPS, Genco, CILCORP and CILCO were comparable in the second quarter and first six months of 2004 to the same periods in 2003. Interest Interest expense decreased at Ameren in the second quarter and first six months of 2004, as compared to the same periods in 2003, primarily due to the redemption of Ameren floating rate notes at the end of 2003, as well as redemptions of long-term debt during 2003 at its subsidiaries as noted below. Interest expense decreased at CIPS in the second quarter and first six months of 2004, as compared to the same periods of 2003, primarily due to the maturity or redemption of first mortgage bonds in the second quarter of 2003. Genco's interest expense was reduced in the second quarter and first six months of 2004, as compared to the same periods of 2003, primarily due to a reduction in principal amounts outstanding on intercompany promissory notes to CIPS and Ameren along with decreased borrowings from Ameren's non state-regulated subsidiary money pool. Interest expense decreased at CILCO in the second quarter and first six months of 2004, as compared to the same periods of 2003, primarily due to the redemption of long-term debt in the second quarter of 2003 and the first quarter of 2004. Interest expense increased at CILCORP in the second quarter and first six months of 2004 due to increased non state-regulated subsidiary money pool borrowings, partially offset by redemptions of debt at CILCO and repurchases of CILCORP debt. UE's interest expense was comparable in the second quarter and first six months of 2004 to the same periods in 2003. Income Taxes Income tax expense was flat at Ameren for the first six months of 2004, as compared to the same period in 2003. Higher pre-tax income was offset by a lower effective tax rate at Ameren for the second quarter of 2004, as compared to the same period in 2003, primarily due to the recording of the expected nontaxable federal Medicare subsidy in the second quarter of 2004 and the exercising of stock options by our employees in the first six months of 2004, which resulted in lower taxable income, but no income statement expense. Income tax expense increased at CIPS and Genco in the second quarter and first six months of 2004, as compared to the same periods in 2003, primarily due to higher pre-tax income. Income tax expense decreased at UE, CILCORP and CILCO primarily due to lower pre-tax income in 2004. UE's effective tax rate was also impacted by the recording of the expected nontaxable federal Medicare subsidy. 61 LIQUIDITY AND CAPITAL RESOURCES The tariff-based gross margins of Ameren's rate-regulated utility operating companies continue to be the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows. In addition, we plan to utilize short-term debt to support normal operations and other capital requirements. The following table presents net cash provided by (used in) operating, investing and financing activities for the six months ended June 30, 2004 and 2003:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
Operating revenue:
Electric	$	126,099		$	123,712		$	304,868		$	305,011
Gas	24,762			21,801			142,961			222,496
Total operating revenues	150,861			145,513			447,829			527,507
Operating expenses:
Cost of fuel	28,323			54,683			74,648			108,647
Cost of gas	12,050			9,803			84,022			162,299
Purchased power	16,658			15,670			40,705			35,329
Other operations and maintenance	28,163			26,974			95,026			89,448
Depreciation and amortization	17,849			17,173			53,194			51,642
Income taxes	12,467			2,368			20,122			12,312
Other taxes	9,903			9,415			30,811			31,074
Total operating expenses	125,413			136,086			398,528			490,751
Operating income	25,448			9,427			49,301			36,756
Other income and deductions:
Cost of equity funds capitalized	14			—			14			—
Company-owned life insurance, net	53			(332		)	(614		)	(950		)
Other, net	8,466			1,792			13,854			7,077
Total other income and (deductions)	8,533			1,460			13,254			6,127
Interest expense:
Interest on long-term debt	5,135			4,642			13,889			13,299
Cost of borrowed funds capitalized	(370		)	(14		)	(1,017		)	(58		)
Other	680			1,121			2,709			4,599
Total interest expense	5,445			5,749			15,581			17,840
Net income before preferred dividends	28,536			5,138			46,974			25,043
Dividends on preferred stock	540			540			1,619			1,619
Net income available for common stock	27,996			4,598			45,355			23,424
Other comprehensive income (loss)	606			(5,828		)	5,630			(12,697		)
Comprehensive income (loss)	$	28,602		$	(1,230	)	$	50,985		$	10,727

(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) 2003 amounts include January 2003 predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. Cash Flows from Operating Activities Cash flows provided by operating activities increased for all Ameren Companies, except Genco, for the six months ended June 30, 2004, as compared to the same period in 2003. The increase in cash flows provided by operating activities for Ameren was due to increased earnings resulting from warmer weather in the second quarter of 2004 compared to the same period in 2003, stronger power prices that benefited interchange margins, solid organic growth in Ameren's service territory, partially offset by costs of the Callaway refueling outage. Ameren's and UE's cash flows from operating activities also increased due to $18 million of cash received in the first six months of 2004 related to UE's settlement of a dispute over mine reclamation issues with a coal supplier. In addition, Ameren operating cash flows benefited in 2004 by $18 million (UE - $13 million, CIPS - $5 million) from a refund of exit fees for costs incurred related to entering an RTO and $8 million from the return of other amounts (UE - $4 million, CIPS - $2 million). Increases in cash flows from operating activities in the first six months of 2004, compared to the same period in 2003, were partially offset by a net use of cash for changes in working capital requirements. Significant uses of cash for the period ended June 30, 2004, compared to 2003, included higher accounts receivables in the current period due to warmer weather in the first six months of 2004 compared to 2003 and lower accounts payable due to reduced days outstanding. The net cash used for working capital requirements was partially offset by lower income taxes paid due to timing differences and decreased materials and supplies inventories resulting from decreased natural gas volumes being put into storage during the winter injection period. Cash flows from operating activities increased for UE, CILCORP and CILCO for the six months ended June 30, 2004, compared to the same period in 2003, primarily due to the working capital changes, partially offset by decreased net earnings. UE's cash from operating activities also benefited from the timing of income tax payments and the Midwest ISO refund. CIPS' cash flows from operating activities increased for the first six months of 2004, compared to the same period in 2003, principally due to increased earnings associated with lower purchased power costs and the Midwest ISO exit fee refund. These benefits were partially offset by working capital changes principally due to reduced taxes paid due to the timing of payments and increased accounts receivable in 2004. Genco's cash flows from operating activities decreased in the first six months of 2004, compared to the same period in 2003, due to working capital changes primarily resulting from reduced taxes paid in the six months ended June 30, 2004, compared to the same period in the prior year. 62 Cash Flows from Investing Activities Cash flows from investing activities increased for Ameren and Genco and decreased for UE, CIPS, CILCORP and CILCO for the six months ended June 30, 2004 as compared to the same period in 2003. Ameren's decrease in cash used in investing activities was primarily due to $489 million in cash paid for the acquisitions of CILCORP and Medina Valley in early 2003. Excluding the acquisition costs described above, Ameren's cash flows used in investing activities increased by approximately $40 million for the six months ended June 30, 2004 compared to the same period in 2003. The increase in investing activities for Ameren was principally due to higher construction expenditures at UE, CILCORP and CILCO. UE's construction expenditures for the six months ended June 30, 2004 primarily included upgrades and replacement of condenser bundles and low pressure rotor equipment related to the refueling outage in the second quarter of 2004 at UE's Callaway nuclear plant. In addition, UE's construction expenditures included upgrades at UE's various other power plants and additional construction expenditures for new transmission and distribution lines. CILCORP's and CILCO's construction expenditures were primarily related to power plant upgrades that were made in order for CILCO's non rate-regulated subsidiary, AERG, to have more flexibility in fuel supply for power generation in the future. Cash flows provided by investing activities for CIPS decreased for the six months ended June 30, 2004, compared to the same period in 2003, primarily due to lower cash receipts related to CIPS' intercompany note receivable with Genco in the first six months of 2004, which totaled $49 million compared to $62 million in the first six months of 2003. Genco's decrease in cash flows used in investing activities primarily resulted from reduced construction expenditures in the first six months of 2004 compared to the same period in 2003. Genco's construction expenditures in 2004 included costs primarily associated with the replacement of a turbine generator at one of its power plants. We continually review our generation portfolio and expected electrical needs, and as a result, we could modify our plan for generation capacity, which could include the timing of when certain assets will be added to, or removed from, our portfolio, the type of generation asset technology that will be employed, or whether capacity may be purchased, among other things. Any changes that we plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material. Cash Flows from Financing Activities Ameren Ameren's cash flows from financing activities increased for the six months ended June 30, 2004, as compared to the same period in 2003. In February 2004, Ameren received net proceeds of $853 million from the issuance of 19.1 million common shares. The proceeds are ultimately expected to be utilized to pay the cash portion of the purchase price for Ameren's acquisition of Illinois Power and Dynegy's 20% interest in EEI and to reduce Illinois Power debt assumed as part of this transaction and pay related premiums. During the first six months of 2004, these proceeds were indirectly used to repay a $100 million bank term loan at CILCO, repay short term debt of approximately $181 million, and invested in short-term investments. The common stock proceeds received in the first quarter of 2003 were used to fund a portion of the acquisitions of CILCORP in January 2003 and Medina Valley in February 2003. See Note 2 - Acquisitions to our financial statements under Part I, Item 1 of this report for further explanation. In addition, Ameren's increase in cash flows from financing activities was due to the decrease in redemptions, repurchases and maturities of long-term debt totaling $260 million in the first six months of 2004 compared to $420 million in the same period in 2003. The increase in cash flows from financing activities at Ameren described above was partially offset by an increase in the redemptions, repurchases and maturities of short-term debt, as well as the termination of UE's nuclear fuel lease, totaling $193 million in the first six months of 2004, compared to $111 million in the same period in 2003. Due to the increase in number of common shares outstanding, Ameren's dividend payments on common stock increased during the six months ended June 30, 2004, compared to the same period in 2003, which also caused a decrease in Ameren's cash flows from financing activities. UE UE's cash flows from financing activities decreased for the six months ended June 30, 2004, as compared to the same period in 2003. In 2004, cash provided by borrowings from the utility money pool arrangement of $342 million was partially offset by the $217 million of cash used for repurchases of short-term debt and the nuclear fuel lease 63 termination payment. The lease agreement, which was scheduled to expire on August 31, 2031, provided for the financing of a portion of UE's nuclear fuel that was processed for use or was consumed at UE's Callaway nuclear plant. CIPS CIPS' cash flows from financing activities decreased for the six months ended June 30, 2004, principally due to $74 million of repayments to the utility money pool arrangement in 2004 compared to $39 million of borrowings from the money pool arrangement in 2003. The net decrease in cash provided by the money pool arrangement in 2004 was partially offset by a decrease in redemptions of long-term debt in the first six months of 2004, compared to same period in 2003, and reduced dividend contributions to Ameren, which totaled $28 million in the first six months of 2004, compared to $39 million in the same period of 2003. Genco Genco's cash flows from financing activities increased for the six months ended June 30, 2004, as compared to the same period in 2003, primarily due to borrowings from the non state-regulated subsidiary money pool arrangement that totaled $32 million in 2004 compared to repayments to the money pool arrangement of $37 million in 2003. The increase in cash flows was offset by an increase in dividends paid to Ameren, which totaled $35 million in 2004 compared to $2 million in 2003. Genco has affiliate notes payable of $324 million and $34 million to CIPS and Ameren, respectively, which, by their current terms, have final payments of principal and interest due on May 1, 2005. The note payable to CIPS was issued in conjunction with the transfer of its electric generating assets and related liabilities to Genco. Genco and CIPS expect to renew or modify the CIPS note to extend the principal maturity, which could include continued amortization of the principal amount. However, such extension could require regulatory approval. Genco and Ameren are currently evaluating various alternatives with respect to the note payable to Ameren. In the event the maturities of these notes are not extended or restructured, Genco may need to access other financing sources to meet the maturity obligation to the extent it does not have cash available from its operating cash flows. Such sources of financing could include borrowings under the non state-regulated subsidiary money pool, or infusion of equity capital or new direct borrowings from Ameren, all subject to applicable regulatory financing authorizations and provisions in Genco's borrowing agreements. CILCORP CILCORP's cash flows from financing activities decreased for the six months ended June 30, 2004, as compared to the same period in 2003. The decrease was primarily due to an increase in repurchases of long-term debt. Borrowings from the non state-regulated subsidiary money pool arrangement that totaled $87 million in 2004 were the primary source of funds for the repurchase of CILCO's $100 million secured bank term loan. Dividends of $18 million in 2004 also contributed to the increase in cash used by financing activities in 2004 compared to 2003. CILCO CILCO's cash flows from financing activities increased for the six months ended June 30, 2004, as compared to the same period in 2003, primarily due to reduced redemptions and repurchases of short-term debt and reduced dividend contributions made to CILCORP in 2004 compared to 2003. CILCO's increase in cash flows from financing activities was offset by reduced borrowings from the utility money pool arrangement in 2004 compared to the same period in 2003. The proceeds received by CILCO from the money pool arrangement along with available cash in the first quarter of 2004 were used to repay CILCO's $100 million bank term loan facility. Short-term Borrowings and Liquidity Short-term borrowings consist of commercial paper issuances and bank line of credit drawings with maturities generally within 1 to 45 days. As of June 30, 2004, Ameren had short-term borrowings totaling $35 million, of which $32 million was borrowed at EEI. The average short-term borrowings at EEI were $10 million for the six months ended June 30, 2004, with a weighted-average interest rate of 1.7%. Peak short-term borrowings for EEI were $44 million for the six months ended June 30, 2004, with a weighted-average interest rate of 1.7%. CIPS, Genco, CILCORP and CILCO had no short-term borrowings as of June 30, 2004 and December 31, 2003. At December 31, 2003, Ameren and 64 UE were the only Ameren Companies that had short-term borrowings outstanding, which totaled $161 million and $150 million, respectively. In July 2004, Ameren entered into two new credit agreements for $700 million in revolving credit facilities to be used for general corporate purposes, including support of Ameren and UE commercial paper programs. The $700 million in new facilities includes a $350 million three-year revolving credit facility and a $350 million five-year revolving credit facility. These new credit facilities replaced Ameren's existing $235 million 364-day revolving credit facility, which matured in July 2004, and a $130 million multi-year revolving credit facility, which would have matured in July 2005. An existing Ameren $235 million multi-year revolving credit facility, which matures in July 2006, remains outstanding and available. At July 31, 2004, certain of the Ameren Companies had committed bank credit facilities that totaled $1.2 billion, all of which were available for use by UE, CIPS, CILCO and Ameren Services through a utility money pool arrangement. In addition, $935 million of the $1.2 billion was available for use by Ameren directly and most of the non rate-regulated affiliates including, but not limited to, Resources Company, Genco, Marketing Company, AFS, AERG and Ameren Energy, through a non state-regulated subsidiary money pool agreement. We have money pool agreements with and among our subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained between rate-regulated and non rate-regulated businesses. See Note 8 - Related Party Transactions to our financial statements under Part I, Item 1 of this report for a detailed explanation of the money pool arrangements. The committed bank credit facilities are used to support our commercial paper programs under which there were no amounts outstanding at June 30, 2004 (December 31, 2003 - $150 million). Access to our credit facilities for any of Ameren's subsidiaries is subject to reduction based on use by affiliates. The following table presents the various committed credit facilities of the Ameren Companies and EEI as of July 31, 2004:

~~See~~=================================================================================================================== ~~Notes~~Credit ~~to Consolidated~~Facility ~~Financial~~Expiration ~~Statements~~Amount Committed Amount Available ------------------------------------------------------------------------------------------------------------------- Ameren:(a) Multi-year revolving............ July 2006 $ 235 $ 235 Multi-year revolving............ July 2007 350 350 Multi-year revolving............ July 2009 350 350 ------------------------------------------------------------------------------------------------------------------- UE: Various 364-day revolving....... through July 2005 154 154 ------------------------------------------------------------------------------------------------------------------- CIPS: Two 364-day revolving............ through July 2005 15 15 ------------------------------------------------------------------------------------------------------------------- CILCO: Three 364-day revolving......... through June 2005 60 60 ------------------------------------------------------------------------------------------------------------------- EEI: Two bank credit facilities...... through June 2005 45 17 ------------------------------------------------------------------------------------------------------------------- Total ........................ $ 1,209 $ 1,181 ===================================================================================================================

(a) CILCORP and Genco may access the credit facilities through intercompany borrowing arrangements. In addition to committed credit facilities, a further source of liquidity for the Ameren Companies is available cash and cash equivalents. Ameren and UE are authorized by the SEC under PUHCA to have up to an aggregate of $1.5 billion and $1 billion, respectively, of short-term unsecured debt instruments outstanding at any time. In addition, CIPS, CILCORP and CILCO each have PUHCA authority to have up to an aggregate of $250 million each of short-term unsecured debt instruments outstanding at any time. Genco is authorized by the FERC to have up to $300 million of short-term debt outstanding at any time. Long-term Debt and Equity The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt for the six months ended June 30, 2004 and 2003. For additional information related to the 65 terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1 of this report.

===================================================================================================================== Six Months Ended June 30, Month Issued, Redeemed, -------------------------- Repurchased or Matured 2004 2003 --------------------------------------------------------------------------------------------------------------------- Issuances Long-term debt UE: 5.50% Senior secured notes due 2014.................. May $ 104 $ - 4.75% Senior secured notes due 2015.................. April - 114 5.50% Senior secured notes due 2034.................. March - 184 --------------------------------------------------------------------------------------------------------------------- Total Ameren long-term debt issuances.................... $ 104 $ 298 --------------------------------------------------------------------------------------------------------------------- Common stock Ameren: 6,325,000 Shares at $40.50........................... January $ - $ 256 19,063,181 Shares at $45.90.......................... February 875 - DRPlus and 401(k)(a)................................. Various 60 52 ---------------------------------------------------------------------------------------------------------------------- Total Ameren common stock issuances...................... $ 935 $ 308 ---------------------------------------------------------------------------------------------------------------------- Total Ameren long-term debt and common stock issuances... $ 1,039 $ 606 ====================================================================================================================== Redemptions, Repurchases and Maturities Long-term debt UE: 7.00% First mortgage bonds due 2024.................. June $ 100 $ - 81/4% First mortgage bonds due 2022.................. April - 104 8.00% First mortgage bonds due 2022.................. May - 85 CIPS: 6.99% Series 97-1 first mortgage bonds due 2003...... March $ - $ 5 6 3/8% Series Z first mortgage bonds due 2003........ April - 40 7 1/2% Series X first mortgage bonds due 2003........ April - 50 CILCORP: 9.375% Senior bonds due 2029......................... May 20 - CILCO: Secured bank term loan............................... February 100 - 6.82% First mortgage bonds due 2003.................. February - 25 8.20% First mortgage bonds due 2022.................. April - 65 7.80% Two series of first mortgage bonds due 2023.... April - 10 EEI: 2000 Bank term loan, 7.61% due 2004.................. June 40 - Medina Valley: Secured term loan due 2019........................... June - 36 ---------------------------------------------------------------------------------------------------------------------- Total Ameren long-term debt redemptions, repurchases and maturities....................... $ 260 $ 420 ======================================================================================================================

(a) Includes issuances of common stock of 1.2 million shares in the first six months of 2004 and 1.3 million shares in the first six months of 2003 under our DRPlus and in connection with our 401(k) plans. Ameren In June 2004, the SEC declared effective a Form S-3 shelf registration statement filed by Ameren covering the offering from time to time of up to $2 billion of various forms of securities including long-term debt, trust preferred securities and equity securities. In July 2004, Ameren issued, pursuant to the June 2004 Form S-3 shelf registration statement, 10.9 million shares of its common stock at $42.00 per share for net proceeds of $445 million. The proceeds from these offerings are expected to provide funds required to pay the cash portion of the purchase price for our pending acquisition of Illinois Power and Dynegy's 20 percent interest in EEI, and to reduce Illinois Power debt, assumed as a part of this transaction, and pay related premiums. Pending such use, and/or if the acquisition is not completed, we plan 66 to use the net proceeds to reduce present or future indebtedness and/or repurchase securities of Ameren or its subsidiaries. A portion of the net proceeds may also be temporarily invested in short-term instruments. See Note 2 - Acquisitions to our financial statements under Part I, Item 1 of this report for further information. In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of six million additional shares of its common stock under DRPlus. Shares of common stock sold under the DRPlus are, at Ameren's option, newly issued shares or treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus. For the six months ended June 30, 2004, Ameren received net proceeds of approximately $60 million from the issuance of approximately 1.2 million new common shares under its DRPlus and its 401(k) plans to be used for general corporate purposes. UE UE issued securities totaling $104 million in 2004, pursuant to the September 2003 Form S-3 shelf registration statement with the amount of securities remaining available for issuance at June 30, 2004, totaling $696 million. Indebtedness Provisions, Other Covenants and Off Balance Sheet Arrangements See Note 4 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1 of this report for a discussion of the indebtedness provisions contained in certain of the Ameren Companies' bank credit facilities. Also see Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1 of this report for a discussion of off-balance sheet arrangements and of the covenants and provisions contained in certain of the Ameren Companies' indenture agreements and Articles of Incorporation. At June 30, 2004, the Ameren Companies and EEI were in compliance with the provisions and covenants of their credit agreements, indentures and Articles of Incorporation. We rely on our short-term and long-term capital markets as a significant source of funding for capital requirements not satisfied by our operating cash flows. Our inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain or grow our businesses. Based on our current credit ratings, we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets such that our cost of capital would increase or our ability to access the capital markets would be adversely affected. All of the Ameren Companies expect to fund maturities of long-term debt and contractual obligations through a combination of cash flow from operations and external financing. Dividends The amount and timing of dividends payable on Ameren's common stock are within the sole discretion of Ameren's Board of Directors. Ameren's Board of Directors has not set specific targets or payout parameters when declaring common stock dividends. However, the Board considers various issues including Ameren's historic earnings and cash flow, projected earnings, cash flow and potential cash flow requirements, dividend payout rates at other utilities, return on investments with similar risk characteristics and overall business considerations. Dividends paid by Ameren to stockholders during the first six months of 2004 totaled $232 million or $1.27 per share (2003 - $205 million or $1.27 per share). UE's Board of Directors' declared quarterly preferred stock dividends totaling $1 million payable August 15, 2004, to shareholders of record on July 20, 2004. CIPS' Board of Directors' declared quarterly preferred stock dividends in the amount of $1 million payable September 30, 2004, to shareholders of record on September 15, 2004. CILCO's Board of Directors' declared quarterly preferred stock dividends totaling $1 million, which was paid on July 1, 2004, to shareholders of record on June 4, 2004. Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, provide restrictions on the Ameren Companies' payment of dividends. Ameren would experience restrictions on dividend payments if it were to defer contract adjustment payments on its equity security units. UE would experience restrictions on dividend payments if it were to extend or defer interest payments on its subordinated 67 debentures. CIPS has provisions restricting dividend payments based on ratios of common stock to total capitalization along with provisions related to certain operating expenses and accumulations of earned surplus. Genco's indenture includes restrictions which prohibit making any dividend payments if debt service coverage ratios are below a defined threshold. CILCORP has restrictions in the event leverage ratio and interest coverage ratio thresholds are not met or if CILCORP's senior long-term debt does not have specified ratings as described in its indenture. CILCO has restrictions on dividend payments relative to the ratio of its balance of retained earnings to the annual dividend requirement on its preferred stock and amounts to be set aside for any sinking fund retirement of its 5.85% Series preferred stock. The following table presents dividends paid directly or indirectly to Ameren by its subsidiaries for the six months ended June 30, 2004 and 2003:

~~CENTRAL~~=================================================================================================================== ~~ILLINOIS~~Six ~~LIGHT~~Months ~~COMPANY~~Ended June 30, ------------------------------------------------------------------------------------------------------------------- 2004 2003 ---- ---- UE.................................................................. $ 145 $ 165 CIPS................................................................ 28 39 Genco............................................................... 35 2 CILCORP (parent company only)(a).................................... - (22) CILCO............................................................... 10 22 Non-registrants..................................................... 14 (1) ------------------------------------------------------------------------------------------------------------------- Dividends paid to Ameren............................................ $ 232 $ 205 ===================================================================================================================

(a) Indicates funds retained from CILCO dividend. Credit Ratings On July 30, 2004, Standard & Poor's Ratings Services affirmed its A- long-term corporate credit ratings on Ameren, UE, CIPS, Genco, CILCORP and CILCO and removed the ratings from CreditWatch with negative implications. The A-2 short-term credit for Ameren and UE were not on CreditWatch. The outlook is negative for the long-term ratings. On July 8, 2004, Moody's confirmed Ameren's A3 senior unsecured debt and bank loan ratings along with its A3 issuer rating. Moody's rating outlook for these ratings was stable. This rating action concluded the review of Ameren's long-term ratings that was initiated on February 4, 2004 in connection with Ameren's agreement to purchase Illinois Power from Dynegy. Ameren's Prime-2 rating for short term debt, including commercial paper, was not under review, and was affirmed. Any adverse change in the Ameren Companies' credit ratings may reduce their access to capital and/or increase the costs of borrowings resulting in a negative impact on earnings. At June 30, 2004, if the Ameren Companies were to receive a sub-investment grade rating (less than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP and CILCO could have been required to post collateral for certain trade obligations amounting to $65 million, $29 million, $1 million, $6 million, $2 million and $2 million, respectively. In addition, the cost of borrowing under our credit facilities would increase or decrease based on credit ratings. A credit rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the assigning rating organization. OUTLOOK We expect the following industry-wide trends and company-specific issues to impact earnings in 2004 and beyond: o Economic conditions, which principally impact native load demand, particularly from our industrial customers, were weak for the past few years, but improved in 2003 and early 2004. o Ameren, UE and CIPS have historically achieved weather-adjusted growth in their native electric residential and commercial load of approximately 2% per year and expect this trend to continue for at least the next few years. o Electric rates in UE's, CIPS' and CILCO's Illinois service territories are legislatively fixed through January 1, 2007. An electric rate case settlement in UE's Missouri service territory has resulted in annual reductions of $50 million, $30 million and $30 million on April 1, 2002, April 1, 2003, and April 1, 2004, respectively. In addition, electric rates in Missouri cannot change prior to July 1, 2006, subject to certain exclusions outlined in UE's rate settlement. 68 o The ICC is currently conducting workshops seeking input from interested parties on the framework for retail rate determination and the framework for generation procurement by customers after the current Illinois rate freeze ends in 2006. We believe the ICC will make a final decision on these matters in 2005. o Power prices in the Midwest impact the amount of revenues UE, Genco and CILCO can generate by marketing any excess power into the interchange markets. Power prices in the Midwest also impact the cost of power we purchase in the interchange markets. There continues to be overcapacity in peaking generation in the Midwest. However, power prices increased in 2004 and 2003 relative to 2002, due in part to higher prices for natural gas. o Increased expenses associated with rising employee benefit costs and higher insurance and security costs associated with additional measures UE has taken, or may have to take, at its Callaway nuclear plant and other operating plants related to world events. o UE's Callaway nuclear plant will have a refueling outage in the fall of 2005. Refueling outages occur approximately every 18 months and typically include the replacement of fuel and the performance of maintenance and inspections. Routine refueling outages have historically lasted 30 - 35 days. If inspections discover items requiring additional maintenance, the outage period could be longer, and cost significantly more, than expected. UE's fall 2005 refueling outage is expected to last 70 - 75 days and is expected to be higher in cost due to the installation of new steam generator units. o In January 2004, the MoPSC approved a settlement with UE authorizing an annual gas delivery rate increase of approximately $13 million, which went into effect on February 15, 2004. The settlement provides that gas delivery rates cannot change prior to July 1, 2006, subject to certain exclusions. In October 2003, the ICC issued orders awarding CILCO an increase in annual gas delivery rates of $9 million and awarding CIPS and UE increases in annual gas delivery rates of $7 million and $2 million, respectively that went into effect in November 2003. o In the second quarter of 2004, UE received a refund of $13 million and CIPS received a refund of $5 million upon entering the Midwest ISO. These refunds were for fees previously paid to exit the Midwest ISO. However, Ameren, UE and CIPS will incur higher ongoing operation costs and may lose some revenue as a result of participating in the Midwest ISO. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for additional information. o Ameren, CILCORP and CILCO expect to realize further CILCORP integration synergies associated with reduced overhead expenses and lower fuel costs. o Ameren expects the acquisition of Illinois Power to be accretive to earnings in the first two years of ownership based on a variety of assumptions related to power prices, interest rates, expected synergies and regulatory outcomes, among other things. While Ameren has contractually fixed the cash outlays for approximately 70% of Illinois Power's energy supple needs, expectations for Illinois Power earnings remain sensitive to changing energy prices for Illinois Power's entire power supply requirements, and other assumptions. In February 2004, Ameren sold 19.1 million shares of new common stock and in July 2004, sold 10.9 million shares of new Ameren common stock. Proceeds from these sales are expected to ultimately be used to finance the cash portion of the purchase price of Illinois Power and Dynegy's 20% interest in EEI and to reduce Illinois Power debt assumed as part of this transaction and pay any related premiums. However, prior to the closing of the acquisition of Illinois Power, Ameren expects the new common shares to be dilutive to earnings per share. In the ordinary course of business, we evaluate strategies to enhance our financial position, results of operations and liquidity. These strategies may include potential acquisitions, divestitures, and opportunities to reduce costs or increase revenues, and other strategic initiatives in order to increase Ameren's shareholder value. We are unable to predict which, if any, of these initiatives will be executed, as well as the impact these initiatives may have on our future financial position, results of operations or liquidity, however the impact could be material. RISK FACTORS Ameren may not be able to complete its acquisition of Illinois Power. If Ameren does not complete the acquisition, dilution to its earnings per share will result unless Ameren is able to otherwise use the proceeds from the common stock it issued in February and July 2004, so as to avoid or mitigate such dilution. On February 2, 2004, Ameren entered into an agreement with Dynegy to purchase the stock of Illinois Power and Dynegy's 20% ownership interest in EEI. The total transaction value is approximately $2.3 billion, including the assumption of approximately $1.8 billion of Illinois Power debt and preferred stock. Ameren's financing plan for this 69 transaction includes the issuance of new Ameren common stock. In February 2004, Ameren issued 19.1 million common shares that generated net proceeds of $853 million, and in July 2004, Ameren issued 10.9 million common shares that generated net proceeds of $445 million. Proceeds from these sales are expected to be used to finance the cash portion of the purchase price, to reduce Illinois Power debt assumed as part of this transaction and to pay any related premiums. Pending such use, and /or if the acquisition is not completed, we plan to use the net proceeds to reduce present or future indebtedness and /or repurchase securities of Ameren or our subsidiaries. The acquisition is subject to various regulatory approvals, including the ICC and the SEC and other customary closing conditions. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for information as to the status of these regulatory proceedings. On April 14, 2004, the FCC consented to the transfer of control; on April 30, 2004, the initial 30 calendar day waiting period expired without a request by the FTC or DOJ for additional information or documents under the Hart-Scott-Rodino Act; and in July 2004, the FERC approved the acquisition of Illinois Power and Dynegy's 20% ownership interest in EEI by Ameren. Although Ameren expects to complete the transaction by the end of 2004, it cannot be certain that all of the required approvals will be obtained, or the other closing conditions will be satisfied, within that time frame, if at all, or without terms and conditions that may have a material adverse effect on our operations. Ameren is also relying on the ability of Dynegy to close the sale of Illinois Power when the required approvals are received. If Ameren is unable to complete the acquisition, the issuance of the common stock in February and July 2004, will result in dilution to Ameren's earnings per share unless it is able to otherwise use the proceeds from the common stock it issued, in a manner that will avoid or mitigate such dilution. If Ameren is able to complete its acquisition of Illinois Power, Ameren may not be able to successfully integrate it into its other businesses or achieve the benefits it anticipates. If Ameren completes the acquisition of Illinois Power, it cannot assure you that it will be able to successfully integrate Illinois Power with its other businesses. The integration of Illinois Power with its other businesses will present significant challenges and, as a result, Ameren may not be able to operate the combined company as effectively as expected. Ameren may also fail to achieve the anticipated benefits of the acquisition as quickly or as cost effectively as anticipated or may not be able to achieve those benefits at all. While Ameren expects that this acquisition will be accretive to earnings per share in the first full year of operation after the transaction is completed, this expectation is based on important assumptions, including assumptions related to expected financing arrangements, interest rates, market prices for power, synergies and regulatory outcomes, which may ultimately be incorrect. As a result, if Ameren is unable to integrate its businesses effectively or achieve the benefits anticipated, our financial position, results of operations and liquidity may be materially adversely affected. The electric and gas rates that certain of the Ameren Companies are allowed to charge in Missouri and Illinois are largely set through 2006. This "rate freeze," along with other actions of regulators, can significantly affect our earnings, liquidity and business activities and are largely outside our control. The rates that certain of the Ameren Companies are allowed to charge for their services are the single most important item influencing the financial position, results of operations and liquidity of the Ameren Companies. We are highly regulated and the regulation of the rates that we charge our customers is determined, in large part, outside of our control by governmental organizations, including the MoPSC, the ICC and the FERC. Ameren, UE, CIPS, Genco and CILCORP are also subject to regulation by the SEC under the PUHCA. Decisions made by these regulators could have a material impact on our financial position, results of operations and liquidity. As a part of the settlement of UE's Missouri electric rate case in 2002, UE is subject to a rate moratorium providing for no changes in its electric rates in Missouri before July 1, 2006, subject to limited statutory and other exceptions. A rate reduction of $30 million went into effect on April 1, 2004, which is the last portion of the $110 million rate reduction included in the stipulation entered into as part of the settlement of the Missouri electric rate case. In addition, as a provision of the Illinois legislation related to the restructuring of the Illinois electric industry, a rate freeze is in effect in Illinois through January 1, 2007. This Illinois legislation also contains a provision requiring that earnings from the Illinois jurisdiction in excess of certain levels be shared equally with UE's, CIPS' and CILCO's Illinois customers through 2006. This Illinois legislation is also applicable to Illinois Power. Furthermore, as part of the settlement of UE's Missouri gas rate case, which was approved by the MoPSC on January 13, 2004, UE agreed to a rate moratorium providing for no changes in its gas delivery rates prior to July 1, 2006, subject to certain exceptions (the increased rates approved as part of the settlement became effective on February 15, 2004). The ICC is currently conducting workshops seeking input from interested parties on the framework for retail rate determination and the framework for generation 70 procurement by customers after the current Illinois rate freeze ends in 2006. We believe the ICC will make a decision on these matters in 2005. As a part of the settlement of UE's Missouri electric rate case in 2002, UE also undertook to use commercially reasonable efforts to make critical energy infrastructure investments of $2.25 billion to $2.75 billion from January 1, 2002 through June 30, 2006, including, among other things, the addition of more than 700 megawatts of new generation capacity (240 megawatts of which was added in 2002) and the replacement of steam generators at UE's Callaway nuclear plant. The amount of energy infrastructure investment through June 2006, described in the settlement is consistent with UE's previously disclosed estimate of construction expenditures UE expects to make over the same time period. However, UE's agreement to a rate moratorium will result in these capital expenditures not becoming recoverable in rates, or earning a return, before July 1, 2006. Therefore, UE's undertakings with respect to making energy infrastructure investments and funding new programs, coupled with the rate reductions and rate moratorium described above, could result in increased financing requirements for UE and thus have a material impact on our liquidity. The Ameren Companies do not have the benefit of a fuel adjustment clause in either Missouri or Illinois for their electric operations that would allow them to recover increased fuel and power costs from customers. Therefore, to the extent that we have not hedged our fuel and power costs, we are exposed to changes in fuel and power prices to the extent fuel for our electric generating facilities and power must be purchased on the open market in order for us to serve our customers. Steps taken and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation. At the federal level, the FERC has been mandating changes in the regulatory framework in which transmission-owning public utilities, such as UE, CIPS and CILCO operate. In Missouri, where a majority of our retail electric revenues are currently derived, restructuring bills have been introduced in the past, but no legislation has been passed. Based on historical information in Illinois Power's Annual Reports on Form 10-K for the year ended December 31, 2003, upon completion of the acquisition of Illinois Power, over 50% of Ameren's electric revenues will be derived in Illinois. The Illinois Customer Choice Law provides for electric utility restructuring and retail direct access. Retail direct access, which allows customers to choose their electric generation supplier, was first offered to Illinois residential customers on May 1, 2002. Although retail direct access in Illinois has not had a negative effect on Ameren's revenues or liquidity, we expect competitive forces in the electric supply segment of our business to continue to increase. The potential negative consequences associated with further electric industry restructuring in our service territories, if it occurs, could be significant and could include the impairment and writedown of certain assets, including generation related plant and net regulatory assets, lower revenues, reduced profit margins and increased costs of capital and operations expenses. Increased federal and state environmental regulation could require UE, Genco and CILCO to incur large capital expenditures and increase operating costs. Approximately 65% of Ameren's generating capacity is coal-fired. The balance is nuclear, gas-fired, hydro and oil-fired. The EPA has recently issued proposed regulations with respect to SO2, NOx and mercury emissions from coal-fired power plants. These new rules, if adopted, would require significant additional reductions in these emissions from our power plants in phases, beginning in 2010. The rules are currently under a public review and comment period, and may change before being issued as final late in 2004 or early 2005. Preliminary estimates of capital costs based on current technology on the Ameren systems to comply with the SO2 and NOx rules, as proposed, range from $400 million to $600 million by 2010, with an additional $500 million to $800 million by 2015. The proposed mercury regulations contain a number of options and the final control requirements are highly uncertain. Ameren anticipates additional capital costs to comply with the mercury rules could range from $300 million to $500 million by 2010, with UE incurring approximately half of the costs and Genco incurring most of the remaining costs. Depending upon the final mercury rules, additional amounts could be required to comply with mercury rules by 2018. In addition, Illinois has developed a NOx control regulation for utility generating plant boilers consistent with an EPA program aimed at reducing ozone levels in the eastern United States. In February 2002, the EPA proposed similar rules for Missouri. Ameren currently estimates that the remaining capital expenditures could range from $210 million to 71 $250 million between 2004 and 2008 in order to comply with the final NOx regulations in Missouri and Illinois. This estimate includes the assumption that these rules will require the installation of selective catalytic reduction technology on some units, as well as additional controls. We are unable to predict the ultimate effect of any new environmental regulations, guidelines, enforcement initiatives or legislation on our financial position, results of operations or liquidity. Any of these factors would add significant pollution control costs to UE's, Genco's and CILCO's generating assets and therefore, could also increase financing requirements for some of the Ameren Companies. While costs incurred by UE would be eligible for recovery in rates, subject to MoPSC or ICC approval, as applicable, there is no similar mechanism for recovery of costs by Genco or CILCO in Illinois. UE's and CIPS' participation in a RTO could increase costs, reduce revenues and reduce UE's and CIPS' control over their transmission assets. In December 1999, the FERC issued Order 2000 requiring all utilities subject to FERC jurisdiction to state their intentions for joining a RTO. The MoPSC issued an order in early 2004 authorizing UE to participate in the Midwest ISO for a five year period, with participation after that period subject to further approvals by the MoPSC. Subsequently, the FERC issued a final order allowing UE's and CIPS' participation in the Midwest ISO. Under these orders, the MoPSC continues to set the transmission component of UE's rates to serve its bundled retail load. CILCO is already a member of the Midwest ISO and previously transferred functional control of its transmission system to the Midwest ISO. On May 1, 2004, functional control of the UE and CIPS transmission systems was transferred to the Midwest ISO through GridAmerica LLC, or Grid America. The participation by UE and CIPS in the Midwest ISO is expected to increase annual costs by $10 million to $20 million in the aggregate and could result in a decrease in annual revenues of between $5 million and $10 million in the aggregate. UE and CIPS may also be required to expand their transmission systems according to decisions made by a RTO rather than their internal planning process. In addition, we are unable to determine the full impact of the Energy Markets Tariff tendered by the Midwest ISO for filing at the FERC in March 2004 (discussed in Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report) until further information is available regarding the implementation of the Energy Markets Tariff. Until UE and CIPS achieve some degree of operational experience participating in the Midwest ISO through GridAmerica, we are unable to predict the ultimate impact that such participation or ongoing RTO developments at the FERC or other regulatory authorities will have on our financial position, results of operations or liquidity. The inability of UE and CIPS to recover "through and out" transmission revenues could result in a material net revenue reduction. Through orders issued during late 2003 and early 2004, the FERC had ordered the elimination of regional through-and-out rates assessed by the Midwest ISO that involved transmission service between the Midwest ISO and PJM regions to be effective May 1, 2004. However, on March 19, 2004, the FERC accepted an agreement among affected transmission owners that retains the regional through-and-out rates until December 1, 2004, and provides for continued negotiations aimed at developing a long-term transmission pricing structure to eliminate seams between the PJM and Midwest ISO regions based on specified pricing principles. Until the long-term transmission pricing structure has been established, UE and CIPS cannot predict the ultimate impact that such structure will have on their costs and revenues. The substance and implementation of standard market design rules by the FERC is uncertain and may adversely affect the way in which UE, CIPS and CILCO operate their transmission assets. On July 31, 2002, the FERC issued its standard market design NOPR. The NOPR proposes a number of changes to the way the current wholesale transmission service and energy markets are operated. Specifically, the NOPR proposes that all jurisdictional transmission facilities be placed under the control of an independent transmission provider (similar to a RTO), proposes a new transmission service tariff that provides a single form of transmission service for all users of the transmission system including bundled retail load, and proposes a new energy market and congestion management system that uses locational marginal pricing as its basis. In our initial comments on the NOPR, which were filed at the FERC on November 15, 2002, we expressed our concern with the potential impact of the proposed rules in their current form on the cost and reliability of service to retail customers. We also proposed that certain modifications be made to 72 the proposed rules in order to protect transmission owners from the possibility of trapped transmission costs that might not be recoverable from ratepayers as a result of inconsistent regulatory policies. We filed additional comments on the remaining sections of the NOPR during the first quarter of 2003. In April 2003, the FERC issued a "white paper" reflecting comments received in response to the NOPR. More specifically, the white paper indicated that the FERC will not assert jurisdiction over the transmission rate component of bundled retail service and will insure that existing bundled retail customers retain their existing transmission rights and retain rights for future load growth in its final rule. Moreover, the white paper acknowledged that the final rule will provide the states with input on resource adequacy requirements, allocation of firm transmission rights, and transmission planning. The FERC also requested input on the flexibility and timing of the final rule's implementation. Although issuance of the final rule is uncertain and its implementation schedule is still unknown, the Midwest ISO was in the process of implementing a separate market design similar to the proposed market design in the NOPR. In July 2003, the Midwest ISO filed with the FERC a revised OATT codifying the terms and conditions under which it will implement the new market design. Thereafter, on October 17, 2003, the Midwest ISO filed a motion to withdraw its revised OATT. On October 29, 2003, the FERC issued a series of orders granting the motion for withdrawal of the revised OATT and providing guidance to be followed by the Midwest ISO in developing a new energy market design in the future. In March 2004, the Midwest ISO tendered for filing at the FERC a proposed Energy Markets Tariff, which is intended to supercede its existing OATT (see Note 3 - Rate and Regulatory Matters to our financial statements under Item I, Part 1 of this report). Until the FERC issues a final rule and the Midwest ISO finalizes its new market design, we are unable to predict the ultimate impact of the NOPR or the Midwest ISO new market design on our future financial position, results of operations or liquidity. The market-based rate authority currently held by UE, Genco, CILCO, AERG, Development Company, Marketing Company and Medina Valley could be partially revoked as a result of FERC's new market power analysis screen order. In an order issued in April 2004, the FERC replaced the Supply Margin Assessment Screen previously used to review applications by sellers of electricity at wholesale for authorization to sell power at market-based rates with two alternative measures of market power: (a) an uncommitted pivotal supplier analysis and (b) an uncommitted market share analysis which is to be prepared on a seasonal basis. If an applicant passes both screens, a rebuttable presumption will exist that it lacks generation market power. If the applicant fails either screen, a rebuttable presumption will exist that it has market power. Under such circumstances, the applicant may either seek to rebut the presumption by preparing a delivered price test (identifying the amount of economic capacity from neighboring areas that can be delivered to the control area) or propose mitigation measures. Unless some other mitigation measure is adopted, the applicant's authority to sell power at market-based rates in areas in which it has market power will be revoked, and the applicant will be required to sell at cost-based rates in those areas. UE, Genco, CILCO, AERG, Development Company, Marketing Company and Medina Valley currently have authorization from the FERC to continue to sell power at market-based rates. However, the FERC indicated in its April order that it would apply the new market analysis screens to pending and future market-based rate applications, including three-year market-based rate reviews. All of the aforementioned Ameren entities currently have three-year market-based rate reviews pending at the FERC. Until Ameren has evaluated the impact of the FERC's order with respect to the Ameren system, we are unable to predict the ultimate impact that the new market power analysis screens will have on Ameren's ability to sell power at market-based rates. Increasing costs associated with our defined benefit retirement plans, healthcare plans and other employee related benefits may adversely affect our results of operations, liquidity and financial position. The Ameren Companies made cash contributions totaling $25 million and $31 million to defined benefit retirement plans during 2003 and 2002, respectively. In addition, a minimum pension liability was recorded at December 31, 2002, which resulted in an after-tax charge to OCI and a reduction in stockholders' equity for Ameren of $102 million. At December 31, 2003, the minimum pension liability was reduced, resulting in OCI of $46 million and an increase in stockholders' equity. The Ameren Companies expect to be required under the ERISA to fund an average of approximately $115 million annually from 2005 through 2008, in order to maintain minimum funding levels for our pension plans. These amounts are estimates and may change based on actual stock market performance, changes in 73 interest rates, and any pertinent changes in government regulations, each of which could also result in a requirement to record an additional minimum pension liability. Furthermore, if Ameren completes its acquisition of Illinois Power, we could incur material funding requirements with respect to Illinois Power's existing defined benefit retirement plans. In addition to the costs of our retirement plans, the costs to us of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plans, healthcare plans and other employee benefits may adversely affect our results of operations, liquidity or financial position. UE's, Genco's and CILCO's electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased power purchase costs. UE, CILCO, Genco, AERG, Medina Valley and EEI own and operate coal, nuclear, gas-fired, hydro and oil-fired generating facilities constituting approximately 14,600 megawatts (net) of installed capability. Operation of electric generating facilities involves certain risks which can adversely affect energy output and efficiency levels. Included among these risks are: o increased prices for fuel and fuel transportation as existing contracts expire, o facility shutdowns due to a breakdown or failure of equipment or processes, o longer than anticipated maintenance outages, o disruptions in the delivery of fuel and lack of adequate inventories, o labor disputes, o inability to comply with regulatory or permit requirements, o disruptions in the delivery of electricity, o increased capital expenditures requirements, including those due to environmental regulation, o operator error, and o unusual or adverse weather conditions, including catastrophic events such as fires, explosions, floods or other similar occurrences affecting electric generating facilities. A substantial portion of Genco's and AERG's generating capacity is committed under affiliate contracts which expire over the next several years. Genco and AERG have several electric power supply agreements under which Genco and AERG directly or indirectly supply the full requirements of UE, CIPS and CILCO, including the following: o Under two electric power supply agreements, Genco is obligated to supply to Marketing Company, and Marketing Company, in turn, is obligated to supply to CIPS, all of the energy and capacity needed by CIPS to offer service for resale to its native load customers and to fulfill CIPS' other obligations under all applicable federal and state tariffs or contracts. Any power not used by CIPS is sold by Marketing Company under various long-term wholesale and retail contracts. The agreement between CIPS and Marketing Company was originally set to expire on December 31, 2004. The agreement between Genco and Marketing Company can be terminated by either party upon at least one year's notice, but may not be terminated prior to December 31, 2004. CIPS and Marketing Company filed in July 2004, a request with the FERC to extend their agreement through December 31, 2006. This extension was required by the ICC in its order approving Ameren's acquisition of CILCORP. o AERG has an electric power supply agreement with CILCO to supply it sufficient power to meet its native load requirements. This agreement was originally set to expire on December 31, 2004. AERG and CILCO have agreed to extend the power supply agreement through December 31, 2006. Unlike the CIPS-Marketing Company agreement, the provisions of the agreement between CILCO and AERG allow the parties to extend the term of the agreement, and Ameren believes that no further FERC action is necessary for such an extension to become effective. The ICC required this extension in its order approving Ameren's acquisition of CILCORP. Midwest power markets have experienced high levels of new capacity development over the last several years, which, in part, have contributed to soft long-term power prices in this region. Owners of generating capacity in the 74 Midwest are actively seeking markets for their energy and capacity and have asked our regulators to closely scrutinize power supply arrangements among our subsidiaries when we have sought approval to enter into them. It cannot be predicted whether obtaining extensions on other long-term replacement power sale contracts for the energy and capacity currently committed under these agreements when they expire will be successful. To the extent Genco or AERG cannot secure extensions or other long-term replacement power sale contracts for the energy and capacity currently committed under these agreements, our generating subsidiaries and Marketing Company will face competition from other power suppliers in the Midwest and will be exposed to price risk. Genco participates with UE in an agreement to jointly dispatch its generating facilities with those of UE, which thereby produces benefits and efficiencies for both generating parties. Pending or future federal and state regulatory proceedings and policies may evolve in ways that could impact Genco's ability to continue to participate in these affiliate transactions on current terms. For example, as a result of the pending MoPSC proceeding relating to the transfer of UE's Illinois-based utility business, there is uncertainty as to the terms of the joint dispatch agreement and also as to its duration. The termination of the agreement, or modifications to it, could have a material adverse effect on UE or Genco. Genco's and CILCO's electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risk. As owners of non rate-regulated electric generating facilities, Genco (4,800 megawatts) and AERG (1,100 megawatts) will not have any recovery of their costs or any specified rate of return set by a regulatory body. Of these non rate-regulated electric generating facilities, approximately 3,500 megawatts are currently under full requirements contracts with our affiliates, including the contracts referred to in the immediately preceding risk factor. The remainder of the generating capacity must compete for the sale of energy and capacity. UE is currently seeking regulatory approval of the transfer by Genco to it of approximately 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois, which transfer is expected to occur in 2004, with the result that those CTs will no longer be non rate-regulated. To the extent electric capacity generated by these facilities is not under contract to be sold, either now or in the future, the revenues and results of operations of these non rate-regulated subsidiaries will generally depend on the prices that they can obtain for energy and capacity in Illinois and adjacent markets. Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are: o the current and future market prices for natural gas, fuel oil and coal, o current and forward prices for the sale of electricity, o the extent of additional supplies of electric energy from current competitors or new market entrants, o the pace of deregulation in our market area and the slowing expansion of deregulated markets, o the regulatory and pricing structures developed for Midwest energy markets as they continue to evolve and the pace of development of regional markets for energy and capacity outside of bilateral contracts, o future pricing for, and availability of, transmission services on transmission systems, the effect of RTOs, development and export energy transmission constraints, which could limit the ability to sell energy in markets adjacent to Illinois, o the rate of growth in electricity usage as a result of population changes, regional economic conditions and the implementation of conservation programs, and o climate conditions prevailing in the Midwest market from time to time. UE's ownership and operation of a nuclear generating facility creates business, financial and waste disposal risks. UE owns the Callaway nuclear plant, which represents approximately 14% of UE's generation capability. Therefore, UE is subject to the risks of nuclear generation, which include the following: o the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials, o limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with UE's nuclear operations or those of others in the United States, o uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate, 75 o increased public and governmental concerns over the adequacy of security at nuclear power plants, and o uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives (UE's facility operating license for the Callaway nuclear plant expires in 2024), and o costly and extended outages from scheduled or unscheduled maintenance. The NRC has broad authority under federal law to impose licensing and safety related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as UE's. In addition, although UE has no reason to anticipate a serious nuclear incident at its plant, if an incident did occur, it could harm UE's results of operations or financial position. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Operating performance at UE's Callaway nuclear plant has recently resulted in unscheduled plant outages and the extension of Callaway's scheduled refueling and maintenance outage in 2004. In addition, Ameren and UE have incurred significant unanticipated replacement power and maintenance costs. As a result, the operating performance at UE's Callaway nuclear plant has declined as compared to its past operating performance and the operating performance of other nuclear plants in the United States. Ameren and UE are actively working to address factors leading to the decline in Callaway's operating performance, including management and supervision of operating personnel, equipment reliability, maintenance worker practices, engineering performance and overall organizational effectiveness. However, Ameren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Efforts taken are expected to result in incremental operating costs at Callaway. Further, additional unscheduled or extended outages at Callaway could have a material effect on the financial position, results of operations and cash flows of Ameren and UE. Our energy risk management strategies may not be effective in managing fuel and electricity pricing risks, which could result in unanticipated liabilities to us or increased volatility of our earnings. We are exposed to changes in market prices for natural gas, fuel, electricity and emission credits. Prices for natural gas, fuel, electricity and emission credits may fluctuate substantially over relatively short periods of time and expose us to commodity price risk. We utilize derivatives such as forward contracts, futures contracts, options and swaps to manage these risks. We attempt to manage our exposure from these activities through enforcement of established risk limits and risk management procedures. We cannot assure you that these strategies will be successful in managing our pricing risk, or that they will not result in net liabilities to us as a result of future volatility in these markets. In addition, although we routinely enter into contracts to offset our positions (i.e., to hedge our exposure to the risks of demand, market effects of weather and changes in commodity prices), we do not always hedge the entire exposure of our operations from commodity price volatility. Furthermore, our ability to hedge our exposure to commodity price volatility depends on liquid commodity markets. As a result, to the extent the commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater open positions than we would prefer at a given time. To the extent that open positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position. Our businesses are dependent on our ability to successfully access the capital markets. We may not have access to sufficient capital in the amounts and at the times needed. We rely on access to short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied by our operating cash flows. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain and grow our businesses. Based on our current credit ratings, we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets such that our cost of capital would increase or our ability to access the capital markets would be adversely affected. 76 REGULATORY MATTERS See Note 2 - Acquisitions, Note 3 - Rate and Regulatory Matters and Note 8 - Related Party Transactions to our financial statements under Part I, Item 1 of this report. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Market risk represents the risk of changes in value of a physical contract or a financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates. The following discussion of our risk management activities includes "forward-looking" statements that involve risks and uncertainties. Actual results could differ materially from those projected in the "forward-looking" statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal and operational risks and are not represented in the following discussion. Our risk management objective is to optimize our physical generating assets within prudent risk parameters. Our risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers. Interest Rate Risk We are exposed to market risk through changes in interest rates associated with: o long-term and short-term variable-rate debt; o fixed-rate debt; o commercial paper; o auction-rate long-term debt; and o auction-rate preferred stock. We manage our interest rate exposure by controlling the amount of these instruments we hold within our total capitalization portfolio and by monitoring the effects of market changes in interest rates. The following table presents the estimated increase (decrease) in our annual interest expense and net income if interest rates were to change by 1% on variable rate debt outstanding at June 30, 2004:

~~Consolidated Balance~~=================================================================================================================== ~~Sheets~~Interest Expense Net Income(a) ------------------------------------------------------------------------------------------------------------------- Ameren(b)........................................................... $ 5 $ (3) UE.................................................................. 8 (5) CIPS................................................................ - - Genco............................................................... 2 (1) CILCORP(c).......................................................... 3 (2) CILCO............................................................... 2 (1) ===================================================================================================================

(a) Calculations are based on an effective tax rate of 36%. (b) Includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (c) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. The model does not consider the effects of the reduced level of potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no change in our financial structure. 77 Credit Risk Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. On all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables, executory contracts with market risk exposures and leveraged lease investments. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups comprising our customer base. No non-affiliated customer represents greater than 10%, in the aggregate, of our accounts receivable. Ameren's revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. UE and Genco have credit exposure associated with accounts receivables from nonaffiliated companies for interchange sales. At June 30, 2004, UE's, Genco's and Marketing Company's combined credit exposure to non-investment grade counterparties related to interchange sales was $2 million, net of collateral. We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program, which involves daily exposure reporting to senior management, master trading and netting agreements, and credit support such as letters of credit and parental guarantees. We also analyze each counterparty's financial condition prior to entering into sales, forwards, swaps, futures or option contracts and monitor counterparty exposure associated with our leveraged leases. Equity Price Risk Our costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rate of return on plan assets, discount rate, the rate of increase in healthcare costs and contributions made to the plans. The market value of our plan assets was affected by declines in the equity market for 2000 through 2002 for the pension and postretirement plans. As a result, a minimum pension liability was recorded at December 31, 2002, which resulted in a charge to OCI and a reduction in stockholders' equity. At December 31, 2003, the minimum pension liability was reduced resulting in OCI of $46 million and an increase in stockholders' equity. The minimum pension liability has not changed as of June 30, 2004. The amount of the pension liability as of June 30, 2004, was the result of asset returns, interest rates and our contributions to the plans during 2003. In future years, the liability recorded, the costs reflected in net income or OCI, or cash contributions to the plans could increase materially without a recovery in equity markets in excess of our assumed return on plan assets of 8.5%. If the fair value of the plan assets were to grow and exceed the accumulated benefit obligations in the future, the recorded liability would then be reduced and a corresponding amount of equity would be restored, net of taxes. Commodity Price Risk The Ameren Companies are exposed to changes in market prices for natural gas, fuel and electricity to the extent they cannot be recovered through rates. For a more detailed discussion of our commodity price risk, see Commodity Price Risk under Part II, Item 7A of the Ameren Companies' combined Form 10-K for the fiscal year ended December 31, 2003. Below are tables presenting the percentage of fuel that is price-hedged and the effects a material change in price will have on our coal costs not currently covered under fixed-price contracts as of June 30, 2004. The following table presents the percentages of the required supply of coal for our coal-fired power plants, nuclear fuel and natural gas for our CTs and distribution, as appropriate, which are price-hedged for the remainder of 2004 through 2008:

~~(In~~=================================================================================================================== ~~thousands)~~2004 2005 2006 - 2008 ------------------------------------------------------------------------------------------------------------------- Ameren: Coal..................................................... 100% 92% 60% Nuclear fuel............................................. 100 100 32 Natural gas for generation............................... 27 16 4 Natural gas for distribution............................. 43 17 5 -------------------------------------------------------------------------------------------------------------------

	September 30, 2002		December 31, 2001
	(Unaudited)
ASSETS
Utility Plant, At Original Cost:
Electric	$	1,338,112	$	1,326,231
Gas	464,137		457,165
	1,802,249		1,783,396
Less-Accumulated Provision for Depreciation	1,028,012		985,045
	774,237		798,351
Construction Work in Progress	102,288		34,340
Total Utility Plant	876,525		832,691
Other Property and Investments:
Cash Surrender Value of Company-owned Life Insurance (Net of Related Policy Loans of $69,523 and $65,314)	3,442		3,920
Other	1,050		1,133
Total Other Property and Investments	4,492		5,053
Current Assets:
Cash and Temporary Cash Investments	40,348		12,584
Receivables, Less Allowance for Uncollectible Accounts of $2,067 and $1,800	57,477		49,375
Accrued Unbilled Revenue	22,291		34,067
Fuel, at Average Cost	13,896		18,068
Materials and Supplies, at Average Cost	16,752		15,849
Gas in Underground Storage, at Average Cost	27,128		27,067
Prepaid Taxes	9,583		9,007
FAC Underrecoveries	1,255		1,255
PGA Underrecoveries	2,379		3,236
Other	15,605		20,475
Total Current Assets	206,714		190,983
Deferred Debits:
Unamortized Loss on Reacquired Debt	2,266		2,448
Unamortized Debt Expense	1,668		1,305
Intangible Pension Asset	168		168
Other	10,934		9,065
Total Deferred Debits	15,036		12,986
Total Assets	$	1,102,767	$	1,041,713

(a) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. The following table presents the estimated increase (decrease) in our total fuel expense and net income if coal costs were to change by 1% on any requirements currently not covered by fixed-price contracts for the remainder of 2004 through 2008:

~~See~~=================================================================================================================== ~~Notes~~Fuel ~~to Consolidated~~Expense ~~Financial~~Net ~~Statements~~Income(a) ------------------------------------------------------------------------------------------------------------------- Ameren(b).................................................................. $ 6 $ 3 UE......................................................................... 3 2 CIPS....................................................................... - - Genco...................................................................... 1 1 CILCORP(c)................................................................. 1 - CILCO...................................................................... 1 - ===================================================================================================================

(a) Calculations are based on an effective tax rate of 36%. (b) Includes amounts for non-registrant Ameren subsidiaries. (c) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. Fair Value of Contracts Most of our commodity contracts qualify for treatment as normal purchases and normal sales. However, we utilize derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. Price fluctuations in natural gas, fuel and electricity cause: o an unrealized appreciation or depreciation of our firm commitments to purchase or sell when purchase or sales prices under the firm commitment are compared with current commodity prices; o market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities in inventory under firm commitment; and o actual cash outlays for the purchase of these commodities to differ from anticipated cash outlays. The derivatives that we use to hedge these risks are dictated by risk management policies and include forward contracts, futures contracts, options and swaps. We continually assess our supply and delivery commitment positions against forward market prices and internally-forecasted forward prices and modify our exposure to market, credit and operational risk by entering into various offsetting transactions. In general, we believe these transactions serve to reduce our price risk. See Note 7 - Derivative Financial Instruments to our financial statements under Part I, Item 1 of this report for further information. 79 The following table presents the favorable (unfavorable) changes in the fair value of all contracts marked-to-market during the three months and six months ended June 30, 2004:

8=================================================================================================================== Ameren(a) UE CIPS CILCORP(b) CILCO ------------------------------------------------------------------------------------------------------------------- Three Months Fair value of contracts at beginning of period, net..... $ 18 $ (2) $ 4 $ 11 $ 11 Contracts realized or otherwise settled during the period............................................ - - - - - Changes in fair values attributable to changes in valuation technique and assumptions - - - - - Fair value of new contracts entered into during the period............................................ - - - - - Other changes in fair value........................... 6 - 2 1 1 ------------------------------------------------------------------------------------------------------------------- Fair value of contracts outstanding at end of period, net.................................... $ 24 $ (2) $ 6 $ 12 $ 12 =================================================================================================================== Six Months Fair value of contracts at beginning of period, net..... $ 12 $ (1) $ 1 $ 6 $ 6 Contracts realized or otherwise settled during the period............................................ (4) 1 (1) (3) (3) Changes in fair values attributable to changes in valuation technique and assumptions - - - - - Fair value of new contracts entered into during the period............................................ - - - - - Other changes in fair value........................... 16 (2) 6 9 9 ------------------------------------------------------------------------------------------------------------------- Fair value of contracts outstanding at end of period, net.................................... $ 24 $ (2) $ 6 $ 12 $ 12 ===================================================================================================================

(a) Includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

	September 30, 2002			December 31, 2001
	(Unaudited)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common Stockholder’s Equity:
Common Stock, No Par Value; Authorized 20,000,000 Shares; Outstanding 13,563,871 Shares	$	185,661		$	185,661
Additional Paid-in Capital	52,000			52,000
Retained Earnings	125,400			108,045
Accumulated Other Comprehensive Loss	(175		)	(5,805		)
Total Common Stockholder’s Equity	362,886			339,901
Preferred Stock Without Mandatory Redemption	19,120			19,120
Preferred Stock With Mandatory Redemption	22,000			22,000
Long-term Debt	316,017			242,730
Total Capitalization	720,023			623,751
Current Liabilities:
Current Maturities of Long-Term Debt	26,750			1,400
Notes Payable	—			43,000
Accounts Payable	55,828			81,140
Accrued Taxes	42,805			28,862
Accrued Interest	5,177			9,143
Other	5,191			18,281
Total Current Liabilities	135,751			181,826
Deferred Liabilities and Credits:
Accumulated Deferred Income Taxes	103,396			92,428
Regulatory Liability	34,418			45,377
Investment Tax Credits	13,357			14,553
Other	95,822			83,778
Total Deferred Liabilities and Credits	246,993			236,136
Total Capitalization and Liabilities	$	1,102,767		$	1,041,713

~~See~~------------------------------------------------------------------------------------------------------------------- ~~Notes~~Sources ~~to Consolidated~~Maturity ~~Financial~~Maturity ~~Statements~~Maturity Maturity in Total of Less than 1-3 4-5 Excess of Fair Fair Value 1 Year Years Years 5 Years Value(a) ------------------------------------------------------------------------------------------------------------------- CILCORP:(d) Prices actively quoted .............. $ 8 $ 4 $ - $ - $ 12 Prices provided by other external sources(b)........................ - - - - - Prices based on models and other valuation methods(c).............. - - - - - ------------------------------------------------------------------------------------------------------------------- Total ............................... $ 8 $ 4 $ - $ - $ 12 =================================================================================================================== CILCO: Prices actively quoted .............. $ 8 $ 4 $ - $ - $ 12 Prices provided by other external sources(b)........................ - - - - - Prices based on models and other valuation methods(c).............. - - - - - ------------------------------------------------------------------------------------------------------------------- Total ............................... $ 8 $ 4 $ - $ - $ 12 ===================================================================================================================

(a) Contracts of less than $8 million were with non-investment-grade rated counterparties. (b) Principally power forwards based on a published survey of settled forward pricing and natural gas swap valuations based on NYMEX prices for over-the-counter contracts. (c) Principally coal and SO2 option values based on a Black-Scholes model that includes information from external sources and our estimates. Also includes power forward contract values based on our estimates. (d) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. ITEM 4. Controls and Procedures. (a) Evaluation of Disclosure Controls and Procedures As of June 30, 2004, the principal executive officer and principal financial officer of each registrant have evaluated the effectiveness of the design and operation of such registrant's disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act). Based upon that evaluation, the principal executive officer and principal financial officer of each such registrant have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to such registrant, which is required to be included in such registrant's reports filed or submitted with the SEC under the Exchange Act. (b) Change in Internal Controls There has been no change in the registrants' internal control over financial reporting that occurred during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting. PART II. OTHER INFORMATION ITEM 1. Legal Proceedings. Note 2 - Acquisitions, Note 3 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1 of this report contain information on legal and administrative proceedings which are incorporated by reference under this item. 81 ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES. Ameren Corporation's purchases of equity securities reportable under Item 703 of Regulation S-K:

9====================================================================================================================== (a)Total (b)Average (c)Total Number of (d)Maximum Number (or Number of Price Shares (or Units) Approximate Dollar Value) of Shares Paid per Purchased as Part of Shares (or Units) that May (or Units) Share Publicly Announced Plans Yet Be Purchased Under the Period Purchased(a) (or Unit) or Programs Plans or Programs ---------------------------------------------------------------------------------------------------------------------- April 1 - April 30, 2004........ 1,000 $ 44.21 - - May 1 - May 31, 2004.......... 61,382 43.43 - - June 1 - June 30, 2004......... 950 44.14 - - ---------------------------------------------------------------------------------------------------------------------- Total 63,332 $ 43.45 - - ----------------------------------------------------------------------------------------------------------------------

(a) These shares of Ameren common stock were purchased by Ameren in open-market transactions in satisfaction of Ameren's obligations upon the exercise by employees of options issued under Ameren's Long-term Incentive Plan of 1998. Ameren does not have any publicly announced equity securities repurchase plans or programs. None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the April 1 to June 30, 2004, period. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Ameren At Ameren's annual meeting of shareholders held on April 27, 2004, the following matters were presented to the meeting for a vote and the results of such voting are as follows: Item (1) Election of 12 directors (comprising Ameren's full Board of Directors) to serve until the next annual meeting of shareholders in 2005.

~~CENTRAL~~=================================================================================================================== ~~ILLINOIS~~Name ~~LIGHT~~For ~~COMPANY~~Withheld Non-Voted Brokers(a) ------------------------------------------------------------------------------------------------------------------- Susan S. Elliott 151,719,167 3,971,806 0 Clifford L. Greenwalt 151,468,735 4,222,238 0 Thomas A. Hays 151,678,396 4,012,577 0 Richard A. Liddy 150,385,122 5,305,851 0 Gordon R. Lohman 151,764,063 3,926,910 0 Richard A. Lumpkin 150,526,942 5,164,031 0 John Peters MacCarthy 147,760,462 7,930,511 0 Paul L. Miller, Jr. 150,616,064 5,074,909 0 Charles W. Mueller 151,794,798 3,896,175 0 Douglas R. Oberhelman 141,796,966 13,894,007 0 Gary L. Rainwater 151,353,286 4,337,686 0 Harvey Saligman 150,480,134 5,210,839 0 ===================================================================================================================

(a) Broker shares included in the quorum but not voting on the item. Item (2) Ratification of PricewaterhouseCoopers LLP as Ameren's independent registered public accounting firm for the fiscal year ending December 31, 2004. =================================================================================================================== For Against Abstain Non-Voted Brokers(a) ------------------------------------------------------------------------------------------------------------------- 151,263,408 2,667,991 1,758,182 18,926,816 ===================================================================================================================

(a) Broker shares included in the quorum but not voting on the item. 82 Item (3) Shareholder proposal relating to the storage of irradiated fuel rods at UE's Callaway nuclear plant. =================================================================================================================== For Against Abstain Non-Voted Brokers(a) ------------------------------------------------------------------------------------------------------------------- 10,155,207 101,417,459 9,541,877 53,501,853 ===================================================================================================================

(a) Broker shares included in the quorum but not voting on the item. UE At UE's annual meeting of shareholders held on April 27, 2004, the following matter was presented to the meeting for a vote and the results of such voting are as follows: Item (1) Election of six directors (comprising UE's full Board of Directors) to serve until the next annual meeting ofshareholders in 2005.

~~Consolidated~~=================================================================================================================== ~~Statements~~Name ofFor ~~Cash~~Withheld ~~Flows~~Non-Voted Brokers(a) ------------------------------------------------------------------------------------------------------------------- Warner L. Baxter 102,557,609 10,061 0 Gary L. Rainwater 102,557,609 10,061 0 Gary L. Randolph 102,557,009 10,061 0 Steven R. Sullivan 102,557,609 10,061 0 Thomas R. Voss 102,557,509 10,161 0 David A. Whiteley 102,557,009 10,061 0 ===================================================================================================================

(a) Broker shares included in the quorum but not voting on the item. CIPS At CIPS' annual meeting of shareholders held on April 27, 2004, the following matter was presented to the meeting for a vote and the results of such voting are as follows: Item (1) Election of six directors (comprising CIPS' full Board of Directors) to serve until the next annual meeting of shareholders in 2005.

~~(In~~=================================================================================================================== ~~thousands~~Name For Withheld Non-Voted Brokers(a) ------------------------------------------------------------------------------------------------------------------- Warner L. Baxter 25,813,624 31,963 0 Daniel F. Cole 25,813,619 31,968 0 Gary L. Rainwater 25,813,614 31,973 0 Steven R. Sullivan 25,813,619 31,968 0 Thomas R. Voss 25,813,616 31,971 0 David A. Whiteley 25,813,624 31,963 0 ===================================================================================================================

(a) Broker shares included in the quorum but not voting on the item. CILCO At CILCO's annual meeting of shareholders held on April 27, 2004, the following matter was presented to the meeting for a vote and the results of such voting are as follows: Item (1) Election of six directors (comprising CILCO's full Board of Directors) to serve until the next annual meeting of shareholders in 2005.

=================================================================================================================== Name For Withheld Non-Voted Brokers(~~Unaudited~~a) ------------------------------------------------------------------------------------------------------------------- Warner L. Baxter 13,794,566 1,243 0 Scott A. Cisel 13,794,566 1,243 0 Daniel F. Cole 13,794,566 1,243 0 Gary L. Rainwater 13,794,566 1,243 0 Steven R. Sullivan 13,794,566 1,243 0 Thomas R. Voss 13,794,566 1,243 0 ===================================================================================================================

(a) Broker shares included in the quorum but not voting on the item. 83 GENCO and CILCORP The information called for by this item is omitted in reliance on General Instruction H(1)(a) and (b) of Form 10-Q. ITEM 5. OTHER INFORMATION. Reference is made to Item 2. Properties under Part I of the Ameren Companies' combined Form 10-K for the fiscal year ended December 31, 2003 for a discussion of UE's, CIPS' and CILCO's written notice to MAIN of their intent to withdraw from that organization effective January 1, 2005. MAIN is a regional electric reliability council organized for coordinating the planning and operation of bulk power supply in the central United States. In July 2004, UE, CIPS and CILCO further notified MAIN that they agree to delay their withdrawal to January 1, 2006 provided the configuration of MAIN remains the same. The right to withdraw effective January 1, 2005, was reserved in the event that certain utilities elect not to remain as regular MAIN members after December 31, 2004. UE, CIPS and CILCO intend to join another RRO prior to their withdrawal from MAIN. UE, CIPS and CILCO may withdraw their notice of intent to withdraw from MAIN at any time. ITEM 6. Exhibits and Reports on Form 8-K. (a) Exhibits. The documents listed below are being filed on behalf of Ameren, UE, CIPS, Genco, CILCORP and CILCO (collectively the "Ameren Companies").

	Nine Months Ended September 30,
	2002			2001
Cash flows from operating activities:
Net income before preferred dividends	$	46,974		$	25,043
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	53,194			51,642
Deferred income taxes, investment tax credit and regulatory liability, net	5,663			(16,597		)
Changes in operating assets and liabilities:
Increase in accounts receivable	(8,102		)	(8,202		)
Decrease (increase) in fuel, materials and supplies, and gas in underground storage	3,208			(4,810		)
Decrease in accrued unbilled revenue	11,776			46,810
Decrease in accounts payable	(25,312		)	(27,619		)
Increase (decrease) in accrued taxes and interest	9,977			(3,981		)
Capital lease payments	484			484
Decrease (increase) in other current assets	7,540			(7,838		)
(Decrease) increase in other current liabilities	(7,460		)	9,727
Increase in other non-current assets	(2,483		)	(819		)
Increase in other non-current liabilities	4,787			17,178
Net cash provided by operating activities	100,246			81,018
Cash flows from investing activities:
Capital expenditures	(95,803		)	(38,513		)
Cost of equity funds capitalized	(14		)	—
Other	(2,162		)	(1,788		)
Net cash used in investing activities	(97,979		)	(40,301		)
Cash flows from financing activities:
Common dividends paid	(28,000		)	(30,000		)
Preferred dividends paid	(1,619		)	(1,619		)
Payments on capital lease obligation	(484		)	(484		)
Decrease in short-term borrowing	(43,000		)	(9,300		)
Long-term debt issued	100,000			—
Long-term debt retired	(1,400		)	—
Net cash provided by (used in) financing activities	25,497			(41,403		)
Net increase (decrease) in cash and temporary cash investments	27,764			(686		)
Cash and temporary cash investments at beginning of year	12,584			8,777
Cash and temporary cash investments at September 30	$	40,348		$	8,091
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of cost of borrowed funds capitalized)	$	24,017		$	23,963
Income taxes	$	14,605		$	22,547

~~See~~---------------------------------------------------------------------------------------------------------------------------- ~~Notes~~Exhibit ~~to Consolidated~~Designation Registrant(s) Nature of Exhibit ---------------------------------------------------------------------------------------------------------------------------- 31.8 Genco Rule 13a-14(a)/15d-14(a) Certification of Principal Financial ~~Statements~~Officer of Genco ---------------------------------------------------------------------------------------------------------------------------- 31.9 CILCORP Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCORP ---------------------------------------------------------------------------------------------------------------------------- 31.10 CILCORP Rule13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCORP ---------------------------------------------------------------------------------------------------------------------------- 31.11 CILCO Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCO ---------------------------------------------------------------------------------------------------------------------------- 31.12 CILCO Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCO ---------------------------------------------------------------------------------------------------------------------------- Section 1350 Certifications ---------------------------------------------------------------------------------------------------------------------------- 32.1 Ameren Section 1350 Certification of Principal Executive Officer of Ameren ---------------------------------------------------------------------------------------------------------------------------- 32.2 Ameren Section 1350 Certification of Principal Financial Officer of Ameren ---------------------------------------------------------------------------------------------------------------------------- 32.3 UE Section 1350 Certification of Principal Executive Officer of UE ---------------------------------------------------------------------------------------------------------------------------- 32.4 UE Section 1350 Certification of Principal Financial Officer of UE ---------------------------------------------------------------------------------------------------------------------------- 32.5 CIPS Section 1350 Certification of Principal Executive Officer of CIPS ---------------------------------------------------------------------------------------------------------------------------- 32.6 CIPS Section1350 Certification of Principal Financial Officer of CIPS ---------------------------------------------------------------------------------------------------------------------------- 32.7 Genco Section 1350 Certification of Principal Executive Officer of Genco ---------------------------------------------------------------------------------------------------------------------------- 32.8 Genco Section 1350 Certification of Principal Financial Officer of Genco ---------------------------------------------------------------------------------------------------------------------------- 32.9 CILCORP Section 1350 Certification of Principal Executive Officer of CILCORP ---------------------------------------------------------------------------------------------------------------------------- 32.10 CILCORP Section 1350 Certification of Principal Financial Officer of CILCORP ---------------------------------------------------------------------------------------------------------------------------- 32.11 CILCO Section 1350 Certification of Principal Executive Officer of CILCO ---------------------------------------------------------------------------------------------------------------------------- 32.12 CILCO Section 1350 Certification of Principal Financial Officer of CILCO ----------------------------------------------------------------------------------------------------------------------------

* Revisions to the Code of Ethics are also being posted on Ameren's website within five business days following the date of the revision, in accordance with SEC regulation. (b) Reports on Form 8-K. The Ameren Companies filed the following reports on Form 8-K during the quarterly period ended June 30, 2004:

10Date of Report Items Reported Financial Statements Filed -------------- -------------- -------------------------- Ameren: April 29, 2004 (a) 12 (b) May 18, 2004 5, 7 None UE: May 18, 2004 5, 7 None CIPS: None Genco: None CILCORP: None CILCO: None

(a) This report was furnished pursuant to Item 12 and not deemed "filed" for purposes of Section 18 of the Exchange Act. (b) Consolidated operating statistics for three months ended March 31, 2004, and March 31, 2003, unaudited consolidated balance sheet as of March 31, 2004, and December 31, 2003, unaudited consolidated statement of income for three months ended March 31, 2004, and March 31, 2003, and unaudited consolidated statement of cash flows for three months ended March 31, 2004 and March 31, 2003. 85 SIGNATURES Pursuant to the requirements of the Exchange Act, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries. AMEREN CORPORATION (Registrant) /s/ Martin J. Lyons ------------------------------------------- Martin J. Lyons Vice President and Controller (Principal Accounting Officer) UNION ELECTRIC COMPANY (Registrant) /s/ Martin J. Lyons ------------------------------------------- Martin J. Lyons Vice President and Controller (Principal Accounting Officer) CENTRAL ILLINOIS PUBLIC SERVICE COMPANY (Registrant) /s/ Martin J. Lyons ------------------------------------------- Martin J. Lyons Vice President and Controller (Principal Accounting Officer) AMEREN ENERGY GENERATING COMPANY (Registrant) /s/ Martin J. Lyons ------------------------------------------- Martin J. Lyons Vice President and Controller (Principal Accounting Officer) 86 CILCORP INC. (Registrant) /s/ Martin J. Lyons ------------------------------------------- Martin J. Lyons Vice President and Controller (Principal Accounting Officer) CENTRAL ILLINOIS LIGHT COMPANY (Registrant) /s/ Martin J. Lyons ------------------------------------------- Martin J. Lyons Vice President and Controller (Principal Accounting Officer) Date: August 9, 2004 87

CILCORP Inc. and Subsidiaries

Statements of Segments of Business

Three Months Ended September 30, 2002

(In thousands)

(Unaudited)

	CILCO Electric			CILCO Gas			CILCO Other			Other Businesses			Discont. Oper.			Total
Revenues	$	126,099		$	24,762		$	40,730		$	9,948		$	—		$	201,539
Interest income	—			—			172			23			—			195
Total	126,099			24,762			40,902			9,971						201,734
Operating expenses	73,692			21,405			26,996			9,230			—			131,323
Depreciation and amortization	12,240			5,609			—			355			—			18,204
Total	85,932			27,014			26,996			9,585						149,527
Interest expense	4,261			1,554			—			10,801			—			16,616
Preferred stock dividends	—			—			540			—			—			540
Fixed charges and other expenses	(384		)	—			(53		)	—			—			(437		)
Total	3,877			1,554			487			10,801			—			16,719
Income (loss) from continuing oper. before income taxes	36,290			(3,806		)	13,419			(10,415		)	—			35,488
Income taxes	13,873			(1,501		)	5,535			(5,095		)	—			12,812
Income (loss) from continuing oper.	22,417			(2,305		)	7,884			(5,320		)	—			22,676
Effect of discontinued oper.	—			—			—			—			(4		)	(4		)
Segment net income (loss)	$	22,417		$	(2,305	)	$	7,884		$	(5,320	)	$	(4	)	$	22,672

See Notes to Consolidated Financial Statements.

CILCORP Inc. and Subsidiaries

Statements of Segments of Business

Three Months Ended September 30, 2001

(In thousands)

(Unaudited)

	CILCO Electric			CILCO Gas			CILCO Other		Other Businesses			Discont. Oper.			Total
Revenues	$	123,712		$	21,801		$	36,429	$	14,291		$	—		$	196,233
Interest income	—			—			302		68			—			370
Total	123,712			21,801			36,731		14,359			—			196,603
Operating expenses	97,467			19,078			34,599		(15,040		)	—			136,104
Depreciation and amortization	11,721			5,452			—		4,219			—			21,392
Total	109,188			24,530			34,599		(10,821		)	—			157,496
Interest expense	4,115			1,648			—		11,466			—			17,229
Preferred stock dividends	—			—			540		—			—			540
Fixed charges and other expenses	(14		)	—			332		—			—			318
Total	4,101			1,648			872		11,466			—			18,087
Income (loss) from continuing oper. before income taxes	10,423			(4,377		)	1,260		13,714			—			21,020
Income taxes	4,100			(1,732		)	340		6,701			—			9,409
Income (loss) from continuing oper.	6,323			(2,645		)	920		7,013			—			11,611
Effect of discont. operations	—			—			—		—			(4,278		)	(4,278)
Segment net income (loss)	$	6,323		$	(2,645	)	$	920	$	7,013		$	(4,278	)	$	7,333

See Notes to Consolidated Financial Statements.

CILCORP Inc. and Subsidiaries

Statements of Segments of Business

Nine Months Ended September 30, 2002

(In thousands)

(Unaudited)

	CILCO Electric			CILCO Gas		CILCO Other		Other Businesses			Discont. Oper.			Total
Revenues	$	304,868		$	142,961	$	90,917	$	39,669		$	—		$	578,415
Interest income	—			—		218		329			—			547
Total	304,868			142,961		91,135		39,998			—			578,962
Operating expenses	207,183			118,029		70,096		36,110			—			431,418
Depreciation and amortization	36,381			16,813		—		1,057			—			54,251
Total	243,564			134,842		70,096		37,167			—			485,669
Interest expense	12,100			4,498		—		32,872			—			49,470
Preferred stock dividends	—			—		1,619		—			—			1,619
Fixed charges and other expenses	(1,031		)	—		614		—			—			(417		)
Total	11,069			4,498		2,233		32,872			—			50,672
Income (loss) from continuing oper. before income taxes	50,235			3,621		18,806		(30,041		)	—			42,621
Income taxes	18,548			1,479		7,280		(13,497		)	—			13,810
Income (loss) from continuing oper.	31,687			2,142		11,526		(16,544		)	—			28,811
Effect of discontinued oper.	—			—		—		—			(16		)	(16		)
Segment net income (loss)	$	31,687		$	2,142	$	11,526	$	(16,544	)	$	(16	)	$	28,795

See Notes to Consolidated Financial Statements.

CILCORP Inc. and Subsidiaries

Statements of Segments of Business

Nine Months Ended September 30, 2001

(In thousands)

(Unaudited)

	CILCO Electric			CILCO Gas		CILCO Other		Other Businesses			Discont. Oper.			Total
Revenues	$	305,011		$	222,496	$	75,433	$	39,621		$	—		$	642,561
Interest income	—			—		582		223			—			805
Total	305,011			222,496		76,015		39,844			—			643,366
Operating expenses	231,803			194,994		66,888		4,802			—			498,487
Depreciation and amortization	35,245			16,397		—		12,660			—			64,302
Total	267,048			211,391		66,888		17,462			—			562,789
Interest expense	12,779			5,119		—		34,997			—			52,895
Preferred stock dividends	—			—		1,619		—			—			1,619
Fixed charges and other expenses	(58		)	—		950		—			—			892
Total	12,721			5,119		2,569		34,997			—			55,406
Income (loss) from cont. oper. before income taxes	25,242			5,986		6,558		(12,615		)	—			25,171
Income taxes	9,919			2,393		2,050		(1,717		)	—			12,645
Income (loss) from continuing oper.	15,323			3,593		4,508		(10,898		)	—			12,526
Effect of discont. operations	—			—		—		—			(4,278		)	(4,278		)
Segment net income (loss)	$	15,323		$	3,593	$	4,508	$	(10,898	)	$	(4,278	)	$	8,248

See Notes to Consolidated Financial Statements.

CILCORP INC. AND CENTRAL ILLINOIS LIGHT COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1. Introduction

CILCORP Inc. (CILCORP or the Holding Company) is a wholly-owned subsidiary of The AES Corporation (AES). The consolidated financial statements include the accounts of CILCORP, Central Illinois Light Company (CILCO), QST Enterprises Inc. (QST) and its subsidiaries, QST Energy Inc. (QST Energy), and CILCORP Infraservices Inc. (CILCORP Infraservices), and CILCORP’s other subsidiaries (collectively, the Company), after elimination of significant intercompany transactions. The consolidated financial statements of CILCO include the accounts of CILCO and its subsidiaries, CILCO Exploration and Development Company, CILCO Energy Corporation, and Central Illinois Generation, Inc. CILCORP owns 100% of the common stock of its first-tier subsidiaries. In the fourth quarter of 1998, the operations of QST and its subsidiaries (excluding ESE Land Corporation and CILCORP Infraservices Inc. - see Management’s Discussion and Analysis) were discontinued and, therefore, are being reported as discontinued operations in the financial statements. Prior year amounts have been reclassified on a basis consistent with the 2002 presentation.

On April 29, 2002, The AES Corporation (AES) announced an agreement with Ameren Corporation to sell 100 percent of its ownership interest in CILCORP and its subsidiaries. The transaction is subject to regulatory approvals by the Illinois Commerce Commission (ICC), the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Securities and Exchange Commission (SEC), and expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. AES expects the sale to close in the first quarter of 2003.

The accompanying unaudited consolidated financial statements have been prepared according to the rules and regulations of the SEC. Although the Company believes the disclosures are adequate to make the information presented not misleading, these consolidated financial statements should be read along with the Company’s 2001 Annual Report on Form 10-K.

In the Company’s opinion, the consolidated financial statements furnished reflect all normal and recurring adjustments necessary for a fair presentation of the results of operations for the periods presented. Operating results for interim periods are not necessarily indicative of operating results to be expected for the year or of the Company’s future financial condition.

NOTE 2. Contingencies

On May 11, 2001, CILCO and Enron Power Marketing, Inc. (EPMI), a subsidiary of Enron Corp. (Enron), entered into a new Master Agreement for electric purchases and sales, which covered energy transactions scheduled for deliveries during the period of 2001-2003. On November 30, 2001, CILCO notified EPMI that events of default had occurred under the Master Agreement and declared the Master Agreement terminated effective December 20, 2001. Due to contractual provisions and EPMI’s and Enron’s actions, management does not believe CILCO will be required to pay any amount to Enron or its affiliates and has therefore recorded no liability for undelivered electric purchases. Enron and EPMI filed Chapter 11 bankruptcy petitions on December 2, 2001, in the U. S. Bankruptcy Court for the Southern District of New York. Thereafter, CILCO purchased replacement power to serve its retail customers which had previously been partially supported by the EPMI transactions. While the ultimate outcome is unpredictable, management does not believe that EPMI’s

defaults under the Master Agreement, its filing for bankruptcy protection, CILCO’s termination of the Master Agreement, or CILCO’s purchase of replacement electricity will have a material adverse effect on CILCO’s financial position or results of operations.

On May 4, 2001, CILCO and Enron subsidiary Enron North America Corp. (ENA) entered into a natural gas transaction for daily deliveries not to exceed 10,000 MMBtu per day during calendar year 2002. CILCO has received no natural gas deliveries pursuant to this transaction. On October 24, 2001, CILCO and ENA entered into a short-term natural gas transaction giving CILCO the right to call upon ENA for the delivery of 10,000 MMBtu per day during the period from November 1, 2001, through March 31, 2002. Since late November 2001, ENA was unable to deliver natural gas when called upon by CILCO. ENA’s failure to deliver natural gas is an event of default under the Master Firm Sales Agreement governing the October transaction. On December 2, 2001, ENA filed a Chapter 11 bankruptcy petition in the U. S. Bankruptcy Court for the Southern District of New York. To the extent that it has been necessary, CILCO has purchased replacement natural gas. Because these transactions are part of a larger and more diversified natural gas supply portfolio and are subject to the Purchased Gas Adjustment clause, management does not believe ENA’s failure to supply natural gas or its subsequent bankruptcy filing will have a material adverse effect on CILCO’s financial position or results of operations.

NOTE 3. Accounting for Price Risk Management Activities

The Company utilizes commodity futures contracts, options and swaps in the normal course of its natural gas and electric business activities to reduce market or price risk. Since January 1, 2001, all derivative transactions have been accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Transactions and Hedging Activities” (SFAS 133), as interpreted and amended. SFAS 133 requires that an entity recognize all derivatives (including derivatives embedded in other contracts), as defined, as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the derivative’s fair value are to be recognized currently in earnings, unless specific hedge accounting criteria are met. All of the Company’s derivatives qualify as cash flow hedges. Under SFAS 133, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is reported as a component of Other Comprehensive Income (OCI) until the hedged transaction affects earnings, at which time the amount accumulated in OCI is reclassified into earnings. In addition, under SFAS 133, any ineffective portion of the gain or loss is recognized in earnings immediately. All of the Company’s cash flow hedges are highly effective, and therefore, because any ineffectiveness is immaterial, all gains and losses have been recorded in OCI until the hedged transaction affects earnings. If a cash flow hedge is terminated because it is probable that the hedged transaction will not occur, the related balance in OCI as of such date is immediately recognized in earnings. If a cash flow hedge is terminated early for other reasons, the related balance in OCI as of the termination date is recognized in earnings concurrently with the related hedged transaction.

Gains/losses on derivatives that hedge non-regulated activities are reflected in operating results when the hedged commitments are recognized. The net gain reflected in operating results from derivative financial instruments for non-regulated activities for the quarter ended September 30, 2002, was $0.3 million for natural gas (included in Gas Purchased for Resale). The previously recorded gain/loss associated with these settled derivative financial instruments was removed from OCI. The open derivative positions are then marked-to-market through OCI. The net effect of these adjustments was to record an after-tax gain in OCI in the amount of $0.6 million for the quarter

ended September 30, 2002. The after-tax balance in OCI associated with these open derivative positions and unrealized gains on settled positions at September 30, 2002, was a gain of $0.9 million. The corresponding asset is reflected on the balance sheet in prepayments and other. The portion of OCI for open positions reflects hedges of natural gas sales of 2,280,000 MMBtu for commitments through February 2004. Approximately $0.9 million of OCI related to derivative financial instruments as of September 30, 2002, is expected to be recognized as an increase to operating earnings over the next twelve months based on market prices as of September 30, 2002. The actual amount recognized in earnings will be based on the market conditions at the time the derivatives are settled.

Beginning in March 2002, the Company is hedging its anticipated summer injections into storage fields utilizing collars (a combination of a put option and a call option) and futures to hedge the cost for customers charged the Purchased Gas Adjustment (PGA). In May 2002, the Company implemented a winter 2002-2003 hedging strategy related to regulated gas activities. This strategy also utilizes collars and futures to help protect customers from large price fluctuations. Gains and losses on PGA-related positions are being recorded as regulatory assets or liabilities in accordance with Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). For the quarter ended September 30, 2002, a mark-to-market gain of $0.9 million was recorded in the regulatory liability for all PGA-related derivatives, bringing the regulatory liability to $0.9 million. The corresponding asset is reflected on the balance sheet in prepayments and other. This reflects hedges of natural gas sales of 500,000 MMBtu for commitments through March 2003.

In December 2001, the Financial Accounting Standards Board (FASB) revised its earlier conclusion, Derivatives Implementation Group (DIG) Issue C-15, related to contracts involving the purchase or sale of electricity. Contracts for the purchase or sale of electricity, both forward and option contracts, including capacity contracts, may qualify for the normal purchases and sales exemption and are not required to be accounted for as derivatives under SFAS 133. In order for contracts to qualify for this exemption, they must meet certain criteria, which include the requirement for physical delivery of the electricity to be purchased or sold under the contract only in the normal course of business. Additionally, contracts that have a price based on an underlying that is not clearly and closely related to the electricity being sold or purchased or that are denominated in a currency that is foreign to the buyer or seller are not considered normal purchases and normal sales and are required to be accounted for as derivatives under SFAS 133. This revised conclusion was effective beginning April 1, 2002. The Company has determined that its physical contracts qualify for the normal purchases and sales exemption as redefined in DIG Issue C-15 and are not to be accounted for as derivatives under SFAS 133.

NOTE 4. Other Comprehensive Income

Rollforward of Accumulated Other Comprehensive Income -

CILCORP Inc.

	Pension			SFAS 133		Total
	(In thousands)
Accumulated other comprehensive income (loss) - June 30, 2002 balance	$	(9,333	)	$	331	$	(9,002	)
Other comprehensive income -
Pension	—			—		—
SFAS 133	—			606		606
Accumulated other comprehensive income (loss) - September 30, 2002 balance	$	(9,333	)	$	937	$	(8,396	)

Rollforward of Accumulated Other Comprehensive Income -

Central Illinois Light Company

	Pension			SFAS 133		Total
	(In thousands)
Accumulated other comprehensive income (loss) - June 30, 2002 balance	$	(1,112	)	$	331	$	(781	)
Other comprehensive income -
Pension	—			—		—
SFAS 133	—			606		606
Accumulated other comprehensive income (loss) - September 30, 2002 balance	$	(1,112	)	$	937	$	(175	)

NOTE 5. Impact of Accounting Standards

In June 2001, the FASB issued Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (SFAS 142), and Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143).

SFAS 142 requires that goodwill and intangible assets that have indefinite useful lives be tested at least annually for impairment rather than be amortized. The provisions of SFAS 142 were required to be applied starting with fiscal years beginning after December 15, 2001. The Company adopted SFAS 142 on January 1, 2002, and, as a result, annual goodwill amortization of approximately $15.3 million has ceased. Net income would have been $11.2 million and $19.8 million for the quarter and nine months ended September 30, 2001, respectively, had CILCORP discontinued the amortization of goodwill effective January 1, 2001. The initial impairment assessment has been performed, utilizing the requirements of SFAS 142, and the Company has determined that its fair value exceeds its carrying value and therefore, goodwill for the Company is considered not impaired. The Company has identified the following four reporting units under the provisions of SFAS 142: CILCO Electric, CILCO Gas, CILCO Other and Other Businesses. The Company has completed the allocation of goodwill to the reporting units as follows:

	CILCO Electric		CILCO Gas		CILCO Other		Other Businesses		Total
	(In thousands)
	(Unaudited)
Goodwill, net of accumulated amortization of $33,753, as of December 31, 2001	$	350,256	$	132,514	$	2,118	$	94,323	$	579,211

SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. The Company has not yet quantified the effect, if any, of this new standard on the consolidated financial statements.

Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144), was issued in August 2001, and is effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. SFAS 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. The adoption of SFAS 144 has not had a significant impact on the Company’s financial position or results of operations.

Statement of Financial Accounting Standards No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections” (SFAS 145), was issued in April 2002. The provisions of SFAS 145 related to the rescission of FASB Statement No. 4 shall be applied in fiscal years beginning after May 15, 2002. All other provisions of this Statement are effective for financial statements issued on or after May 15, 2002. Management has determined that adoption of SFAS 145 has no material effect on the Company’s consolidated financial statements.

In June 2002, the FASB issued Statement of Financial Accounting Standards No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (SFAS 146). The provisions of SFAS 146 are effective for exit or disposal activities that are initiated after December 31, 2002. The Company has not yet quantified the effect, if any, of this new standard on the consolidated financial statements.

Emerging Issues Task Force (EITF) Issue No. 02-03 - Issues Involved in Accounting for Contracts Under EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-03). In June 2002, the EITF reached a consensus on Issue 1 of EITF 02-03 (consensus). The key requirements are that all gains and losses on energy trading contracts and related physical transactions must be shown net in the income statement. The gross transaction volumes for those energy trading contracts that are physically settled must be disclosed in the notes to the financial statements. The consensus is effective for financial statements issued for periods ending after July 15, 2002.

The Company currently accounts for all its non-regulated power and gas marketing activities at gross in the Consolidated Statements of Income. The Company has reviewed all its current power and gas marketing contracts and all contracts closed in prior periods and identified no trading contracts subject to EITF 02-03 or EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”.

NOTE 6. Additional Minimum Pension Liability

At December 31 of each year, the Company reviews each pension plan to determine if the plans’ accumulated benefit obligations exceed the fair value of the plan assets. If the accumulated benefit obligations exceed the fair value of the plan assets, an additional minimum pension liability is recorded on the balance sheet, with a corresponding charge to other comprehensive income. Downturns in the stock market affect the value of the pension assets, and accordingly, the additional minimum pension liability at December 31, 2002, may be a material amount.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

CILCORP Inc. (CILCORP) is a wholly-owned subsidiary of The AES Corporation (AES). The financial condition and operating results of CILCORP and its subsidiaries (the Company) primarily reflect the operations of subsidiary Central Illinois Light Company (CILCO).

In July 2000, AES announced plans to acquire IPALCO Enterprises, Inc. (IPALCO), a utility holding company headquartered in Indianapolis, Indiana. Following this announcement, AES indicated that as part of the Securities and Exchange Commission (SEC) approval process for the IPALCO transaction, AES expected to restructure its ownership interests in CILCORP within a specified period of time in order to continue as an exempt holding company under the Public Utility Holding Company Act of 1935 (PUHCA). On March 23, 2001, AES received an order from the SEC which allowed AES’ continued exemption from PUHCA. The exemption order required AES to divest its ownership interests in CILCO’s regulated utility assets within two years of the closing (March 27, 2001) of AES’ acquisition of IPALCO. On April 29, 2002, AES announced an agreement with Ameren Corporation to sell 100 percent of its ownership interest in CILCORP and its subsidiaries. The transaction is subject to regulatory approvals by the Illinois Commerce Commission (ICC), the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the SEC, and expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. AES expects the sale to close in the first quarter of 2003.

The Other Businesses segment includes the operations of the Holding Company itself (Holding Company), its investment subsidiary, CILCORP Investment Management Inc. (CIM), CILCORP Ventures Inc. (CVI), and CILCORP Infraservices Inc., which provides utility infrastructure operation and maintenance services. The results of QST and its subsidiaries (excluding ESE Land Corporation and CILCORP Infraservices Inc.) are reported as discontinued operations (see Results of Operations - QST Enterprises Discontinued Operations).

Forward-Looking Information

Forward-looking information is included in Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A). Certain material contingencies are also described in Note 2 to the Consolidated Financial Statements.

Some important factors could cause actual results or outcomes to differ materially from those expressed or implied in MD&A. The business and profitability of CILCORP and its subsidiaries are influenced by economic and geographic factors, including ongoing changes in environmental laws and weather conditions; the extent and pace of development of competition for retail and wholesale energy customers; changes in technology; changes in company-wide operation and plant availability compared to historical performance and changes in historical operating cost structure, including changes in various costs and expenses; pricing and transportation of commodities; market supply and demand for energy and energy derivative financial instruments; inflation; capital market conditions; and environmental protection and compliance costs. Prevailing governmental policies, statutory changes, and regulatory actions with respect to rates, tariffs, industry structure and recovery of various costs incurred by CILCO in the course of its business and increasing wholesale and retail competition in the electric and gas business affect its earnings. In addition, actual results or outcomes could differ materially from those expressed or implied in MD&A due to the announced transaction, concluded or not, by CILCORP’s sole

shareholder, The AES Corporation, to sell its ownership interest in CILCORP and its subsidiaries to Ameren Corporation. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and, to a significant degree, are beyond the control of CILCORP and its subsidiaries. CILCORP and its subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of changes in actual results, assumptions or other factors.

Capital Resources & Liquidity

The Company believes that internal and external sources of capital which are or are expected to be available will be adequate to fund its capital expenditures, pay its financial obligations, meet working capital needs and retire or refinance debt as it matures.

CILCORP

CILCORP (the Holding Company) is currently authorized by its Board of Directors to borrow up to $60 million on a short-term basis. At September 30, 2002, the Holding Company had no short-term debt outstanding.

In October 1999, the Holding Company issued $225 million of 8.7% senior notes (due 2009) and $250 million of 9.375% senior notes (due 2029). Along with equity funds provided by AES, the proceeds of the notes were used by AES to acquire all outstanding shares of CILCORP common stock for approximately $886 million, to pay transaction costs related to the acquisition, and to retire short-term debt.

CILCO

Capital expenditures totaled $96.1 million for the nine months ended September 30, 2002. Capital expenditures are anticipated to be approximately $38.9 million for the remainder of 2002 and are currently estimated to be approximately $80.2 million in 2003. The increase in capital expenditures in 2002 and 2003 over 2001 relates primarily to the installation of nitrogen oxide (NOx) reduction equipment at the Edwards and Duck Creek generating stations.

CILCO is currently authorized by its Board of Directors to issue up to $150 million of short–term debt, but had no short-term debt at September 30, 2002. At September 30, 2002, committed bank lines of credit totaled $90 million, all of which were unused. A $30 million bank line expires in the fourth quarter of 2002, with the remaining lines expiring in 2003. CILCO has not determined if it will renew or replace the $30 million bank line. CILCO plans to finance its 2002 and 2003 capital expenditures with funds provided by operations, short-term debt and long-term debt. In June 2002, CILCO obtained a two-year $100 million senior secured term loan. The proceeds of the borrowings were used to reduce short-term debt, and will be used to refund medium-term notes maturing in 2003 and for general corporate purposes. The

loan is secured by a first mortgage on substantially all of CILCO’s property and has a variable interest rate. The average interest rate on this term loan is currently 2.98%. Future funds provided by operations may be affected by the deregulation of the electric and natural gas utility industries (see Competition).

CIM

At September 30, 2002, CIM had outstanding debt of $12.6 million, borrowed from CILCORP.

CVI

At September 30, 2002, CVI had outstanding debt of $4.8 million, borrowed from CILCORP.

Competition

CILCO, as a regulated public utility, has an obligation to provide electricity and natural gas to retail customers within its defined service territory; thus, CILCO has not generally been in competition with other energy suppliers for retail electric or gas customers in these areas. However, the passage of the Electric Service Customer Choice and Rate Relief Law of 1997 (Customer Choice Law) began a transition process to a fully competitive retail market for electricity in Illinois. During the mandatory transition period, electric utilities are prohibited from increasing base rates, unless the electric utility demonstrates that its 2-year average earned rate of return is below the 2-year average of the monthly average yield of the U.S. Treasury long-term bond index. The initial mandatory transition period ends on January 1, 2005. Recently enacted legislation extends this rate freeze and transition period to January 1, 2007. For CILCO, this extension is applicable, provided that Ameren Corporation’s acquisition of CILCORP and its subsidiaries closes. Electricity and natural gas also compete with other forms and sources of energy available to customers. For example, within the City of Springfield, CILCO’s natural gas business competes with the City’s municipal electric system to provide customer energy needs.

Primarily as a result of the Customer Choice Law, the electric industry in Illinois will change significantly during the coming years at both the wholesale and retail levels. As of December 31, 2000, all non-residential customers had the ability to choose their electric supplier. Residential electric customers were able to choose their electric supplier as of May 1, 2002.

If a customer chooses to leave its present electricity supplier, that utility will collect a fee for delivering power and may assess an additional transition charge on the customer. This collection methodology must be filed with and approved by the Illinois Commerce Commission (ICC) and is designed to help utilities recover a portion of the costs of past investments made under a regulated system. The transition charge will usually reduce a customer’s economic incentive to switch suppliers. Transition charges may be collected through 2006 (2008 upon the ICC’s finding that a utility’s financial condition is impaired and the utility meets other requirements specified in the Customer Choice Law).

On March 9, 2000, CILCO filed revised tariff sheets with the ICC eliminating the collection of the customer transition charge effective March 17, 2000. At a March 15, 2000, hearing, the ICC approved CILCO’s revised tariffs, thereby

eliminating the collection of any customer transition charge. CILCO cannot re-establish the collection of a transition charge until it files, and the ICC approves, revised tariff sheets that reinstate a transition charge.

The Customer Choice Law also requires electric base rate reductions that vary by utility. CILCO reduced its residential base rates by 2% in August 1998, by 2% in October 2000, and by an additional 1% in October 2002. Also, CILCO’s return on common equity will, in general, be capped (the Equity Cap) at an index (a 12-month average yield for long-term U.S. Treasury bonds plus 8% for calendar years 1998 and 1999 and a 12 month-average yield for long-term U.S. Treasury bonds plus 9% for calendar years 2000 through 2004) plus 1.5 percentage points. The Equity Cap was 16.1% in 2001, 16.6% in 2000, and 15.1% in 1999. If CILCO’s two-year average return on common equity exceeds the two-year average of the Equity Cap, fifty percent of the earnings in excess of the average Equity Cap must be refunded to customers in the following year.

On June 30, 1999, Senate Bill 24 (a clarification and technical correction of the Customer Choice Law) was signed into law. This law allows certain utilities, including CILCO, to increase the Equity Cap by an additional 2% over the Equity Cap provided under the Customer Choice Law, for the period 2000 through 2004. The increase in the Equity Cap is allowed in exchange for these utilities offering choice of electricity suppliers to selected manufacturing customers on June 1, 2000, and to the remaining manufacturing customers on October 1, 2000, earlier than previously allowed under the Customer Choice Law. Utilities selecting this option must also waive the right to seek a two-year extension on the collection of transition charges. On April 13, 2000, CILCO filed revised tariff sheets with the ICC to make these selected customers eligible for choice on June 1, 2000, in order to increase the equity cap by 2%, as outlined in Senate Bill 24.

With the enactment of the Customer Choice Law, electric generation in Illinois became deregulated and competitive. As a result, the accounting principles applicable to rate-regulated enterprises (Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71)) no longer apply to the electric generation portion of CILCO’s business. There were no impairments to CILCO assets as a result of transitioning from SFAS 71. Its ability to keep total production costs competitive in a deregulated market will determine whether and to what extent the value of these assets may be impaired in the future.

With electric choice beginning on October 1, 1999, for its industrial customers and some of its commercial customers, and with all other non-residential customers being able to choose their electric supplier on December 31, 2000, CILCO has entered into multi-year contracts with targeted customers representing approximately 45% of total 2001 electric kWh sales to non-residential customers. These contracts, most of which expire in 2004, were designed to capture a significant portion of the margin that the customers paid to CILCO in the most recent twelve months. In 2002, CILCO has been negotiating new contracts with targeted at-risk customers who are currently being served under bundled tariff rates. For those contracts expiring in 2002, CILCO has been negotiating contract extensions with selected customers.

The ultimate market price for electricity, the cost for a utility to produce or buy electricity, and the number of customers that may be gained or lost due to customer choice of supplier in Illinois cannot be predicted. As a result, management cannot predict the ultimate impact that the Customer Choice Law will have on CILCORP’s financial position or results of operation, but the effect could be significant. However, CILCO is currently a low-cost provider of electricity, and management will continue to position CILCO for competition by controlling costs, maintaining good customer relations, and developing

flexibility to meet individual customer requirements. As of September 30, 2002, all electric customers eligible for choice continue to purchase their electricity supply from CILCO, other than those who self-generate. As of September 30, 2002, CILCO has contracts totaling approximately 2.6 million megawatt hours of retail load outside of its service territory for 2002. CILCO will supply these new customers by primarily purchasing electricity from other suppliers. CILCO has made the necessary firm supply and transmission arrangements to meet customer requirements.

Results of Operations

CILCO Electric Operations

The following table summarizes the components of CILCO electric income for the three months and nine months ended September 30, 2002 and 2001.

	Three Months Ended September 30,						Nine Months Ended September 30,
Components of Electric Income	2002			2001			2002			2001
	(In thousands)
	(Unaudited)
Revenue:
Electric retail	$	122,683		$	118,634		$	296,989		$	291,530
Sales for resale	3,416			5,078			7,879			13,481
Total revenue	126,099			123,712			304,868			305,011
Cost of sales:
Cost of fuel	28,323			54,683			74,648			108,647
Purchased power	16,658			15,670			40,705			35,329
Revenue taxes	6,020			5,506			15,443			15,053
Total cost of sales	51,001			75,859			130,796			159,029
Gross margin	75,098			47,853			174,072			145,982
Operating expenses:
Other operations and maintenance	20,397			19,258			69,176			65,586
Depreciation and amortization	12,240			11,721			36,381			35,245
Other taxes	2,294			2,350			7,211			7,188
Total operating expenses	34,931			33,329			112,768			108,019
Total	40,167			14,524			61,304			37,963
Fixed charges and other:
Cost of equity funds capitalized	(14		)	—			(14		)	—
Interest on long-term debt	3,761			3,314			10,125			9,495
Cost of borrowed funds capitalized	(370		)	(14		)	(1,017		)	(58		)
Other interest	500			801			1,975			3,284
Total	3,877			4,101			11,069			12,721
Income before income taxes	36,290			10,423			50,235			25,242
Income taxes	13,873			4,100			18,548			9,919
Electric income	$	22,417		$	6,323		$	31,687		$	15,323

Electric gross margin increased 57% for the quarter and 19% for the nine months ended September 30, 2002, compared to the same periods in 2001, primarily as a result of a Fuel Adjustment Clause (FAC) settlement agreement in the third quarter of 2001 between the Company and the Illinois Commerce Commission (ICC). In its order dated August 21, 2001, the ICC approved the agreement requiring the Company to refund $17.8 million related to the 1999 FAC reconciliation and $2.6 million related to the 2000 FAC reconciliation. Increased residential sales also contributed to the increase in electric gross margin for the quarter and nine months ended September 30, 2002. In the first quarter of 2002, CILCO also received a payment discount in conjunction with

the termination of an out-of-market long-term coal contract. The discount reduced cost of fuel by $0.8 million for the first quarter of 2002. On December 20, 2000, as part of the 1999 FAC reconciliation hearings, the ICC ordered changes in CILCO’s calculation of allowable fuel costs applicable to sales subject to the FAC. These changes revised the allocation of generated and purchased power between regulated and non-regulated sales. As a result of this order, the regulated sales margin decreased and the non-regulated sales margin increased for January through March 2001. On March 9, 2001, the ICC issued an emergency rule in response to the margin shifts. The emergency rule restored the previous calculation method for off-system non-regulated sales. On July 25, 2001, the ICC entered a final order, amending the emergency rule by changing the method for allocating fuel costs to non-regulated sales within CILCO’s service territory.

Retail sales volumes increased 7% for the quarter and 2% for the nine months ended September 30, 2002, compared to the same periods in 2001. Residential sales increased 13% for the quarter and 7% for the nine months ended September 30, 2002, compared to the same periods in 2001. Commercial sales increased 6% for the quarter and 2% for the nine months ended September 30, 2002, compared to the same periods in 2001. Industrial sales increased 2% for the quarter and decreased 2% for the nine months ended September 30, 2002, compared to the same periods in 2001. Cooling degree days were 22% higher for the quarter and nine months ended September 30, 2002, compared to the same periods in 2001.

Sales for resale decreased 33% for the quarter and 42% for the nine months ended September 30, 2002, compared to the same periods in 2001. Sales for resale vary based on the energy requirements of native load customers, neighboring utilities and power marketers, CILCO’s available capacity for bulk power sales and the price of power available for sale.

The overall level of business activity in CILCO’s service territory and weather conditions are expected to continue to be the primary factors affecting electric sales in the near term. CILCO’s electric sales will also be affected in the long term by deregulation and increased competition in the electric utility industry.

The cost of fuel decreased 48% for the quarter and 31% for the nine months ended September 30, 2002, compared to the same periods in 2001, primarily due to the FAC settlement with the ICC in 2001. Additionally, CILCO renegotiated a long-term coal supply contract in late 2001 which resulted in lower coal costs in 2002. Purchased power increased 6% and 15% for the quarter and nine months ended September 30, 2002, respectively, compared to the same periods in 2001.

Electric operation and maintenance expense increased 6% for the quarter and 5% for the nine months ended September 30, 2002, compared to the same periods in 2001. The increase was mainly due to increased costs for pension, other post-employment benefits and tree trimming, partially offset by lower uncollectible accounts expense. Also contributing to the unfavorable variance for the nine months ended September 30, 2002, were expenses incurred as the result of an ice storm in the first quarter of 2002.

Fixed charges and other expenses decreased 5% for the quarter and 13% for the nine months ended September 30, 2002, compared to the same periods in 2001, primarily due to decreased short-term borrowings and increased capitalized interest related to NOx reduction projects at the power plants.

Income tax expense increased for the quarter and for the nine months ended September 30, 2002, compared to the same periods in 2001, due to increases in income before income taxes.

CILCO Gas Operations

The following table summarizes the components of CILCO gas income for the three months and nine months ended September 30, 2002 and 2001.

	Three Months Ended September 30,						Nine Months Ended September 30,
Components of Gas Income	2002			2001			2002		2001
	(In thousands)
	(Unaudited)
Revenue:
Sale of gas	$	23,386		$	20,423		$	138,429	$	218,387
Transportation services	1,376			1,378			4,532		4,109
Total revenue	24,762			21,801			142,961		222,496
Cost of sales:
Cost of gas	12,050			9,803			84,022		162,299
Revenue taxes	989			987			6,421		7,126
Total cost of sales	13,039			10,790			90,443		169,425
Gross margin	11,723			11,011			52,518		53,071
Operating expenses:
Other operations and maintenance	7,766			7,716			25,850		23,862
Depreciation and amortization	5,609			5,452			16,813		16,397
Other taxes	600			572			1,736		1,707
Total operating expenses	13,975			13,740			44,399		41,966
Total	(2,252		)	(2,729		)	8,119		11,105
Fixed charges and other:
Interest on long-term debt	1,374			1,328			3,764		3,804
Other interest expense	180			320			734		1,315
Total	1,554			1,648			4,498		5,119
Income (loss) before income taxes	(3,806		)	(4,377		)	3,621		5,986
Income taxes	(1,501		)	(1,732		)	1,479		2,393
Gas income (loss)	$	(2,305	)	$	(2,645	)	$	2,142	$	3,593

Gas gross margin increased 6% for the quarter and decreased 1% for the nine months ended September 30, 2002, compared to the same periods in 2001. Residential sales volumes increased 2% for the quarter and decreased 1% for the nine months ended September 30, 2002, compared to the same periods in 2001. Commercial sales volumes increased 6% for the quarter and decreased 7% for the nine months ended September 30, 2002, compared to the same periods in 2001. Heating degree days were 8% lower for the nine months ended September 30, 2002, compared to the same period in 2001. Industrial sales volumes decreased 14% for the quarter and for the nine months ended September 30, 2002, compared to the same periods in 2001.

The overall level of business activity in CILCO’s service territory and weather conditions are expected to continue to be the primary factors

affecting gas sales in the near term. CILCO’s gas sales may also be affected by further deregulation at the retail level in the natural gas industry.

Revenue from gas transportation services remained relatively constant for the quarter and increased 10% for the nine months ended September 30, 2002, while gas transportation sales volumes increased 5% for the quarter and 17% for the nine months ended September 30, 2002, compared to the same periods in 2001.

The cost of gas increased 23% for the quarter and decreased 48% for the nine months ended September 30, 2002, compared to the same periods in 2001, primarily due to fluctuations in natural gas prices. These costs were passed through to customers via the Purchased Gas Adjustment (PGA).

Gas operation and maintenance expense increased 1% for the quarter and 8% for the nine months ended September 30, 2002, compared to the same periods in 2001. The increases were primarily due to increases in expenses for public liability claims, pension and other post-employment benefits, partially offset by decreased uncollectible accounts expense.

Fixed charges and other expenses decreased 6% for the quarter and 12% for the nine months ended September 30, 2002, compared to the same periods in 2001, mainly due to decreased short-term borrowings.

Income tax expense decreased for the nine months ended September 30, 2002, compared to the same period in 2001, due to a decrease in income before income taxes.

CILCO Other Operations

The following table summarizes CILCO’s Other income and deductions for the three months and nine months ended September 30, 2002 and 2001.

	Three Months Ended September 30,						Nine Months Ended September 30,
Components of CILCO Other	2002			2001			2002			2001
	(In thousands)
	(Unaudited)
Revenue	$	40,730		$	36,429		$	90,917		$	75,433
Expense	(25,649		)	(33,505		)	(66,661		)	(64,728		)
Gross margin	15,081			2,924			24,256			10,705
Other income and deductions:
Interest income	172			302			218			582
Operating expenses	(1,347		)	(1,094		)	(3,384		)	(2,160		)
Other taxes	—			—			(51		)	—
Preferred stock dividends	(540		)	(540		)	(1,619		)	(1,619		)
Other	53			(332		)	(614		)	(950		)
Total other income and (deductions)	(1,662		)	(1,664		)	(5,450		)	(4,147		)
Income before income taxes	13,419			1,260			18,806			6,558
Income taxes	5,535			340			7,280			2,050
Other income	$	7,884		$	920		$	11,526		$	4,508

Gross margin increased $12.2 million for the quarter and $13.6 million for the nine months ended September 30, 2002, compared to the same periods in 2001, primarily due to increased margin per MWh sold and to increased non-regulated electricity sales in Illinois outside of CILCO’s service territory. The higher margin per MWh sold is not expected to continue beyond third quarter 2002 operating results. These sales of electricity were to customers eligible to choose their energy supplier under the Customer Choice Law.

Operating expenses increased for the quarter and nine months ended September 30, 2002, compared to the same periods in 2001, primarily due to increased administrative and bad debt expenses for non-regulated sales.

Proceeds from company-owned life insurance in the third quarter of 2002 reduced other deductions by approximately $0.5 million for the quarter and nine months ended September 30, 2002, compared to the same periods in 2001.

Other Businesses Operations

The following table summarizes Other Businesses revenue and expenses for the three months and nine months ended September 30, 2002 and 2001. Other Businesses results include income earned and expenses incurred at the Holding Company, CIM, CVI, and CILCORP Infraservices Inc.

Components of Other Businesses	Three Months Ended September 30,						Nine Months Ended September 30,
Operating Income (Loss)	2002			2001			2002			2001
	(In thousands)
	(Unaudited)
Revenue:
Leveraged lease revenue	$	1,265		$	1,326		$	3,881		$	4,065
Interest income	23			68			329			223
Gas marketing revenue	8,802			7,788			35,119			29,227
Other revenue (expense)	(119		)	5,177			669			6,329
Total revenue	9,971			14,359			39,998			39,844
Expenses:
Gas purchased for resale	8,531			8,056			34,709			29,659
Fuel for generation and purchased power	—			(23,377		)	—			(26,045		)
Operating expenses	678			254			1,338			1,115
Depreciation and amortization	355			4,219			1,057			12,660
Interest expense	10,801			11,466			32,872			34,997
Other taxes	21			27			63			73
Total expenses	20,386			645			70,039			52,459
Income (loss) before income taxes	(10,415		)	13,714			(30,041		)	(12,615		)
Income taxes	(5,095		)	6,701			(13,497		)	(1,717		)
Other Businesses income (loss)	$	(5,320	)	$	7,013		$	(16,544	)	$	(10,898	)

Gas marketing revenue increased 13% for the quarter and 20% for the nine months ended September 30, 2002, while gas purchased for resale increased 6% for the quarter and 17% for the nine months ended September 30, 2002, compared to the same periods in 2001. These increases were due to increased gas marketing sales at CVI subsidiary CILCORP Energy Services Inc.

Other revenue decreased 102% for the three months ended and 89% for the nine months ended September 30, 2002, compared to the same periods in 2001, due primarily to a $4.5 million settlement in the third quarter of 2001 of a preacquisition contingency related to litigation at QST Energy. See related discussion at Results of Operations - QST Enterprises Discontinued Operations.

Fuel for generation and purchased power was impacted by the settlement of a preacquisition contingency in 2001. In September 2001, CILCORP recorded an $18 million reduction in a preacquisition contingency related to an out-of-market coal contract with a corresponding reduction in cost of fuel. The adjustment to this liability was necessitated by a change in the Company’s plan relative to this contract. Accordingly, the company made a new assessment of the potential liability and recorded an adjustment to the original liability. Fuel for generation and purchased power was also

impacted in 2001 by $4.0 million in amortization related to the preacquisition liability for this out-of-market coal contract. This contract was settled during the fourth quarter of 2001 and the preacquisition contingency related to this contract was removed.

Depreciation and amortization decreased during the quarter and nine months ended September 30, 2002, following the Company’s adoption of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (SFAS 142) in January 2002. SFAS 142 requires that goodwill and intangible assets that have indefinite useful lives be tested at least annually for impairment rather than be amortized. Accordingly, the Company has ceased goodwill amortization which was approximately $11.5 million during the nine months ended 2001. See related discussion in Note 5 to the Consolidated Financial Statements.

Interest expense decreased 6% for the quarter and nine months ended September 30, 2002, compared to the same periods in 2001, mainly due to the retirement of CILCORP’s medium-term notes in 2001 and to lower short-term debt in 2002. This decrease was partially offset by interest on deferred compensation arrangements for two former officers that was recorded during the second quarter of 2002.

The income tax benefit increased significantly during the quarter and nine months ended September 30, 2002, compared to the same periods in 2001, due to lower income before income taxes.

QST Enterprises Discontinued Operations

QST Enterprises and QST Energy ceased operations during the fourth quarter of 1998, except for fulfillment of contractual commitments for 1999 and beyond. Accordingly, the results of QST Enterprises are reported as discontinued operations. An initial loss provision was recorded for the discontinued energy operations in 1998. Subsequent purchase accounting adjustments included additional discontinued operations loss accruals for QST Enterprises.

Loss from operations of discontinued businesses, net of tax:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
	(In thousands)
	(Unaudited)
QST Enterprises, net of tax of $(3), $(2,813), $(11) and $(2,813)	$	(4	)	$	(4,278	)	$	(16	)	$	(4,278	)
	$	(4	)	$	(4,278	)	$	(16	)	$	(4,278	)

QST Enterprises’ financial results for all periods shown were in excess of the discontinued operations provision and are shown as losses for those periods. Beginning in 1999, QST Energy was involved in litigation against two of its California commercial customers. On July 19, 2001, QST Energy and the two customers signed a settlement agreement and mutual release which resolved all of the pending lawsuits. A cash settlement of $6 million was paid to QST Energy and applied against the accounts receivable balance at QST Energy, which was $13 million at the time of settlement. CILCORP had reserved $4.5 million as a preacquisition contingency related to this litigation. The remaining receivable of $7.0 million at QST Energy was written off during the third quarter of 2001, and was partially offset by the $4.5 million gain recorded at CILCORP.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market Risk Sensitive Instruments

CILCORP and its subsidiaries (the Company) are exposed to non-trading risks through its daily business activities. These non-trading activities may include the market or commodity price risk related to CILCO’s retail tariff activity and the Company’s non-regulated commodity marketing activities.

The majority of the Company’s electricity sales during the third quarter of 2002 were to CILCO retail customers in Illinois under tariffs regulated by the Illinois Commerce Commission (ICC). Gas costs, prudently incurred in connection with sales to customers under tariffs regulated by the ICC, are recovered through the Company’s Purchased Gas Adjustment (PGA). Prior to October 29, 2001, prudently incurred costs of fuel used to generate electricity and purchased power costs were recovered from retail customers that purchase energy through regulated tariffs under the Fuel Adjustment Clause (FAC). Thus, through October 28, 2001, there had been very limited commodity price risk associated with CILCO’s traditional regulated sales. CILCO filed to eliminate the FAC on September 10, 2001. The ICC approved the elimination of the FAC on October 24, 2001, for bills issued on or after October 29, 2001. While the Company is exposed to increased commodity price risk due to the elimination of the FAC, sufficient supply has been placed under contract to limit the Company’s exposure to market risk at any given time. When this supply is added to CILCO generation capacity, a reserve margin of over 10% is experienced, based on a peak load of 1,270 MW during the summer cooling season. Since CILCO supplies over 90% of its native load with its generation capacity, generation can be adjusted on a real-time basis to match actual load at any given time. CILCO is subject to the risk that generation becomes unavailable due to forced outages. The Company’s historical unplanned outage rate is 5.1%. In the event that CILCO generation and purchased supply is insufficient to meet load requirements, CILCO would have to purchase electric supply from the market at prevailing market rates.

The market risk inherent in the non-regulated activities of CILCORP and its subsidiaries is the potential loss arising from adverse changes in natural gas and electric commodity prices relative to the physical and financial positions that the Company maintains. The prices of natural gas and electricity are subject to fluctuations resulting from changes in supply and demand. The Company is engaged in non-regulated electric retail and natural gas sales in Illinois, including wholesale power purchases and sales to utilize its electric generating capability. At September 30, 2002, these non-regulated activities had net open market price risk positions of approximately 289,000 MWh of electricity and 220,000 Mcf of natural gas. A market price sensitivity of 10% applied to positions open in the next twelve months is not material to the Company. See Note 3 for a discussion of the Company’s use of financial derivatives for hedging purposes. Due to the high correlation between the changes in the value of the financial instrument positions held by the Company and the change in price of the underlying commodity, the net effect on the Company’s net income resulting from the change in value of these financial instruments is not expected to be material.

Item 4. Controls and Procedures

Evaluation of Disclosure controls and Procedures. CILCORP’s vice president, CILCORP’s chief financial officer, CILCO’s president and CILCO’s chief financial officer, after evaluating the effectiveness of the Company’s “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-14(c)) as of a date (the “Evaluation Date”) within 90 days before the filing date of this quarterly report, have concluded that as of the Evaluation Date, our disclosure controls and procedures were effective to ensure that material information relating to us and our consolidated subsidiaries is recorded, processed, summarized and reported in a timely manner.

Changes in Internal Controls. There were no significant changes in our internal controls or, to our knowledge, in other factors that could significantly affect such controls subsequent to the Evaluation Date.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Reference is made to “Environmental Matters” of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and to “Note 7 - Commitments and Contingencies” of Item 8. Financial Statements and Supplementary Data in the Company’s 2001 Annual Report on Form 10-K and to “Note 2 - Contingencies”, herein, for certain pending legal proceedings and/or proceedings known to be contemplated by governmental authorities.

The Company and its subsidiaries are subject to certain claims and lawsuits in connection with work performed in the ordinary course of their businesses. Except as otherwise referred to above, in the opinion of management, all such claims currently pending either will not result in a material adverse effect on the financial position and results of operations of the Company or are adequately covered by: (i) insurance; (ii) contractual or statutory indemnification; and/or (iii) reserves for potential losses.

Item 5. Other Information

None

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits

99.1 Statement of President Under 18 U.S.C. §1350

99.2 Statement of Chief Financial Officer Under 18 U.S.C. §1350

99.3 Statement of Chief Executive Officer Under 18 U.S.C. §1350

99.4 Statement of Chief Financial Officer Under 18 U.S.C. §1350

(b) Reports on Form 8-K

None

SIGNATURES

Pursuant to the requirements of the Securities Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		CILCORP Inc.
		(Registrant)
Date November 8, 2002
		/s/ L. M. Lee
		President
Date November 8, 2002
		/s/ T. S. Romanowski
		Chief Financial Officer
		And Treasurer
		CENTRAL ILLINOIS LIGHT COMPANY
		(Registrant)
Date November 8, 2002
		/s/ L. M. Lee
		Chief Executive Officer
Date November 8, 2002
		/s/ T. S. Romanowski
		Chief Financial Officer
		And Treasurer

CERTIFICATIONS

CERTIFICATION OF VICE PRESIDENT

I, Robert J. Sprowls, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CILCORP Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 8, 2002 /s/ Robert J. Sprowls Vice President

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Thomas S. Romanowski, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CILCORP Inc.;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: November 8, 2002 /s/ Thomas S. Romanowski Chief Financial Officer

CERTIFICATION OF PRESIDENT

I, Robert J. Sprowls, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Central Illinois Light Company;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: November 8, 2002 /s/ Robert J. Sprowls President

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Thomas S. Romanowski, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Central Illinois Light Company;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: November 8, 2002 /s/ Thomas S. Romanowski Chief Financial Officer

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