UNION ELECTRIC CO - Quarter Report: 2005 March (Form 10-Q)

Three Months

Joint Dispatch Agreement

UE sales to Genco

Genco sales to UE

1Q 2005 Combined 10-Q for Ameren Corporation and Subsidiaries

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 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 March 31, 2005

( ) Transition report pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

for the transition period from ___ to ____.

Commission File Number	Exact Name of Registrant as specified in its charter; State of Incorporation; Address and Telephone Number	IRS Employer 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) 677-5271

1-2732	Central Illinois Light Company	37-0211050
	(Illinois Corporation)
	300 Liberty Street
	Peoria, Illinois 61602
	(309) 677-5271

1-3004	Illinois Power Company	37-0344645
	(Illinois Corporation)
	500 S. 27th Street
	Decatur, Illinois 62521
	(217) 424-6600

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 require-ments 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)
Illinois Power Company	Yes	( )	No	(X)

The number of shares outstanding of each Registrant’s classes of common stock as of May 2, 2005, was as follows:

Ameren Corporation	Common stock, $.01 par value per share - 195,908,104

Union Electric Company	Common stock, $5 par value per share, 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

Illinois Power Company	Common stock, no par value, held by Ameren Corporation (parent company of the Registrant) - 23,000,000

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 with the reduced disclosure format allowed under that General Instruction.

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., Central Illinois Light Company, and Illinois Power 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.

On September 30, 2004, Ameren Corporation completed its acquisition of Illinois Power Company (see Note 2 - Acquisitions to our financial statements under Part I, Item 1, of this report for further information). Commencing with the Annual Report on Form 10-K for the fiscal year ended December 31, 2004, Illinois Power Company is included in the combined filing of Ameren Corporation and its other Registrant subsidiaries.

TABLE OF CONTENTS

	Page
Glossary of Terms and Abbreviations	4

Forward-looking Statements	6

PART I Financial Information

Item 1. Financial Statements (Unaudited)
Ameren Corporation
Consolidated Statement of Income	7
Consolidated Balance Sheet	8
Consolidated Statement of Cash Flows	9
Union Electric Company
Consolidated Statement of Income	10
Consolidated Balance Sheet	11
Consolidated Statement of Cash Flows	12
Central Illinois Public Service Company
Statement of Income	13
Balance Sheet	14
Statement of Cash Flows	15
Ameren Energy Generating Company
Consolidated Statement of Income	16
Consolidated Balance Sheet	17
Consolidated Statement of Cash Flows	18
CILCORP Inc.
Consolidated Statement of Income	19
Consolidated Balance Sheet	20
Consolidated Statement of Cash Flows	21
Central Illinois Light Company
Consolidated Statement of Income	22
Consolidated Balance Sheet	23
Consolidated Statement of Cash Flows	24
Illinois Power Company
Consolidated Statement of Income	25
Consolidated Balance Sheet	26
Consolidated Statement of Cash Flows	27

Combined Notes to Financial Statements	28

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
Item 3. Quantitative and Qualitative Disclosures About Market Risk	68
Item 4. Controls and Procedures	71

PART II Other Information
Item 1. Legal Proceedings	72
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	72
Item 6 Exhibits	72

Signatures	74

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 on page 6 of 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.

GLOSSARY OF TERMS AND ABBREVIATIONS

We use the words “our,” “we” or “us” with respect to certain information that relates to all Ameren Companies, as defined below. When appropriate, subsidiaries of Ameren are named specifically as we discuss their various business activities.

AERG - AmerenEnergy Resources Generating Company, a CILCO subsidiary that operates a non-rate-regulated electric generation business in Illinois.

AFS - Ameren Energy Fuels and Services Company, a Resources Company subsidiary that procures fuel and natural gas and manages the related risks for the Ameren Companies.

Ameren - Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.

Ameren Companies - The individual Registrants within the Ameren consolidated group.

Ameren Energy - Ameren Energy, Inc., an Ameren Corporation subsidiary that 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, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.

Capacity factor - A percentage measure that indicates how much of an electric power generating unit’s capacity was used during a specific period.

CILCO - Central Illinois Light Company, a CILCORP subsidiary that operates a rate-regulated electric transmission and distribution business, a primarily non-rate-regulated electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business, all in Illinois, as AmerenCILCO. CILCO owns all of the common stock of AERG.

CILCORP - CILCORP Inc., an Ameren Corporation subsidiary that operates as a holding company for CILCO.

CIPS - Central Illinois Public Service Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS.

CT - Combustion turbine electric generation equipment used primarily for peaking capacity.

Development Company - Ameren Energy Development Company, a Resources Company subsidiary and Genco parent, which primarily develops and constructs generating facilities for Genco.

DMG - Dynegy Midwest Generation, Inc., a Dynegy subsidiary.

DOE - Department of Energy, a U.S. government agency.

DRPlus - Ameren Corporation’s dividend reinvestment and direct stock purchase plan.

Dynegy - Dynegy Inc.

DYPM - Dynegy Power Marketing, Inc., a Dynegy subsidiary.

EEI - Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary (40% owned by UE and 40% owned by Resources Company) that operates electric generation and transmission facilities in Illinois. The remaining 20% is owned by Kentucky Utilities Company.

EPA - Environmental Protection Agency, a U.S. government agency.

Equivalent availability factor - A measure that indicates the percentage of time an electric power generating unit 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.

FERC - Federal Energy Regulatory Commission, a U.S. government agency.

FIN - A FASB Interpretation intended to clarify accounting pronouncements previously issued by the FASB.

Fitch - Fitch Ratings, a credit rating agency.

FSP - FASB Staff Position, which provides application guidance on FASB literature.

FTRs - Financial Transmission Rights, financial instruments that entitle the holder to pay or receive compensation for certain congestion-related transmission charges between two designated points.

GAAP - Generally accepted accounting principles in the United States of America.

Genco - Ameren Energy Generating Company, a Development Company subsidiary that operates a non-rate-regulated electric generation business in Illinois and Missouri.

Gigawatthour - One thousand megawatthours.

GridAmerica Companies - UE, CIPS, American Transmission Systems, Inc. (a subsidiary of FirstEnergy Corp.), and Northern Indiana Public Service Company (a subsidiary of NiSource, Inc.). Effective November 1, 2005, UE and CIPS will withdraw from GridAmerica and become direct members of MISO.

Heating degree-days - The summation of negative differences between the mean daily temperature and a 65- degree 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.

ICC - Illinois Commerce Commission, a state agency that regulates the Illinois utility businesses and operations of CIPS, CILCO, IP and prior to May 2, 2005, UE.

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.

Illinova - Illinova Corporation, the former parent company of IP.

IP - Illinois Power Company, which was acquired from Dynegy by, and became a subsidiary of, Ameren Corporation on September 30, 2004. IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenIP.

IP LLC - Illinois Power Securitization Limited Liability Company, which is a special-purpose Delaware limited liability company. Under FIN No. 46R, “Consolidation of Variable-interest Entities,” IP LLC was no longer consolidated within IP’s financial statements as of December 31, 2003.

IP SPT - Illinois Power Special Purpose Trust, which was created as a subsidiary of IP LLC to issue TFNs as allowed under Illinois’ deregulation legislation. Pursuant to FIN No. 46R, IP SPT is a variable-interest entity, as the equity investment is not sufficient to permit IP SPT to finance its activities without additional subordinated debt. As of December 31, 2003, under FIN No. 46R, IP SPT was no longer consolidated within IP’s financial statements.

Jobs Creation Act - The American Jobs Creation Act of 2004.

Kilowatthour - A measure of electricity consumption equivalent to the use of 1,000 watts of power over a period of one hour.

Marketing Company - Ameren Energy Marketing Company, a Resources Company subsidiary that markets power, primarily for periods over one year.

Medina Valley - AmerenEnergy Medina Valley Cogen (No. 4) LLC and its subsidiaries, which are all Resources Company subsidiaries, which indirectly own a 40-megawatt gas-fired electric generation plant.

Megawatthour - One thousand kilowatthours.

MGP - Manufactured gas plant.

MISO - Midwest Independent Transmission System Operator, Inc.

MISO Day Two Market - A market that began operating on April 1, 2005, and uses market-based pricing to compensate market participants for power, incorporating transmission congestion and line losses. The previous system required generators to make advance reservations for transmission service.

Money pool - Borrowing agreements among Ameren and its 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. These are 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.

Native Load Customers - The wholesale and retail customers on whose behalf UE, CIPS, CILCO and IP have undertaken an obligation to construct and operate an electric transmission and distribution system.

NOPR - Notice of Proposed Rulemaking issued by the FERC.

NO_x - Nitrogen oxide.

NRC - Nuclear Regulatory Commission, a U.S. government agency.

NYMEX - New York Mercantile Exchange.

OCI - Other Comprehensive Income (Loss) as defined by GAAP.

PGA - Purchased Gas Adjustment tariffs, which allow the passing through of the actual cost of natural gas to utility customers.

PUHCA - Public Utility Holding Company Act of 1935, as amended.

Resources Company - Ameren Energy Resources Company, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Development Company, Genco, Marketing Company, AFS, and Medina Valley.

RTO - Regional Transmission Organization.

S&P - Standard and Poor’s, a division of The McGraw Hill Companies, Inc., a credit rating agency.

SEC - Securities and Exchange Commission, a U.S. government agency.

SFAS - Statement of Financial Accounting Standards, the accounting and financial reporting rules issued by the FASB.

SO₂- Sulfur dioxide.

TFN - Transitional Funding Trust Notes issued by IP SPT as allowed under Illinois’ deregulation legislation. IP must designate a portion of cash received from customer billings to fund payment of the TFNs. The proceeds received by IP are remitted to IP SPT and are restricted for the sole purpose of making payments of principal and interest on, and paying other fees and expenses related to, the TFNs. Since the application of FIN No. 46R, IP does not consolidate IP SPT; the obligation to IP SPT appears on IP’s balance sheet.

UE - Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri and prior to May 2, 2005, in Illinois, as AmerenUE.

FORWARD-LOOKING STATEMENTS

Statements in this report not based on historical facts are considered “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” provi-sions 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 our other filings with the SEC, could cause actual results to differ materially from management expectations as suggested by such forward-looking statements:

·	regulatory actions, including changes in regulatory policies and ratemaking determinations;

·	changes in laws and other governmental actions, including monetary and fiscal policies;

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, and the implementation of deregulation, such as when the current electric rate freeze and current power supply contracts expire in Illinois in 2006;

·	the effects of participation in the MISO;

·	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;

·	the effectiveness of our risk management strategies and the use of financial and derivative instruments;

·	prices for power in the Midwest;

·	business and economic conditions, including their impact on interest rates;

·	disruptions of the capital markets or other events that make the Ameren Companies’ access to necessary capital more difficult or costly;

·	the impact of the adoption of new accounting standards and the application of appropriate technical accounting rules and guidance;

·	actions of credit ratings agencies and the effects of such actions;

·	weather conditions and other natural phenomena;

·	generation plant construction, installation and performance;

·	operation of UE’s nuclear power facility, including planned and unplanned outages, and decommissioning costs;

·	the effects of strategic initiatives, including acquisitions and divestitures;

·	the impact of current environmental regulations on utilities and power generating companies and the expectation that more stringent requirements will be introduced over time, which could have a negative financial effect;

·	labor disputes, future wages and employee benefits costs, including changes in returns on benefit plan assets;

·	difficulties in integrating IP with Ameren’s other businesses;

·	changes in the energy markets, environmental laws or regulations, interest rates, or other factors that could adversely affect assumptions in connection with the CILCORP and IP acquisitions;

·	the impact of conditions imposed by regulators in connection with their approval of Ameren’s acquisition of IP;

·	the inability of our counterparties to meet their obligations with respect to our contracts and financial instruments;

·	the cost and availability of transmission capacity;

·	legal and administrative proceedings; and

·	acts of sabotage, war or terrorist activities.

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 to reflect new information, future events, or otherwise.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions, except per share amounts)

	Three Months Ended
	March 31,
	2005			2004
Operating Revenues:
Electric	$	1,129		$	915
Gas		496			301
Other		1			2
Total operating revenues		1,626			1,218

Operating Expenses:
Fuel and purchased power		416			273
Gas purchased for resale		354			213
Other operations and maintenance		345			306
Depreciation and amortization		157			130
Taxes other than income taxes		91			80
Total operating expenses		1,363			1,002

Operating Income		263			216

Other Income and (Deductions):
Miscellaneous income		7			8
Miscellaneous expense		(1	)		(1	)
Total other income and (deductions)		6			7

Interest Charges and Preferred Dividends:
Interest		74			64
Preferred dividends of subsidiaries		3			3
Net interest charges and preferred dividends		77			67

Income Before Income Taxes		192			156

Income Taxes		71			59

Net Income	$	121		$	97

Earnings per Common Share – Basic and Diluted	$	0.62		$	0.55

Dividends per Common Share	$	0.635		$	0.635
Average Common Shares Outstanding		195.3			174.3

The accompanying notes are an integral part of these consolidated financial statements.

AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except per share amounts)

	March 31,			December 31,
	2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	30		$	69
Accounts receivables – trade (less allowance for doubtful
accounts of $16 and $14, respectively)		501			442
Unbilled revenue		246			336
Miscellaneous accounts and notes receivable		44			38
Materials and supplies		563			623
Other current assets		54			74
Total current assets		1,438			1,582
Property and Plant, Net		13,332			13,297
Investments and Other Noncurrent Assets:
Investments in leveraged leases		136			140
Nuclear decommissioning trust fund		235			235
Goodwill and other intangibles, net		927			940
Other assets		449			411
Total investments and other noncurrent assets		1,747			1,726
Regulatory Assets		816			829
TOTAL ASSETS	$	17,333		$	17,434


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	351		$	423
Short-term debt		421			417
Accounts and wages payable		365			567
Taxes accrued		113			26
Other current liabilities		425			374
Total current liabilities		1,675			1,807
Long-term Debt, Net		4,982			5,021
Preferred Stock of Subsidiary Subject to Mandatory Redemption		20			20
Deferred Credits and Other Noncurrent Liabilities:
Accumulated deferred income taxes, net		1,870			1,886
Accumulated deferred investment tax credits		137			139
Regulatory liabilities		1,056			1,042
Asset retirement obligations		445			439
Accrued pension and other postretirement benefits		806			756
Other deferred credits and liabilities		295			315
Total deferred credits and other noncurrent liabilities		4,609			4,577
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption		195			195
Minority Interest in Consolidated Subsidiaries		14			14
Commitments and Contingencies (Notes 3, 9 and 10)
Stockholders' Equity:
Common stock, $.01 par value, 400.0 shares authorized –
shares outstanding of 195.8 and 195.2, respectively		2			2
Other paid-in capital, principally premium on common stock		3,976			3,949
Retained earnings		1,903			1,904
Accumulated other comprehensive loss		(28	)		(45	)
Other		(15	)		(10	)
Total stockholders’ equity		5,838			5,800
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	17,333		$	17,434


The accompanying notes are an integral part of these consolidated financial statements.

AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)

	Three Months Ended
	March 31,
		2005			2004
Cash Flows From Operating Activities:
Net income	$	121		$	97
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		157			130
Amortization of nuclear fuel		8			8
Amortization of debt issuance costs and premium/discounts		3			3
Deferred income taxes, net		3			(24	)
Deferred investment tax credits, net		(2	)		(3	)
Coal contract settlement		-			9
Other		23			30
Changes in assets and liabilities, excluding the effects of the acquisitions:
Receivables, net		20			37
Materials and supplies		60			75
Accounts and wages payable		(168	)		(181	)
Taxes accrued		87			79
Assets, other		(1	)		(15	)
Liabilities, other		46			(1	)
Net cash provided by operating activities		357			244

Cash Flows From Investing Activities:
Capital expenditures		(210	)		(165	)
Nuclear fuel expenditures		(3	)		(3	)
Other		11			7
Net cash used in investing activities		(202	)		(161	)

Cash Flows From Financing Activities:
Dividends on common stock		(124	)		(116	)
Capital issuance costs		-			(22	)
Redemptions, repurchases, and maturities:
Nuclear fuel lease		-			(67	)
Short-term debt		-			(159	)
Long-term debt		(189	)		(100	)
Issuances:
Common stock		30			903
Short-term debt		4			-
Long-term debt		85			-
Net cash provided by (used in) financing activities		(194	)		439

Net change in cash and cash equivalents		(39	)		522
Cash and cash equivalents at beginning of year		69			111
Cash and cash equivalents at end of period	$	30		$	633

Cash Paid During the Periods:
Interest	$	41		$	45
Income taxes, net		4			34

The accompanying notes are an integral part of these consolidated financial statements.

UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)

	Three Months Ended,
	March 31,
	2005			2004
Operating Revenues:
Electric	$	533		$	548
Gas		75			72
Total operating revenues		608			620

Operating Expenses:
Fuel and purchased power		144			146
Gas purchased for resale		45			44
Other operations and maintenance		181			190
Depreciation and amortization		76			72
Taxes other than income taxes		55			55
Total operating expenses		501			507

Operating Income		107			113

Other Income and (Deductions):
Miscellaneous income		8			5
Miscellaneous expense		(2	)		(1	)
Total other income and (deductions)		6			4

Interest Charges		25			25

Income Before Income Taxes		88			92

Income Taxes		31			34

Net Income		57			58

Preferred Stock Dividends		1			1

Net Income Available to Common Stockholder	$	56		$	57



The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.

UNION ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except per share amounts)

	March 31,			December 31,
	2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	2		$	48
Accounts receivable – trade (less allowance for doubtful
accounts of $6 and $3, respectively)		182			188
Unbilled revenue		94			118
Miscellaneous accounts and notes receivable		15			20
Advances to money pool, net		64			-
Materials and supplies		182			199
Other current assets		12			18
Total current assets		551			591
Property and Plant, Net		7,106			7,075
Investments and Other Noncurrent Assets:
Nuclear decommissioning trust fund		235			235
Other assets		271			263
Total investments and other noncurrent assets		506			498
Regulatory Assets		585			585
TOTAL ASSETS	$	8,748		$	8,749


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	3		$	3
Short-term debt		384			375
Accounts and wages payable		154			326
Taxes accrued		108			51
Other current liabilities		103			108
Total current liabilities		752			863
Long-term Debt, Net		2,143			2,059
Deferred Credits and Other Noncurrent Liabilities:
Accumulated deferred income taxes, net		1,217			1,217
Accumulated deferred investment tax credits		106			108
Regulatory liabilities		780			776
Asset retirement obligations		437			431
Accrued pension and other postretirement benefits		239			219
Other deferred credits and liabilities		78			80
Total deferred credits and other noncurrent liabilities		2,857			2,831
Commitments and Contingencies (Notes 3, 9 and 10)
Stockholders' 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		718			718
Retained earnings		1,685			1,688
Accumulated other comprehensive loss		(31	)		(34	)
Total stockholders' equity		2,996			2,996
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	8,748		$	8,749

The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.

UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)

	Three Months Ended
	March 31,
	2005			2004
Cash Flows From Operating Activities:
Net income	$	57		$	58
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		76			72
Amortization of nuclear fuel		8			8
Amortization of debt issuance costs and premium/discounts		2			1
Deferred income taxes, net		(11	)		(22	)
Deferred investment tax credits, net		(2	)		(1	)
Coal contract settlement		-			9
Pension accrual		20			23
Other		2			2
Changes in assets and liabilities:
Receivables, net		26			11
Materials and supplies		17			14
Accounts and wages payable		(153	)		(142	)
Taxes accrued		57			63
Assets, other		9			15
Liabilities, other		(1	)		(19	)
Net cash provided by operating activities		107			92

Cash Flows From Investing Activities:
Capital expenditures		(117	)		(105	)
Nuclear fuel expenditures		(3	)		(3	)
Changes in money pool advances		(64	)		13
Other		(1	)		-
Net cash used in investing activities		(185	)		(95	)

Cash Flows From Financing Activities:
Dividends on common stock		(60	)		(79	)
Dividends on preferred stock		(1	)		(1	)
Capital issuance costs		(1	)		-
Changes in money pool borrowings		-			292
Redemptions, repurchases, and maturities:
Nuclear fuel lease		-			(67	)
Short-term debt		-			(150	)
Issuances:
Short-term debt		9			-
Long-term debt		85			-
Net cash provided by (used) in financing activities		32			(5	)

Net change in cash and cash equivalents		(46	)		(8	)
Cash and cash equivalents at beginning of year		48			15
Cash and cash equivalents at end of period	$	2		$	7

Cash Paid During the Periods:
Interest	$	17		$	27
Income taxes, net		-			17


The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF INCOME
(Unaudited) (In millions)

	Three Months Ended
	March 31,
	2005		2004
Operating Revenues:
Electric	$	128	$	127
Gas		84		85
Total operating revenues		212		212

Operating Expenses:
Purchased power		86		80
Gas purchased for resale		59		56
Other operations and maintenance		33		37
Depreciation and amortization		13		13
Taxes other than income taxes		8		9
Total operating expenses		199		195

Operating Income		13		17

Other Income and (Deductions):
Miscellaneous income		5		7
Total other income and (deductions)		5		7

Interest Charges		7		8

Income Before Income Taxes		11		16

Income Taxes		3		6

Net Income		8		10

Preferred Stock Dividends		1		1

Net Income Available to Common Stockholder	$	7	$	9

The accompanying notes as they relate to CIPS are an integral part of these consolidated financial statements.

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
BALANCE SHEET
(Unaudited) (In millions)

	March 31,		December 31,
	2005		2004
ASSETS
Current Assets:
Cash and cash equivalents	$	2	$	2
Accounts receivable – trade (less allowance for doubtful
accounts of $1 and $1, respectively)		66		48
Unbilled revenue		52		71
Miscellaneous accounts and notes receivable		12		13
Current portion of intercompany note receivable – Genco		249		249
Current portion of intercompany tax receivable – Genco		11		11
Materials and supplies		25		56
Other current assets		10		18
Total current assets		427		468
Property and Plant, Net		950		953
Investments and Other Noncurrent Assets:
Intercompany tax receivable – Genco		135		138
Other assets		35		23
Total investments and other noncurrent assets		170		161
Regulatory Assets		31		33
TOTAL ASSETS	$	1,578	$	1,615


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	20	$	20
Accounts and wages payable		67		76
Borrowings from money pool		13		68
Taxes accrued		7		-
Other current liabilities		38		32
Total current liabilities		145		196
Long-term Debt, Net		430		430
Deferred Credits and Other Noncurrent Liabilities:
Accumulated deferred income taxes, net		293		298
Accumulated deferred investment tax credits		10		10
Regulatory liabilities		155		151
Other deferred credits and liabilities		42		40
Total deferred credits and other noncurrent liabilities		500		499
Commitments and Contingencies (Notes 3 and 9)
Stockholders' Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding		-		-
Other paid-in capital		121		121
Preferred stock not subject to mandatory redemption		50		50
Retained earnings		330		323
Accumulated other comprehensive income (loss)		2		(4	)
Total stockholders' equity		503		490
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,578	$	1,615

The accompanying notes as they relate to CIPS are an integral part of these consolidated financial statements.

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF CASH FLOWS
(Unaudited) (In millions)

	Three Months Ended
	March 31,
	2005			2004
Cash Flows From Operating Activities:
Net income	$	8		$	10
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		13			13
Deferred income taxes, net		(2	)		(9	)
Other		4			2
Changes in assets and liabilities:
Receivables, net		5			7
Materials and supplies		31			26
Accounts and wages payable		(9	)		(9	)
Taxes accrued		7			11
Assets, other		9			(7	)
Liabilities, other		-			7
Net cash provided by operating activities		66			51

Cash Flows From Investing Activities:
Capital expenditures		(10	)		(9	)
Net cash used in investing activities		(10	)		(9	)

Cash Flows From Financing Activities:
Dividends on common stock		-			(19	)
Dividends on preferred stock		(1	)		(1	)
Changes in money pool borrowings		(55	)		(24	)
Net cash used in financing activities		(56	)		(44	)

Net change in cash and cash equivalents		-			(2	)
Cash and cash equivalents at beginning of year		2			16
Cash and cash equivalents at end of period	$	2		$	14

Cash Paid During the Periods:
Interest	$	2		$	3
Income taxes paid (refunded), net		(5	)		6

The accompanying notes as they relate to CIPS are an integral part of these consolidated financial statements.

AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)

	Three Months Ended
	March 31,
	2005			2004
Operating Revenues:
Electric	$	225		$	216
Total operating revenues		225			216

Operating Expenses:
Fuel and purchased power		99			94
Other operations and maintenance		38			28
Depreciation and amortization		19			19
Taxes other than income taxes		(2	)		5
Total operating expenses		154			146

Operating Income		71			70

Other Income and (Deductions):
Miscellaneous expense		-			(1	)
Total other income and (deductions)		-			(1	)

Interest Charges		21			23

Income Before Income Taxes		50			46

Income Taxes		19			17

Net Income	$	31		$	29

The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.

AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except shares)

	March 31,			December 31,
	2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	-		$	1
Accounts receivable		102			96
Miscellaneous accounts and notes receivable		7			-
Materials and supplies		140			89
Other current assets		1			2
Total current assets		250			188
Property and Plant, Net		1,744			1,749
Other Noncurrent Assets		13			18
TOTAL ASSETS	$	2,007		$	1,955


LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt	$	225		$	225
Current portion of intercompany notes payable – CIPS and Ameren		283			283
Borrowings from money pool		115			116
Accounts and wages payable		72			54
Current portion of intercompany tax payable – CIPS		11			11
Taxes accrued		34			35
Other current liabilities		37			22
Total current liabilities		777			746
Long-term Debt, Net		473			473
Deferred Credits and Other Noncurrent Liabilities:
Accumulated deferred income taxes, net		151			144
Accumulated deferred investment tax credits		11			12
Intercompany tax payable – CIPS		135			138
Accrued pension and other postretirement benefits		7			5
Other deferred credits and liabilities		2			2
Total deferred credits and other noncurrent liabilities		306			301
Commitments and Contingencies (Notes 3 and 9)
Stockholder's Equity:
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding		-			-
Other paid-in capital		225			225
Retained earnings		228			211
Accumulated other comprehensive loss		(2	)		(1	)
Total stockholder's equity		451			435
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	2,007		$	1,955

The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.

AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Three Months Ended
	March 31,
		2005			2004
Cash Flows From Operating Activities:
Net income	$	31		$	29
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		19			19
Deferred income taxes, net		7			9
Deferred investment tax credits, net		(1	)		-
Other		1			-
Changes in assets and liabilities:
Accounts receivable		(13	)		(5	)
Materials and supplies		(51	)		2
Accounts and wages payable		28			(14	)
Taxes accrued, net		(1	)		16
Assets, other		6			4
Liabilities, other		12			7
Net cash provided by operating activities		38			67

Cash Flows From Investing Activities:
Capital expenditures		(24	)		(16	)
Net cash used in investing activities		(24	)		(16	)

Cash Flows From Financing Activities:
Dividends on common stock		(14	)		(18	)
Changes in money pool borrowings		(1	)		(33	)
Net cash used in financing activities		(15	)		(51	)

Net change in cash and cash equivalents		(1	)		-
Cash and cash equivalents at beginning of year		1			2
Cash and cash equivalents at end of period	$	-		$	2

Cash Paid During the Periods:
Interest	$	8		$	10
Income taxes paid (refunded)		10			(3	)

The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.

CILCORP INC.
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)


	Three Months Ended
	March 31,
	2005			2004
Operating Revenues:
Electric	$	93		$	98
Gas		128			141
Other		1			1
Total operating revenues		222			240

Operating Expenses:
Fuel and purchased power		33			45
Gas purchased for resale		94			107
Other operations and maintenance		42			43
Depreciation and amortization		18			16
Taxes other than income taxes		7			9
Total operating expenses		194			220

Operating Income		28			20

Other Income and (Deductions):
Miscellaneous expense		(2	)		(1	)
Total other income and (deductions)		(2	)		(1	)

Interest Charges and Preferred Dividends:
Interest		12			12
Preferred dividends of subsidiaries		1			-
Net interest charges and preferred dividends		13			12

Income Before Income Taxes		13			7

Income Taxes		4			3

Net Income	$	9		$	4

The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.

CILCORP INC.
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except shares)

	March 31,			December 31,
		2005			2004

ASSETS
Current Assets:
Cash and cash equivalents	$	4		$	7
Accounts receivables – trade (less allowance for doubtful
accounts of $3 and $3, respectively)		58			46
Unbilled revenue		32			46
Miscellaneous accounts and notes receivable		7			9
Materials and supplies		120			134
Other current assets		6			19
Total current assets		227			261
Property and Plant, Net		1,178			1,179
Investments and Other Noncurrent Assets:
Investments in leveraged leases		111			113
Goodwill and other intangibles, net		559			559
Other assets		54			33
Total investments and other noncurrent assets		724			705
Regulatory Assets		11			11
TOTAL ASSETS	$	2,140		$	2,156

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt	$	16		$	16
Borrowings from money pool, net		165			166
Intercompany note payable – Ameren		76			72
Accounts and wages payable		75			99
Other current liabilities		72			58
Total current liabilities		404			411
Long-term Debt, Net		621			623
Preferred Stock of Subsidiary Subject to Mandatory Redemption		20			20
Deferred Credits and Other Noncurrent Liabilities:
Accumulated deferred income taxes, net		208			214
Accumulated deferred investment tax credits		9			10
Regulatory liabilities		41			38
Accrued pension and other postretirement benefits		247			242
Other deferred credits and liabilities		29			31
Total deferred credits and other noncurrent liabilities		534			535
Preferred Stock of Subsidiary Not Subject to Mandatory Redemption		19			19
Commitments and Contingencies (Notes 3 and 9)
Stockholder's Equity:
Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding		-			-
Other paid-in capital		565			565
Retained earnings (deficit)		(42	)		(21	)
Accumulated other comprehensive income		19			4
Total stockholder's equity		542			548
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	2,140		$	2,156


The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.

CILCORP INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)


	Three Months Ended
	March 31,
		2005			2004
Cash Flows From Operating Activities:
Net income	$	9		$	4
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		18			16
Deferred income taxes, net		(8	)		2
Other		8			3
Changes in assets and liabilities:
Receivables, net		4			19
Materials and supplies		14			33
Accounts and wages payable		(24	)		7
Taxes accrued		(9	)		1
Assets, other		13			(4	)
Liabilities, other		16			14
Net cash provided by operating activities		41			95

Cash Flows From Investing Activities:
Capital expenditures		(19	)		(35	)
Changes in money pool advances		4			-
Other		2			2
Net cash used in investing activities		(13	)		(33	)

Cash Flows From Financing Activities:
Dividends on common stock		(30	)		-
Changes in money pool borrowings		(5	)		47
Proceeds from intercompany note payable – Ameren		4			-
Redemptions, repurchases, and maturities:
Intercompany note payable – Ameren		-			(8	)
Long-term debt		-			(100	)
Net cash used in financing activities		(31	)		(61	)

Net change in cash and cash equivalents		(3	)		1
Cash and cash equivalents at beginning of period		7			11
Cash and cash equivalents at end of period	$	4		$	12

Cash Paid During the Periods:
Interest	$	3		$	4
Income taxes		1			3

The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.

CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)

	Three Months Ended
	March 31,
		2005			2004
Operating Revenues:
Electric	$	93		$	98
Gas		125			127
Total operating revenues		218			225

Operating Expenses:
Fuel and purchased power		31			45
Gas purchased for resale		91			94
Other operations and maintenance		44			47
Depreciation and amortization		17			16
Taxes other than income taxes		6			8
Total operating expenses		189			210

Operating Income		29			15

Other Income and (Deductions):
Miscellaneous expense		(1	)		(1	)
Total other income and (deductions)		(1	)		(1	)

Interest Charges		4			3

Income Before Income Taxes		24			11

Income Taxes		8			5

Net Income		16			6

Preferred Stock Dividends		1			-

Net Income Available to Common Stockholder	$	15		$	6


The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.

CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions)

	March 31,		December 31,
	2005		2004
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	2
Accounts receivable - trade (less allowance for doubtful
accounts of $3 and $3, respectively)		58		46
Unbilled revenue		32		43
Miscellaneous accounts and notes receivable		7		11
Materials and supplies		55		68
Other current assets		4		6
Total current assets		157		176
Property and Plant, Net		1,165		1,165
Other Noncurrent Assets		51		29
Regulatory Assets		11		11
TOTAL ASSETS	$	1,384	$	1,381

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	16	$	16
Borrowings from money pool		163		169
Accounts and wages payable		74		95
Taxes accrued		9		-
Other current liabilities		53		49
Total current liabilities		315		329
Long-term Debt, Net		122		122
Preferred Stock Subject to Mandatory Redemption		20		20
Deferred Credits and Other Noncurrent Liabilities:
Accumulated deferred income taxes, net		127		130
Accumulated deferred investment tax credits		10		10
Regulatory liabilities		178		176
Accrued pension and other postretirement benefits		140		131
Other deferred credits and liabilities		26		26
Total deferred credits and other noncurrent liabilities		481		473
Commitments and Contingencies (Notes 3 and 9)
Stockholders' Equity:
Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding		-		-
Preferred stock not subject to mandatory redemption		19		19
Other paid-in capital		313		313
Retained earnings		111		115
Accumulated other comprehensive income (loss)		3		(10	)
Total stockholders' equity		446		437
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,384	$	1,381


The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.

CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)

	Three Months Ended
	March 31,
	2005			2004
Cash Flows From Operating Activities:
Net income	$	16		$	6
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		17			16
Deferred income taxes, net		(4	)		2
Other		11			3
Changes in assets and liabilities:
Receivables, net		3			14
Materials and supplies		13			29
Accounts and wages payable		(21	)		11
Taxes accrued		9			-
Assets, other		1			(5	)
Liabilities, other		-			3
Net cash provided by operating activities		45			79

Cash Flows From Investing Activities:
Capital expenditures		(19	)		(35	)
Net cash used in investing activities		(19	)		(35	)

Cash Flows From Financing Activities:
Dividends on common stock		(20	)		-
Dividends on preferred stock		(1	)		-
Changes in money pool borrowings		(6	)		51
Redemptions, repurchases, and maturities:
Long-term debt		-			(100	)
Net cash used in financing activities		(27	)		(49	)

Net change in cash and cash equivalents		(1	)		(5	)
Cash and cash equivalents at beginning of year		2			8
Cash and cash equivalents at end of period	$	1		$	3

Cash Paid During the Periods:
Interest	$	3		$	4
Income taxes		1			3

The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.

ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)

	-------Successor--------		------Predecessor------
	Three		Three
	Months		Months
	Ended		Ended
	March 31,		March 31,
	2005		2004
Operating Revenues:
Electric	$	235	$	247
Gas		197		210
Total operating revenues		432		457

Operating Expenses:
Purchased power		157		151
Gas purchased for resale		146		154
Other operations and maintenance		42		47
Depreciation and amortization		21		20
Amortization of regulatory assets		-		11
Taxes other than income taxes		22		21
Total operating expenses		388		404

Operating Income		44		53

Other Income and (Deductions):
Interest income from former affiliate		-		43
Miscellaneous income		2		5
Total other income and (deductions)		2		48

Interest Charges		10		39

Income Before Income Taxes		36		62

Income Taxes		14		25

Net Income		22		37

Preferred Stock Dividends		1		1

Net Income Applicable to Common Stockholder	$	21	$	36

The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.

ILLINOIS POWER COMPANY
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions)

	------------------------Successor-------------------------
	March 31,		December 31,
	2005		2004

ASSETS
Current Assets:
Cash and cash equivalents	$	5	$	5
Account receivables (less allowance for doubtful
accounts of $6 and $6, respectively)		134		101
Unbilled revenue		66		98
Miscellaneous accounts and notes receivable		17		8
Advances to money pool		105		140
Materials and supplies		33		85
Other current assets		44		69
Total current assets		404		506
Property and Plant, Net		1,999		1,984
Investments and Other Noncurrent Assets:
Investment in IP SPT		7		7
Goodwill		307		320
Other assets		41		37
Accumulated deferred income taxes		76		65
Total investments and other noncurrent assets		431		429
Regulatory Assets		187		198
TOTAL ASSETS	$	3,021	$	3,117


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	-	$	70
Current maturities of long-term debt to IP SPT		72		74
Accounts and wages payable		113		122
Taxes accrued		7		5
Other current liabilities		114		102
Total current liabilities		306		373
Long-term Debt, Net		710		713
Long-term Debt to IP SPT		254		278
Deferred Credits and Other Noncurrent Liabilities:
Regulatory liabilities		82		76
Accrued pension and other postretirement liabilities		251		248
Other deferred credits and other noncurrent liabilities		140		149
Total deferred credits and other noncurrent liabilities		473		473
Commitments and Contingencies (Notes 3 and 9)
Stockholders’ Equity:
Common stock, no par value, 100.0 shares authorized –
23.0 shares outstanding		-		-
Other paid-in-capital		1,204		1,207
Preferred stock not subject to mandatory redemption		46		46
Retained earnings		28		27
Total stockholders’ equity		1,278		1,280
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,021	$	3,117

The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.

ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)

	-------Successor-------			------Predecessor------
	Three			Three
	Months			Months
	Ended			Ended
	March 31,			March 31,
	2005			2004
Cash Flows From Operating Activities:
Net income	$	22		$	37
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		21			31
Amortization of debt issuance costs and premium/discounts		2			2
Deferred income taxes		7			(6	)
Other		(21	)		-
Changes in assets and liabilities:
Receivables, net		(10	)		3
Materials and supplies		52			32
Accounts and wages payable		(9	)		(12	)
Assets, other		4			27
Liabilities, other		45			19
Net cash provided by operating activities		113			133

Cash Flows From Investing Activities:
Capital expenditures		(31	)		(30	)
Changes in money pool advances		35			-
Other		(3	)		2
Net cash (used in) provided by investing activities		1			(28	)

Cash Flows From Financing Activities:
Dividends on common stock		(20	)		-
Dividends preferred stock		(1	)		(1	)
Redemptions, repurchases, and maturities:
Long-term debt		(92	)		(22	)
TFN overfunding		(1	)		(2	)
Net cash used in financing activities		(114	)		(25	)

Net change in cash and cash equivalents		-			80
Cash and cash equivalents at beginning of period		5			17
Cash and cash equivalents at end of year	$	5		$	97

Cash Paid During the Periods:
Interest	$	8		$	14
Income taxes paid (refunded), net		(10	)		34

The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY (Consolidated)

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

AMEREN ENERGY GENERATING COMPANY (Consolidated)

CILCORP INC. (Consolidated)

CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)

ILLINOIS POWER COMPANY (Consolidated)

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

March 31, 2005

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 transmission and 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 subsidiaries are listed below. Also see Glossary of Terms and Abbreviations.

UE, or Union Electric Company, also known as AmerenUE, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri and prior to May 2, 2005, in 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 prior to May 2, 2005, in west central Illinois. This area has an estimated population of 3 million and includes the greater St. Louis area. UE supplies electric service to 1.2 million customers and natural gas service to 140,000 customers. See Note 3 - Rate and Regulatory Matters for information regarding the May 2005 transfer of UE’s Illinois electric and natural gas transmission and distribution businesses to CIPS and the planned addition of a large new electric customer in June 2005.

CIPS, or Central Illinois Public Service Company, also known as AmerenCIPS, 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 20,000 square miles. CIPS supplies electric service to 325,000 customers and natural gas service to 170,000 customers.

Genco, or 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 representing in the aggregate approximately 2,860 megawatts of capacity and related liabilities to Genco at historical net book value. The transfer was made in exchange for a subordinated promissory note from Genco in the amount of $552 million and shares of Genco’s common stock. Since Genco commenced operations, it has acquired 25 CTs, which gave it a total installed generating capacity of approximately 4,751 megawatts as of March 31, 2005. Genco is a subsidiary of Development Company, a subsidiary of Resources Company, which is a subsidiary of Ameren. See Note 3 - Rate and Regulatory Matters for information regarding the May 2005 transfer of Genco’s 10 CTs located in Pinckneyville and Kinmundy, Illinois to UE.

CILCO, or Central Illinois Light Company, also known as AmerenCILCO, 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 transmission and distribution business in Illinois. CILCO was incorporated in Illinois in 1913. CILCORP was incorporated in Illinois in 1985. CILCO supplies electric and gas utility service to portions of central and east central Illinois in areas of 3,700 and 4,500 square miles, respectively, with an estimated population of 1 million. CILCO supplies electric service to 205,000 customers and natural gas service to 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 respect of all the outstanding stock of AERG and AERG’s assumption of certain liabilities. The net book value of the transferred assets was $378 million. No gain or loss was recognized, as the transaction was accounted for as a transfer between entities under common control. The transfer was made in conjunction with the Illinois Customer Choice Law.

IP, or Illinois Power Company, also known as AmerenIP, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren acquired IP on September 30, 2004, from Dynegy, which had acquired it as part of Illinova in early 2000. IP was incorporated in Illinois in 1923. It supplies electric and gas utility service to portions of central, east central, and southern Illinois, serving an estimated population of 1.4 million in an area of 15,000 square miles, contiguous to our other service territories. IP supplies electric service

to 600,000 customers and natural gas service to 415,000 customers, including most of the Illinois portion of the greater St. Louis area. See Note 2 -

Acquisitions and Note 8 - Related Party Transactions for further information.

Ameren has various other subsidiaries responsible for the short- and long-term marketing of power, procurement of fuel, management of commodity risks and provision of other shared services. Ameren has an 80% ownership interest in EEI through UE and Resources Company, which each own 40% of EEI. This 80% ownership in EEI includes a 20% interest indirectly acquired by Resources Company from a Dynegy subsidiary on September 30, 2004. Ameren consolidates EEI for financial reporting purposes, while UE reports 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. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income and Cash Flows for the period ended March 31, 2004, do not reflect IP’s results of operations or financial position. See Note 2 - Acquisitions for further information on the accounting for the IP acquisition. 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 information in this report is 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 better enables readers to understand the impact of these factors on Ameren’s earnings. All references in this report to earnings per share are based on diluted shares.

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 2005 reporting. These statements should be read in conjunction with the financial statements and the notes thereto included in the Ameren Companies’ combined 2004 Annual Report on Form 10-K.

As part of the acquisition of IP on September 30, 2004, Ameren “pushed down” the effects of purchase accounting to the financial statements of IP. Accordingly, IP’s postacquistion financial statements reflect a new basis of accounting, and separate financial statement amounts are presented for preacquisition (predecessor) and postacquisition (successor) periods, separated by a bold black line. As a result of the acquisition of IP, certain reclassifications have been made to make IP prior-year financial statements conform to our current presentation.

Earnings Per Share

There were no differences between Ameren’s basic and diluted earnings per share for the three month periods ended March 31, 2005 and 2004, due to an immaterial number of stock options outstanding.

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. Decommissioning costs associated with UE’s Callaway nuclear plant comprise substantially all of Ameren’s asset retirement obligations. UE has recorded asset retirement obligations related to its Callaway nuclear plant decommissioning costs and for a UE river structure. Additionally, Genco has recorded an asset retirement obligation for the retirement costs for a Genco power plant ash pond. CILCORP and CILCO have recorded asset retirement obligations related to CILCO’s power plant ash ponds (now owned by AERG).

Asset retirement obligations at Ameren and UE increased by $6 million for the quarter ended March 31, 2005, to reflect the accretion of obligations to their present value. Increases to Genco’s, CILCORP’s and CILCO’s asset retirement obligations due to accretion were immaterial during this period. Substantially all of this accretion was recorded as an increase to regulatory assets.

In February 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations,” which clarifies 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 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. An exhibit to the interpretation provides examples of when to recognize conditional asset retirement obligations, including asbestos removal and chemically treated utility poles. We are in the process of evaluating the impact of this new interpretation. It will likely require accrual of additional liabilities by the Ameren Companies and their subsidiaries and could result in increased expense, which, while not yet quantified, could be material. This interpretation is effective for us no later than December 31, 2005.

FASB Staff Position SFAS No. 106-2 - “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”

In May 2004, the FASB issued FSP SFAS 106-2, which provides guidance on accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Ameren, UE, CIPS, Genco, CILCORP and CILCO elected to adopt FSP SFAS 106-2 during the second quarter ended June 30, 2004, retroactive to January 1, 2004. The effect of the federal subsidy provided by this Medicare Prescription Drug Act was a reduction of various components of Ameren’s and principally UE’s net periodic postretirement benefit costs.

Predecessor IP’s adoption of FSP SFAS 106-2 on July 1, 2004, had no impact on IP’s results of operations, financial position or liquidity because its drug benefit was not actuarially equivalent to the drug benefit under Medicare Part D.

Revenue

Interchange Revenues

The following table presents the interchange revenues included in Operating Revenues - Electric for the three months ended March 31, 2005 and 2004:

	Three Months
	2005			2004
Ameren^(a)	$	113		$	100
UE		97			84
CIPS		9			10
Genco		42			39
CILCORP		15			11
CILCO		15			11
IP^(b)		(c	)		(c	)

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP. Includes interchange revenues for EEI of $7 million for the three months ended March 31, 2005 (2004 - $15 million).

(b)	2004 amount represents predecessor information.

(c)	Less than $1 million.

Purchased Power

The following table presents the purchased power expenses included in Operating Expenses - Fuel and Purchased Power for the three months ended March 31, 2005 and 2004. See Note 8 - Related Party Transactions for further information on affiliate purchased power transactions.

	Three Months
	2005		2004
Ameren^(a)	$	205	$	75
UE		38		53
CIPS		86		80
Genco		49		40
CILCORP		9		21
CILCO		9		21
IP^(b)		157		151

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP.

(b)	2004 amount represents predecessor information.

Excise Taxes

Excise taxes reflected on Missouri electric, Missouri gas, and Illinois gas customer bills are imposed on us. They are recorded gross in Operating Revenues and Taxes Other than Income Taxes. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer. They are recorded as tax collections payable and included in Taxes Accrued. The following table presents excise taxes recorded in Operating Revenues and Taxes Other than Income Taxes for the three months ended March 31, 2005 and 2004:

	Three Months
	2005		2004
Ameren^(a)	$	40	$	34
UE		22		24
CIPS		4		5
CILCORP		3		5
CILCO		3		5
IP^(b)		11		12

(a)	Excludes 2004 amounts for IP.

(b)	2004 amount represents predecessor information.

NOTE 2 - ACQUISITIONS

IP and EEI

On September 30, 2004, Ameren completed the acquisition of all the common stock and 662,924 shares of preferred stock of IP and an additional 20% ownership interest in EEI from subsidiaries of Dynegy. Ameren acquired IP to complement its existing Illinois gas and electric operations. The purchase included IP’s rate-regulated electric and natural gas transmission and distribution business serving 600,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. With the acquisition, IP became an Ameren subsidiary operating as AmerenIP.

The total transaction value was $2.3 billion, including the assumption of $1.8 billion of IP debt and preferred stock and consideration, including transaction costs, of $440 million in cash, net of $51 million cash acquired and a working capital adjustment of $5 million received from Dynegy in February 2005 pursuant to the terms of the stock purchase agreement. Ameren placed $100 million of the cash portion of the purchase price in a six-year escrow account pending resolution of certain contingent environmental obligations of IP and other Dynegy affiliates for which Ameren has been provided indemnification by Dynegy. See Note 9 - Commitments and Contingencies for information on the IP environmental matter to which the indemnification and escrow applies. In addition, this transaction included a fixed-price capacity power supply agreement for IP’s annual purchase in 2005 and 2006 of 2,800 megawatts of electricity from DYPM. This agreement is expected to supply about 70% of IP’s electric customer requirements during those two years. The remaining 30% of IP’s power needs in 2005 and 2006 will be supplied by other companies through contracts and open market purchases. In the event that suppliers are unable to supply the electricity required by existing agreements, IP would be forced to find alternative suppliers to meet its load requirements, thus exposing itself to market price risk, which could have a material impact on Ameren’s and IP’s results of operations, financial position or liquidity.

Ameren funded this acquisition with the issuance of new Ameren common stock. Ameren issued an aggregate of 30 million common shares in February 2004 and July 2004, which generated net proceeds of $1.3 billion. Proceeds from these issuances were used to finance the cash portion of the purchase price and to reduce IP debt assumed as part of this transaction and to pay related premiums.

In March 2005, the FERC denied appeals of its approvals of the IP and EEI acquisitions made by the Missouri Office of Public Counsel and a group of electric industrial customers of UE.

The following table presents the estimated fair values of the assets acquired and liabilities assumed at the date of Ameren’s acquisition of IP. Ameren is completing its valuations of the net assets and liabilities of IP and EEI acquired, including third-party valuations of property and plant, intangible assets, pension and other postretirement benefit obligations, and contingent obligations. As a result, the allocation of the purchase price is preliminary and subject to further adjustment. The fair value of IP’s power supply agreements, including the fixed-price capacity power supply agreement with DYPM, recorded at the acquisition date resulted in a net liability of $109 million (March 31, 2005 - $77 million). This amount will be amortized over 27 months following the acquisition date. In addition, IP recorded a fair value adjustment, resulting in a net asset of $20 million (March 31, 2005 - $18 million), for IP’s power supply agreement with EEI that expires at the end of 2005. The excess of the purchase price for IP’s common stock and preferred stock over tangible net assets acquired has been allocated preliminarily to goodwill in the amount of $307 million, net of future tax benefits. No specifically identifiable intangible assets have been identified. For income tax purposes, we expect that a portion of the purchase price will be allocated to goodwill and that such portion will be deducted ratably over a 15-year period.

Current assets	$	370
Property and plant		1,967
Investments and other noncurrent assets		397
Goodwill		307
Total assets acquired		3,041
Current liabilities		228
Long-term debt, including current maturities		1,982
Accrued pension and other postretirement liabilities		244
Other noncurrent liabilities		208
Total liabilities assumed		2,662
Preferred stock assumed		13
Net assets acquired	$	366

The following unaudited pro forma financial information presents a summary of Ameren’s consolidated results of operations for the quarter ended March 31, 2004, as if the acquisition of IP had been completed at the beginning of 2004, including pro forma adjustments, which are based upon preliminary estimates, to reflect the allocation of the purchase price to the acquired net assets. The pro forma financial information does not include cost savings that may result from the combination of Ameren with IP.

For the quarter ended March 31,		2004
Operating revenues	$	1,675
Net income		141
Earnings per share - basic		0.73
- diluted		0.73

This pro forma information is not necessarily indicative of the results of operations as they would have been had the transaction been effected on the assumed date, nor is it an indication of trends for future results.

IP’s Note Receivable from Former Affiliate of $2.3 billion was eliminated as of September 30, 2004, and prior to Ameren’s acquisition of IP to meet the conditions of the closing.

The portion of the total transaction value attributable to Ameren’s acquisition of Dynegy’s 20% ownership interest in EEI now held by Resources Company was $125 million. This transaction was accounted for as a step acquisition. The excess of the purchase price for this ownership interest over 20% of the fair value of EEI’s net assets acquired has been preliminarily allocated to property and plant ($80 million) and emission allowances ($41 million), partially offset by a net liability for power supply agreements ($25 million) and a reduction to net deferred tax assets ($38 million). The remaining excess was allocated to goodwill in the amount of $54 million, subject to change based on our final valuation.

NOTE 3 - RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings. With respect to pending matters, we are unable to predict the ultimate outcome of these regulatory proceedings, the timing of the final decisions of the various agencies or the impact on our results of operations, financial position or liquidity.

Intercompany Transfer of Illinois Service Territory and Electric Generating Facilities

Illinois Service Territory Transfer

On May 2, 2005, following the receipt of all required regulatory approvals, UE completed the transfer of its Illinois-based electric and natural gas utility businesses, including its Illinois-based distribution assets, certain of its transmission assets and approximately 100 employees, at an estimated net book value of $138 million to CIPS. Under the terms of the asset transfer agreement among UE, CIPS and Ameren, the net book value will be adjusted within 60 days after the closing to reflect the actual net book value of the transferred assets as of the closing date. UE’s electric generating facilities and a certain insignificant amount of its electric transmission and communication facilities in Illinois were not part of the transfer. Pursuant to the asset transfer agreement, UE transferred 50 percent of the assets directly to CIPS in consideration for a CIPS subordinated promissory note in the principal amount of approximately $69 million and 50 percent of the assets by means of a dividend in kind to Ameren, followed by a capital contribution by Ameren to CIPS. With the completion of this transfer, UE no longer operates as a public utility subject to ICC regulation.

In February 2005, the MoPSC issued an order approving the transfer and clarified its order in March 2005. The MoPSC’s order, as clarified, included the following principal conditions:

The order allows UE to recover in rates up to 6% of unknown UE generation-related liabilities associated with the generation that was formerly allocated to UE’s Illinois service territory if UE can show that the benefits of the transfer of the Illinois service territory outweigh these costs in future rate cases.

The order requires an amendment to the joint dispatch agreement among UE, Genco and CIPS, to declare that margins on short-term power sales will be divided based on generation output as opposed to load. This amendment is expected to provide UE with additional annual margins and Genco with reduced annual margins of $7 million to $24 million. However, this reduction to Genco’s margins is expected to be mitigated by margins received from additional power sales by Genco (through Marketing Company) to CIPS to serve the transferred UE Illinois-based electric utility business through the end of 2006 under the current power supply contracts. The increased allocation of short-term power sales margins to UE would have the effect of lowering the revenue required to be collected through rates the next time electric rates are adjusted. The MoPSC also ordered that UE may complete the transfer prior to receipt of all regulatory approvals necessary to effectuate the required amendment to the joint dispatch agreement based on UE’s commitment that for ratemaking purposes the joint dispatch agreement amendment should be deemed to be made by UE as of the date the transfer is closed. In the event that the regulatory approvals for the amendment are not obtained, this commitment would result in just the allocation of these additional margins to UE for determining the revenue requirements in the ratemaking process, with no impact on Genco’s margins.

The order requires that, in a future rate case, revenues UE could have received for incremental energy transfers under the joint dispatch agreement resulting from the service territory transfer be imputed based on market prices unless UE can show the benefits of the transfer of the Illinois service territory outweigh the difference between the market prices and the actual cost-based charges for such incremental energy transfers.

See Note 8 - Related Party Transactions for a more detailed discussion of the joint dispatch agreement.

Electric Generating Facilities Transfer

On May 2, 2005, following the receipt of all required regulatory approvals, Genco completed the transfer to UE of its 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois, for a total estimated net book value of $240 million. Under the terms of each asset transfer agreement between Genco and UE, the net book value will be adjusted within 90 days after the closing to reflect the actual net book value of the transferred assets as of the closing date. These transfers complete the remainder of UE’s commitment under the 2002 Missouri electric rate case settlement to add 700 megawatts of generation capacity by June 30, 2006.

The Illinois service territory transfer and the electric generating facilities transfer, discussed above, were accounted for at book value with no gain or loss recognition. Genco plans to use the proceeds from the transfer to reduce borrowings.

Missouri

Authority to Serve Noranda

UE filed in December 2004 with the MoPSC for authority to extend its Missouri electric service territory to include the area where Noranda Aluminum, Inc. (Noranda) is located. Earlier in December, Noranda and UE signed an agreement whereby, subject to MoPSC approval, UE would serve Noranda under a proposed tariff that had a 15-year term of service. UE would supply up to approximately 470 megawatts (peak load) electric service (or approximately 5% of UE’s generating capability, including currently committed purchases) pursuant to the proposed tariff to Noranda’s primary aluminum smelter in southeast Missouri subject to the satisfaction of certain conditions.

With the completion, on May 2, 2005, of UE’s Illinois service territory transfer to CIPS and the transfer of Genco’s 550 megawatts of CTs to UE, as discussed above in this Note, and authorizations granted by the MoPSC and the FERC, all conditions of the supply agreement between UE and Noranda were satisfied and therefore the tariff by which UE will serve Noranda will become effective June 1, 2005.

Illinois

Electric

By 2002, all of the Illinois residential, commercial and industrial customers of UE, CIPS, CILCO and IP had a choice in electric suppliers under the provisions of the Illinois Customer Choice Law. Under the Illinois Customer Choice Law, UE, CIPS, CILCO and IP rates initially were frozen through January 1, 2005. Due to an amendment to the Illinois Customer Choice Law, the rate freeze was extended through January 1, 2007. As a result of this extension, and pursuant to orders of the ICC, CIPS and Marketing Company, and CILCO and AERG extended their respective power supply agreements through December 31, 2006. See Note 8 - Related Party Transactions for a discussion of these affiliate power supply agreements.

On January 1, 2007, the current Illinois electric rate freeze expires, and the supply contracts for generation to serve the power requirements of CIPS, CILCO and IP expire on December 31, 2006. Prior to December 31, 2006, determinations must be made as to how all Illinois distribution companies will procure their generation needs and how they will set future rates for the generation and delivery service components of customer rates.

During 2004, the ICC conducted workshops to seek input from interested parties on the framework for retail electric rate determination and generation procurement after the current Illinois electric rate freeze expires on January 1, 2007, and supply contracts expire on December 31, 2006. A report issued by the ICC in late 2004 which outlines a process, among others, that would have CIPS, CILCO and IP procure power through an auction monitored by the ICC, received strong support in the ICC workshops. The form of power supply would meet the full requirements of the utility and the risk of fluctuations in power requirements would be borne by the supplier. In addition, the report noted that many stakeholders, including Ameren, supported a process whereby the price of power resulting from the auction would be the price used to determine the generation component of customer rates. This purchased power would be charged to customers through a direct pass-through mechanism. With regard to the delivery service component of customer rates, it is expected that all Illinois delivery service companies will file rate cases, at which time the delivery service component of customer rates will be updated. Genco and AERG would probably participate in the auction through Marketing Company, but there may be a limit imposed by the ICC on the maximum amount of power they could supply CIPS, CILCO and IP. In February 2005, CIPS, CILCO and IP filed with the ICC a proposed process for the generation procurement auction and a rate mechanism to pass generation costs through to customers, among other things. These proposals are subject to review and approval by the ICC within eleven months of the filings. In addition, the Illinois legislature held hearings regarding the framework for retail rate determination and generation procurement in early 2005. We cannot predict what actions, if any, the Illinois legislature will take, or whether the ICC will approve our proposals for generation procurement or electric rate determination.

Gas

IP is seeking authority from the ICC to raise its natural gas delivery rates. In March 2005, an administrative law judge issued a proposed order authorizing an annual rate increase of approximately $14 million. The ICC staff has proposed an approximate $11 million annual rate increase. By law, the ICC is required to issue its decision by May 2005. In the order approving Ameren’s acquisition of IP, the ICC prohibits IP from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond IP’s now-pending request for a gas delivery rate increase.

Federal

New Market Power Analysis Screen Order

UE, Genco, CIPS, CILCO, AERG, Development Company, Marketing Company, and Medina Valley currently have authorization from the FERC to sell wholesale power at market-based rates. As required, these Ameren companies filed an updated market power analysis with the FERC in December 2004. In March 2005, the FERC issued an order accepting the updated market power analysis of the Ameren companies and allowing them to continue selling power at market-based rates. The FERC also granted the application of IP to sell power at market-based rates in this March 2005 order.

NOTE 4 - SHORT-TERM BORROWINGS AND LIQUIDITY

Short-term borrowings typically consist of commercial paper issuances and drawings under committed bank credit facilities with maturities generally within 1 to 45 days.

The following table summarizes the short-term borrowing activity and relevant interest rates as of March 31, 2005 and December 31, 2004, respectively:

	Ameren^(a)			UE
March 31, 2005:
Short-term borrowings at March 31, 2005	$	421		$	384
Average daily borrowings outstanding during 2005		329			291
Weighted average interest rate during 2005		2.71	%		2.50	%
Peak short-term borrowings during 2005		447			403
Peak interest rate during 2005		3.01	%		2.95	%

December 31, 2004:
Short-term borrowings at December 31, 2004	$	417		$	375
Average daily borrowings outstanding during 2004		47			33
Weighted average interest rate during 2004		2.19	%		1.56	%
Peak short-term borrowings during 2004		419			375
Peak interest rate during 2004		2.97	%		2.40	%

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes amounts for IP prior to September 30, 2004.

At March 31, 2005, certain of the Ameren Companies had committed bank credit facilities totaling $1,164 million, $779 million of which was available for use, subject to applicable regulatory short-term borrowing authorizations, by UE, CIPS, CILCO, IP, and Ameren Services through a utility money pool arrangement. All of the $779 million was available for use, subject to applicable regulatory short-term borrowing authorizations, by Ameren directly, by CILCORP through direct short-term borrowings from Ameren, and by most of the non-rate-regulated subsidiaries including, but not limited to, Resources Company, Genco, Marketing Company, AFS, AERG, and Ameren Energy, through a non-state-regulated subsidiary money pool agreement. The committed bank credit facilities are used to support our commercial paper programs under which $385 million was outstanding for Ameren and UE at March 31, 2005 (December 31, 2004 - $375 million). Access to credit facilities for the Ameren Companies is subject to reduction based on use by affiliates. In the first quarter of 2005, UE increased the size of its commercial paper program from $430 million to $500 million.

Ameren has money pool agreements with and among its 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 entities. In addition, a unilateral borrowing agreement exists between Ameren, IP and Ameren Services, which enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money pool agreement, together with any outstanding external short-term borrowings by IP, may not exceed $500 million pursuant to authorizations from the ICC and the SEC under the PUHCA. Ameren Services is responsible for operation and administration of the agreements. See Note 8 - Related Party Transactions for a detailed explanation of the money pool arrangements and the unilateral borrowing agreement.

EEI has two bank credit facilities which will mature in the second quarter of 2005. EEI intends to renew both facilities for a one-year term.

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 SEC’s 50% aggregate investment limitation under the PUHCA. Based on Ameren’s aggregate investment in these exempt wholesale generators as of March 31, 2005, the maximum permissible borrowings under Ameren’s non-state-regulated subsidiary money pool pursuant to this limitation for these entities totaled $473 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’, CILCO’s and IP’s total indebtedness to 60% of total capitalization pursuant to a calculation defined in the agreement. Exceeding these debt levels would result in a default under the credit arrangements. As of March 31, 2005, the ratio of total indebtedness to total capitalization (calculated in accordance with this provision) for Ameren, UE, CIPS, CILCO and IP was 50%, 45%, 50%, 42%, and 45% respectively (2004 - 50%, 44%, 53%, 43%, not applicable for IP). In addition, certain of these credit agreements contain indebtedness cross-default provisions and material adverse

change clauses that could trigger a default under these facilities in the event that any of Ameren’s 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 arrangements contains credit rating triggers. One of EEI’s credit agreements contains a credit rating trigger under which a default can occur in the event any of the credit ratings of EEI’s sponsors (UE, CIPS, IP and Kentucky Utilities Company) fall below Baa3 or BBB- by Moody’s and S&P and the sponsors do not cover a payment default. At March 31, 2005, the Ameren Companies and EEI were in compliance with their credit agreement provisions and covenants.

NOTE 5 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to an effective SEC Form S-3 registration statement, and under our 401(k) plans, pursuant to effective SEC Form S-8 registration statements, Ameren issued a total of 0.6 million new shares of common stock in the first quarter of 2005 valued at $30 million.

In March 2002, Ameren issued $345 million of adjustable conversion-rate equity security units consisting of $345 million of senior unsecured notes due 2007 and stock purchase contracts. In February 2005, the annual interest rate on these senior unsecured notes was reset to 4.263% through a remarketing process in accordance with and as required by the original terms of the related financing agreements. The proceeds from remarketing the senior unsecured notes were used by the holders of the equity security units to purchase treasury securities to secure their obligations to purchase Ameren common stock on May 15, 2005, pursuant to the stock purchase contracts. Ameren did not receive any proceeds as part of the remarketing. In the remarketing, Ameren purchased $95 million in principal amount of the senior unsecured notes which were subsequently retired.

In January 2005, UE issued, pursuant to its effective September 2003 SEC Form S-3 shelf registration statement, $85 million of 5.00% senior secured notes due February 1, 2020, with interest payable semi-annually on February 1 and August 1 of each year beginning in August 2005. UE received net proceeds of $83 million, which were used to repay short-term debt incurred to fund the December 2004 maturity of UE’s $85 million 7.375% first mortgage bonds.

CILCORP

In conjunction with Ameren’s acquisition of CILCORP in January 2003, CILCORP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $2 million for the three months ended March 31, 2005 (2004 - $2 million), and was included in interest expense in the Consolidated Statements of Income of Ameren and CILCORP.

In conjunction with Ameren’s acquisition of IP in September 2004, IP’s long-term debt was recorded at fair value. Amortization related to fair value adjustments was $5 million for the three months ended March 31, 2005 (2004 - less than $1 million), and was included in interest expense in the Consolidated Statements of Income of Ameren and IP.

Indenture Provisions and Other Covenants

UE’s indenture agreements and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. For the issuance of additional first mortgage bonds, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required. For the 12 months ended March 31, 2005, UE had a coverage ratio of 7.6 times the annual interest charges on the first mortgage bonds outstanding, which would permit UE to issue an additional $3.6 billion of first mortgage bonds at an assumed interest rate of 7%. For the issuance of additional preferred stock, earnings coverage of at least 2.5 times the annual dividend on preferred stock outstanding and to be issued is required under UE’s articles of incorporation. For the 12 months ended March 31, 2005, UE had a coverage ratio of 62.4 times the annual dividend requirement on preferred stock outstanding, which would permit UE to issue an additional $2 billion in preferred stock at an assumed dividend rate of 7%. The ability to issue such securities in the future will depend on such tests at that time.

In addition, UE’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.65 billion of free and unrestricted retained earnings at March 31, 2005.

CIPS

CIPS’ indenture agreements and articles of incorporation include covenants that must be complied with before first mortgage bonds and preferred stock are issued. For the issuance of additional first mortgage bonds, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required, except in certain cases when additional first mortgage bonds are issued on the basis of retired bonds. For the 12 months ended March 31, 2005, CIPS had a coverage ratio of 3.1 times the annual interest charges for one year on the aggregate amount of first mortgage bonds outstanding. Consequently, the most restrictive test under the indenture agreements would allow CIPS to issue an additional $138 million of first mortgage bonds, assuming an interest rate of 7%. For the issuance of additional preferred stock, earnings coverage of 1.5 times annual interest charges on all long-term debt and the annual preferred stock dividends is required under CIPS’ articles of incorporation. For the 12 months ended March 31, 2005, CIPS had a coverage ratio of 2 times the sum of the annual interest charges and dividend requirements on all long-term debt and preferred stock outstanding as of March 31, 2005, and consequently had the ability to issue an additional $148 million of preferred stock, assuming a dividend rate of 7%. The ability to issue such securities in the future will depend on such coverage ratios at that time.

Genco

Genco’s senior note indenture includes provisions that require it to maintain a senior debt service coverage ratio of at least 1.75 to 1 (for both the prior four fiscal quarters and for the succeeding four six-month periods) in order to pay dividends or to make payments of principal or interest under certain subordinated indebtedness, excluding amounts payable under its intercompany note payable to CIPS. For the 12 months ended March 31, 2005, this ratio was 5.1 to 1. In addition, the indenture also restricts Genco from incurring any additional indebtedness, with the exception of certain permitted indebtedness defined in the indenture, unless its senior debt service coverage ratio equals at least 2.5 to 1 for the most recently ended four fiscal quarters and its senior debt to total capital ratio does not exceed 60% - both after giving effect to the additional indebtedness on a pro forma basis. This debt incurrence restriction is to be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of debt incurrence after considering the additional indebtedness. As of March 31, 2005, Genco’s senior debt to total capital ratio was 53%. The ability to issue such securities in the future will depend on such coverage ratios at that time.

CILCORP

Covenants in CILCORP's indenture governing its senior notes and bonds require CILCORP to maintain a debt-to-capital ratio no greater than 0.67 to 1 and an interest coverage ratio of at least 2.2 to 1 in order to make any payment of dividends or intercompany loans to affiliates other than to its direct and indirect subsidiaries, including CILCO. However, in the event CILCORP is not in compliance with these tests, CILCORP may make such payments of dividends or intercompany loans if its senior long-term debt rating is at least BB+ from S&P, Baa2 from Moody’s, and BBB from Fitch. For the 12 months ended March 31, 2005, CILCORP's debt-to-capital ratio was 0.58 to 1 and its interest coverage ratio was 2.4 to 1, calculated in accordance with applicable provisions of this indenture. At March 31, 2005, CILCORP’s senior long-term debt ratings from S&P, Moody’s, and Fitch were BBB+, Baa2, and BBB+, respectively. The common stock of CILCO is pledged as security to the holders of these senior notes.

CILCO

CILCO’s indenture agreement and articles of incorporation include covenants that must be complied with before CILCO may issue first mortgage bonds and preferred stock. For the issuance of additional first mortgage bonds, an earnings coverage of twice the annual interest requirements on first mortgage bonds outstanding and to be issued, or earnings of at least 12% of the principal amount of all bonds outstanding and to be issued is required, except in certain cases when additional first mortgage bonds are issued on the basis of retired bonds. For the 12 months ended March 31, 2005, CILCO had an earnings coverage ratio of 8.1 times the annual interest charges for one year on the aggregate amount of bonds outstanding or at least 55% of the principal amount of all mortgage bonds outstanding under the mortgage. Accordingly, the most restrictive test under the indenture agreement would allow CILCO to issue an additional $496 million of first mortgage bonds. For the issuance of additional shares of preferred stock, the articles of incorporation provide that no class of shares with rights superior to the currently issued preferred stock as to payment of dividends or as to assets shall be issued, unless the net income available for the payment of the dividends for a period of 12 consecutive calendar months within the 15 months immediately preceding the issuance shall be at least 2 ½ times the annual dividend requirements of all then-outstanding shares of preferred stock. Consequently, the most restrictive test under which CILCO could issue additional shares of preferred stock would allow CILCO to issue additional preferred stock in the amount of $155 million. The ability to issue such securities in the future will depend on such coverage ratios at that time.

IP’s indenture agreements and articles of incorporation include covenants and provisions related to the issuance of first mortgage bonds and preferred stock. For the issuance of additional first mortgage bonds based on property additions, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required. For the 12 months ended March 31, 2005, IP had a coverage ratio of 3.37 times the annual interest charges on the first mortgage bonds outstanding, which would permit IP to issue an additional $850 million of first mortgage bonds, assuming an interest rate of 7%. For the issuance of additional preferred stock, earnings coverage of at least 1.5 times the annual dividend on preferred stock outstanding and to be issued is required under IP’s articles of incorporation. For the 12 months ended March 31, 2005, IP had a coverage ratio of 1.62 times the annual dividend requirement on preferred stock outstanding, which would permit IP to issue an additional $114 million of preferred stock assuming a dividend rate of 7%. The ability to issue such securities in the future will depend on such tests at that time.

The IP SPT TFNs contain restrictions that prohibit IP LLC from making any loan or advance to, or certain investments in, any other person. Also, as long as the TFNs are outstanding, the IP SPT shall not, directly or indirectly, pay any dividend or make any distribution (by reduction of capital or otherwise) to any owner of a beneficial interest in the IP SPT.

Off-Balance Sheet Arrangements

At March 31, 2005, none of the Ameren Companies had any off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance sheet financing arrangements in the near future.

NOTE 6 - OTHER INCOME AND DEDUCTIONS

The following table presents Other Income and Deductions for each of the Ameren Companies for the three months ended March 31, 2005 and 2004:

	Three Months
	2005			2004
Ameren:^(a)
Miscellaneous income:
Interest and dividend income	$	1		$	2
Allowance for equity funds used during construction		4			3
Other		2			3
Total miscellaneous income	$	7		$	8
Miscellaneous expense:
Minority interest in subsidiary	$	(1	)	$	(1	)
Total miscellaneous expense	$	(1	)	$	(1	)
UE:
Miscellaneous income:
Interest and dividend income	$	-		$	1
Equity in earnings of subsidiary		1			1
Allowance for equity funds used during construction		5			3
Other		2			-
Total miscellaneous income	$	8		$	5
Miscellaneous expense:
Other	$	(2	)		(1	)
Total miscellaneous expense	$	(2	)	$	(1	)
CIPS:
Miscellaneous income:
Interest and dividend income	$	5		$	7
Total miscellaneous income	$	5		$	7
Genco:
Miscellaneous expense:
Loss on disposition of property	$	-		$	(1	)
Total miscellaneous expense	$	-		$	(1	)
CILCORP:
Miscellaneous expense:
Other	$	(2	)	$	(1	)
Total miscellaneous expense	$	(2	)	$	(1	)
CILCO:
Miscellaneous expense:
Other	$	(1	)	$	(1	)
Total miscellaneous expense	$	(1	)	$	(1	)

	Three Months
		2005		2004
IP:^(b)
Miscellaneous income:
Interest and dividend income	$	1	$	-
Tilton Lease		-		4
Other		1		1
Total miscellaneous income	$	2	$	5

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP.

(b)	2004 amounts represent predecessor information.

NOTE 7 - DERIVATIVE FINANCIAL INSTRUMENTS

The following table presents balances in certain accounts for cash flow hedges as of March 31, 2005:

	Ameren^(a)			UE		CIPS		Genco			CILCORP		CILCO
2005:
Balance Sheet:
Other assets	$	70		$	10	$	17	$	1		$	34	$	34
Other deferred credits and liabilities		23			15		2		1			-		-
Accumulated OCI:
Power forwards^(b)		(1	)		-		-		(1	)		-		-
Interest rate swaps^(c)		4			-		-		4			-		-
Gas swaps and future contracts^(d)		56			9		15		-			32		32

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.

(b)	Represents the mark-to-market value 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 three 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 March 2008.

The pretax net gain or loss on power forward derivative instruments is included in Operating Revenues - Electric or Operating Expenses - Fuel and Purchased Power at Ameren, UE and Genco. This represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI due to transactions going to delivery or settlement, resulting in a less than $1 million gain for Ameren, UE and Genco for the quarter ended March 31, 2005 (2004 - less than $1 million gain for Ameren and Genco and less than $1 million loss for UE).

Other Derivatives

The following table represents the net change in market value of option transactions, which are used to manage our positions in SO₂ emission allowances and coal. Certain of these transactions are treated as nonhedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. 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 options is recorded as Operating Expenses - Fuel and Purchased Power.

	Three Months
Gains (Losses)^(a)	2005			2004
SO₂ options:
Ameren^(b)	$	(6	)	$	(1	)
UE		(1	)		(3	)
Genco		(5	)		2

(a)	Coal option gains and losses were less than $1 million for all periods shown above.

(b)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP.

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, and 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, 2004. Below are updates to several of these related party transactions as well as additional related party transactions.

Electric Power Supply Agreements

The following table presents the amount of gigawatthour sales under related party electric power supply agreements.

	Three Months
	2005		2004
Electric Power Supply Agreements
Genco sales to Marketing Company		4,900		4,921
Marketing Company sales to CIPS		2,055		1,942
AERG sales to CILCO		1,270		1,330
EEI sales to UE		697		816
EEI sales to CIPS		572		407
EEI sales to IP		413		-

Joint Dispatch Agreement

UE and Genco jointly dispatch electric generation under a joint dispatch agreement among UE, Genco and CIPS. Each affiliate has the option to serve its load requirements from its own generation first and then to allow access to any available generation to its affiliate. Any excess generation not used by UE or Genco through the joint dispatch agreement is sold to third parties through Ameren Energy, serving as each affiliate’s agent. Ameren Energy also acts as agent on behalf of UE and Genco to purchase power when they require it. The termination of the joint dispatch agreement, or modifications to it, could have a material effect on Ameren, UE or Genco. The joint dispatch agreement can be terminated by either party upon one year’s notice.

The following table presents the amount of gigawatthour sales under the joint dispatch agreement.

See Note 3 - Rate and Regulatory Matters for a discussion of a MoPSC order to amend the joint dispatch agreement.

Money Pools

Utility

Through the utility money pool, the pool participants can access committed credit facilities at Ameren that totaled $935 million at March 31, 2005. 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. Based on outstanding UE commercial paper borrowings at March 31, 2005, $779 million was available for borrowing under Ameren credit facilities through the utility money pool agreement. 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 quarter ended March 31, 2005 was 2.5% (2004 - 1.0%).

Non-state-regulated subsidiaries

At March 31, 2005, $779 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 quarter ended March 31, 2005 was 8.2% (2004 - 8.8%).

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. At March 31, 2005, CILCORP had notes payable under this agreement of $76 million at an average interest rate of 8.2%.

Intercompany Promissory Notes

As of March 31, 2005, Genco had subordinated affiliate notes payable of $249 million and $34 million to CIPS and Ameren, respectively. These notes had a 7% interest rate, a 10-year amortization schedule and a maturity date of May 1, 2005. The note payable to CIPS was issued on May 1, 2000, in conjunction with the transfer of its electric generating assets and related liabilities to Genco. As of May 1, 2005, Genco amended certain terms of the CIPS note by the issuance to CIPS of an amended and restated subordinated promissory note in the principal amount of approximately $249 million with an interest rate of 7.125% per annum, a 5-year amortization schedule and a maturity date of May 1, 2010. On May 1, 2005, the remaining principal balance under Genco’s note payable to Ameren was repaid.

On May 2, 2005, CIPS issued to UE a subordinated promissory note in the principal amount of approximately $69 million as consideration for approximately 50% of UE’s Illinois-based utility assets transferred to CIPS on that date. The note bears interest at 4.70% per annum and has a 10-year amortization schedule and a maturity date of May 2, 2010. See Note 3 - Rate and Regulatory Matters for a discussion of this intercompany transfer.

Intercompany Transfer of Illinois Service Territory and Electric Generating Facilities

See Note 3 - Rate and Regulatory Matters for a discussion of the related party transactions engaged in with respect to the intercompany transfer of Illinois service territory and electric generating facilities.

Summary of Related Party Transactions

The following tables present the impact of related party transactions on the Ameren Companies’ statements of income and balance sheets, based primarily on the transactions discussed above and in 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, 2004.


	Three Months
Consolidated Statement of Income	2005			2004
Operating revenues from affiliates:
Power supply agreement with EEI	$	(a	)	$	(a	)
Joint dispatch agreement with Genco		41			30
Agency agreement with Ameren Energy		55			53
Gas transportation agreement with Genco		(a	)		(a	)
Total operating revenues	$	96		$	83
Fuel and purchased power expenses from affiliates:
Power supply agreements:
EEI	$	14		$	16
Marketing Company		2			2
Joint dispatch agreement with Genco		11			12
Agency agreement with Ameren Energy		9			19
Total fuel and purchased power expenses	$	36		$	49
Other operating expenses:
Support service agreements:
Ameren Services	$	41		$	38
Ameren Energy		1			3
AFS		1			1
Total other operating expenses	$	43		$	42
Interest expense:
Borrowings (advances) related to money pool	$	(a	)	$	(a	)

(a)	Less than $1 million.


Consolidated Balance Sheet	March 31, 2005		December 31, 2004
Assets:
Miscellaneous accounts and notes receivable	$	13	$	8
Advances to money pool, net		64		-
Liabilities:
Accounts payable and wages payable	$	35	$	53

CIPS


	Three Months
Statement of Income	2005			2004
Operating revenues from affiliates:
Power supply agreements:
Marketing Company	$	9		$	8
Total operating revenues	$	9		$	8
Fuel and purchased power expenses from affiliates:
Power supply agreements:
Marketing Company	$	76		$	72
EEI		9			8
Total fuel and purchased power expenses	$	85		$	80
Other operating expenses:
Support service agreements:
Ameren Services	$	11		$	12
AFS		(a	)		(a	)
Total other operating expenses	$	11		$	12
Interest income:
Note receivable from Genco	$	4		$	7
Borrowings (advances) related to money pool		(a	)		(a	)

(a)	Less than $1 million.


Balance Sheet	March 31, 2005		December 31, 2004
Assets:
Miscellaneous accounts and notes receivable	$	11	$	12
Promissory note receivable from Genco		249		249
Tax receivable from Genco^(a)		146		149
Liabilities:
Accounts payable and wages payable	$	47	$	49
Borrowings from money pool		13		68

(a)	Amount includes current portion of $11 million as of March 31, 2005, and December 31, 2004.

Genco


	Three Months
Consolidated Statement of Income	2005			2004
Operating revenues from affiliates:
Power supply agreements:
Marketing Company	$	179		$	173
EEI		(a	)		(a	)
Joint dispatch agreement with UE		11			12
Agency agreement with Ameren Energy		32			27
Operating lease with Development Company		3			3
Total operating revenues	$	225		$	215
Fuel and purchased power expenses from affiliates:
Joint dispatch agreement with UE	$	41		$	30
Agency agreement with Ameren Energy		6			7
Power purchase agreement with Marketing Company		2			(a	)
Gas transportation agreement with UE		(a	)		(a	)
Total fuel and purchased power expenses	$	49		$	38
Other operating expenses:
Support service agreements:
Ameren Services	$	5		$	4
Ameren Energy		1			1
AFS		1			(a	)
Total other operating expenses	$	7		$	5
Interest expense:
Borrowings from money pool	$	2		$	3
Note payable to CIPS		4			7
Note payable to Ameren		1			1

(a)	Less than $1 million.


Consolidated Balance Sheet	March 31, 2005		December 31, 2004
Assets:
Miscellaneous accounts and notes receivable	$	91	$	86
Liabilities:
Accounts payable and wages payable	$	25	$	13
Interest payable		4		5
Promissory note payable to CIPS		249		249
Promissory note payable to Ameren		34		34
Tax payable to CIPS^(a)		146		149
Borrowings from money pool		115		116

(a)	Amount includes current portion of $11 million as of March 31, 2005, and December 31, 2004.

CILCORP


	Three Months
Consolidated Statement of Income	2005		2004
Operating revenues from affiliates:
Power supply agreements:
Bilateral supply agreement with Marketing Company	$	15	$	10
Total operating revenues	$	15	$	10
Fuel and purchased power expenses from affiliates:
Executory tolling agreement with Medina Valley	$	10	$	10
Bilateral supply agreement with Marketing Company		3		4
Total fuel and purchased power expenses	$	13	$	14


	Three Months
Consolidated Statement of Income		2005		2004
Other operating expenses:
Support services agreements:
Ameren Services	$	12	$	13
AFS		1		(a	)
Total other operating expenses	$	13	$	13
Interest expense:
Note payable to Ameren	$	2	$	1
Borrowings from money pool		1		1

(a)	Less than $1 million.


Consolidated Balance Sheet	March 31, 2005		December 31, 2004
Assets:
Miscellaneous accounts and notes receivable	$	7	$	9
Liabilities:
Accounts and wages payable	$	19	$	42
Note payable to Ameren		76		72
Borrowings from money pool, net		165		166

CILCO


	Three Months
Consolidated Statement of Income	2005		2004
Operating revenues from affiliates:
Power supply agreements:
Bilateral supply agreement with Marketing Company	$	15	$	10
Total operating revenues	$	15	$	10
Fuel and purchased power expenses from affiliates:
Executory tolling agreement with Medina Valley	$	10	$	10
Bilateral supply agreement with Marketing Company		3		4
Total fuel and purchased power expenses	$	13	$	14
Other operating expenses:
Support services agreements:
Ameren Services	$	12	$	12
AFS		1		(a	)
Total other operating expenses	$	13	$	12
Interest expense:
Borrowings from money pool	$	1	$	1

(a)	Less than $1 million.


Consolidated Balance Sheet	March 31, 2005		December 31, 2004
Assets:
Miscellaneous accounts and notes receivable	$	7	$	11
Liabilities:
Accounts and wages payable	$	18	$	42
Borrowings from money pool		163		169


	Three Months
Consolidated Statement of Income	2005		2004^(a)
Operating revenues from affiliates and former affiliates:
Retail natural gas sales DMG	$	-	$	2
Transmission sales to DYPM		-	$	4
Interest income from former affiliates		-		43
Total operating revenues	$	-	$	49
Fuel and purchased power expenses from affiliates and former affiliates:
Power supply agreements:
DMG	$	-		124
EEI		7		-
Gas purchased from Dynegy		-		6
Total fuel and purchased power expenses	$	7	$	130


	Three Months
	2005		2004^(a)
Other operating expenses:
Services and facilities agreement - Dynegy	$	-	$	3
Total other operating expenses	$	-	$	3
Interest expense (income):
Interest expense for IP SPT	$	(b)	$	6
Interest expense on Tilton lease		-		4
Interest income on Tilton lease		-		(4	)
Advances to money pool	$	(1)		-

(a)	Represents predecessor information.

(b)	Less than $1 million.


Consolidated Balance Sheet	March 31, 2005		December 31, 2004
Assets:
Miscellaneous accounts and notes receivable	$	5	$	4
Advances related to money pool		105		140
Investment in IP SPT		7		7
Liabilities:
Accounts and wages payable	$	24	$	4
Long-term debt to IP SPT^(a)		326		352

(a)	Amount includes current portion of $72 million as of March 31, 2005, and $74 million as of December 31, 2004, and includes a purchase accounting fair value adjustment of $16 million as of March 31, 2005, and $18 million as of December 31, 2004.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 3 - Rate and Regulatory Matters, Note 14 - Related Party Transactions and 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, 2004.

Callaway Nuclear Plant

The following table presents insurance coverage at UE’s Callaway nuclear plant at March 31, 2005:


Type and Source of Coverage	Maximum Coverages		Maximum Assessments 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. While the renewal of Price-Anderson is pending, 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 $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 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 to reflect changes in the Consumer Price Index. Utilities owning a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or if coverage is not available, UE self-insures the risk. If a serious nuclear incident occurred, it could have a material but indeterminable adverse effect on our results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. In addition, we have entered into various long-term commitments for the purchase of electricity. For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and 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, 2004.

As of March 31, 2005, the commitments for the procurement of coal have increased from amounts previously disclosed as of December 31, 2004. The following table presents the total estimated coal purchase commitments at March 31, 2005:


	2005		2006		2007		2008		2009		Thereafter^(a)
Ameren^(b)	$	740	$	694	$	646	$	489	$	239	$	40
UE		377		342		325		233		92		20
Genco		204		207		186		158		108		11
CILCORP		77		65		58		42		16		4
CILCO		77		65		58		42		16		4

(a)	Commitments for coal are until 2010.

(b)	Includes amounts for Registrant and non-Registrant Ameren subsidiaries and intercompany eliminations.

Environmental Matters

We are subject to various environmental regulations by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, and natural gas storage plant, transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These address noise, emissions, and impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological/historical resources), chemical and waste handling. Our activities often require complex and often lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operations, as required. The more significant matters are discussed below.

Clean Air Act

In March 2005, the EPA issued its final regulations with respect to SO₂ and NO_x emissions (the Clean Air Interstate Rule) and mercury emissions from coal-fired power plants. The new regulations will require significant additional reductions in these emissions from UE, Genco and CILCO power plants in phases, beginning in 2010. The following table presents

preliminary estimated capital costs based on current available technology to comply with theClean Air Interstate Rule and mercuryrules:


	2005		2006 - 2009		2010 - 2015		Total
Ameren	$	50	$	510 - $1,360	$	355 - $1,130	$	1,400 - $1,900
UE		20		160 - 880		175 - 880		840 - 1,140
Genco		10		250 - 340		140 - 200		400 - 550
CILCO		20		100 - 140		40 - 50		160 - 210

Each state has 18 months, or until the fall of 2006, to develop a state regulation implementing the Clean Air Interstate Rule and mercury rules. While the federal rules mandate a specific emissions cap for SO₂, NO_x and mercury emissions by state from utility boilers, the states have considerable flexibility in allocating emission allowances to individual utility boilers. In addition, a state may choose to hold back certain emission allowances for growth or other reasons, and may implement a more stringent program than required by the federal rule. The costs reflected in the above table assume each Ameren generating unit will be allocated allowances based on the model “cap and trade” rule guidelines issued by the EPA. Should either Missouri or Illinois decide to develop alternative allowance allocations for utility units, the cost impact could be material. At this time, we are unable to determine the impact of such a state decision on our results of operations, financial position or liquidity.

Emission Credits

As of March 31, 2005, UE, Genco, CILCO, and EEI held 1.56 million, 0.48 million, 0.27 million, and 0.32 million tons, respectively, of SO₂ emission allowances with vintages from 2005 to 2012. Each company possesses additional allowances for use in periods beyond 2012. As of March 31, 2005, UE, Genco, CILCO and EEI Illinois facilities held 213, 17,522, 4,266 and 5,490 tons, respectively, of NO_X emission allowances with vintages from 2004 to 2007. The Illinois Environmental Protection Agency (the Illinois EPA) is still determining some NO_x emission allowance allocations for this period and 2008. UE, Genco, CILCO and EEI expect to use a substantial portion of the SO₂ and NO_x allowances for ongoing operations. Allocations of NO_x emission allowances for Missouri facilities are pending the finalization of rules by Missouri regulators. New environmental regulations, including the Clean Air 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.

New Source Review

The EPA has been conducting an enforcement initiative in an effort to determine whether modifications at a number of coal-fired power plants owned by other electric utilities in the U.S. are subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were made.

IP and DMG had been the subject of a Notice of Violation from the EPA and a complaint filed in 1999 by the United States in the U.S. District Court for the Southern District of Illinois alleging violations of the Clean Air Act and certain related federal and Illinois regulations in connection with certain equipment repairs, replacements, and maintenance activities at the three Baldwin Power Station generating units, currently owned by DMG and formerly owned by IP.

Pursuant to the terms of the stock purchase agreement covering Ameren’s acquisition of IP from Dynegy, Dynegy agreed to fully indemnify Ameren and IP in the event of an adverse ruling and in any settlement arising from or out of this litigation. To secure payment of the indemnification obligations of Dynegy, Ameren, pursuant to the terms of the stock purchase agreement, deposited $100 million of the cash portion of the purchase price into an escrow account with the funds to be released to Dynegy on the sooner of (1) December 31, 2010; (2) the date on which the senior unsecured debt of Dynegy Holdings Inc., a Dynegy subsidiary, achieves an investment grade rating from S&P or Moody’s; or (3) the occurrence of specified events relating to contingent environmental liabilities associated with IP’s former generating facilities, including the Baldwin Power Station.

DMG has entered into a comprehensive settlement with the EPA, the U.S. and other intervening parties that resolves this litigation. The settlement agreement is set forth in a consent decree and resolves all claims in the litigation as well as similar claims that may have been brought with respect to other generation facilities owned by DMG and formerly owned by IP. If approved by the Court, this consent decree will relieve IP of any civil liability under the Clean Air Act and related federal and Illinois regulations with respect to IP’s former ownership of the Baldwin Power Station and other generation assets now owned by DMG. The consent decree, upon its approval by the Court, is also expected to satisfy the conditions for the release to Dynegy of the $100 million of the IP purchase price that is held in an escrow account as discussed above.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility and AERG’s E.D. Edwards and Duck Creek facilities. All of these facilities are coal-fired power plants. The information request requires Genco to provide responses to specific EPA questions regarding certain projects and maintenance activities in order to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standard requirements of the Clean Air Act. Genco intends to comply with this information request, but cannot predict the outcome of this matter at this time.

Remediation

We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of fault, legality of original disposal, or ownership of a disposal site. UE, CIPS, CILCO and IP have each been identified by the federal or state governments as a potentially responsible party at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and were transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS or CILCO has contractually agreed to indemnify Genco or AERG for remediation costs associated with pre-existing environmental contamination at the transferred sites.

As of March 31, 2005, UE, CIPS, CILCO, and IP owned or were otherwise responsible for one, 13, four, and 25 former MGP sites, respectively, in Illinois. All of these sites are in various stages of investigation, evaluation and remediation. Under its current schedule, Ameren anticipates that remediation at these sites should be completed by 2015. The ICC permits each company to recover remediation and litigation costs associated with their former MGP sites located in Illinois from their Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred; costs are subject to annual reconciliation review by the ICC. The total costs deferred, net of recoveries from insurers and through environmental adjustment rate riders, at March 31, 2005, were $1 million, $23 million, $4 million, and $64 million for UE, CIPS, CILCO, and IP, respectively. On May 2, 2005, as a part of its Illinois utility service territory transfer, UE transferred its one Illinois-based former MGP site to CIPS. In connection with the transfer, CIPS succeeded to UE’s ICC-approved environmental adjustment rate rider which permits CIPS to recover remediation and litigation costs associated with UE’s former MGP site from UE’s transferred Illinois electric and natural gas utility customers. For a

discussion of the Illinois service territory transfer, see Note 3 - Rate and Regulatory Matters in this report.

In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. Unlike Illinois, UE does not have in effect in Missouri a rate rider mechanism which permits remediation costs associated with MGP sites to be recovered from utility customers. UE does not have any retail utility operations in Iowa. Because of the unknown and unique characteristics of each site (such as amount and type of residues present, physical characteristics of the site and the environmental risk), and uncertain regulatory requirements, we are not able to determine the maximum liability for the remediation of these sites. UE has recorded a $16 million liability as of March 31, 2005, to represent its estimated minimum obligation. At this time, we are unable to determine what portion of these costs, if any, will be eligible for recovery from insurance carriers.

In June 2000, the EPA notified UE and numerous other companies that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From approximately 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2 and currently owns a parcel of property that is used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other potentially responsible parties to evaluate the extent of potential contamination with respect to Sauget Area 2.

In October 2002, UE was included in a Unilateral Administrative Order list of potentially liable parties for groundwater contamination for a portion of the Sauget Area 2 site. The Unilateral Administrative Order encompasses the groundwater contamination releasing to the Mississippi River adjacent to Monsanto Chemical Company’s (now known as Solutia) former chemical waste landfill and the resulting impact area in the Mississippi River. UE was asked to participate in response activities that involve the installation of a barrier wall around a chemical waste site with three recovery wells to divert groundwater flow. The projected cost for this remedy method is $26 million. In November 2002, UE sent a letter to the EPA asserting its defenses to the Unilateral Administrative Order and requested its removal from the list of potentially responsible parties under the Unilateral Administrative Order. Solutia agreed to comply with the Unilateral Administrative Order. However, in December 2003, Solutia filed for bankruptcy protection; it is now seeking to discharge its environmental liabilities. In March 2004, Pharmacia Corporation, the former parent company of Solutia, confirmed its intent to comply with the EPA’s Unilateral Administrative Order.

As the status of future remediation at Sauget Area 2 or compliance with the Unilateral Administrative Order is uncertain, we are unable to predict the ultimate impact of the Sauget Area 2 site on our results of operations, financial position or liquidity. In December 2004, the U.S. Supreme Court, in Cooper Industries, Inc. vs. Aviall Services, Inc., limited the circumstances under which potentially responsible parties could assert cost-recovery claims against other potentially responsible parties. As a result of this ruling, UE may not be able to recover from other potentially responsible parties the costs it incurs in complying with EPA orders. Any liability or responsibility which may be imposed on UE as a result of this Sauget, Illinois environmental matter was not transferred to CIPS as a part of UE’s May 2005 utility service territory transfer discussed above and in Note 3 - Rate and Regulatory Matters.

In December of 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $4 million at March 31, 2005, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort to treat and discharge the recycle system water in order to address these groundwater and surface water issues. Future AERG capital expenditures at Duck Creek under the AERG proposal will include construction of a dry fly ash collection system, a landfill, and a new pond. AERG estimates that future capital expenditures for the indicated activities could be approximately $19 million by 2008.

In addition, our operations or those of our predecessor companies, involve the use, disposal and, in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine the impact these actions may have on our results of operations, financial position, or liquidity.

Asbestos-Related Litigation

Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits that 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; as many as 166 parties are named in some pending cases and as few as five in others. However, the average number of parties is 58 in the cases that were pending as of March 31, 2005.

The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and most former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a Dynegy subsidiary prior to

Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS or CILCO has contractually agreed to indemnify 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 January 1, 2005 through March 31, 2005, 10 additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois; 16 lawsuits were dismissed and one was settled. The following table presents the status as of March 31, 2005, of the asbestos-related lawsuits that have been filed against the Ameren Companies:


		Specifically Named as Defendant
	Total^(a)	Ameren	UE	CIPS	Genco	CILCO	IP
Filed	276	24	149	104	2	20	122
Settled	58	-	35	21	-	2	26
Dismissed	116	11	72	31	1	4	50
Pending	102	13	42	52	1	14	46

(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.

As of March 31, 2005, four asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity. See Note 3 - Rate and Regulatory Matters - IP and EEI Acquisition under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the year ended December 31, 2004, for information on the ICC’s approval of a tariff rider through which asbestos-related litigation claims will be allowed to be recovered from IP’s electric customers, subject to certain terms, commencing in 2007.

Other Matters

Leveraged Leases

Ameren owns interests in assets that have been financed as leveraged leases. One of these leveraged leases is a $10 million investment at March 31, 2005, in an aircraft leased to Delta Air Lines. Delta Air Lines reported significant operating losses and disclosed in its Form 10-K filing for the year ended December 31, 2004, that its results are unsustainable and underscore the urgent need to reduce its cost structure. Ameren could lose all or a portion of its investment 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 March 31, 2005, Delta Air Lines was current on its payments on 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 and sells 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 2012. UE has sufficient storage capacity at its Callaway nuclear plant until 2020. It 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, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the 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. Ameren and UE have recorded an asset retirement obligation for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. See the discussion of SFAS No.143 in Note 1 - Summary of Significant Accounting Policies. Decommissioning costs are charged to cost of services used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2004, 2003 and 2002. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest study was filed in 2002; an updated cost study is expected to be filed in September 2005. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that 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. It may be used only 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. In connection with UE’s transfer of its Illinois electric and gas utility businesses to CIPS on May 2, 2005, the assets and liabilities related to the Illinois portion of the decommissioning trust fund are being transferred to the Missouri and the FERC jurisdictions. See Note 3 - Rate and Regulatory Matters for further information about this intercompany transfer.

NOTE 11 - STOCKHOLDERS’ EQUITY

Outstanding Shares of Common Stock

The following table reconciles the outstanding shares of Ameren common stock for the three months ended March 31, 2005 and 2004:


	Three Months
	2005	2004
Shares outstanding at beginning of period	195.2	162.9
Shares issued	0.6	19.6
Shares outstanding at end of period	195.8	182.5

Paid-In Capital

Ameren’s paid-in capital increased $27 million as of March 31, 2005 compared to December 31, 2004 due to the issuance of 0.6 million new shares of common stock valued at $30 million under DRPlus and Ameren’s 401(k) plans offset by $3 million related to Ameren’s open market purchases for employee stock options and restricted stock awards. 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 shareholders. A reconciliation of net income to comprehensive income for the three months ended March 31, 2005 and 2004, is shown below for the Ameren Companies:


	Three Months
	2005			2004
Ameren:^(a)
Net income	$	121		$	97
Unrealized gain on derivative hedging instruments, net of taxes of $15 and $-, respectively		17			-
Total comprehensive income, net of taxes	$	138		$	97
UE:
Net income	$	57		$	58
Unrealized gain on derivative hedging instruments, net of taxes of $2 and $1, respectively		3			2
Total comprehensive income, net of taxes	$	60		$	60
CIPS:
Net income	$	8		$	10
Unrealized gain on derivative hedging instruments, net of taxes of $3 and $1, respectively		6			3
Reclassification adjustments for (gains) included in net income, net of taxes of $- and $-, respectively		-			(1	)
Total comprehensive income, net of taxes	$	14		$	12
Genco:
Net income	$	31		$	29
Unrealized (loss) on derivative hedging instruments, net of (benefit) of $- and $(1), respectively		(1	)		(1	)
Total comprehensive income, net of taxes	$	30		$	28
CILCORP:
Net income	$	9		$	4
Unrealized gain on derivative hedging instruments, net of taxes of $8 and $1, respectively		15			3
Total comprehensive income, net of taxes	$	24		$	7
CILCO:
Net income	$	16		$	6
Unrealized gain on derivative hedging instruments, net of taxes of $8 and $1, respectively		13			3
Total comprehensive income, net of taxes	$	29		$	9
IP:^(b)
Net income	$	22		$	37
Minimum pension liability adjustment, net of taxes of $- and $-, respectively		-			1
Total comprehensive income, net of taxes	$	22		$	38

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP.

(b)	Includes predecessor information for the first quarter of 2004.

NOTE 12 - RETIREMENT BENEFITS

Ameren’s pension plans are funded in compliance with income tax regulations and federal funding requirements. Based on our assumptions at December 31, 2004, in order to maintain minimum funding levels for Ameren’s pension plans, we expect future required contributions to aggregate $400 million for the period of 2005 to 2009, with no minimum contribution required until 2008 assuming continuation of the current federal interest rate relief beyond 2005. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in government regulations.

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 ended March 31, 2005 and 2004:


	Pension Benefits
	2005			2004^(a)
Service cost	$	15		$	11
Interest cost		42			33
Expected return on plan assets		(46	)		(30	)
Amortization cost:
Prior service cost		2			2
Losses		10			7
Net periodic benefit cost	$	23		$	23


	Postretirement Benefits
	2005			2004^(a)
Service cost	$	6		$	4
Interest cost		19			17
Expected return on plan assets		(12	)		(9	)
Amortization cost:
Prior service cost		(1	)		(1	)
Losses		10			10
Net periodic benefit cost	$	22		$	21

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP.

UE, CIPS, Genco, CILCORP, CILCO and IP are participants in Ameren’s plans and are responsible for their proportional share of the pension and other postretirement costs. The following table presents the pension and other postretirement costs incurred for the three months ended March 31, 2005 and 2004:


	Pension Benefits
	2005		2004
Ameren^(a)	$	23	$	23
UE		13		14
CIPS		3		3
Genco		2		2
CILCORP		3		4
CILCO		4		6
IP^(b)		2		-


	Postretirement Benefits
	2005		2004
Ameren^(a)	$	22	$	21
UE		11		13
CIPS		3		3
Genco		1		1
CILCORP		4		4
CILCO		6		6
IP^(b)		3		-

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP.

(b)	Includes predecessor information for first quarter of 2004.

NOTE 13 - SEGMENT INFORMATION

As discussed in the Ameren Companies combined Form 10-K for the fiscal year ended December 31, 2004, 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.

Ameren’s reportable segment Utility Operations includes the operations of UE, CIPS, Genco, CILCORP and CILCO. The operations of IP are included in Ameren’s Utility Operations segment from September 30, 2004.

The accounting policies for segment data are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data include intersegment revenues, as well as a charge for allocating costs of administrative support services to each of the operating companies, which, in each case, is eliminated upon consolidation. Ameren Services allocates administrative support services based on various factors, such as headcount, number of customers, and total assets. The following table presents information about the reported revenues and net income of Ameren for the three months ended March 31, 2005 and 2004:


	Utility Operations		Other			Reconciling Items^(b)			Total
2005:
Operating revenues	$	1,944	$	-		$	(318	)	$	1,626
Net income		125		(4	)		-			121
2004:⁽^a⁾
Operating revenues	$	1,515	$	-		$	(297	)	$	1,218
Net income		97		-			-			97

(a)	Excludes 2004 amounts for IP.

(b)	Elimination of intercompany revenues.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

OVERVIEW

Ameren Executive Summary

Ameren’s net earnings in the first quarter of 2005 benefited from higher prices for interchange power sales, the addition of IP and improved availability and capacity factors at Ameren’s power plants. Milder winter weather, reduced emission credit sales and higher fuel costs offset some of the positive factors this year.

Increased plant availability allowed Ameren to take advantage of higher power prices in the interchange markets. The power markets continue to be driven by high prices for natural gas and higher coal and transportation costs. However, Ameren also experienced higher fuel costs this year and expects this trend to continue.

In late February, CIPS, CILCO and IP made initial filings with the ICC to outline a proposed method for procuring power in 2007 and beyond. Later this year, or early next year, CIPS, CILCO and IP will make filings with the ICC that will serve as a basis for adjusting electric distribution rates. By January 1, 2006, UE will provide an updated cost of service study to the MoPSC staff and others. These are milestone events for Ameren.

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 as discussed below. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. 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 Ameren's principal subsidiaries.

·	UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri and prior to May 2, 2005, in Illinois.

·	CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

·	Genco operates a non-rate-regulated electric generation business in Illinois and Missouri.

CILCO 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, through its subsidiary, AERG, and a rate-regulated natural gas transmission and distribution business in Illinois.

·	IP operates a rate-regulated electric and natural gas transmission and distrubution business in Illinois. See Note 2 - Acquisitions to our financial statements under Part I, Item 1, of this report for further information.

The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income and Cash Flows for the three months ended March 31, 2004, do not reflect IP’s results of operations or financial position. See Note 2 - Acquisitions for further information on the accounting for the IP acquisition. See also Note 2 - Acquisitions under Part II, Item 8 of the Ameren Companies’ combined Form 10-K for the year ended December 31, 2004, for information on the accounting for the CILCORP acquisition. 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 information in this report is expressed in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information is useful because it enables readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on weighted-average diluted common shares outstanding during the applicable period.

IP Acquisition

On September 30, 2004, Ameren completed the acquisition from Dynegy of all the common stock and 662,924 shares of preferred stock of IP (based in Decatur, Illinois) and an additional 20% ownership interest in EEI. Ameren acquired IP to complement its existing Illinois electric and gas operations. The purchase included IP’s rate-regulated electric and natural gas transmission and distribution business serving 600,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. With the acquisition, IP became an Ameren subsidiary operating as AmerenIP.

and other Dynegy affiliates for which Ameren has been provided indemnification by Dynegy. See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for information on the IP environmental matter to which the indemnification and escrow applies. In addition, this transaction included a fixed-price power supply agreement for IP’s annual purchase in 2005 and 2006 of 2,800 megawatts of electricity from DYPM. The contract was marked to fair value at closing of the IP acquisition. This agreement is expected to supply about 70% of IP’s electric customer requirements during those two years. The remaining 30% of its power needs in 2005 and 2006 will be supplied under other arrangements. In the event that any of IP’s suppliers are unable to supply the electricity required by existing agreements, IP would be forced to find alternative suppliers to meet its load requirements, thus exposing IP to market price risk, which could have a material impact on Ameren’s and IP’s results of operations, financial condition, or liquidity.

Ameren funded this acquisition with the issuance of new Ameren common stock. Ameren issued an aggregate of approximately 30 million common shares in February 2004 and July 2004, which generated net proceeds of about $1.3 billion. Proceeds from these issuances were used to finance the cash portion of the purchase price and to reduce high-cost IP debt assumed as part of this transaction and to pay related premiums.

Ameren expects the acquisition of IP to be accretive to earnings in the first two years of ownership. That belief is based on a variety of assumptions related to power prices, interest rates, and synergies, among other things. In December 2004, 230 IP employees accepted a voluntary separation opportunity, which provides an enhanced separation benefit and extended medical and dental benefits. Employees who accepted the voluntary separation opportunity will leave IP throughout 2005 as business needs warrant. These voluntary separations are consistent with Ameren’s plan for the integration of IP and conditions in the ICC order approving the acquisition, which relate to the realization of administrative synergies from the acquisition. As of March 31, 2005, estimated separation costs of $26 million have been deferred as a regulatory asset for future recovery from customers, which is also consistent with the ICC order.

For income tax purposes, Ameren and Dynegy have elected to treat Ameren’s acquisition of IP stock as an asset acquisition under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended.

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 affect the demand for our services. Our results are also affected by seasonal fluctuations caused by winter heating and summer cooling demand. With approximately 85% of Ameren’s revenues directly subject to regulation by various state and federal agencies, decisions by regulators can have a material impact on the prices we charge for our services. Our non-rate-regulated sales are subject to market conditions for power. We principally use 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 currently 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 (PGAs) in each state for our gas delivery businesses. The electric and gas rates for UE in Missouri are set through June 2006, and are set for CIPS, CILCO and IP in Illinois through the end of 2006, so that cost decreases or increases will not be immediately reflected in rates. Fluctuations in interest rates affect 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 costs, operating and administrative costs, and capital investment are key factors that we seek to control in order to optimize our results of operations, financial position and liquidity.

Ameren’s net income increased $24 million to $121 million, or 62 cents per share, in the first quarter of 2005 from $97 million, or 55 cents per share, in the first quarter of 2004. The change in net income was primarily due to the inclusion of IP results for three months in 2005, increased margins on interchange power sales as a result of higher power prices, and improved power plant availability and capacity factors. Partially offsetting these increases to net income were the effect of mild winter weather, decreased emission allowance sales, higher fuel costs and electric rate reductions in the first quarter of the current year.

As a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren’s principal subsidiaries to Ameren’s consolidated net income for the three months ended March 31, 2005 and 2004:


	Three Months
	2005			2004
Net income:
UE^(a)	$	56		$	57
CIPS		7			9
Genco^(a)		31			29
CILCORP^(a)		9			4
IP^(b)		21			-
Other^(c)		(3	)		(2	)
Ameren net income	$	121		$	97

(a)	Includes earnings from unregulated interchange power sales that provided $22 million (2004 - $17 million) of UE’s net income, $12 million (2004 - $10 million) of Genco’s net income and $5 million of CILCORP’s net income in the current year.

(b)	Ameren acquired IP on September 30, 2004.

(c)	Includes corporate general and administrative expenses, transition costs associated with the IP acquisition and other non-rate-regulated operations.

Acquisition Accounting

The amortization of noncash purchase accounting fair value adjustments at IP increased Ameren’s and IP’s net income by $14 million and $10 million, respectively, for the three months ended March 31, 2005, as compared with the prior-year period. The amortization of the fair value adjustments at IP that increased net income were related to pension and postretirement liabilities, long-term debt, and a power supply contract with Dynegy to supply IP 2,800 megawatts for 2005 and 2006. Partially offsetting these items at IP was the amortization of the fair value adjustment related to a power supply contract with EEI that expires in 2005. The following table presents the favorable (unfavorable) impact on Ameren’s and IP’s net income related to the amortization of purchase accounting fair value adjustments associated with the IP acquisition during the three months ended March 31, 2005:


	Three Months
	2005
	Ameren			IP
Statement of Income line item:
Other operations and maintenance^(a)	$	7		$	7
Interest^(b)		6			6
Purchased power^(c)		10			4
Income taxes^(d)		(9	)		(7	)
Impact on net income	$	14		$	10

(a)	Related to the adjustment to fair value of the pension plan and postretirement plans.

(b)

Related to the adjustment to fair value of all the IP debt assumed at acquisition on September 30, 2004 and the unamortized gain or loss on reacquired debt. The net write-up to fair value of all the IP debt assumed, excluding early redemption premiums, is being amortized over the anticipated remaining life of the debt.

(c)	Related to the amortization of fair value adjustments to power supply contracts.

(d)	Tax effect of the above amortization adjustments.

The amortization of fair value adjustments at EEI as a result of the additional 20% interest acquired by Ameren on September 30, 2004, were related to plant in service, emission credits and a power supply agreement with IP that expires in 2005. The following table presents the favorable (unfavorable) impact on Ameren’s net income related to the amortization of purchase accounting fair value adjustments associated with the EEI acquisition during the three months ended March 31, 2005:


	Three Months
	2005
Statement of Income line item:
Interchange revenues^(a)	$	1
Fuel and purchased power^(b)		(1	)
Depreciation and amortization^(c)		(1	)
Income taxes^(d)		-
Impact on net income	$	(1	)

(a)	Related to the amortization of a power supply contract.

(b)	Related to the amortization of emission credits.

(c)	Includes the amortization of the fair value adjustment related to plant assets.

(d)	Tax effect of the above amortization adjustments.

Electric Operations

The following table presents the favorable (unfavorable) variations in electric margins, defined as electric revenues less fuel and purchased power costs, for the three months ended March 31, 2005, from the comparable period in 2004. We consider electric and interchange margins useful measures to analyze the change in profitability of our electric operations between periods. We have included the analysis below as a complement to our financial information provided in accordance with GAAP. However, electric and interchange margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we are providing elsewhere in this report.

The variation for Ameren shows the contribution from IP for the three months ended March 31, 2005, as a separate line item, which facilitates comparison with other margin components. IP’s electric margins in 2005 include purchase accounting

adjustments and are compared with the same period in 2004 when Ameren did not own IP and it did not contribute to Ameren’s electric margins.


Three Months	Ameren^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP^(b)
Electric revenue change:
IP - January to March, 2005	$	235		$	-		$	-		$	-		$	-		$	-		$	-
Effect of weather (estimate)		(6	)		(2	)		(1	)		-			(2	)		(2	)		(1	)
Growth and other (estimate)		(6	)		(4	)		3			6			(7	)		(7	)		(11	)
Emission credits		(15	)		(15	)		-			-			-			-			-
Rate reductions		(7	)		(7	)		-			-			-			-			-
Interchange revenues		13			13			(1	)		3			4			4			-
Total	$	214		$	(15	)	$	1		$	9		$	(5	)	$	(5	)	$	(12	)
Fuel and purchased power change:
IP - January to March, 2005	$	(157	)	$	-		$	-		$	-		$	-		$	-		$	-
Fuel:
Generation and other		6			(4	)		-			14			(3	)		(1	)		-
Price		(19	)		(9	)		-			(10	)		3			3			-
Purchased power		27			15			(6	)		(9	)		12			12			(6	)
Total	$	(143	)	$	2		$	(6	)	$	(5	)	$	12		$	14		$	(6	)
Net change in electric margins	$	71		$	(13	)	$	(5	)	$	4		$	7		$	9		$	(18	)

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.

(b)	Compared to predecessor information for the three months ended March 31, 2004.

Ameren

Ameren’s electric margin increased $71 million for the three months ended March 31, 2005, compared with the same period in 2004. The acquisition of IP added electric margins of $78 million in the first quarter of 2005. Otherwise, electric margin decreased in the first quarter of 2005 primarily due to lower emission allowance sales, unfavorable weather conditions, rate reductions, and reduced low margin sales into the deregulated Illinois marketplace. Revenues from emission credit sales at UE decreased $15 million in the first quarter of 2005 as compared with the same period in 2004. Partially offsetting these reductions were increased interchange margins as discussed below.

We experienced mild winter weather conditions during the first quarter of 2005 compared with the same period in 2004. Heating degree-days during that period in our service territory were down 4% from the prior year and down 8% from normal conditions. Excluding the three months of IP sales in the current year, weather-sensitive residential and commercial sales were down 2% and 1%, respectively, compared with the prior year period.

Industrial sales, excluding IP sales in the current year, declined almost 6%, primarily as a result of the expiration and non-renewal of low margin power sales contracts outside of Ameren’s core service territory. Excluding the expired contracts, industrial sales rose approximately 1% over the same period in the prior year.

Rate reductions resulting from the 2002 UE electric rate case settlement in Missouri negatively affected electric revenues by $7 million during the first quarter of 2005. These were the final rate reductions under the rate case settlement.

Margins on interchange sales increased $17 million for the first three months of 2005 compared with the same period in 2004. Interchange margins increased principally because of higher power prices. In addition, there was increased availability of low-cost generation resulting from reduced demand from native load customers due to the mild weather as well as improved power plant availability. High natural gas, emission allowance and coal prices in 2005 have been contributing to the high power prices. Average realized power prices on interchange sales increased to approximately $38 per megawatthour in the first three months of 2005 from approximately $31 per megawatthour in the comparable period of 2004. Ameren’s baseload electric generating plants’ average capacity factor was approximately 76% in the first quarter of 2005 compared with 75% in the same period of 2004 and the equivalent availability factor was approximately 84%, as compared with 82% in the prior-year period.

Ameren’s fuel and purchased power costs, excluding the three months of IP results, decreased $14 million in the first quarter of 2005 compared with the same period of 2004 because of reduced demand, lower industrial sales and increased plant availability, partially offset by higher fuel costs.

UE’s electric margin decreased $13 million for the first three months of 2005 compared with the same period in 2004 primarily because of decreased emission credit sales and rate reductions from the 2002 Missouri rate case settlement. In addition, unfavorable weather conditions resulted in a decrease in residential and commercial sales of 2%. Partially offsetting these decreases to electric revenues were increased interchange margins. Margins on interchange sales with non-affiliates increased $8 million in the first three months of 2005, as compared with the same period of 2004, primarily

because of higher power prices. Margins on sales to affiliates also increased over the same period in 2004 because of increased sales to Genco resulting from a major plant maintenance outage at Genco. Fuel and purchased power was flat in the first quarter of 2005 as compared to the year-ago period as decreased power purchases due to the mild weather and improved plant availability were offset by higher fuel costs.

CIPS

CIPS’ electric margin decreased $5 million in the first quarter of 2005 compared with the same period of 2004 primarily because of unfavorable weather conditions and increased purchased power costs.

Genco

Genco’s electric margin increased $4 million in the first quarter of 2005 compared with the same period of 2004. The increase in electric margin was primarily attributable to an increase in wholesale margins on sales to new customers and increased interchange margins. Interchange margins increased $4 million in the three months ended March 31 2005, as compared with the same period in 2004, primarily because of the higher power prices. Partially offsetting these increases was a loss of $6 million due to the settlement of SO₂ emission allowance options in the first quarter of 2005. Increased purchased power, principally from UE, was the result of a major power plant maintenance outage in the first quarter of 2005.

CILCORP and CILCO

Electric margin at CILCORP and CILCO increased $7 million and $9 million, respectively, during the first quarter of 2005 compared with the same period of 2004. Increases in electric margin were due to increased interchange margins and the use of lower cost coal at one of AERG’s power plants, partially offset by the mild weather and reduced margin due to transfers of non-rate-regulated customers to Marketing Company.

IP’s electric margin decreased $18 million in the first quarter of 2005 compared with the same period of 2004 primarily because of unfavorable weather conditions and reduced industrial revenues ($8 million) because of customers choosing alternative suppliers. In addition, purchased power costs increased due to higher power prices as a result of the mix of purchases under various contracts. While power costs decreased under contracts with DYPM, costs on remaining power purchase contracts were higher than in the first quarter of the prior year.

Gas Operations

The following table presents the favorable (unfavorable) variations in gas margins, defined as gas revenues less gas purchased for resale, for the three months ended March 31, 2005, from the comparable period in 2004. We consider gas margin to be a useful measure to analyze the change in profitability of our gas utility operations between periods. We have included the table below as a complement to our financial information provided in accordance with GAAP. However, gas margin may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we are providing elsewhere in this report.


	Three Months
Ameren^(a)	$	54
UE		2
CIPS		(4	)
CILCORP		(c	)
CILCO		1
IP^(b)		(5	)

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.

(b)	Compared to predecessor information for the three months ended March 31, 2004.

(c)	Less than $1 million.

Ameren’s gas margin increased due to the inclusion of three months of IP results in the current year ($51 million). Excluding the IP results, gas margin increased $3 million as rate increases of $3 million at UE and increased transportation revenues offset the effect of mild winter weather in 2005. Gas sales in the first quarter of 2005 increased almost 70%, due to the IP acquisition, while gas sales in Ameren’s preacquisition service territory were down 5% in the same period, as a result of the mild weather. CIPS’ and IP’s gas margins decreased primarily due to unfavorable weather conditions. CILCORP’s and CILCO’s gas margins were comparable to the first quarter of 2004.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren’s other operations and maintenance expenses increased $39 million for the three months ended March 31, 2005, compared with the same period in 2004. The three months of IP results in the current year accounted for $42 million of other operations and maintenance expense. Excluding the three months of IP results in the current year, other operations and maintenance expenses were relatively flat compared to 2004 with several offsetting increases and decreases as discussed below.

Other operations and maintenance expenses decreased $9 million at UE in the first quarter of 2005, as compared with the first three months of 2004, primarily as a result of decreased power plant maintenance costs. In the first quarter of 2004, there was an unscheduled outage at the Callaway nuclear plant and planned outages at two coal-fired plants that were more extensive than in 2005. The decrease at UE in 2005 was also attributable to decreased labor costs.

Other operations and maintenance expenses decreased $4 million at CIPS in the first three months of 2005 compared with the same period of 2004 primarily because of a decrease in bad debt expense.

Genco’s other operations and maintenance expenses increased $10 million in the first quarter of 2005 compared with the first quarter of 2004 primarily as a result of increased power plant maintenance costs due to a major power plant maintenance outage in the first quarter of 2005.

CILCORP’s other operations and maintenance expenses were comparable in the first quarter of 2005 with the same period in 2004.

CILCO’s other operations and maintenance expenses decreased $3 million in the first quarter of 2005, as compared with the first three months of 2004, primarily as a result of reduced power plant maintenance.

Other operations and maintenance expenses at IP decreased $5 million in the first three months of 2005 compared with the same period of 2004. The decrease was primarily due to reduced costs associated with injuries and damages and bad debt expense.

Depreciation and Amortization

Ameren’s depreciation and amortization expenses increased $27 million in the first three months of 2005, as compared with the same period of 2004, because of the acquisition of IP, which added $21 million, as well as capital additions.

Depreciation and amortization expenses at UE increased $4 million in the first three months of 2005 compared with the first quarter of 2004 because of capital additions.

IP’s depreciation and amortization expenses, excluding the amortization of regulatory assets, were comparable in the first quarter of 2005 with the first quarter of 2004. Amortization of regulatory assets at IP decreased $11 million in the first three months of 2005, as compared with the same period of 2004. The transition cost regulatory asset was eliminated in conjunction with Ameren’s acquisition of IP.

Depreciation and amortization expenses at CIPS, Genco, CILCORP and CILCO were comparable for the three months ended March 31, 2005, with the same period in 2004.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $11 million at Ameren in the first three months of 2005 compared with the same period of 2004 principally because of the acquisition of IP, which added $22 million. Excluding the three months of IP included in the current year, taxes other than income taxes at Ameren decreased $11 million primarily because of decreased gross receipts taxes ($5 million) and property taxes ($5 million) as discussed below.

UE’s taxes other than income taxes were comparable in the first quarter of 2005 with the same period in 2004 as decreased gross receipt taxes of $2 million were offset by increased property taxes of $2 million.

Genco’s taxes other than income taxes decreased $7 million in the first three months of 2005 compared with the same period of 2004 due to a favorable property tax court decision.

Both CILCORP’s and CILCO’s taxes other than income taxes decreased $2 million in the first three months of 2005, as compared with the same period of 2004, primarily because of reduced gross receipts taxes.

Taxes other than income taxes at CIPS and IP were comparable in the first three months of 2005 with the same period of 2004.

Other Income and Deductions

Other income and deductions at Ameren, Genco, CILCORP and CILCO were comparable in the first three months of 2005 with the same period of 2004.

Other income and deductions at UE increased $2 million in the first three months of 2005 compared with the same period of 2004 primarily because of an increase in allowance for funds used during construction as a result of capital additions.

CIPS’ other income and deductions decreased $2 million in the first quarter of 2005 compared with the first quarter of 2004 primarily because of reduced interest income on the intercompany note receivable from Genco.

Other income and deductions at IP decreased $46 million in the first three months of 2005, as compared with the same period of 2004, primarily because of reduced interest income after the elimination of IP’s Note Receivable from Former Affiliate in conjunction with Ameren’s acquisition of IP.

See Note 6 - Other Income and Deductions to our financial statements under Part I, Item 1, of this report for further information.

Interest

Interest expense increased at Ameren in the first three months of 2005 compared with the same period of 2004 principally due to the acquisition of IP, which added $10 million. Excluding the three months of IP results in the current year, interest expense was comparable to the first quarter of 2004.

Genco’s interest expense was $2 million lower in the first three months of 2005, as compared with the same period of 2004, primarily because of a reduction in principal amounts outstanding on intercompany promissory notes to CIPS and Ameren.

Interest expense decreased $29 million at IP in the first three months of 2005 compared with the first quarter of 2004 primarily because of redemptions and repurchases of indebtedness of $700 million in the fourth quarter of 2004 and $70 million in the first quarter of 2005 and reductions in notes payable to IP SPT.

Interest expense at UE, CIPS, CILCORP and CILCO in the first three months of 2005 was comparable to the same period of 2004.

Income Taxes

Income tax expense increased at Ameren in the first three months of 2005 compared with the same period of 2004 because of higher pretax income and the inclusion of three months of IP results in 2005, partially offset by the recognition in the 2005 first quarter of the nontaxable federal Medicare Prescription Drug Subsidy and the recognition of a deduction allowed under the Jobs Creation Act. Income tax expense was higher at Genco, CILCORP and CILCO in the first quarter of 2005 compared with the first quarter of 2004 due to higher pretax income. Income tax expense was lower at UE, CIPS and IP in the first quarter of 2005 compared with the same period of 2004 due to lower pretax income and, in the case of CIPS, a reduction in estimates for anticipated settlements of uncertain tax positions. UE’s income tax expense was also reduced in the current year by the recognition of the Medicare Prescription Drug Subsidy and the Jobs Creation Act deduction.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO and IP) 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. For cash flows from operating activities, Genco principally relies on sales to an affiliate under a contract expiring at the end of 2006 and sales to other wholesale and industrial customers under long-term contracts. In addition, we plan to use short-term borrowings to support normal operations and other temporary capital requirements.

The following table presents net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2005 and 2004:


	Net Cash Provided By Operating Activities							Net Cash Provided By (Used In) Investing Activities									Net Cash Provided By (Used In) Financing Activities
	2005		2004		Variance			2005			2004			Variance			2005			2004			Variance
Ameren^(a)	$	357	$	244	$	113		$	(202	)	$	(161	)	$	(41	)	$	(194	)	$	439		$	(633	)
UE		107		92		15			(185	)		(95	)		(90	)		32			(5	)		37
CIPS		66		51		15			(10	)		(9	)		(1	)		(56	)		(44	)		(12	)
Genco		38		67		(29	)		(24	)		(16	)		(8	)		(15	)		(51	)		36
CILCORP		41		95		(54	)		(13	)		(33	)		20			(31	)		(61	)		30
CILCO		45		79		(34	)		(19	)		(35	)		16			(27	)		(49	)		22
IP^(b)		113		133		(20	)		1			(28	)		29			(114	)		(25	)		(89	)

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP.

(b)	2004 amounts include predecessor information.

Cash Flows from Operating Activities

Cash flows provided by operating activities increased for Ameren, UE and CIPS in the first three months of 2005 compared with the same period of 2004. Ameren’s increase in cash flows from operating activities was due to the addition of cash flows generated from IP, which was acquired on September 30, 2004. Excluding IP’s cash flows from operations of $113 million in the first three months of 2005, Ameren’s cash flows from operating activities were flat compared to 2004. Otherwise, a $30 million reduction in cash taxes in the first three months of 2005 compared to the same period in 2004 was offset by the purchase of SO₂ emission allowances of $42 million in 2005 and the absence in 2005 of

$9 million of cash flows in 2004 from a coal contract settlement and the timing of other working capital items.

UE’s cash flows from operating activities increased in the first three months of 2005 compared with the same period in 2004 principally due to a $17 million reduction in taxes paid. A change in working capital at UE was principally due to the timing and amount of accounts and wages payable related to the payment of certain annual incentive payments and property taxes. In the first three months of 2004, UE’s cash flows from operating activities benefited from the receipt of $9 million related to a coal contract settlement.

CIPS’ increase in cash flows from operating activities in the first three months of 2005 was due to the receipt of a refund of $5 million from Ameren based on its tax sharing agreement with Ameren compared with tax payments of $6 million in the same period in 2004 and a greater quarter-over-quarter reduction in natural gas inventories. These increases were partially offset by decreased operating margins as discussed under Results of Operations.

Cash flows provided by operating activities decreased for Genco in the first three months of 2005 compared with the same period of 2004. Genco’s decrease was attributed to purchases of SO₂ emission allowances and increased coal inventories of $12 million. A $13 million variance caused by the payment of taxes in the first three months of 2005 compared with a refund received in the same period in 2004 also contributed to the decrease in Genco’s cash flows from operating activities. These decreases in cash flows from operating activities were partially offset by differences in the timing and amount of accounts and wages payable along with incremental earnings as discussed under Results of Operations.

Cash flows from operating activities decreased for CILCORP and CILCO in the first three months of 2005 compared with the same period in 2004 primarily because of a smaller quarter-over-quarter reduction in gas inventories. Also contributing to the reduction in cash flows from operating activities were differences in the timing and amount of accounts and wages payable related to certain annual incentive payments and property taxes. CILCORP’s and CILCO’s decrease in cash flows from operating activities was partially offset by increased operating margins as discussed under Results of Operations.

IP’s decrease in cash flows from operating activities in the first three months of 2005 as compared to the year-ago period was principally due to lower operating margins as described under Results of Operations. These decreases were partially offset by a $10 million tax refund received in the first three months of 2005 compared with a $34 million tax payment made in the same period in 2004. IP received this refund because of lower estimated taxable income resulting from the debt redemptions made in the fourth quarter of 2004.

Cash Flows from Investing Activities

Cash flows used in investing activities increased for Ameren, UE and Genco and decreased for CILCORP and CILCO for the three months ended March 31, 2005 compared with the same period in 2004. IP’s cash flows from investing activities increased for the first three months of 2005 as compared to the same period in 2004.

Ameren’s increase in cash used in investing activities was primarily attributed to $31 million of additional capital expenditures incurred with the addition of IP and increased capital expenditures at Ameren’s other subsidiaries as described below.

UE’s cash flows used in investing activities increased because of contributions made to the money pool arrangement in the first three months of 2005 compared with receipt of cash in the same period in 2004. Incremental capital expenditures also contributed to UE’s increase in cash flows used in investing activities in the first three months of 2005 compared with the same period in 2004.

CIPS’ cash flows used in investing activities were relatively flat in the first three months of 2005 as compared with the same period of 2004.

Genco’s cash flows used in investing activities increased in the first three months of 2005 compared with the same period in 2004 because of an increase in capital expenditures as discussed below.

CILCORP’s and CILCO’s cash flows used in investing activities decreased in the first three months of 2005 compared with the same period in 2004 primarily because of reduced capital expenditures at power plants as discussed below. An additional $4 million received for payment on prior period money pool advances by CILCORP decreased its cash flows used in investing activities in the first three months of 2005 compared with the same period in 2004.

IP’s cash flows from investing activities increased in the first three months of 2005 primarily because of proceeds received from the return of advances made to the money pool arrangement in the fourth quarter of 2004.

Capital Expenditures

Ameren’s capital expenditures for the first quarter of 2005 included expenditures at UE’s Callaway nuclear plant for steam generators and low pressure rotor equipment replacement. UE’s capital expenditures also included costs for transmission, distribution and other generation-related

activities at certain of its coal-fired plants. Genco’s capital expenditures were attributed to an extended planned outage at one of its plants in the current year quarter. CILCORP’s and CILCO’s capital expenditures in 2005 were primarily related to power plant upgrades to allow more flexibility in future fuel supply for power generation. Capital expenditures at IP consisted of projects to upgrade and maintain the reliability of IP’s electric and gas transmission and distribution systems and to add new customers to the system.

Intercompany Transfer of Illinois Service Territory and Electric Generating Facilities

On May 2, 2005, UE completed the transfer of its Illinois-based electric and natural gas utility businesses to CIPS, at an estimated net book value of $138 million. UE transferred 50 percent of the assets directly to CIPS in consideration for a CIPS subordinated promissory note in the principal amount of approximately $69 million and 50 percent of the assets by means of a dividend in kind to Ameren, followed by a capital contribution by Ameren to CIPS. See Note 3 - Rate and Regulatory Matters, under Part I, Item 1 of this report for a discussion of the asset transfer.

On May 2, 2005, Genco completed the transfer to UE of its 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois, for a total estimated net book value of $240 million. UE paid for the assets with borrowings from the money pool arrangement. Genco will utilize these transfer proceeds to eliminate its $34 million affiliate note payable with Ameren, reduce its money pool borrowings and also use a portion of the proceeds to fund the maturity of its $225 million 7.75% senior notes due 2005. See Note 3 - Rate and Regulatory Matters, under Part I, Item 1, of this report for a discussion of the asset transfers.

We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity may be purchased, among other things. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.

See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a further discussion of environmental matters.

Cash Flows from Financing Activities

Cash flows from financing activities decreased for Ameren in the first three months of 2005 as compared with the same period of 2004, primarily because of the receipt of $903 million in proceeds in the first quarter of 2004 from the issuance of common stock. These proceeds were used to fund the acquisition of IP and Dynegy’s 20% interest in EEI on September 30, 2004. See Note 2 - Acquisitions to our financial statements under Part I, Item 1, of this report for further information. Reduced redemptions and repurchases of short-term debt and long-term debt in the first three months of 2005 as compared to the year-ago period partially offset the effect of the lower proceeds from issuance of common stock.

UE’s cash flows from financing activities increased in the first three months of 2005 compared with the same period of 2004. This increase was caused, in part, by cash proceeds received from the issuance of long-term debt and short-term debt in 2005, less redemptions of long-term and short-term debt in 2005, and a nuclear fuel lease payment that was made in the first three months of 2004. A decrease in the payment of dividends to Ameren was another contributing factor to UE’s increase in cash flows from investing activities. The increases were offset by reduced proceeds received from money pool borrowings in the first three months of 2005 compared with the same period in 2004.

CIPS’ cash flows used in financing activities increased in the first three months of 2005, as compared with the same period of 2004. This increase resulted from the additional use of cash to repay money pool borrowings. This increase was offset by an absence of dividend payments to Ameren in the first three months of 2005 compared with $19 million paid in the same period in 2004.

Genco’s cash flows used in financing activities decreased in the first three months of 2005, as compared with the same period of 2004, primarily because of a $32 million decrease in cash from money pool borrowings. A decrease in payments of common dividends in the first quarter of 2005 compared to the same period in 2004 also contributed to the decrease in Genco’s cash used in financing activities.

As of March 31, 2005, Genco had subordinated affiliate notes payables of $249 million and $34 million to CIPS and Ameren, respectively, which by their terms had final payments of principal and interest due on May 1, 2005. As of May 1, 2005, Genco amended certain terms of the CIPS note by the issuance to CIPS of an amended and restated subordinated promissory note in the principal amount of approximately $249 million with an interest rate of 7.125% per annum, a 5-year amortization schedule and a maturity of May 1, 2010. In May 2005, Genco paid the outstanding $34 million note payable it had with Ameren with proceeds received from the transfer of its CTs at Pinckneyville and Kinmundy, Illinois to UE.

CILCORP’s and CILCO’s cash flows used in financing activities decreased in the first three months of 2005 compared with the same period of 2004. This decrease was caused by less redemptions of long-term debt partially offset

by dividend payments made in the first quarter of 2005 compared to none in the 2004 period. Borrowings from the money pool in the first three months of 2004 were used to partially fund the repayment of a bank term loan.

IP’s cash flows used in financing activities increased in the first three months of 2005 compared with the same period of 2004 primarily because of incremental redemptions, repurchases and maturities of long-term debt and dividend payments made to Ameren in 2005.

Short-term Borrowings and Liquidity

For information on short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility money pool arrangement and non-state-regulated subsidiary money pool arrangement, see Note 4 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report.

The following table presents the various committed bank credit facilities of certain of the Ameren Companies and EEI as of March 31, 2005:


Credit Facility	Expiration	Amount Committed	Amount Available
Ameren:^(a)
Multiyear revolving	July 2006	$ 235	$ 79
Multiyear revolving	July 2007	350	350
Multiyear revolving	July 2009	350	350
UE:
Various 364-day revolving	through July 2005	154	-
CIPS:
Two 364-day revolving	through July 2005	15	-
CILCO:
Three 364-day revolving	through August 2005	60	-
EEI:
Two bank credit facilities	through June 2005	45	11
Total		$1,209	$790

(a)	Ameren Companies may access these credit facilities through intercompany borrowing arrangements.

In addition to committed credit facilities, a further source of liquidity for Ameren from time to time is available cash and cash equivalents. At March 31, 2005, Ameren had $30 million of cash and cash equivalents.

Ameren and UE are authorized by the SEC under PUHCA to have an aggregate of up to of $1.5 billion and $1 billion, respectively, of short-term unsecured debt instruments outstanding at any time. In addition, CIPS, CILCORP and CILCO have PUHCA authority to have an aggregate of up to $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 and preferred stock for the three months ended March 31, 2005 and 2004, for certain of the Ameren Companies. For additional information, see Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.

	Month Issued, Redeemed, Repurchased or Matured	Three Months
	Month Issued, Redeemed, Repurchased or Matured	2005 2004
Issuances
Long-term debt
UE:
5.00% Senior secured notes due 2020	January	$ 85 $ -
Total Ameren long-term debt issuances		$ 85 $ -
Common stock
Ameren:
19,063,181 Shares at $45.90	February	$ - $875
DRPlus and 401(k)^(a)	Various	30 28
Total common stock issuances		$ 30 $903
Total Ameren long-term debt and common stock issuances		$115 $903


	Month Issued, Redeemed, Repurchased or Matured	Three Months
	Month Issued, Redeemed, Repurchased or Matured	2005 2004
Redemptions, Repurchases and Maturities
Long-term debt
Ameren:
Senior notes due 2007^(b)	February	$95 $ -
CILCO:
Secured bank term loan	February	- 100
IP:
6.75% mortgage bonds due 2005	March	70 -
Note payable to IP SPT
5.38% Series due 2005	Various	22 22
Less: IP activity prior to acquisition date		- (22)
Total Ameren long-term debt redemptions, repurchases and maturities^(c)		$187 $100

(a)	Includes issuances of common stock of 0.6 million shares during the three months ended March 31, 2005 and 0.5 million shares during the three months ended March 31, 2004 under DRPlus and 401(k) plans.

(b)	A component of the adjustable conversion-rate equity security units. See Note 5 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.

The following table presents the authorized amounts under SEC Form S-3 shelf registration statements filed and declared effective for certain of the Ameren Companies as of March 31, 2005:


	Effective Date	Authorized Amount	Issued	Available
Ameren	June 2004	2,000	459	1,541
UE^(a)	September 2003	1,000	689	311
CIPS	May 2001	250	150	100

(a)	UE issued securities totaling $85 million in January 2005.

In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under 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, UE and CIPS may sell all or a portion of the remaining securities registered under the shelf registration statements if market conditions and capital requirements warrant such a sale. Any such offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

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 covenants and 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 covenants and provisions contained in certain of the Ameren Companies’ indenture agreements and articles of incorporation.

At March 31, 2005, Ameren and its subsidiaries were in compliance with their credit agreement and articles of incorporation provisions and covenants.

We rely on access to 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 and grow our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), 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 events might cause our cost of capital to increase or our ability to access the capital markets to be adversely affected.

Dividends

The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The 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 three months of 2005 totaled $124 million, or 63.5 cents per share (2004 - $116 million or 63.5 cents per share). On April 26, 2005, Ameren’s board of directors declared a quarterly common stock dividend of 63.5 cents per share payable on June 30, 2005, to shareholders of record on June 8, 2005.

UE’s preferred stock dividends are payable May 15, 2005, and August 15, 2005, to shareholders of record on April 20, 2005, and July 20, 2005, respectively. CIPS’ preferred stock dividends are payable June 30, 2005 and September 30, 2005, to shareholders of record on June 8, 2005, and September 8, 2005, respectively. CILCO’s preferred stock dividend is payable July 1, 2005, to shareholders of record on June 3, 2005. CILCO paid a preferred stock dividend of approximately $1 million on April 1, 2005. IP’s preferred stock dividend is payable August 1, 2005, to shareholders of record on July 11, 2005. IP paid a preferred stock dividend of approximately $1 million on May 2, 2005.

Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends. UE would experience restrictions on dividend payments if it were to extend or defer interest payments on its subordinated debentures. CIPS has provisions in its articles of incorporation restricting dividend payments based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Genco’s indenture includes restrictions that prohibit making any dividend payments if debt service coverage ratios are below a defined threshold. CILCORP has restrictions if 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. At March 31, 2005, none of the conditions described above that would restrict the payment of dividends existed. In its approval of the acquisition of IP by Ameren, the ICC issued an order that provides for the ability of IP to pay dividends on its common stock subject to certain conditions related to credit ratings of IP and Ameren and the elimination of IP’s 11.50% mortgage bonds. Given the current credit ratings of IP and the amount of IP’s 11.50% mortgage bonds that remain outstanding, IP’s payment of dividends on its common stock is restricted to $80 million in 2005 and $160 million cumulatively through 2006. In addition, in accordance with the order issued by the ICC, IP will establish a dividend policy comparable to the dividend policy of Ameren’s other Illinois utilities and consistent with achieving and maintaining a common equity to total capitalization ratio between 50% and 60%.

The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the three months ended March 31, 2005 and 2004:


	Three Months
	2005		2004
UE	$	60	$	79
CIPS		-		19
Genco		14		18
CILCORP		30		-
IP^(a)		20		-
Dividends paid by Ameren	$	124	$	116

(a)	Prior to October 2004, the ICC prohibited IP from paying dividends. If permitted to be paid, IP’s dividends would have been paid directly to Illinova or indirectly to Dynegy.

Contractual Obligations

For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and 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, 2004. See Note 12 - Pension and Other Postretirement Benefits to our financial statements under Part I, Item 1 of this report for information regarding expected minimum funding levels for our pension plan.

Subsequent to December 31, 2004, obligations related to the procurement of coal increased at Ameren, UE, Genco, CILCORP and CILCO to $2,848 million, $1,389 million, $874 million, $262 million and $262 million, respectively, as of March 31, 2005. Total other obligations at December 31, 2004, updated for material changes since year-end through March 31, 2005, at Ameren, UE, Genco, CILCORP and CILCO are $4,170 million, $1,685 million, $919 million, $620 million and $620 million, respectively.

Credit Ratings

On March 31, 2005, Moody’s upgraded IP’s credit ratings. IP’s senior secured debt rating was upgraded from Baa3 to Baa1, its issuer rating was upgraded from Ba1 to Baa2, and its preferred stock rating was upgraded from Ba3 to Ba1. This rating action concluded Moody’s review for possible upgrade that was initiated for these ratings on March 18, 2005. The ratings outlook for IP is now stable.

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and/or increase the cost of borrowings, resulting in a negative impact on earnings. At March 31, 2005, if UE, CIPS, Genco, CILCORP, CILCO or IP were to receive a sub-investment-grade rating (less than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP could have been required to post collateral for certain trade obligations amounting to $104 million, $25 million, $- million, $1 million, $6 million, $6 million, and $31 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease based on credit ratings. A credit rating is not a recommendation to buy, sell or hold securities and it 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 industrywide trends and Ameren-specific issues to affect earnings in 2005 and beyond:

·	Ameren, CILCORP, CILCO and IP expect to continue to focus on realizing integration synergies associated with these acquisitions, including lower fuel costs at CILCORP and CILCO and reduced administrative and operating expenses at IP.

·	We expect continued economic growth in our service territory to benefit electric demand in 2005.

In 2005, we expect natural gas and coal prices to support power prices similar to 2004 levels. In the first quarter of 2005, power prices exceeded 2004 levels. Power prices in the Midwest affect the amount of revenues UE, Genco and CILCO (through AERG) can generate by marketing any excess power into the interchange markets and influence the cost of power we purchase in the interchange markets.

·	Ameren’s coal and related transportation costs rose in 2004 and are expected to increase 3% to 5% in 2005 and again in 2006, and to increase, at a minimum, by 3% to 5% again in 2007.

In April 2005, the Missouri House of Representatives passed Senate Bill 179. This bill was previously passed by the Missouri Senate. If signed by the Governor of Missouri, this bill would enable the MoPSC to put in place an environmental cost recovery mechanism for Missouri’s utilities. In addition, it would enable the MoPSC to allow electric utilities to recover fuel and purchased power costs through a similar recovery mechanism. The legislation also includes rate case filing requirements, a 2 1/2 percent annual rate increase cap for the environmental recovery mechanism and prudency reviews, among other things.

On April 1, 2005, the MISO Day Two Markets began operating. The Day Two markets present an opportunity for increased power sales from UE, Genco and CILCO power plants. During the first month of Day Two operations, we have seen what we believe is suboptimal dispatching of power plants and some price volatility.

Due to recent or future regulatory proceedings, there could be changes to the agreement between UE and Genco to dispatch electric generation jointly or changes to the effect of that agreement on revenues. Any change would likely result in a transfer of electric margins between Genco and UE and could ultimately affect the pricing of electric transfers between Genco and UE. Ameren’s earnings could be affected if and when electric rates for UE are adjusted by the MoPSC to reflect any such transfers, amendments to the joint dispatch agreement and other changes in costs of providing electric service. See Note 3 - Rate and Regulatory Matters and Note 8 - Related Party Transactions to our financial statements under Part I, Item 1, of this report for a more detailed description of the joint dispatch agreement and potential impacts.

UE’s Callaway nuclear plant will have a refueling and maintenance outage in the fall of 2005, which is expected to last 70 to 75 days. During this outage, major capital equipment will be replaced, which means that the outage will last longer than a typical refueling outage, which usually lasts 30 to 35 days and occurs approximately every 18 months. The delivery of some major equipment for this outage is dependent on adequate water levels in the Missouri River. Any delays or damage during shipment could result in additional costs and deferral of the project. These potential low water levels, caused by a persistent drought in the Missouri River basin, could also cause reduced operations at the Callaway nuclear plant and UE’s Labadie plant. During a refueling outage, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases versus non-outage years.

· Over the next few years, we expect increased expenses for rising employee benefit costs as well as higher insurance and security costs associated with additional measures we

have taken, or may have to take, at UE’s Callaway nuclear plant and our other operating plants.

·	We are currently undertaking cost reduction or control initiatives associated with the strategic sourcing of purchases and streamlining of administrative functions. UE, Genco and CILCO are also seeking to raise the

equivalent availability and capacity factors of power plants from 2004 levels.

Electric rates for Ameren’s operating subsidiaries have been fixed or declining for periods ranging from 12 years to 22 years. In 2006, electric rate adjustment moratoriums and intercompany power supply contracts expire in Ameren’s regulatory jurisdictions. Approximately 8 million megawatthours supplied annually by Genco and 6 million megawatthours supplied annually by AERG have been subject to contracts to provide CIPS and CILCO, respectively, with power. The prices in these power supply contracts of $34.00 per megawatthour for AERG and $38.50 per megawatthour for Genco were below estimated market prices for similar contracts in April 2005. CIPS, CILCO and IP made a filing with the ICC, in February 2005, outlining, among other things, a proposed framework for generation procurement after 2006. In 2005, Ameren will also begin the process of preparing utility cost-of-service studies to be submitted in Illinois and Missouri in late 2005 or early 2006 to determine rates for UE, CIPS, CILCO and IP. In March 2005 legislative hearings, Ameren indicated it expected the average rates for its Illinois utilities, on a combined basis, may increase by 10% to 20% in 2007 over present bundled rate levels, with 50% to 70% of this increase resulting from higher power costs. This estimate was based on a number of assumptions about auction results, ratemaking outcomes and various other factors. The final results of the auction process and regulatory proceedings could be significantly different from these assumptions. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.

· The EPA has issued more stringent emission limits on all coal-fired power plants. Between 2005 and 2015, Ameren expects that certain of the Ameren Companies will be required

to invest between $1.4 and $1.9 billion to retrofit their power plants with pollution control equipment. These investments will also result in higher ongoing operating expenses.

Approximately two-thirds of this investment will be in Ameren’s regulated Missouri operations and therefore is expected to be recoverable over time from ratepayers. The

recoverability of amounts expended in non-rate-regulated operations will depend on the adjustment of market prices for power as a result of this increased investment.

The outcome and developments related to the above items could have a material impact on our results of operations, financial position, or liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position or liquidity.

RISK FACTORS

Ameren may not be able to integrate IP successfully into its other businesses or achieve the benefits it anticipates.

Ameren cannot ensure that it will be able to integrate IP successfully with its other businesses. The integration of IP with its other businesses will present significant challenges; 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 it may not be able to achieve those benefits at all. Ameren expects that this acquisition will be accretive to earnings per share in the first two years. This expectation is based on important assumptions, which may be incorrect, including assumptions related to expected financing arrangements, regulatory treatment, interest rates, market prices for power, and synergies. As a result, if Ameren is unable to integrate its businesses effectively or to achieve the benefits anticipated, its results of operations, financial position and liquidity may be materially adversely affected.

The electric and gas rates that certain Ameren Companies are allowed to charge in Missouri and Illinois are largely set through 2006. These “rate freezes,” along with other actions of regulators that can significantly affect our earnings, liquidity and business activities, are largely outside our control.

The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, and liquidity of the Ameren Companies. Our industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental organizations outside of our control, including the MoPSC, the ICC, and the FERC. We are also subject to regulation by the SEC under the PUHCA. Decisions made by these regulators could have a material impact on our results of operations, financial position and liquidity.

As a part of the settlement of UE’s Missouri electric rate case in 2002, UE is subject to a rate moratorium that prohibits changes in its electric rates in Missouri before July 1, 2006, subject to limited statutory and other exceptions. In addition, a provision of the Illinois legislation related to the restructuring of the Illinois electric industry put a rate freeze into effect in Illinois through January 1, 2007, for CIPS, CILCO and IP. This Illinois legislation also requires that 50% of the earnings from each respective Illinois jurisdiction in excess of certain levels be refunded to CIPS’, CILCO’s and IP’s Illinois customers through 2006. 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. UE will

make no changes in its gas delivery rates prior to July 1, 2006, subject to certain exceptions. Also, in the order approving Ameren’s acquisition of IP, the ICC prohibited IP from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond IP’s then-pending request for a gas delivery rate increase. The ICC conducted workshops seeking input from interested parties on the framework to be used for retail rate determination and for generation procurement by customers after the current Illinois rate freeze and supply contracts end in 2006. In February 2005, CIPS, CILCO and IP filed with the ICC a proposed format for the generation procurement auction and a rate mechanism to legislators to pass generation costs through to customers, among other things.

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, for among other things, the addition of more than 700 megawatts of new generation capacity. UE satisfied its commitment with respect to the addition of new generation capacity by the construction of 240 megawatts of CTs in 2002 and the acquisition of 550 megawatts of CTs from Genco in May 2005. Ameren also committed IP to make between $275 million and $325 million in energy infrastructure investments over its first two years of ownership, in conjunction with the ICC’s approval of Ameren’s acquisition of IP. UE’s agreement to a rate moratorium in Missouri and CIPS’, CILCO’s and IP’s rate freezes mean that capital expenditures will not become recoverable in rates, and will not earn a return, before July 1, 2006, for UE and January 1, 2007, for CIPS, CILCO and IP. Therefore, undertakings with respect to energy infrastructure investments and funding new programs, coupled with the rate reductions and rate moratoriums, could result in increased financing requirements for UE, CIPS, CILCO and IP and thus have a material impact on our results of operations, financial position and liquidity.

The Ameren Companies do not have in either Missouri or Illinois a fuel adjustment clause for their electric operations that would allow them to recover from customers’ costs for purchased power or increased fuel used for generation. 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 that 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 for transmission-owning public utilities such as UE, CIPS, CILCO and IP. In Missouri, restructuring bills have been introduced in the past, but no legislation has been passed. In Illinois, which since the acquisition of IP, supplies over 50% of Ameren’s electric revenues, the Illinois Customer Choice Law provides for electric utility restructuring and retail competition.

Principally because of rate reductions and rate moratoriums that affect certain Ameren Companies, increased costs and investments have resulted in decreased returns in our distribution utility businesses. In 2005, Ameren will begin the process for preparing and submitting proposals for utility rate adjustments in Illinois and Missouri to take effect after the expiration of the applicable rate moratoriums.

We are not able to predict what rate treatment certain Ameren Companies will receive after the rate moratoriums expire in Missouri and Illinois. There are currently activities under way in Illinois to determine the framework for retail electric rate determination and generation procurement after the current Illinois electric rate freeze and supply contracts expire in 2006. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report. In response to competitive, economic, political, legislative and regulatory pressures, we may be subject to further rate moratoriums, rate refunds, limits on rate increases or rate reductions, any and all of which could have a significant adverse affect on our results of operations, financial position and liquidity. See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report.

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. In March 2005, the EPA issued final regulations with respect to SO₂, NO_x, and mercury emissions from coal-fired power plants. These new rules will require significant additional reductions in these emissions from our power plants in phases, beginning in 2010. Preliminary estimates of capital costs, based on Ameren systems’ current technology, to comply with the EPA proposed SO₂, NO_x, and mercury emission regulations, range from $1.4 billion to $1.9 billion by 2015.

Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. Coal-fired power plants are significant sources of carbon dioxide emissions, a principal greenhouse gas. The related Kyoto Protocol was signed by the United States, but it has since been rejected by the president, who instead has asked for an 18% voluntary decrease in carbon intensity. In response to the administration’s request, six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the Tennessee Valley Authority (TVA), signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% - 5% decrease in carbon intensity from the utility sector between 2002 and 2012 on a voluntary basis. Currently, Ameren is considering various initiatives to comply

with the MOU. These include enhanced generation at our nuclear and hydro power plants, increased efficiency measures at our coal-fired units, and investing in renewable energy and carbon sequestration projects.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility and AERG’s E.D. Edwards and Duck Creek facilities. All of these facilities are coal-fired plants. The information request requires Genco to provide responses to specific EPA questions regarding certain projects and maintenance activities in order to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standard requirements of the Clean Air Act. Genco intends to comply with this information request, but cannot predict the outcome of this matter at this time.

We are unable to predict the ultimate effect of any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation on our results of operations, financial position or liquidity. Any of these factors would add significant pollution control expenditures and operating costs to UE’s, Genco’s and CILCO’s generating assets and, therefore, could also increase financing requirements for some Ameren Companies. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs by Genco or CILCO in Illinois.

UE’s, CIPS’, CILCO’s and IP’s participation in the MISO could increase costs, reduce revenues, and reduce UE’s, CIPS’, CILCO’s and IP’s control over their transmission assets. Genco could also incur increased costs or reduced revenues as a result of participation in the MISO Day Two Markets.

On May 1, 2004, functional control of the UE and CIPS transmission systems was transferred to the MISO. On September 30, 2004, IP transferred functional control of its transmission system to the MISO. CILCO had transferred functional control of its transmission system to the MISO before the acquisition. The participation by UE, CIPS and IP in the MISO is expected to increase annual costs by $10 million to $25 million in the aggregate because the companies will be subject to the MISO’s administrative costs. Participation could also result in a decrease in annual revenues of $5 million to $15 million in the aggregate, because of the MISO’s method of allocating transmission revenues. UE, CIPS, CILCO and IP may also be required to expand their transmission systems according to decisions made by MISO rather than according to their internal planning process. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8, of the Ameren Companies’ combined Form 10-K for the year ended December 31, 2004.

In July 2002, the FERC issued its standard market design NOPR. The NOPR proposed three important changes to the way the current wholesale transmission service and energy markets are operated: the placement of all jurisdictional transmission facilities under the control of an independent transmission provider (similar to the MISO); a new transmission service tariff that would provide a single form of transmission service for all users of the transmission system, including bundled retail load; and a new transmission management system. This new design would use market-based pricing to compensate market participants for power, as well as for transmission congestion and losses. The current system requires generators to make advance reservations for transmission service.

In April 2003, the FERC issued a white paper reflecting comments received in response to the NOPR. The white paper indicated that the FERC will not assert jurisdiction over the transmission rate component of bundled retail service. The FERC will ensure in its final rule that existing bundled retail customers retain their existing transmission rights and their 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. We believe that the proposed NOPR could have a negative impact on the cost and reliability of service to retail customers. It could lead to trapped transmission costs that might not be recoverable from ratepayers as a result of inconsistent regulatory policies.

Although issuance of the final rule is uncertain and its implementation schedule unknown, the MISO implemented a separate market design similar to the market design proposed by the NOPR. This new market design is referred to as the MISO Day Two Market. The MISO Day Two Market, which began operation on April 1, 2005, is designed to result in improved transparency of power pricing and efficiency in generation dispatch. Since this is a new and complex market, there could be significant initial price volatility. During the first month of Day Two operations, we have seen what we believe is suboptimal dispatching of power plants and some price volatility. Ultimately, price transparency and dispatch efficiency could result in lower prices on market-based power sales by UE, Genco, AERG and CILCO to their customers. In

addition, the movement of power could result in unanticipated transmission congestion charges or credits. The MISO has allocated FTRs, which are financial instruments intended to hedge the risk of day-ahead congestion, to UE, CIPS, Genco, CILCO and IP. The MISO also has issued FTRs to IP for the portion of IP load not served pursuant to the power supply agreement between DYPM and IP. DYPM has assumed the risk of congestion for the IP load served pursuant to this power supply agreement. UE, CIPS, Genco, CILCO and IP may not have been allocated the appropriate number of these FTRs. In addition, these instruments could prove ineffective in hedging the day-ahead congestion risk.

Until we achieve some degree of operational experience participating in the MISO, including the MISO Day Two Market, we are unable to predict the impact that the MISO participation or ongoing RTO developments at the FERC or other regulatory authorities will have on our results of operations, financial position or liquidity.

Increasing costs associated with our defined benefit retirement plans, health care plans, and other employee- related benefits may adversely affect our results of operations, financial position, and liquidity.

We have defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and other actuarial assumptions have a significant impact on our earnings and funding requirements. Assuming that we continue to receive federal interest rate relief beyond 2005, we do not expect contributions to our defined benefit plans to be required until 2008 and 2009, when an aggregate $400 million is expected to be paid. This amount is an estimate; it may change because of actual stock market performance, changes in interest rates, or any pertinent changes in government regulations, any of which could also result in a requirement to record an additional minimum pension liability.

In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plans, health care plans and other employee benefits may adversely affect our results of operations, financial position or liquidity.

UE’s, Genco’s, CILCO’s, AERG’s, Medina Valley’s and EEI’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, and increased purchased power costs.

UE, Genco, CILCO, AERG, Medina Valley, and EEI own and operate coal, nuclear, gas-fired, hydro, and oil-fired generating facilities. Operation of electric generating facilities involves certain risks that can adversely affect energy output and efficiency levels. Included among these risks are:

·	increased prices for fuel and fuel transportation as existing contracts expire;

·	facility shutdowns due to a failure of equipment or processes or operator error;

·	longer-than-anticipated maintenance outages;

·	disruptions in the delivery of fuel and lack of adequate inventories;

·	labor disputes;

·	inability to comply with regulatory or permit requirements;

·	disruptions in the delivery of electricity;

·	increased capital expenditures requirements, including those due to environmental regulation; and

·	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 CILCO’s generating capacity is committed under affiliate contracts that expire at the end of 2006. Upon expiration of these contracts, Genco’s and CILCO’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risk.

As of March 31, 2005, Genco and CILCO, through AERG, owned 4,199 megawatts and 1,165 megawatts, respectively, of non-rate-regulated electric generating facilities. Of these non-rate-regulated electric generating facilities, approximately 3,300 megawatts are currently under full-requirements contracts with our affiliates. The remainder of the generating capacity must compete for the sale of energy and capacity.

To the extent electric capacity generated by these facilities is not under contract to be sold, 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:

·	the current and future market prices for natural gas, fuel oil and coal;

·	current and forward prices for the sale of electricity;

·	the extent of additional supplies of electric energy from current competitors or new market entrants;

·	the pace of deregulation in our market area and the expansion of deregulated markets;

·	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;

·	future pricing for, and availability of, transmission services on transmission systems, and the effect of

RTOs and export energy transmission constraints, which could limit the ability to sell energy in markets adjacent to Illinois;

·	the rate of growth in electricity usage as a result of population changes, regional economic conditions, and the implementation of conservation programs; and

·	climate conditions prevailing in the Midwest market.

In a report issued by the ICC in late 2004, a process was outlined that would have CIPS, CILCO and IP procuring power through an auction monitored by the ICC after the current Illinois rate freeze and supply contracts end in 2006. Genco and AERG, through Marketing Company, would probably participate in this auction, but there might be a limit on the maximum amount of power they could supply to Ameren’s Illinois utilities. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.

Genco and UE have signed an agreement to dispatch their generating facilities jointly, which produces benefits and efficiencies for both generating parties. Recently completed or future federal and state regulatory proceedings and policies may evolve in ways that could affect Genco’s ability to participate in these affiliate transactions on current terms. For example, as a result of the MoPSC order approving the transfer of UE’s Illinois-based utility business to CIPS, certain terms of the joint dispatch agreement were ordered to be modified; this could result in margins from interchange sales of $7 million to $24 million being transferred from Genco to UE or just reduced at UE through the ratemaking process. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a more detailed description of these modifications. The termination of the joint dispatch agreement, or modifications to it, could have a material effect on UE or Genco.

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 capacity. Therefore, UE is subject to the risks of nuclear generation, which include the following:

·	potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;

·	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with UE’s nuclear operations or those of others in the United States;

·	uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate;

·	increased public and governmental concerns over the adequacy of security at nuclear power plants;

·	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

·	costly and extended outages for scheduled or unscheduled maintenance.

The NRC has broad authority under federal law to impose licensing and safety requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines, shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as UE’s. In addition, if a serious nuclear incident occurred, it could have a material but indeterminable adverse effect on UE’s results of operations, financial position or liquidity. 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 resulted in unscheduled or extended outages including the extension of Callaway’s scheduled refueling and maintenance outage in 2004. In addition, Ameren and UE incurred significant unanticipated replacement power and maintenance costs. As a result, the operating performance at UE’s Callaway nuclear plant has declined in comparison with both its past operating performance and the operating performance of other nuclear plants in the U.S. Ameren and UE are actively working to address the factors that led to the decline in Callaway’s operating performance. Management and supervision of operating personnel, equipment reliability, maintenance worker practices, engineering performance, and overall organizational effectiveness have been reviewed with some actions taken and other actions currently under consideration. However, Ameren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Any actions taken are expected to result in incremental operating costs at Callaway. Further, additional unscheduled or extended outages at Callaway could have a material adverse effect on the results of operations, financial position and liquidity 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 or increased volatility in 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 use long-term purchase and sales contracts in addition to derivatives such as forward contracts, futures contracts, options, and swaps to manage

these risks. We attempt to manage our risk associated with 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.

Although we routinely enter into contracts 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 unhedged positions than we would prefer at a given time. To the extent that unhedged positions exist, fluctuating commodity prices can adversely affect our results of operations, financial position and liquidity.

Our counterparties may not meet their obligations to us.

We are exposed to risk that counterparties who owe us money, energy or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements (which include agreements for a subsidiary of Dynegy and others to supply electricity to IP during 2005 and 2006) fail to perform, IP might be forced to replace the underlying commitment at then-current market prices. In such event, we might incur losses in addition to the amounts, if any, already paid to the counterparties.

Our facilities are considered critical infrastructure and may be targets for acts of terrorism.

Like other electric and gas utilities, our power generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues or significant additional costs to repair, which could have a material adverse effect on our results of operations, financial position and liquidity.

Our businesses are dependent on our ability to access the capital markets successfully. We may not have access to sufficient capital in the amounts and at the times needed.

We use short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements, including those related to future environmental compliance, 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 expand 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 that could increase our cost of capital or impair our ability to access the capital markets.

REGULATORY MATTERS

See Note 3 - Rate and Regulatory Matters 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 asset 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 nonfinancial or nonquantifiable. Such risks, principally business, legal and operational risks, 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 comprises senior-level Ameren officers.

Interest Rate Risk

We are exposed to market risk through changes in interest rates associated with:

·	long-term and short-term variable-rate debt;

·	fixed-rate debt;

·	commercial paper; and

·	auction-rate long-term debt.

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 increase by 1% on variable rate debt outstanding at March 31, 2005:


	Interest Expense		Net Income^(a)
Ameren	$	14	$	(9	)
UE		8		(5	)
CIPS		1		-
Genco		1		(1	)
CILCORP		3		(2	)
CILCO		2		(1	)
IP		3		(2	)

(a)	Calculations are based on an effective tax rate of 37%.

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 probably 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.

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 who make up our customer base. At March 31, 2005, no nonaffiliated customer represented greater than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. UE, Genco and Marketing Company have credit exposure associated with accounts receivable from nonaffiliated companies for interchange sales. At March 31, 2005, UE’s, Genco’s and Marketing Company’s combined credit exposure to non-investment-grade counterparties related to interchange sales was $3 million, net of collateral (2004 - $4 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk-management program that 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 we monitor counterparty exposure associated with our leveraged leases. We are currently evaluating our credit exposure associated with the implementation of the MISO Day Two on April 1, 2005, but we are unable to predict at this time what impact it will have, if any.

Equity Price Risk

Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rate of return on plan assets, the discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of our plan assets was negatively affected by volatility in the equity markets in 2003 and 2004 for the pension and postretirement plans. As a result, at December 31, 2004, we recognized an additional minimum pension liability as prescribed by SFAS No. 87, “Employers’ Accounting for Pensions,” which resulted in an after-tax charge to OCI of $6 million, offsetting the $46 million of OCI in 2003 from a reduction in the minimum pension liability and an increase in stockholders’ equity. The minimum pension liability has not changed as of March 31, 2005.

The amount of the pension liability as of March 31, 2005, was the result of asset returns, interest rates, and our contributions to the plans during 2004. 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, then the recorded liability would 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, 2004.

The following table presents the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant and natural gas for our gas-fired generation (CTs) and retail distribution, as appropriate, which are price-hedged over the remainder of 2005 through 2009:


	2005	2006	2007 - 2009
Ameren:
Coal	97%	91%	53%
Coal transportation	100	95	83
Nuclear fuel	100	100	34
Natural gas for generation	39	8	2
Natural gas for distribution^(a)	n/a	17	5
UE:
Coal	96%	89%	50%
Coal transportation	100	99	85
Nuclear fuel	100	100	34
Natural gas for generation	10	6	3
Natural gas for distribution^(a)	n/a	17	7
CIPS:
Natural gas for distribution^(a)	n/a	29%	13%
Genco:
Coal	100%	100%	62%
Coal transportation	99	95	65
Natural gas for generation	50	7	3
CILCORP:
Coal	100%	77%	51%
Coal transportation	100	69	64
Natural gas for distribution^(a)	n/a	24	9
CILCO:
Coal	100%	77%	51%
Coal transportation	100	69	64
Natural gas for distribution^(a)	n/a	24	9
IP:
Natural gas for distribution^(a)	n/a	7%	0%

(a)

Represents the percentage of natural gas price hedged for the peak winter season which includes the months of November through March. The year 2005 represents the period January 2005 through March 2005 and therefore is non-applicable (N/A) for this report. The year 2006 represents November 2005 through March 2006. This continues each successive year through March 2009.

The following table presents the estimated annual increase in our total fuel expense and decrease in net income if coal and coal transportation costs were to increase by 1% on any requirements currently not covered by fixed-price contracts for the remainder of 2005 through 2009:


	Coal					Transportation
	Fuel Expense		Net Income^(a)			Fuel Expense		Net Income^(a)
Ameren	$	6	$	(4	)	$	2	$	(1	)
UE		4		(2	)		-		-
Genco		1		(1	)		1		-
CILCORP		1		(b	)		1		-
CILCO		1		(b	)		1		-

(a)	Calculations are based on an effective tax rate of 37%.

(b)	Less than $1 million.

In the event of a significant change in coal prices, UE, Genco and CILCO would probably take actions to further mitigate their 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 or fuel sources.

See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further information.

Fair Value of Contracts

Most of our commodity contracts qualify for treatment as normal purchases and normal sales. We use 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:

·	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;

·	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

·	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 governed by risk-management policies that control the use of forward contracts, futures, options and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring sufficient volumes are available to meet our requirements. See Note 7 - Derivative Financial Instruments to our financial statements under Part I, Item 1, of this report for further information.

The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the quarter ended March 31, 2005. The sources used to determine the fair value of these contracts were primarily active quotes and other external sources. All of these contracts have maturities of less than three years.


	Ameren^(a)			UE			CIPS		CILCORP		CILCO
Fair value of contracts at beginning of period, net	$	21		$	(10	)	$	6	$	14	$	14
Contracts realized or otherwise settled during the period		(6	)		-			-		1		1
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		32			5			9		19		19
Fair value of contracts outstanding at end of period, net	$	47		$	(5	)	$	15	$	34	$	34

(a)	Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations.

ITEM 4. CONTROLS AND PROCEDURES.

(a)	Evaluation of Disclosure Controls and Procedures

As of March 31, 2005, the principal executive officer and principal financial officer of each of the Ameren Companies 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 of the Ameren Companies have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to such Registrant that is required in such Registrant’s reports filed or submitted to the SEC under the Exchange Act.

(b)	Change in Internal Controls

There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting, except for the following. As a result of the acquisition of IP on September 30, 2004, Ameren is integrating the accounting and financial reporting processes of IP into certain Ameren shared service functions. In that regard, certain aspects of IP's internal control over financial reporting were modified to conform to the existing Ameren internal controls during the quarter ended March 31, 2005. On April 1, 2005, Ameren converted IP from its legacy financial information systems (excluding IP's billing system) to the financial information systems of Ameren. As a result of these system conversions, certain of Ameren's internal controls over financial reporting were modified to accommodate the accounting processes of IP. Additionally, on April 1, 2005, certain internal controls over financial reporting were implemented or modified in conjunction with Ameren's participation in the MISO Day Two Market. These internal controls primarily related to revenue and cost recognition associated with power sales and purchases.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Ameren’s purchases of equity securities reportable under Item 703 of Regulation S-K:


Period	(a) Total Number of Shares (or Units) Purchased^(a)	(b) Average Price Paid per Share (or Unit)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 1 - January 31, 2005	6,730	$49.35	-	-
February 1 - February 28, 2005	330,676	51.19	-	-
March 1 - March 31, 2005	5,350	51.24	-	-
Total	342,756^(a)	$51.16	-	-

(a)

190,640 of 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. Included in February’s figures were 152,116 shares of Ameren common stock purchased by Ameren in open-market transactions to satisfy the 2005 restricted stock awards granted to employees 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 January 1 to March 31, 2005, period.

ITEM 6. EXHIBITS.

(a) Exhibits. The documents listed below are being filed on behalf of Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP as indicated.

Exhibit Designation	Registrant(s)	Nature of Exhibit
Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3	UE	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE
31.4	UE	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE
31.5	CIPS	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CIPS
31.6	CIPS	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CIPS
31.7	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco
31.8	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco
31.9	CILCORP	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCORP
31.10	CILCORP	Rule 13a-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
31.13	IP	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of IP
31.14	IP	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of IP

Exhibit Designation	Registrant(s)	Nature of Exhibit
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	Section 1350 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
32.13	IP	Section 1350 Certification of Principal Executive Officer of IP
32.14	IP	Section 1350 Certification of Principal Financial Officer of IP

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 signaature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.


	AMEREN CORPORATION (Registrant)

	By:	/s/ Martin J. Lyons
		Martin J. Lyons
		Vice President and Controller (Principal Accounting Officer)


	UNION ELECTRIC COMPANY (Registrant)

	By:	/s/ Martin J. Lyons
		Martin J. Lyons
		Vice President and Controller (Principal Accounting Officer)


	CENTRAL ILLINOIS PUBLIC SERVICE COMPANY (Registrant)

	By:	/s/ Martin J. Lyons
		Martin J. Lyons
		Vice President and Controller (Principal Accounting Officer)


	AMEREN ENERGY GENERATING COMPANY (Registrant)

	By:	/s/ Martin J. Lyons
		Martin J. Lyons
		Vice President and Controller (Principal Accounting Officer)


	CILCORP INC. (Registrant)

	By:	/s/ Martin J. Lyons
		Martin J. Lyons
		Vice President and Controller (Principal Accounting Officer)


	CENTRAL ILLINOIS LIGHT COMPANY (Registrant)

	By:	/s/ Martin J. Lyons
		Martin J. Lyons
		Vice President and Controller (Principal Accounting Officer)


	ILLINOIS POWER COMPANY (Registrant)

	By:	/s/ Martin J. Lyons
		Martin J. Lyons
		Vice President and Controller (Principal Accounting Officer)

Date: May 10, 2005