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

Ameren's Combined 3Q 10-Q

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 September 30, 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)
	370 South Main Street
	Decatur, Illinois 62523
	(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)

Indicate by check mark whether each Registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

Ameren Corporation	Yes	( )	No	(X)
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 November 1, 2005, was as follows:

Ameren Corporation	Common stock, $.01 par value per share - 204,273,646

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 filings of Ameren Corporation and its other Registrant subsidiaries.

TABLE OF CONTENTS

	Page
Glossary of Terms and Abbreviations...........................................................................................................................................................................................................................................	5

Forward-looking Statements............................................................................................................................................................................................................................................................	7

PART I Financial Information

Item 1. Financial Statements (Unaudited)
Ameren Corporation
Consolidated Statement of Income.........................................................................................................................................................................................................................	8
Consolidated Balance Sheet....................................................................................................................................................................................................................................	9
Consolidated Statement of Cash Flows.................................................................................................................................................................................................................	10
Union Electric Company
Consolidated Statement of Income.........................................................................................................................................................................................................................	11
Consolidated Balance Sheet....................................................................................................................................................................................................................................	12
Consolidated Statement of Cash Flows.................................................................................................................................................................................................................	13
Central Illinois Public Service Company
Statement of Income..................................................................................................................................................................................................................................................	14
Balance Sheet.............................................................................................................................................................................................................................................................	15
Statement of Cash Flows..........................................................................................................................................................................................................................................	16
Ameren Energy Generating Company
Consolidated Statement of Income.........................................................................................................................................................................................................................	17
Consolidated Balance Sheet....................................................................................................................................................................................................................................	18
Consolidated Statement of Cash Flows.................................................................................................................................................................................................................	19
CILCORP Inc.
Consolidated Statement of Income.........................................................................................................................................................................................................................	20
Consolidated Balance Sheet....................................................................................................................................................................................................................................	21
Consolidated Statement of Cash Flows.................................................................................................................................................................................................................	22
Central Illinois Light Company
Consolidated Statement of Income.........................................................................................................................................................................................................................	23
Consolidated Balance Sheet....................................................................................................................................................................................................................................	24
Consolidated Statement of Cash Flows.................................................................................................................................................................................................................	25
Illinois Power Company
Consolidated Statement of Income.........................................................................................................................................................................................................................	26
Consolidated Balance Sheet....................................................................................................................................................................................................................................	27
Consolidated Statement of Cash Flows.................................................................................................................................................................................................................	28

Combined Notes to Financial Statements......................................................................................................................................................................................................................	29

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations..............................................................................................................................	53
Item 3. Quantitative and Qualitative Disclosures About Market Risk...................................................................................................................................................................................	76
Item 4. Controls and Procedures..................................................................................................................................................................................................................................................	79

PART II Other Information
Item 1. Legal Proceedings..............................................................................................................................................................................................................................................................	80
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds....................................................................................................................................................................................	80
Item 5. Other Information...............................................................................................................................................................................................................................................................	80
Item 6. Exhibits................................................................................................................................................................................................................................................................................	81

Signatures...........................................................................................................................................................................................................................................................................................	82

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 7 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 their various business activities are discussed.

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.

Baseload - The minimum amount of electric power delivered or required over a given period of time at a steady rate.

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 and various non-rate-regulated subsidiaries.

CIM - CILCORP Investment Management Inc., a non-rate-regulated subsidiary of CILCORP that holds investments in several leasing transactions and owns interests in several leasing credit partnerships.

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.

Cooling degree-days - The summation of positive differences between the mean daily temperature and a 65- degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity for summer space cooling for residential and commercial customers.

CT - Combustion turbine 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.

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.

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 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 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 46R, IP SPT was no longer consolidated within IP’s financial statements.

IRS - Internal Revenue Service.

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.

LIBOR - London Interbank Offered Rate, the interest rate that banks charge each other for loans.

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 Energy 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.

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, which has been repealed effective February 8, 2006 by the Energy Policy Act of 2005 enacted on August 8, 2005.

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 Ratings Services, 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 46R, IP does not consolidate IP SPT and therefore 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, including the costs associated with operating in the MISO Day Two Energy Market;

·	the availability of fuel for the production of electricity, such as coal and natural gas, and purchased power and natural gas for distribution;

·	the ability of suppliers to add or pass through volatility of future market prices for fuel commodities with the risk of our 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;

·	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 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						Nine Months Ended
		September 30,						September 30,
		2005			2004			2005			2004
Operating Revenues:
Electric	$	1,719		$	1,227		$	4,257		$	3,155
Gas		149			78			819			498
Other		-			2			3			5
Total operating revenues		1,868			1,307			5,079			3,658

Operating Expenses:
Fuel and purchased power		621			320			1,524			863
Gas purchased for resale		90			47			550			335
Other operations and maintenance		391			314			1,109			956
Depreciation and amortization		158			136			472			398
Taxes other than income taxes		98			77			284			231
Total operating expenses		1,358			894			3,939			2,783

Operating Income		510			413			1,140			875

Other Income and (Deductions):
Miscellaneous income		6			8			19			20
Miscellaneous expense		(3	)		(1	)		(12	)		(6	)
Total other income and (deductions)		3			7			7			14

Interest Charges and Preferred Dividends:
Interest		70			62			221			192
Preferred dividends of subsidiaries		4			3			10			8
Net interest charges and preferred dividends		74			65			231			200

Income Before Income Taxes		439			355			916			689

Income Taxes		159			123			330			242

Net Income	$	280		$	232		$	586		$	447

Earnings per Common Share – Basic and Diluted	$	1.37		$	1.20		$	2.94		$	2.44

Dividends per Common Share	$	0.635		$	0.635		$	1.905		$	1.905
Average Common Shares Outstanding		203.8			193.5			199.6			183.5

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

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

		September 30,			December 31,
		2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	278		$	69
Accounts receivables – trade (less allowance for doubtful
accounts of $16 and $14, respectively)		480			442
Unbilled revenue		305			336
Miscellaneous accounts and notes receivable		21			38
Materials and supplies		840			623
Other current assets		59			74
Total current assets		1,983			1,582
Property and Plant, Net		13,402			13,297
Investments and Other Assets:
Investments in leveraged leases		124			140
Nuclear decommissioning trust fund		244			235
Goodwill and other intangibles, net		957			940
Other assets		496			411
Regulatory assets		884			829
Total investments and other assets		2,705			2,555
TOTAL ASSETS	$	18,090		$	17,434

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	347		$	423
Short-term debt		23			417
Accounts and wages payable		461			567
Taxes accrued		196			26
Other current liabilities		369			374
Total current liabilities		1,396			1,807
Long-term Debt, Net		5,201			5,021
Preferred Stock of Subsidiary Subject to Mandatory Redemption		19			20
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,980			1,886
Accumulated deferred investment tax credits		132			139
Regulatory liabilities		1,207			1,042
Asset retirement obligations		416			439
Accrued pension and other postretirement benefits		763			756
Other deferred credits and liabilities		310			315
Total deferred credits and other liabilities		4,808			4,577
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption		195			195
Minority Interest in Consolidated Subsidiaries		15			14
Commitments and Contingencies (Notes 3, 9 and 10)
Stockholders' Equity:
Common stock, $.01 par value, 400.0 shares authorized –
shares outstanding of 204.2 and 195.2, respectively		2			2
Other paid-in capital, principally premium on common stock		4,375			3,949
Retained earnings		2,109			1,904
Accumulated other comprehensive loss		(17	)		(45	)
Other		(13	)		(10	)
Total stockholders’ equity		6,456			5,800
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	18,090		$	17,434

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

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

	Nine Months Ended
		September 30,
		2005			2004
Cash Flows From Operating Activities:
Net income	$	586		$	447
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		447			398
Amortization of nuclear fuel		25			21
Amortization of debt issuance costs and premium/discounts		11			8
Deferred income taxes and investment tax credits, net		83			43
Coal contract settlement		-			28
Other		4			(16	)
Changes in assets and liabilities, excluding the effects of the acquisition:
Receivables, net		(1	)		21
Materials and supplies		(134	)		(32	)
Accounts and wages payable		(72	)		(192	)
Taxes accrued		172			257
Assets, other		(28	)		(41	)
Liabilities, other		(11	)		5
Pension and postretirement benefit obligations, net		7			(211	)
Net cash provided by operating activities		1,089			736

Cash Flows From Investing Activities:
Capital expenditures		(660	)		(547	)
Acquisitions, net of cash acquired		12			(451	)
Nuclear fuel expenditures		(16	)		(7	)
Other		16			28
Net cash used in investing activities		(648	)		(977	)

Cash Flows From Financing Activities:
Dividends on common stock		(383	)		(356	)
Capital issuance costs		(4	)		(40	)
Redemptions, repurchases, and maturities:
Nuclear fuel lease		-			(67	)
Short-term debt		(394	)		(130	)
Long-term debt		(262	)		(451	)
Preferred stock		(1	)		(1	)
Issuances:
Common stock		430			1,418
Long-term debt		382			404
Net cash provided by (used in) financing activities		(232	)		777

Net change in cash and cash equivalents		209			536
Cash and cash equivalents at beginning of year		69			111
Cash and cash equivalents at end of period	$	278		$	647

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,						Nine Months Ended,
		September 30,						September 30,
		2005			2004			2005			2004
Operating Revenues:
Electric	$	876		$	768		$	2,134		$	1,957
Gas		19			17			120			114
Total operating revenues		895			785			2,254			2,071

Operating Expenses:
Fuel and purchased power		261			148			586			420
Gas purchased for resale		8			11			66			69
Other operations and maintenance		188			186			562			579
Depreciation and amortization		90			73			242			219
Taxes other than income taxes		66			61			180			172
Total operating expenses		613			479			1,636			1,459

Operating Income		282			306			618			612

Other Income and (Deductions):
Miscellaneous income		4			5			15			14
Miscellaneous expense		(2	)		(1	)		(6	)		(6	)
Total other income and (deductions)		2			4			9			8

Interest Charges		29			23			81			74

Income Before Income Taxes		255			287			546			546

Income Taxes		91			105			193			197

Net Income		164			182			353			349

Preferred Stock Dividends		1			1			4			4

Net Income Available to Common Stockholder	$	163		$	181		$	349		$	345

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)

		September 30,			December 31,
		2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	1		$	48
Accounts receivable – trade (less allowance for doubtful
accounts of $5 and $3, respectively)		224			187
Unbilled revenue		134			118
Miscellaneous accounts and notes receivable		4			13
Accounts receivable – affiliates		34			8
Current portion of intercompany note receivable - CIPS		6			-
Materials and supplies		259			199
Other current assets		14			18
Total current assets		676			591
Property and Plant, Net		7,266			7,075
Investments and Other Assets:
Nuclear decommissioning trust fund		244			235
Intercompany note receivable - CIPS		61			-
Other assets		290			263
Regulatory assets		568			585
Total investments and other assets		1,163			1,083
TOTAL ASSETS	$	9,105		$	8,749

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	3		$	3
Short-term debt		-			375
Borrowings from money pool		81			2
Accounts and wages payable		111			252
Accounts and wages payable - affiliates		237			72
Taxes accrued		181			51
Other current liabilities		101			108
Total current liabilities		714			863
Long-term Debt, Net		2,442			2,059
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,251			1,217
Accumulated deferred investment tax credits		97			108
Regulatory liabilities		811			776
Asset retirement obligations		407			431
Accrued pension and other postretirement benefits		218			219
Other deferred credits and liabilities		93			80
Total deferred credits and other liabilities		2,877			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		722			718
Retained earnings		1,762			1,688
Accumulated other comprehensive loss		(36	)		(34	)
Total stockholders' equity		3,072			2,996
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,105		$	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)

	Nine Months Ended
	September 30,
		2005			2004
Cash Flows From Operating Activities:
Net income	$	353		$	349
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		242			219
Amortization of nuclear fuel		23			21
Amortization of debt issuance costs and premium/discounts		3			4
Deferred income taxes and investment tax credits, net		27			19
Coal contract settlement		-			28
Other		14			5
Changes in assets and liabilities:
Receivables, net		(96	)		(27	)
Materials and supplies		2			(24	)
Accounts and wages payable		44			(164	)
Taxes accrued		130			231
Assets, other		(25	)		(36	)
Liabilities, other		(2	)		10
Pension and other postretirement obligations, net		(1	)		(106	)
Net cash provided by operating activities		714			529

Cash Flows From Investing Activities:
Capital expenditures		(629	)		(374	)
Nuclear fuel expenditures		(16	)		(7	)
Other		10			-
Net cash used in investing activities		(635	)		(381	)

Cash Flows From Financing Activities:
Dividends on common stock		(209	)		(230	)
Dividends on preferred stock		(4	)		(4	)
Capital issuance costs		(3	)		(4	)
Changes in money pool borrowings		79			189
Redemptions, repurchases, and maturities:
Nuclear fuel lease		-			(67	)
Short-term debt		(375	)		(150	)
Long-term debt		-			(288	)
Issuances:
Long term debt		382			404
Capital contribution from parent		4			-
Net cash used in financing activities		(126	)		(150	)

Net change in cash and cash equivalents		(47	)		(2	)
Cash and cash equivalents at beginning of year		48			15
Cash and cash equivalents at end of period	$	1		$	13

Non-cash Investing Activities:

In 2005, UE sold an interest in assets to CIPS in exchange for a promissory note from CIPS, and UE contributed an interest in assets to Ameren Corporation. See Note 3 for further details.

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					Nine Months Ended
		September 30,					September 30,
		2005			2004		2005			2004
Operating Revenues:
Electric	$	244		$	166	$	542		$	432
Gas		22			21		133			134
Other		1			-		2			-
Total operating revenues		267			187		677			566

Operating Expenses:
Purchased power		140			85		331			244
Gas purchased for resale		12			10		86			82
Other operations and maintenance		39			37		106			109
Depreciation and amortization		17			13		48			39
Taxes other than income taxes		9			6		24			20
Total operating expenses		217			151		595			494

Operating Income		50			36		82			72

Other Income and (Deductions):
Miscellaneous income		4			6		13			19
Miscellaneous expense		(1	)		-		(5	)		(1	)
Total other income and (deductions)		3			6		8			18

Interest Charges		7			8		22			24

Income Before Income Taxes		46			34		68			66

Income Taxes		15			11		22			25

Net Income		31			23		46			41

Preferred Stock Dividends		1			1		2			2

Net Income Available to Common Stockholder	$	30		$	22	$	44		$	39

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)

	September 30,		December 31,
	2005		2004
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	2
Accounts receivable – trade (less allowance for doubtful
accounts of $2 and $1, respectively)		69		48
Unbilled revenue		58		71
Accounts receivable – affiliates		8		12
Current portion of intercompany note receivable – Genco		34		249
Current portion of intercompany tax receivable – Genco		11		11
Advances to money pool		51		-
Materials and supplies		81		56
Other current assets		15		19
Total current assets		327		468
Property and Plant, Net		1,121		953
Investments and Other Assets:
Intercompany note receivable – Genco		163		-
Intercompany tax receivable – Genco		130		138
Other assets		39		23
Regulatory assets		54		33
Total investments and other assets		386		194
TOTAL ASSETS	$	1,834	$	1,615

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	20	$	20
Accounts and wages payable		40		27
Accounts and wages payable - affiliates		75		49
Borrowings from money pool		-		68
Current portion of intercompany note payable - UE		6		-
Taxes accrued		16		-
Other current liabilities		43		32
Total current liabilities		200		196
Long-term Debt, Net		410		430
Deferred Credits and Other Noncurrent Liabilities:
Accumulated deferred income taxes and investment tax credits, net		310		308
Intercompany note payable - UE		61		-
Regulatory liabilities		222		151
Other deferred credits and liabilities		40		40
Total deferred credits and other noncurrent liabilities		633		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		189		121
Preferred stock not subject to mandatory redemption		50		50
Retained earnings		347		323
Accumulated other comprehensive income (loss)		5		(4	)
Total stockholders' equity		591		490
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,834	$	1,615

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

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

	Nine Months Ended
	September 30,
		2005			2004
Cash Flows From Operating Activities:
Net income	$	46		$	41
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		48			39
Amortization of debt issuance costs and premium/discounts		1			1
Deferred income taxes and investment tax credits, net		(5	)		(12	)
Other		1			6
Changes in assets and liabilities:
Receivables, net		21			14
Materials and supplies		(25	)		(13	)
Accounts and wages payable		39			(7	)
Taxes accrued		16			22
Assets, other		(35	)		(12	)
Liabilities, other		41			18
Pension and other postretirement obligations, net		-			(18	)
Net cash provided by operating activities		148			79

Cash Flows From Investing Activities:
Capital expenditures		(41	)		(32	)
Proceeds from intercompany note receivable - Genco		52			49
Changes in money pool advances		(51	)		-
Net cash provided by (used in) investing activities		(40	)		17

Cash Flows From Financing Activities:
Dividends on common stock		(21	)		(46	)
Dividends on preferred stock		(2	)		(2	)
Changes in money pool borrowings		(68	)		(60	)
Redemptions, repurchases, and maturities:
Long-term debt		(20	)		-
Capital contribution from parent		1			-
Net cash used in financing activities		(110	)		(108	)

Net change in cash and cash equivalents		(2	)		(12	)
Cash and cash equivalents at beginning of year		2			16
Cash and cash equivalents at end of period	$	-		$	4

Non-cash Investing Activities:

In 2005, CIPS purchased an interest in assets from UE in exchange for a promissory note to UE, and CIPS received a contribution of assets from Ameren Corporation. See Note 3 for further details.

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				Nine Months Ended
		September 30,				September 30,
		2005		2004		2005		2004
Operating Revenues:
Electric	$	287	$	233	$	777	$	655
Other		2		-		2		2
Total operating revenues		289		233		779		657

Operating Expenses:
Fuel and purchased power		162		107		398		292
Other operations and maintenance		32		32		108		103
Depreciation and amortization		18		19		55		57
Taxes other than income taxes		4		5		7		16
Total operating expenses		216		163		568		468

Operating Income		73		70		211		189

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

Interest Charges		17		25		57		72

Income Before Income Taxes		56		46		155		117

Income Taxes		24		17		61		42

Net Income	$	32	$	29	$	94	$	75

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)

	September 30,			December 31,
		2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	-		$	1
Accounts receivable - affiliates		93			86
Accounts receivable		13			10
Advances to money pool		65			-
Materials and supplies		161			89
Other current assets		2			2
Total current assets		334			188
Property and Plant, Net		1,501			1,749
Other Assets		12			18
TOTAL ASSETS	$	1,847		$	1,955

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt	$	225		$	225
Current portion of intercompany notes payable – CIPS		34			283
Borrowings from money pool		-			116
Accounts and wages payable		28			32
Accounts and wages payable - affiliates		81			28
Current portion of intercompany tax payable – CIPS		11			11
Taxes accrued		-			35
Other current liabilities		30			16
Total current liabilities		409			746
Long-term Debt, Net		474			473
Intercompany Notes Payable – CIPS		163			-
Deferred Credits and Other Noncurrent Liabilities:
Accumulated deferred income taxes, net		180			144
Accumulated deferred investment tax credits		10			12
Intercompany tax payable – CIPS		130			138
Accrued pension and other postretirement benefits		5			5
Other deferred credits and liabilities		11			2
Total deferred credits and other noncurrent liabilities		336			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		226			225
Retained earnings		247			211
Accumulated other comprehensive loss		(8	)		(1	)
Total stockholder's equity		465			435
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	1,847		$	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)

	Nine Months Ended
	September 30,
		2005			2004
Cash Flows From Operating Activities:
Net income	$	94		$	75
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		55			57
Amortization of debt issuance costs and discounts		1			1
Deferred income taxes and investment tax credits, net		35			29
Other		(21	)		(2	)
Changes in assets and liabilities:
Accounts receivable		(10	)		(5	)
Materials and supplies		(56	)		-
Accounts and wages payable		59			(20	)
Taxes accrued, net		(35	)		6
Assets, other		6			1
Liabilities, other		7			(10	)
Pension and other postretirement obligations, net		-			(17	)
Net cash provided by operating activities		135			115

Cash Flows From Investing Activities:
Capital expenditures		(52	)		(37	)
Proceeds from asset sale to UE		241			-
Changes in money pool advances		(65	)		-
Net cash provided by (used in) investing activities		124			(37	)

Cash Flows From Financing Activities:
Dividends on common stock		(59	)		(57	)
Changes in money pool borrowings		(116	)		(45	)
Redemptions, repurchases, and maturities:
Intercompany notes payable – CIPS and Ameren		(86	)		(53	)
Capital contribution from parent		1			75
Net cash used in financing activities		(260	)		(80	)

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

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						Nine Months Ended
		September 30,						September 30,
		2005			2004			2005			2004
Operating Revenues:
Electric	$	116		$	108		$	309		$	295
Gas		41			37			215			228
Other		2			1			4			3
Total operating revenues		159			146			528			526

Operating Expenses:
Fuel and purchased power		54			39			126			117
Gas purchased for resale		27			24			150			162
Other operations and maintenance		41			53			122			143
Depreciation and amortization		18			18			54			51
Taxes other than income taxes		4			4			15			18
Total operating expenses		144			138			467			491

Operating Income		15			8			61			35

Other Income and (Deductions):
Miscellaneous expense		(2	)		(2	)		(7	)		(4	)
Total other income and (deductions)		(2	)		(2	)		(7	)		(4	)

Interest Charges and Preferred Dividends:
Interest		12			13			37			39
Preferred dividends of subsidiaries		1			-			2			1
Net interest charges and preferred dividends		13			13			39			40

Income (Loss) Before Income Taxes		-			(7	)		15			(9	)

Income Tax Benefit		(5	)		(9	)		(1	)		(11	)

Net Income	$	5		$	2		$	16		$	2

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)

	September 30,			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)		37			46
Unbilled revenue		30			46
Accounts receivables – affiliates		14			9
Materials and supplies		147			134
Other current assets		27			19
Total current assets		259			261
Property and Plant, Net		1,190			1,179
Investments and Other Assets:
Investments in leveraged leases		109			113
Goodwill and other intangibles, net		559			559
Other assets		78			33
Regulatory assets		32			11
Total investments and other assets		778			716
TOTAL ASSETS	$	2,227		$	2,156

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt	$	16		$	16
Borrowings from money pool, net		81			166
Intercompany note payable – Ameren		100			72
Accounts and wages payable		49			57
Accounts and wages payable - affiliates		44			42
Other current liabilities		81			58
Total current liabilities		371			411
Long-term Debt, Net		612			623
Preferred Stock of Subsidiary Subject to Mandatory Redemption		19			20
Deferred Credits and Other Noncurrent Liabilities:
Accumulated deferred income taxes, net		198			214
Accumulated deferred investment tax credits		9			10
Regulatory liabilities		69			46
Accrued pension and other postretirement benefits		244			242
Other deferred credits and liabilities		19			23
Total deferred credits and other noncurrent liabilities		539			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		666			565
Retained earnings (deficit)		(34	)		(21	)
Accumulated other comprehensive income		35			4
Total stockholder's equity		667			548
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	2,227		$	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)


	Nine Months Ended
	September 30,
		2005			2004
Cash Flows From Operating Activities:
Net income	$	16		$	2
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		49			51
Deferred income taxes and investment tax credits, net		(19	)		10
Other		1			5
Changes in assets and liabilities:
Receivables, net		20			61
Materials and supplies		(13	)		8
Accounts and wages payable		(9	)		(26	)
Taxes accrued		(8	)		11
Assets, other		9			5
Liabilities, other		9			(6	)
Pension and other postretirement benefit obligations, net		2			(21	)
Net cash provided by operating activities		57			100

Cash Flows From Investing Activities:
Capital expenditures		(71	)		(95	)
Other		4			4
Net cash used in investing activities		(67	)		(91	)

Cash Flows From Financing Activities:
Dividends on common stock		(30	)		(18	)
Changes in money pool borrowings		(85	)		46
Proceeds from intercompany notes payable - Ameren		28			10
Redemptions, repurchases, and maturities:
Long-term debt		(6	)		(123	)
Preferred stock		(1	)		(1	)
Capital contribution from parent		101			75
Net cash provided by (used in) financing activities		7			(11	)

Net change in cash and cash equivalents		(3	)		(2	)
Cash and cash equivalents at beginning of year		7			11
Cash and cash equivalents at end of period	$	4		$	9

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						Nine Months Ended
		September 30,						September 30,
		2005			2004			2005			2004
Operating Revenues:
Electric	$	116		$	108		$	309		$	295
Gas		41			34			212			206
Other		1			-			1			-
Total operating revenues		158			142			522			501

Operating Expenses:
Fuel and purchased power		49			33			117			109
Gas purchased for resale		27			21			146			140
Other operations and maintenance		43			55			127			150
Depreciation and amortization		17			16			50			48
Taxes other than income taxes		4			4			14			18
Total operating expenses		140			129			454			465

Operating Income		18			13			68			36

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

Interest Charges		3			5			10			12

Income Before Income Taxes		13			7			52			20

Income Tax Expense (Benefit)		2			(2	)		15			2

Net Income		11			9			37			18

Preferred Stock Dividends		1			-			2			1

Net Income Available to Common Stockholder	$	10		$	9		$	35		$	17

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)

		September 30,		December 31,
		2005		2004
ASSETS
Current Assets:
Cash and cash equivalents	$	2	$	2
Accounts receivable - trade (less allowance for doubtful
accounts of $3 and $3, respectively)		37		46
Unbilled revenue		30		43
Accounts receivable - affiliates		3		11
Materials and supplies		90		68
Other current assets		25		6
Total current assets		187		176
Property and Plant, Net		1,187		1,165
Other Assets		76		29
Regulatory Assets		32		11
TOTAL ASSETS	$	1,482	$	1,381

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	16	$	16
Borrowings from money pool		81		169
Accounts and wages payable		49		53
Accounts and wages payable - affiliates		42		42
Other current liabilities		63		49
Total current liabilities		251		329
Long-term Debt, Net		122		122
Preferred Stock Subject to Mandatory Redemption		19		20
Deferred Credits and Other Noncurrent Liabilities:
Accumulated deferred income taxes, net		128		130
Accumulated deferred investment tax credits		9		10
Regulatory liabilities		211		184
Accrued pension and other postretirement benefits		142		131
Other deferred credits and liabilities		17		18
Total deferred credits and other noncurrent liabilities		507		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		414		313
Retained earnings		130		115
Accumulated other comprehensive income (loss)		20		(10	)
Total stockholders' equity		583		437
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,482	$	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)

	Nine Months Ended
	September 30,
		2005			2004
Cash Flows From Operating Activities:
Net income	$	37		$	18
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		50			48
Deferred income taxes and investment tax credits, net		(5	)		12
Other		6			1
Changes in assets and liabilities:
Receivables, net		30			54
Materials and supplies		(22	)		(8	)
Accounts and wages payable		-			(30	)
Taxes accrued		(17	)		(11	)
Assets, other		-			3
Liabilities, other		(9	)		4
Pension and other postretirement benefit obligations, net		11			(7	)
Net cash provided by operating activities		81			84

Cash Flows From Investing Activities:
Capital expenditures		(71	)		(95	)
Other		-			1
Net cash used in investing activities		(71	)		(94	)

Cash Flows From Financing Activities:
Dividends on common stock		(20	)		(10	)
Dividends on preferred stock		(2	)		(1	)
Changes in money pool borrowings		(88	)		44
Redemptions, repurchases, and maturities:
Long-term debt		-			(100	)
Preferred stock		(1	)		(1	)
Capital contribution from parent		101			75
Net cash provided by (used in) financing activities		(10	)		7

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

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--		--Successor--			--Predecessor--
		Three		Three		Nine			Nine
		Months		Months		Months			Months
		Ended		Ended		Ended			Ended
		September 30,		September 30,		September 30,			September 30,
		2005		2004		2005			2004
Operating Revenues:
Electric	$	358	$	327	$	861		$	832
Gas		61		52		331			328
Other		1		-		1			-
Total operating revenues		420		379		1,193			1,160

Operating Expenses:
Purchased power		187		191		509			496
Gas purchased for resale		37		29		227			222
Other operations and maintenance		64		44		166			143
Depreciation and amortization		19		21		59			61
Amortization of regulatory assets		-		11		-			32
Taxes other than income taxes		14		15		54			52
Total operating expenses		321		311		1,015			1,006

Operating Income		99		68		178			154

Other Income and (Deductions):
Interest income from former affiliate		-		43		-			128
Miscellaneous income		2		4		6			16
Miscellaneous expense		-		-		(1	)		(1	)
Total other income and (deductions)		2		47		5			143

Interest Charges		11		35		32			114

Income Before Income Taxes		90		80		151			183

Income Taxes		36		29		60			71

Net Income		54		51		91			112

Preferred Stock Dividends		1		1		2			2

Net Income Available to Common Stockholder	$	53	$	50	$	89		$	110

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)

		September 30,		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)		96		101
Unbilled revenue		81		98
Miscellaneous accounts and notes receivable		24		8
Advances to money pool		50		140
Materials and supplies		130		85
Other current assets		8		69
Total current assets		394		506
Property and Plant, Net		2,019		1,984
Investments and Other Assets:
Investment in IP SPT		7		7
Goodwill		326		320
Other assets		43		37
Regulatory assets		222		198
Accumulated deferred income taxes		18		65
Total investments and other assets		616		627
TOTAL ASSETS	$	3,029	$	3,117

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	-	$	70
Current maturities of long-term debt to IP SPT		68		74
Accounts and wages payable		131		118
Accounts and wages payable - affiliates		25		4
Taxes accrued		19		5
Other current liabilities		85		102
Total current liabilities		328		373
Long-term Debt, Net		706		713
Long-term Debt to IP SPT		207		278
Deferred Credits and Other Liabilities:
Regulatory liabilities		113		76
Accrued pension and other postretirement liabilities		252		248
Other deferred credits and other noncurrent liabilities		124		149
Total deferred credits and other liabilities		489		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		1,196		1,207
Preferred stock not subject to mandatory redemption		46		46
Retained earnings		57		27
Total stockholders’ equity		1,299		1,280
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,029	$	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---
	Nine			Nine
	Months			Months
	Ended			Ended
	September 30,			September 30,
	2005			2004
Cash Flows From Operating Activities:
Net income	$	91		$	112
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		31			95
Amortization of debt issuance costs and premium/discounts		2			4
Deferred income taxes and investment tax credits, net		39			(59	)
Other		-			1
Changes in assets and liabilities:
Receivables, net		11			23
Materials and supplies		(45	)		(13	)
Accounts and wages payable		34			(2	)
Assets, other		25			13
Liabilities, other		15			(29	)
Pension and other postretirement benefit obligations, net		4			13
Net cash provided by operating activities		207			158

Cash Flows From Investing Activities:
Capital expenditures		(95	)		(100	)
Changes in money pool advances		90			-
Other		1			4
Net cash used in investing activities		(4	)		(96	)

Cash Flows From Financing Activities:
Dividends on common stock		(60	)		-
Dividends on preferred stock		(2	)		(2	)
Prepaid interest on note receivable from former affiliate		-			43
Redemptions, repurchases, and maturities:
Long-term debt		(135	)		(65	)
TFN over funding		(6	)		(4	)
Net cash used in financing activities		(203	)		(28	)

Net change in cash and cash equivalents		-			34
Cash and cash equivalents at beginning of year		5			17
Cash and cash equivalents at end of period	$	5		$	51

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)

September 30, 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 and payments on its obligations are dependent on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.

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. 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 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.

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

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. 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. 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 periods ended September 30, 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.

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 Form 10-K for the fiscal year ended December 31, 2004.

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 postacquisition 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 material differences between Ameren’s basic and diluted earnings per share for the three months and nine months ended September 30, 2005 and 2004.

Asset Retirement Obligations

Asset retirement obligations at Ameren and UE increased by $6 million and $18 million for the three months and nine months ended September 30, 2005, respectively, to reflect the accretion of obligations to their present value. Additionally, Ameren and UE’s asset retirement obligations decreased by $42 million for the quarter ended September 30, 2005, due to revisions in estimated future cash flows to decommission UE’s Callaway nuclear plant. Increases to Genco’s, CILCORP’s, and CILCO’s asset retirement obligations due to accretion were immaterial during the three and nine months ended September 30, 2005. Substantially all of this accretion was recorded as an increase to regulatory assets. A change in estimate resulted in a $1 million increase in Genco’s asset retirement obligation during the nine months ended September 30, 2005.

Accounting Changes and Other Matters

FIN 47, “Accounting for Conditional Asset Retirement Obligations”

In February 2005, the FASB issued FIN 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 o f 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. Ameren, UE, Genco, CILCORP and CILCO expect to record additional asset retirement obligations associated with asbestos removal, ash pond remediation, and river structures. We are still in the process of quantifying the asset retirement obligations. The difference between the net asset and liability recorded upon the adoption of FIN 47 related to rate-regulated assets will be recorded as an additional regulatory asset to the extent that we expect to continue to recover the cost of removal in electric and gas rates. The adoption of this interpretation for the year ended December 31, 2005, could have a material impact on our results of operations.

SFAS No. 153, “Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS No. 153, which amends APB Opinion No. 29 to require the accounting at fair value for nonmonetary exchanges with commercial substance. The Ameren Companies are required to apply the provisions of SFAS No. 153 prospectively to transactions occurring after July 1, 2005. During the third quarter of 2005, Ameren, UE and Genco had emission allowance swaps that were accounted for at fair value under SFAS No. 153. See Note 9 - Commitments and Contingencies for further details related to these transactions.

Interchange Revenues

The following table presents the interchange revenues included in Operating Revenues - Electric for the three months and nine months ended September 30, 2005 and 2004. See Note 8 - Related Party Transactions for further information on affiliate purchased power transactions.

	Three Months				Nine Months
	2005		2004		2005		2004
Ameren^(a)	$	92	$	95	$	359	$	282
UE		110		83		336		238
CIPS		8		7		26		27
Genco		56		38		165		113
CILCORP		-		10		26		30
CILCO		-		10		26		30

(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 $9 million and $24 million for the three months and nine months ended September 30, 2005, respectively (2004 - $15 million and $45 million, respectively).

Purchased Power

The following table presents the purchased power expenses included in Operating Expenses - Fuel and Purchased Power for the three months and nine months ended September 30, 2005 and 2004. See Note 8 - Related Party Transactions for further information on affiliate purchased power transactions.

	Three Months				Nine Months
	2005		2004		2005		2004
Ameren^(a)	$	327	$	119	$	782	$	271
UE		102		55		206		157
CIPS		140		85		331		244
Genco		89		43		206		117
CILCORP		25		10		46		39
CILCO		25		10		46		39
IP^(b)		187		191		509		496

(a)

Includes amounts for Ameren Registrant and non-Registrant subsidiaries and intercompany eliminations, but excludes 2004 amounts for IP. Includes purchased power for EEI of nil and $1 million for the three months and nine months ended September 30, 2005, respectively (2004 - $25 million and $40 million, respectively).

(b)	2004 amounts represent 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 on each company’s statement of income. 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 and nine months ended September 30, 2005 and 2004:

	Three Months				Nine Months
	2005		2004		2005		2004
Ameren^(a)	$	44	$	35	$	125	$	100
UE		35		31		84		82
CIPS		3		2		10		9
CILCORP		1		2		7		9
CILCO		1		2		7		9
IP^(b)		5		9		24		26

(a)	Excludes 2004 amounts for IP.

(b)	2004 amounts represent 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. Cash consideration was $429 million, net of $51 million cash acquired, and included transaction costs. Ameren placed $100 million of the cash portion of the purchase price in an escrow account pending resolution of certain contingent environmental obligations of IP and other Dynegy affiliates for which Ameren was provided indemnification by Dynegy. On July 27, 2005, the conditions for release of the escrow account were satisfied and Dynegy was remitted the $100 million. 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 December 2004, 230 IP employees accepted a voluntary separation opportunity, which provided an enhanced separation benefit and extended medical and dental benefits. Employees who accepted the voluntary separation opportunity have been leaving 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 September 30, 2005, separation costs of $25 million were 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.

During the quarter ended September 30, 2005, Ameren finalized the allocation of the purchase price and completed its valuations of the acquired net assets and liabilities of IP and EEI, including third-party valuations of property and plant, intangible assets, pension and other postretirement benefit obligations, and contingent obligations. 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 (September 30, 2005 - $59 million). This amount is being amortized through December 31, 2006. In addition, IP recorded a fair value adjustment, resulting in a net asset of $20 million (September 30, 2005 - $6 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 net assets acquired was allocated to goodwill in the amount of $326 million, net of future tax benefits. For income tax purposes, a portion of the purchase price will be allocated to goodwill and that portion will be deducted ratably over a 15-year period. Goodwill increased by $6 million since December 31, 2004, primarily because of net adjustments to regulatory assets, income tax accounts, property and plant, accrued environmental reserves, and net assets for IP’s power supply agreement with EEI. These increases in goodwill were partially offset by net adjustments to accrued severance, accrued relocation and accrued claims expenses, as well as cash payments from Dynegy under working capital and indemnification provisions pursuant to the terms of the stock purchase agreement. The following table presents the final estimated fair values of the assets acquired and liabilities assumed at the date of Ameren’s acquisition of IP.

Current assets	$	368
Property and plant		1,962
Investments and other noncurrent assets		370
Goodwill		326
Total assets acquired		3,026
Current liabilities		221
Long-term debt, including current maturities		1,982
Accrued pension and other postretirement liabilities		244
Other non-current liabilities		211
Total liabilities assumed		2,658
Preferred stock assumed		13
Net assets acquired	$	355

The following unaudited pro forma financial information presents a summary of Ameren’s consolidated results of operations for the three months and nine months ended September 30, 2004, as if the acquisition of IP had been completed at the beginning of 2004, including pro forma adjustments 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.

2004	Three Months		Nine Months
Operating revenues	$	1,686	$	4,818
Net income		293		583
Earnings per share - basic		1.51		3.02
- diluted		1.51		3.01

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. The purchase price for this ownership interest was allocated, based on fair value, to property and plant ($55 million) and emission allowances ($48 million), partially offset by a net liability for power supply agreements ($25 million) and a reduction to net deferred tax assets ($31 million). The excess of purchase price over fair value was allocated to goodwill in the amount of $65 million. Goodwill increased by $11 million since December 31, 2004, due to adjustments to property and plant and the net liability for power supply agreements, partially offset by adjustments to both emission allowances and income tax accounts, resulting from the refinement of the third-party valuation of EEI’s net assets.

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 electric and natural gas service territory, including its Illinois-based distribution assets and certain of its transmission assets, at a net book value of $133 million to CIPS. 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% of the assets directly to CIPS in consideration for a CIPS subordinated promissory note in the principal amount of approximately $67 million and 50% 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 in Illinois 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. In testimony filed by UE with the MoPSC to support the transfer, UE indicated this amendment would have provided UE with additional annual margins and Genco with reduced annual margins of $7 million to $24 million based on certain assumptions and historical results. 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 ultimate impact of any modifications to the joint dispatch agreement will be determined by future native load demand, the availability of electric generation from UE and Genco and market prices, among other things, but such impact could be material.

·	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. A proposed amendment of the joint dispatch agreement to reflect this MoPSC order is expected to be filed with the FERC in late 2005.

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.

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, at a net book value of $241 million. This transfer completed the remainder of UE’s commitment under the 2002 Missouri electric rate case settlement, which required the addition of 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.

Missouri

Noranda Aluminum, Inc. (Noranda)

Following the receipt of all regulatory approvals and satisfaction of all regulatory and other conditions, the tariff by which UE serves Noranda became effective June 1, 2005. UE serves Noranda under a 15-year agreement to supply approximately 470 megawatts (peak load) of electricity (or approximately 5% of UE’s generating capability, including currently committed purchases) to Noranda’s primary aluminum smelter in southeast Missouri.

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.

During 2004, the ICC conducted workshops to seek input from interested parties on the framework for retail electric rate determination and power procurement after the current Illinois electric rate freeze expires on January 1, 2007, and supply contracts expire on December 31, 2006. In late 2004 the ICC issued a report outlining a process that would have CIPS, CILCO and IP procure power through an auction monitored by the ICC, which 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 power 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. CIPS, CILCO and IP intend to file revised tariffs with the ICC by the end of 2005 that would modify their electric delivery service rates effective January 2, 2007. Genco and AERG would probably participate in the power procurement auction through Marketing Company, but there is expected to 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 power procurement auction and a rate mechanism to pass power costs through to customers, among other things, which was consistent with the auction process described above. These proposals are subject to review and approval by the ICC by January 2006. The ICC Staff and interveners filed testimony regarding the proposed process for the power procurement auction in June 2005. In its testimony, the ICC Staff continued to support the power procurement auction process, but sought modifications to aspects of the CIPS, CILCO and IP proposals. The Illinois attorney general and the Citizens Utility Board (CUB) in their testimonies recommended, among other things, that the ICC initiate a new docket to investigate alternatives to an auction. CIPS, CILCO and IP filed rebuttal testimony in early July. That testimony modified certain aspects of the February proposal, and substantially addressed issues raised by the ICC staff and certain other interveners. The modifications included changes to the timing of the auction, a limitation of 35% on the amount of power any single supplier can provide Ameren’s Illinois utilities’

expected annual load and allowing suppliers to switch their bids between similar products in the auction in Illinois. The evidentiary phase of the proceedings has now concluded, and the parties are currently filing briefs in support of their respective positions. An administrative law judge proposed order is anticipated in late November or early December 2005.

In May 2005, the Illinois attorney general, the CUB and the Environmental Law and Policy Center (ELPC) filed a motion to dismiss the proposed procurement auction in the CIPS, CILCO and IP February 2005 ICC filing. The administrative law judge denied that motion in June 2005. The Illinois attorney general, the CUB and the ELPC subsequently appealed the administrative law judge’s ruling to the ICC, and this interlocutory appeal was also denied by the ICC in July 2005.

On September 1, 2005, the Illinois attorney general, the Cook County state’s attorney, the CUB and the ELPC filed a two-count complaint in the Circuit Court of Cook County, Illinois against the ICC and the individual ICC commissioners (the attorney general’s lawsuit). The first count asks that the defendants be required to show by what authority the ICC claims it could approve market-based rates for electric service that has not been “declared competitive” pursuant to Section 16-113 of the Illinois Public Utilities Act (PUA). The second count seeks a declaratory judgment that the ICC lacks authority to approve market-based rates for electric service that has not been “declared competitive” pursuant to Section 16-113 of the PUA, and seeks injunctive relief prohibiting ICC approval of proposals by CIPS, CILCO and IP and Commonwealth Edison Company that would impose market-based rates on customers who have electric service that has not been “declared competitive” pursuant to Section 16-113 of the PUA. CIPS, CILCO and IP believe the claims are without merit and are vigorously opposing them. The legal argument underlying the attorney general’s lawsuit is substantially similar to the legal argument presented to the administrative law judge, and to the ICC on interlocutory appeal, and rejected by both, in June and July 2005, respectively (as referred to above).

On September 2, 2005, Illinois Governor Blagojevich sent a letter to the ICC expressing his opposition to CIPS, CILCO and IP’s proposed auction process for procuring electric power to take effect after the current Illinois electric rate freeze expires and requesting dismissal of the pending proceeding for approval of such process. On September 15, 2005, CIPS, CILCO and IP responded to the governor's letter citing the legal deficiencies of his position and the potential adverse consequences which could result if his position is ultimately sustained. Copies of the governor’s letter and CIPS, CILCO and IP’s response letter appear as Exhibits 99.1 and 99.2, respectively to the Current Report on Form 8-K dated September 15, 2005.

Both the Illinois governor's letter and the attorney general's lawsuit assert that the energy component of CIPS, CILCO and IP’s retail rates for electricity should not be based on their costs to procure energy and capacity in the wholesale market. We are unable to predict the ultimate outcome of the attorney general's lawsuit or the pending ICC proceeding (as affected by the governor's letter), the timing of the final decisions on such matters or the impact on our results of operations, financial position, or liquidity. However, any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner could result in material adverse consequences. As noted in the Ameren Illinois utilities' response letter to the Illinois governor, these consequences could include a significant drop in credit ratings (potentially to below investment grade status), a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, reduced customer service, job losses and financial insolvency. See Liquidity and Capital Resources under Part I, Item 2, of this report for a discussion of recent credit rating agency actions.

In light of efforts to limit the ability of CIPS, CILCO and IP to recover their costs, the Ameren Illinois utilities have intervened in the attorney general's lawsuit and are vigorously defending their proposed power procurement auction process in proceedings before the ICC. As interveners in the attorney general’s lawsuit, CIPS, CILCO and IP will deny the allegations in the complaint and seek a determination that the ICC has appropriate legal authority to approve the proposed electric power procurement auction process pending before the ICC. In October 2005, the Ameren Illinois utilities filed a motion for summary judgment in the attorney general’s lawsuit. A hearing in the matter is currently scheduled for December 2005. Subsequent to the governor’s letter, ICC chairman, Edward Hurley, resigned. Illinois Governor Blagojevich immediately appointed Martin A. Cohen to replace Mr. Hurley. Mr. Cohen was previously the executive director of the CUB, which is a leading consumer advocacy group in Illinois. In November 2005, the Illinois Senate rejected Mr. Cohen’s appointment as ICC chairman.

In early 2005, the Illinois legislature held hearings regarding the framework for retail rate determination and power procurement. We cannot predict what actions, if any, the Illinois legislature will take.

Ameren, CIPS, CILCO and IP will continue to explore a number of legal and regulatory actions, strategies and alternatives to address these Illinois electric issues, including the possible proposal of an electric rate increase phase-in plan. There can be no assurance that Ameren and the Ameren Illinois utilities will prevail in opposition to the attorney general's lawsuit, the stated opposition by the Illinois governor and other stakeholders, or that the legal and regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois utilities are considering will be successful.

Gas

In May 2005, the ICC issued an order awarding IP increases in annual natural gas delivery rates of $11 million. 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 this recently authorized gas delivery rate increase. IP filed an appeal in the appellate court for the Third District in Illinois regarding certain disallowances issued by the ICC in its May 2005 order. Ameren sought indemnification from Dynegy with regard to the disallowances under the stock purchase agreement covering Ameren’s acquisition of IP from Dynegy, and in July 2005 Dynegy paid to Ameren $8 million in full settlement of this indemnification claim. Under the terms of the settlement, IP will retain the benefits of any successful appeal of the May 2005 ICC order with no refund obligation to Dynegy.

Federal

Hydroelectric License Renewal

In May 2005, UE, the U.S. Department of the Interior and various state agencies reached a settlement agreement which is expected to lead to the FERC’s relicensing of UE’s Osage hydroelectric plant for another 40 years. The settlement must be approved by the FERC, which, together with the relicense, is expected by year-end 2005. The current FERC license expires on February 28, 2006.

EEI Market-based Rate Request

In September 2005, EEI submitted a filing to the FERC seeking authority to sell power at market-based rates. EEI’s existing contracts with UE, CIPS (which has resold its power entitlement to Marketing Company), IP, Kentucky Utilities Company and the DOE for the supply of power from its Joppa plant expire on December 31, 2005. EEI would use its market rate authority after those contracts expire. The Missouri Office of Public Counsel (OPC) filed a protest with the FERC in EEI’s filing in October 2005. The OPC contended that the FERC should reject EEI’s request and instead compel EEI to sell to UE under the terms of their existing contract, which expires on December 31, 2005. EEI subsequently filed a response to the protest. In its response, EEI contended that the OPC had not presented any evidence which would justify a rejection of EEI’s request, and that the OPC was in effect improperly requesting a continuation of the contract which was set to terminate on December 31, 2005. We cannot predict the outcome of this proceeding.

PUHCA Repeal

The Energy Policy Act of 2005 repeals the PUHCA effective February 8, 2006. Thereafter, authorization from the SEC under the PUHCA will no longer be required for any of the Ameren Companies to take any action, including the issuance of securities. Upon the repeal of the PUHCA, UE, CIPS, CILCO and IP will require the approval of the FERC (instead of the SEC) to issue short-term debt securities. In addition, these Ameren utilities will continue to require authorization from the applicable state public utility regulatory agency in order to issue stock and long-term debt securities. Genco and EEI will continue to be subject to the FERC’s jurisdiction over approval to issue any securities, long-term or short-term. With the repeal of the PUHCA, Ameren and CILCORP will not require SEC (under the PUHCA), FERC or state public utility regulatory agency approval to issue securities.

NOTE 4 - SHORT-TERM BORROWINGS AND LIQUIDITY

Short-term borrowings have typically consisted 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 September 30, 2005 and December 31, 2004, respectively:

	Ameren^(a)	UE
September 30, 2005:
Short-term borrowings at September 30, 2005	$ 23	$ -
Average daily borrowings outstanding during 2005	199	169
Weighted average interest rate during 2005	3.68%	2.55%
Peak short-term borrowings during 2005	$ 468	$ 424
Peak interest rate during 2005	4.71%	3.45%
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.

In July 2005, Ameren, UE, CIPS, CILCO, Genco and IP entered into a five-year revolving credit agreement, maturing on July 14, 2010, with various lenders which provides for loans to, and letters of credit issued for, the accounts of Ameren, UE, CIPS, CILCO, Genco and IP in an amount up to $1.15 billion. The entire amount of the facility is available to Ameren; UE may directly borrow under this facility up to $500 million on a short-term 364-day basis; and CIPS, Genco, CILCO and IP may also each directly borrow under this facility up to $150 million, also on a short-term 364-day basis. The interest rates applicable under the facility are based on a Eurodollar rate plus a margin applicable to the particular borrowing company, a competitive-rate bid by the lenders, or a rate equal to the higher of JPMorgan Chase Bank, N.A.’s prime rate and the sum of the federal funds effective rate plus 1/2 percent per annum, plus the margin applicable to the particular borrowing company. The credit agreement contains customary terms and conditions (see Indebtedness Provisions and Other Covenants below for financial covenant provisions). The Ameren Companies will use the proceeds of any borrowings under this facility for general corporate purposes, including for working capital, commercial paper liquidity support and to fund loans under the money pool arrangements. The obligations of Ameren, UE, CIPS, Genco, CILCO and IP under this facility are several and not joint. The obligations of UE, CIPS, Genco, CILCO and IP are not guaranteed by any other subsidiary. See Exhibit 10.1 to the Current Report on Form 8-K dated July 15, 2005, for the full agreement.

Upon execution of the new $1.15 billion credit agreement, Ameren terminated its $235 million amended and restated three-year revolving credit agreement, dated as of September 21, 2004, and its $350 million three-year revolving credit agreement dated as of July 14, 2004. In addition, this agreement replaced UE’s bilateral credit agreements in an aggregate amount of $153.5 million, CIPS’ bilateral credit agreements in an aggregate amount of $15 million, CILCO’s bilateral credit agreements in an aggregate amount of $60 million and EEI’s bilateral credit agreement in an aggregate amount of $25 million.

Also in July 2005, Ameren, as sole borrower, entered into an amended and restated credit agreement, which revised its $350 million five-year revolving credit agreement dated as of July 14, 2004. The changes to this facility made the entire amount of commitments available in the form of letters of credit as well as loans, extended the maturity date to July 2010 and conformed, as applicable, the affirmative and negative covenants, events of default and representations and warranties to the July 2005 $1.15 billion revolving credit agreement discussed above. See Exhibit 10.2 to the Current Report on Form 8-K, dated July 15, 2005, for the full amended and restated credit agreement.

After giving effect to these changes, at September 30, 2005, Ameren had $1.5 billion of committed credit facilities consisting of two facilities each maturing in July 2010. These facilities are available for use by UE, CIPS, CILCO, IP and Ameren Services through a utility money pool arrangement, subject to applicable regulatory short-term borrowing authorizations. All of the $1.5 billion was available for use, subject to applicable regulatory short-term borrowing authorizations, by Ameren directly, by CILCORP and EEI through direct short-term borrowings from Ameren, and by most of Ameren’s 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 no amounts were outstanding for Ameren and UE at September 30, 2005 (December 31, 2004 - $417 million and $375 million at Ameren and UE, respectively). Access to these credit facilities for the Ameren Companies is subject to reduction based on use by affiliates.

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. Ameren Services is responsible for operation and administration of the money pool agreements. See Note 8 - Related Party Transactions for a detailed explanation of these money pool arrangements.

In April 2005, EEI renewed a $20 million bank credit facility, which is scheduled to mature in the second quarter of 2006.

Ameren and UE are authorized by the SEC under the PUHCA to have an aggregate of up to $1.5 billion and $1 billion, respectively, of short-term unsecured debt instruments outstanding at any time. The aggregate amount of short-term borrowings outstanding at any time at IP may not exceed $500 million pursuant to authorizations from the ICC and the SEC under the PUHCA. In addition, CIPS, CILCORP and CILCO have the PUHCA authority to have an aggregate of up to $250 million each of short-term unsecured debt instruments outstanding at any time. 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 September 30, 2005, the maximum permissible borrowings under Ameren’s non-state-regulated subsidiary money pool pursuant to this limitation for these entities totaled $548 million. See Note 3 - Rate and Regulatory Matters for information on PUHCA repeal.

Genco is authorized by the FERC to have up to $300 million of short-term debt outstanding at any time.

Indebtedness Provisions and Other Covenants

Ameren’s bank credit agreements contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets, and merge with other entities. The $1.15 billion July 2005 revolving credit agreement discussed above also contains a provision that limits Ameren’s, UE’s, CIPS’, Genco’s and IP’s total indebtedness to 65% of total capitalization and CILCO’s total indebtedness to 60% of total capitalization pursuant to a calculation set forth in the agreement. The $350 million July 2005 amended and restated credit agreement contains a similar provision only with respect to Ameren. Exceeding these debt levels would result in a default under the credit agreements. As of September 30, 2005, the ratio of total indebtedness to total capitalization (calculated in accordance with this provision) for Ameren, UE, CIPS, Genco, CILCO and IP was 46%, 44%, 41%, 52%, 28% and 43%, respectively (December 31, 2004 - Ameren 50%, UE 44%, CIPS 53%, CILCO ---43%, not applicable for Genco or IP). The credit agreements also require us to meet minimum ERISA funding rules. In addition, these credit agreements contain cross-default provisions that could trigger a default under the facilities in the event Ameren’s subsidiaries (subject to the definition in the underlying credit agreements), other than certain project finance subsidiaries, default in indebtedness of $50 million or greater, fail to pay the amounts drawn (as a direct borrower) under an Ameren credit facility, or enter bankruptcy proceedings. In addition, a default in indebtedness of $50 million or greater or a bankruptcy would cause a default under the agreements supporting $100 million of Ameren LIBOR swaps.

None of the Ameren Companies’ short-term credit agreements or financing arrangements contain credit rating triggers. EEI’s credit agreement 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, respectively, and the sponsors do not cover a payment default. At September 30, 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 1.6 million new shares of common stock in the first nine months of 2005 valued at $85 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 May 2005, settlement of the stock purchase contracts resulted in Ameren issuing 7.4 million shares of common stock in exchange for $345 million of proceeds. The adjustable conversion-rate equity security units ceased trading on the New York Stock Exchange before the opening of the market on May 16, 2005.

On October 20, 2005, the SEC declared effective a Form S-3 shelf registration statement filed by UE on September 23, 2005, amended on October 12, 2005, covering the offering from time to time of up to $1 billion of various forms of long-term debt and preferred securities.

In July 2005, UE issued, pursuant to its then-effective September 2003 SEC Form S-3 shelf registration statement, $300 million of 5.30% senior secured notes due August 1, 2037, with interest payable semi-annually on February 1 and August 1 of each year beginning in February 2006. UE received net proceeds of $297 million, which were used to repay short-term debt.

In January 2005, UE issued, pursuant to its then-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.

CIPS

In June 2005, $20 million of CIPS’ 6.49% first mortgage bonds matured and were retired.

CILCORP

In October and May 2005, CILCORP paid $80 million and $6 million to repurchase $69 million and $5 million, respectively, in principal amount of its 8.70% senior notes due 2009.

In July 2005, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. The redemption satisfied CILCO’s mandatory sinking fund redemption requirement for this series of preferred stock for 2005.

In conjunction with Ameren’s acquisition of CILCORP in January 2003, CILCORP’s long-term debt was recorded at fair value. Amortization related to fair value adjustments was $2 million (2004 - $2 million) and $6 million (2004 - $6 million) for the three months and nine months ended September 30, 2005, respectively, and was included as a reduction to Interest Charges.

In conjunction with Ameren’s acquisition of IP in September 2004, IP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $3 million and $12 million for the three months and nine months ended September 30, 2005, respectively, and was included as a reduction to Interest Charges.

Indenture Provisions and Other Covenants

The information below represents a summary of the Ameren Companies’ compliance with indenture provisions and other covenants. See Note 6 - Long-term Debt and Equity Financings in the Ameren Companies combined Annual Report on Form 10-K for the fiscal year ended December 31, 2004, for a detailed description of these provisions.

UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. The following table includes the earnings coverage ratio for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended September 30, 2005, at an assumed interest and dividend rate of 7%.

	Interest Coverage Ratio	Bonds Issuable^(a)	Dividend Coverage Ratio	Preferred Stock Issuable
UE	6.6	3,523	64.8	2,116
CIPS	3.9	224	2.3	215
CILCO	11.6	734	24.9	256
IP	4.9	908	3.6	951

(a)	Amount of bonds issuable based on meeting required coverage ratios.

As of September 30, 2005, UE also had $31 million of total retained earnings restricted by a mortgage indenture against payment of common dividends, except those dividends payable in common stock.

Genco’s and CILCORP’s indentures include provisions which require the companies to maintain certain debt service coverage and debt to capital ratios in order for the companies to pay dividends, make certain principal or interest payments, make certain loans to affiliates, or incur additional indebtedness. The following table summarizes these ratios for the 12 months ended September 30, 2005:

	Required Interest Coverage Ratio	Actual Interest Coverage Ratio	Required Debt to Capital Ratio	Actual Debt to Capital Ratio
Genco^(a)	1.75	5.6	60%	51%
CILCORP^(b)	2.2	2.8	67%	51%

(a)	Interest coverage ratio relates to covenants regarding certain dividend, principal and interest payments on certain subordinated intercompany borrowings. The debt to capital ratio relates to a debt incurrence covenant, which also requires an interest coverage ratio of 2.5.

(b)	CILCORP must maintain the required interest coverage ratio and debt to capital ratio in order to make any payment of dividends or intercompany loans to affiliates other than to its direct or indirect subsidiaries.

The ability for the Ameren Companies to issue securities in the future will depend on such tests at that time.

Off-Balance Sheet Arrangements

At September 30, 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 and nine months ended September 30, 2005 and 2004, respectively:

	Three Months						Nine Months
	2005			2004			2005			2004
Ameren:^(a)
Miscellaneous income:
Interest and dividend income	$	3		$	5		$	5		$	10
Allowance for equity funds used during construction		3			2			10			6
Other		-			1			4			4
Total miscellaneous income	$	6		$	8		$	19		$	20
Miscellaneous expense:
Minority interest in subsidiary	$	(1	)	$	(1	)	$	(2	)	$	(4	)
Loss on disposition of property		(1	)		-			(3	)		-
Other		(1	)		-			(7	)		(2	)
Total miscellaneous expense	$	(3	)	$	(1	)	$	(12	)	$	(6	)
UE:
Miscellaneous income:
Interest and dividend income	$	-		$	1		$	-		$	3
Equity in earnings of subsidiary		1			1			3			4
Allowance for equity funds used during construction		3			2			9			6
Gain on disposition of property		-			1			-			1
Other		-			-			3			-
Total miscellaneous income	$	4		$	5		$	15		$	14
Miscellaneous expense:
Other	$	(2	)	$	(1	)	$	(6	)	$	(6	)
Total miscellaneous expense	$	(2	)	$	(1	)	$	(6	)	$	(6	)
CIPS:
Miscellaneous income:
Interest and dividend income	$	4		$	6		$	13		$	19
Total miscellaneous income	$	4		$	6		$	13		$	19
Miscellaneous expense:
Other	$	(1	)	$	-		$	(5	)	$	(1	)
Total miscellaneous expense	$	(1	)	$	-		$	(5	)	$	(1	)
Genco:
Miscellaneous income:
Other	$	-		$	1		$	1		$	-
Total miscellaneous income	$	-		$	1		$	1		$	-
CILCORP:
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(7	)	$	(4	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(7	)	$	(4	)
CILCO:
Miscellaneous expense:
Other	$	(2	)	$	(1	)	$	(6	)	$	(4	)
Total miscellaneous expense	$	(2	)	$	(1	)	$	(6	)	$	(4	)
IP:^(b)
Miscellaneous income:
Interest and dividend income	$	1		$	2		$	3		$	3
Tilton Lease		-			1			-			8
Allowance for equity funds used during construction		-			-			1			-
Gain on disposition of property		-			-			-			1
Other		1			1			2			4
Total miscellaneous income	$	2		$	4		$	6		$	16
Miscellaneous expense:
Other	$	-		$	-		$	(1	)	$	(1	)
Total miscellaneous expense	$	-		$	-		$	(1	)	$	(1	)

(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 September 30, 2005:

	Ameren^(a)			UE			CIPS		Genco			CILCORP		CILCO		IP
2005:
Balance Sheet:
Other assets	$	194		$	22		$	43	$	-		$	82	$	82	$	31
Other deferred credits and liabilities		132			40			22		10			22		22		31
Accumulated OCI:
Power forwards and swaps^(b)		(21	)		(13	)		-		(9	)		-		-		1
Interest rate swaps^(c)		4			-			-		4			-		-		-
Gas swaps and futures contracts^(d)		93			15			21		-			59		59		-

(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.

(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 $2 million loss for Ameren and a $1 million loss for UE and Genco for the three months ended September 30, 2005 (2004 - $2 million loss for Ameren and a $1 million loss for UE and Genco) and a $2 million loss for Ameren and a $1 million loss for UE and Genco for the nine months ended September 30, 2005 (2004 - less than $1 million loss for Ameren, UE and Genco).

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 and coal options is recorded in Operating Expenses - Fuel and Purchased Power.

	Three Months					Nine Months
Gains (Losses)^(a)	2005			2004		2005			2004
SO₂ options:
Ameren^(b)	$	(4	)	$	4	$	(10	)	$	2
UE	$	(4	)	$	4	$	(5	)	$	(2	)
Genco	$	-		$	-	$	(5	)	$	4

(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.

Electric Power Supply Agreements

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

	Three Months					Nine Months
	2005		2004		2005		2004
Genco sales to Marketing Company		6,788		5,121		16,884		14,586
Marketing Company sales to CIPS		3,565		2,143		8,118		5,880
EEI sales to UE		789		796		2,230		2,442
EEI sales to CIPS		394		397		1,337		1,219
EEI sales to IP		433		445		1,227		1,313

Joint Dispatch Agreement

UE and Genco jointly dispatch electric generation under an agreement among UE, Genco and CIPS. Each affiliate has the option to serve its load requirements from its own generation first and then each allows access to any available remaining generation to its affiliate at incremental cost. Any excess generation not used by UE or Genco to serve load requirements is sold to third parties through Ameren Energy, serving as each affiliate’s agent. These third party sales

margins are allocated between UE and Genco using the ratio of each company’s load requirements to the companies’ combined load regardless of which company sourced the power. To allocate power costs between UE and Genco, an intercompany sale is recorded by the company sourcing the power to the other company. Ameren Energy also acts as agent on behalf of UE and Genco to purchase power when they require it. The joint dispatch agreement can be terminated by either party upon one year’s notice.

Due to the MoPSC order approving UE’s Illinois service territory transfer to CIPS or future regulatory proceedings, there could be changes to the agreement between UE and Genco to jointly dispatch electric generation or changes to the effect of that agreement on revenues and/or electric margins. Such changes could affect the pricing or availability of power transferred between Genco and UE. Based on operating performance for the past year, such changes would likely result in a transfer of electric margins from Genco to UE. The ultimate impact of any modifications to the joint dispatch agreement will be determined by future native load demand, the availability of electric generation from UE and Genco and market prices, among other things, but such impact could be material. Ameren’s earnings could be affected if electric rates for UE are adjusted by the MoPSC to reflect the provisions of the MoPSC order approving the service territory transfer and/or other changes to the joint dispatch agreement. See Note 3 - Rate and Regulatory Matters for a discussion of modifications to the joint dispatch agreement ordered by the MoPSC.

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

	Three Months					Nine Months
	2005		2004		2005		2004
Joint Dispatch Agreement
UE sales to Genco		2,804		2,355		9,567		6,339
Genco sales to UE		857		682		2,673		1,974

Money Pools

Utility

Through the utility money pool, the pool participants can access committed credit facilities at Ameren and excess cash at Ameren, UE, CIPS, CILCO and IP. See Note 4 - Short-term Borrowings and Liquidity for amounts available under credit facilities. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent the pool participants have surplus funds or other external sources are used to increase the available amounts. The average interest rate for borrowing under the utility money pool for the three months ended September 30, 2005 was 3.5% (2004 - 1.5%) and for the nine months ended September 30, 2005 was 3.0% (2004 - 1.2%) .

Non-state-regulated subsidiaries

Through the non-state-regulated subsidiary money pool, pool participants can access committed credit facilities at Ameren and excess cash at Ameren, Genco and other pool participants. See Note 4 - Short-term Borrowings and Liquidity for amounts available under credit facilities. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months ended September 30, 2005 was 4.1% (2004 - 8.8%) and for the nine months ended September 30, 2005 was 5.9% (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 September 30, 2005, CILCORP had notes payable under this arrangement of $100 million. The interest rate under this arrangement is the same as the non-state-regulated subsidiary money pool. See Note 3 - Rate and Regulatory Matters regarding PUHCA repeal.

Intercompany Promissory Notes

On May 1, 2005, Genco and CIPS amended the maturity date and interest rate of the subordinated note payable to CIPS by issuing to CIPS 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. As of September 30, 2005, $197 million was outstanding under this note.

Also on May 1, 2005, the remaining principal balance under Genco’s note payable to Ameren of $34 million was repaid.

On May 2, 2005, CIPS issued to UE a subordinated promissory note in the principal amount of approximately $67 million as consideration for 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. As of September 30, 2005, $67 million was outstanding under this note. 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 UE’s Illinois service territory and Genco’s electric generating facilities.

On June 22, 2005, UE purchased an uninstalled 117 megawatt CT and related vendor contract rights from

Development Company for an estimated market price of approximately $25 million. Also on that date, UE also purchased wet compression upgrade equipment for this CT and related vendor contract rights from Resources Company for an estimated market price of approximately $2 million. The unit went into commercial operation on October 14, 2005, at Venice, Illinois.

Summary of Related Party Transactions

The following tables present the impact of related party transactions on the Ameren Companies’ statements of income 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						Nine Months
Consolidated Statement of Income	2005			2004			2005			2004
Operating revenues from affiliates:
Power supply agreement with EEI	$	(a	)	$	5		$	(a	)	$	7
Joint dispatch agreement with Genco		50			31			147			89
Share of joint dispatch agreement interchange sales		60			46			189			142
Gas transportation agreement with Genco		(a	)		(a	)		(a	)		(a	)
Total operating revenues	$	110		$	82		$	336		$	238
Fuel and purchased power expenses from affiliates:
Power supply agreements:
EEI	$	16		$	15		$	46		$	47
Marketing Company		-			2			4			7
Joint dispatch agreement with Genco		26			13			57			37
Total fuel and purchased power expenses	$	42		$	30		$	107		$	91
Other operating expenses:
Support service agreements:
Ameren Services	$	38		$	37		$	119		$	113
Ameren Energy		1			1			3			1
AFS		1			1			3			3
Total other operating expenses	$	40		$	39		$	125		$	117
Interest expense:
Borrowings from money pool	$	2		$	1		$	4		$	2

(a)	Less than $1 million.

CIPS

	Three Months						Nine Months
Statement of Income	2005			2004			2005		2004
Operating revenues from affiliates:
Power supply agreements with Marketing CompanyPMarketing Company	$	8		$	8		$	25	$	24
Fuel and purchased power expenses from affiliates:
Power supply agreements:
Marketing Company	$	121		$	77		$	291	$	220
EEI		8			8			25		24
Total fuel and purchased power expenses	$	129		$	85		$	316	$	244
Other operating expenses:
Support service agreements:
Ameren Services	$	10		$	12		$	32	$	36
AFS		(a	)		1			1		1
Total other operating expenses	$	10		$	13		$	33	$	37
Interest income (expense):
Note receivable from Genco	$	4		$	5		$	12	$	18
Advances to (borrowings from) money pool		1			(a	)		1		(a	)

(a)	Less than $1 million.

Genco

	Three Months						Nine Months
Consolidated Statement of Income	2005			2004			2005			2004
Operating revenues from affiliates:
Power supply agreements:
Marketing Company	$	229		$	190		$	603		$	531
EEI		-			2			(a	)		3
Joint dispatch agreement with UE		26			13			57			37
Share of joint dispatch agreement interchange sales		31			23			109			72
Operating lease with Development Company		3			3			8			8
Total operating revenues	$	289		$	231		$	777		$	651
Fuel and purchased power expenses from affiliates:
Joint dispatch agreement with UE	$	50		$	31		$	147		$	89
Power purchase agreement with Marketing Company		2			(a	)		4			(a	)
Gas transportation agreement with UE		(a	)		(a	)		(a	)		(a	)
Total fuel and purchased power expenses	$	52		$	31		$	151		$	89
Other operating expenses:
Support service agreements:
Ameren Services	$	5		$	4		$	15		$	12
Ameren Energy		1			(a	)		2			1
AFS		1			1			2			2
Total other operating expenses	$	7		$	5		$	19		$	15
Interest expense (income):
Borrowings from (advances to) money pool	$	(1	)	$	4		$	2		$	10
Note payable to CIPS		4			5			12			18
Note payable to Ameren		-			1			1			2

(a)	Less than $1 million.

CILCORP

	Three Months					Nine Months
Consolidated Statement of Income	2005		2004			2005		2004
Operating revenues from affiliates:
Power supply agreements:
Bilateral supply agreement with Marketing Company	$	2	$	9		$	23	$	28
Fuel and purchased power expenses from affiliates:
Executory tolling agreement with Medina Valley	$	9	$	6		$	27	$	23
Bilateral supply agreement with Marketing Company		3		3			10		12
Total fuel and purchased power expenses	$	12	$	9		$	37	$	35
Other operating expenses:
Support services agreements:
Ameren Services	$	9	$	12		$	30	$	37
AFS		1		(a	)		2		1
Total other operating expenses	$	10	$	12		$	32	$	38
Interest expense:
Note payable to Ameren	$	1	$	1		$	4	$	3
Borrowings from money pool		1		1			3		3

(a)	Less than $1 million.

CILCO

	Three Months				Nine Months
Consolidated Statement of Income	2005		2004		2005		2004
Operating revenues from affiliates:
Power supply agreements:
Bilateral supply agreement with Marketing Company	$	2	$	9	$	23	$	28
Fuel and purchased power expenses from affiliates:
Executory tolling agreement with Medina Valley	$	9	$	6	$	27	$	23
Bilateral supply agreement with Marketing Company		3		3		10		12
Total fuel and purchased power expenses	$	12	$	9	$	37	$	35

Three Months

Nine Months

Consolidated Statement of Income

2005

2004

⁾

2005

2004

Other operating expenses:
Support services agreements:
Ameren Services	$	8	$	11	$	29	$	35
AFS		1		1		2		1
Total other operating expenses	$	9	$	12	$	31	$	36
Interest expense:
Borrowings from money pool	$	1	$	2	$	3	$	4

	Three Months						Nine Months
Consolidated Statement of Income		2005			2004^(a	⁾		2005			2004^(a	⁾
Operating revenues from affiliates and former affiliates:
Retail electricity sales to DMG	$	-		$	(b	)	$	-		$	1
Retail natural gas sales to DMG		-			1			-			4
Transmission sales to DYPM		-			4			-			10
Interconnection transmission with DYPM		-			1			-			3
Interest income from former affiliates		-			43			-			128
Total operating revenues	$	-		$	49		$	-		$	146
Fuel and purchased power expenses from affiliates and former affiliates:
Power supply agreements:
DMG	$	-		$	114		$	-		$	346
EEI		13			7			40			21
Gas purchased from Dynegy		-			(b	)		-			6
Total fuel and purchased power expenses	$	13		$	121		$	40		$	373
Other operating expenses:
Support services agreements:
Ameren Services	$	20		$	-		$	42		$	-
AFS		(b	)		-			1			-
Services and facilities agreement - Dynegy		-			3			-			11
Total other operating expenses	$	20		$	3		$	43		$	11
Interest expense (income):
Interest expense for IP SPT	$	3		$	5		$	9		$	17
Interest expense on Tilton lease		-			1			-			8
Interest income on Tilton lease		-			(1	)		-			(8	)
Advances to money pool		(1	)		-			(3	)		-

(a)	Represents predecessor information.

(b)	Less than $1 million.

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 September 30, 2005. This coverage was renewed on October 1, 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 licensed U.S. reactor, payable at $15 million per year. Renewal of Price-Anderson was part of the Energy Policy Act of 2005, which was signed by President Bush in August 2005.

(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 unavailable, 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 and natural gas for distribution. 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 September 30, 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 September 30, 2005:

	2005		2006		2007		2008		2009		Thereafter^(a)
Ameren^(b)	$	776	$	867	$	916	$	869	$	633	$	377
UE		397		413		483		414		279		193
Genco		209		262		247		296		237		107
CILCORP		84		91		87		74		52		36
CILCO		84		91		87		74		52		36

(a)	Commitments for coal are until 2010.

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

As of September 30, 2005, the commitments for the procurement of natural gas have increased from amounts previously disclosed as of December 31, 2004. The following table presents the total estimated natural gas purchase commitments at September 30, 2005:

	2005		2006		2007		2008		2009		Thereafter^(a)
Ameren^(b)	$	478	$	569	$	292	$	168	$	74	$	22
UE		77		62		28		15		7		8
CIPS		81		94		58		41		25		-
Genco		18		19		19		14		2		3
CILCORP		156		195		100		64		35		-
CILCO		156		195		100		64		35		-
IP		126		191		87		33		4		11

(a)	Commitments for natural gas are until 2014.

(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 plants, 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), and chemical and waste handling. Our activities often require complex and 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 until the fall of 2006 to develop state regulations 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 such a state decision would have on our results of operations, financial position, or liquidity.

Emission Credits

As of September 30, 2005, UE, Genco, CILCO, and EEI held 1.58 million, 0.53 million, 0.27 million, and 0.29 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 September 30, 2005, UE, Genco, CILCO and EEI Illinois facilities held 289, 17,579, 4,366, and 5,090 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 2005 through 2008. As of September 30, 2005, the SO₂ and NO_x emission allowances for UE, Genco, CILCO and EEI were carried in inventory at a book value of $63 million, $88 million, $56 million and $44 million, respectively. 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 the level of operations will have a

significant impact on the amount of allowances actually required for ongoing operations.

In the third quarter of 2005, Genco and UE entered into nonmonetary swaps of certain of their earlier vintage- year SO₂ emission allowances for later vintage-year allowances. As a result, Genco recorded a gain equal to the difference between the fair value of allowances received less the book value of allowances exchanged. The gain was recorded as a $21 million (pre-tax) reduction to fuel expense and an increase to inventory. UE recorded an increase to inventory and regulatory liabilities of $63 million. See Note 1 - Summary of Significant Accounting Policies for a discussion of SFAS No. 153, which provides guidance on accounting for exchanges of nonmonetary assets.

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 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.

In May 2005, the court approved a comprehensive settlement among DMG, the EPA, the U.S. and other intervening parties that resolved 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. This consent decree relieves 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.

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 is complying 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 September 30, 2005, CIPS, CILCO, and IP owned or were otherwise responsible for 14, 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. As of September 30, 2005, CIPS, CILCO, and IP had recorded liabilities of $24 million, $3 million, and $64 million, respectively, to represent estimated minimum obligations. 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 utility 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. 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. As of September 30, 2005, UE had recorded $10 million to represent its estimated minimum obligation of its MGP sites. UE also is responsible for four electric sites in Missouri that have corporate clean-up liability, the majority of which are the result of federal agency mandates. As of September 30, 2005, UE had recorded $5 million to represent its estimated minimum obligation for these sites. 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 was 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 issued by the EPA listing 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 and 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 that 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 Illinois utility service territory transfer discussed above and in Note 3 - Rate and Regulatory Matters.

In December 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 September 30, 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.

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.

Sustainable Energy Plan

In July 2005, the ICC entered a resolution affirming Illinois Governor Blagojevich’s Sustainable Energy Plan as well as an ICC Staff report dated July 7, 2005. CIPS, CILCO and IP were requested to file documentation explaining how they intend to implement the plan. The Ameren Illinois utilities continue to give consideration to this plan. The plan calls for, among other things, a renewable portfolio standard whereby 2% of the bundled retail load should be supplied by renewable energy resources in 2007, 3% in 2008, 4% in 2009, 5% in 2010, 6% in 2011, 7% in 2012 and 8% in 2013; and an energy efficiency portfolio standard whereby there is a 10% reduction in projected annual load growth in 2007-2008; 15% in 2009-2011; 20% in 2012-2014; and 25% in 2015-2017.

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 61 in the cases that were pending as of September 30, 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 July 1, 2005 through September 30, 2005, five additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois; 18 lawsuits were dismissed and 16 were settled. The following table presents the status as of September 30, 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		285		26		152		107		2		25		127
Settled		87		-		47		36		-		8		41
Dismissed		135		21		88		42		2		4		59
Pending		63		5		17		29		-		13		27

(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 September 30, 2005, five 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 fiscal 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, acquired through the acquisition of CIPSCO Inc. and CILCORP, that have been financed as leveraged leases. One of these is a $10 million net investment by an Ameren subsidiary in a leveraged lease involving an aircraft leased to Delta Air Lines, Inc. In September 2005, Delta Air Lines filed for protection under Chapter 11 of the U.S. Bankruptcy Code. While Ameren continues in its ownership role of the lease, Ameren cannot predict the ultimate ability of Delta Air Lines to service debt and pay future rentals required under the lease or the outcome of the bankruptcy process. Accordingly, Ameren recorded an impairment of $10 million ($6 million, net of tax), in the third quarter of 2005.

By order dated April 15, 2004, the SEC determined that certain non-utility interests and investments of CILCORP, including investments in several leveraged lease transactions held by CILCORP’s subsidiary, CIM, or CIM’s subsidiaries, are not retainable by Ameren under PUHCA standards. The non-retainable interests primarily consist of lease interests in commercial real estate properties and equipment. The April 2004 SEC Order requires that Ameren cause CIM or any subsidiary to sell or otherwise dispose of the non-retainable interests. Ameren and CILCORP are actively pursuing the sale of their interest in leveraged lease transactions.

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 installed 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 asset retirement obligations 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. An updated cost study for decommissioning UE’s Callaway nuclear plant was filed in August 2005. Based on the results of this updated cost study and associated financial analysis, UE has determined that the current deposits to the trust fund continue to be appropriate and do not need to be changed. The MoPSC is currently reviewing the updated cost study and UE’s application to keep the current deposits to the trust fund unchanged. Also as a result of the cost study, the asset retirement obligation for the Callaway nuclear plant decommissioning costs was revised. See Note 1 - Summary of Significant Accounting Policies for details of the asset retirement obligation adjustment. 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 service territory 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 and nine months ended September 30, 2005 and 2004:


	Three Months		Nine Months
	2005	2004	2005	2004
Shares outstanding at beginning of period	203.8	183.3	195.2	162.9
Shares issued	0.4	11.5	9.0	31.9
Shares outstanding at end of period	204.2	194.8	204.2	194.8

Paid-In Capital

During the nine months ended September 30, 2005, Ameren issued 1.6 million shares of common stock valued at $85 million under DRPlus and Ameren’s 401(k) plans and 7.4 million shares of common stock in exchange for proceeds of $345 million to holders of the adjustable conversion-rate equity security units offset by $5 million related to 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 and nine months ended September 30, 2005 and 2004, is shown below for the Ameren Companies:


	Three Months					Nine Months
	2005			2004		2005			2004
Ameren:^(a)
Net income	$	280		$	232	$	586		$	447
Unrealized gain on derivative hedging instruments, net of taxes of $11, $3, $22, and $15, respectively		15			10		33			16
Reclassification adjustments for (gains) losses included in net income, net of taxes (benefit) of $2, $(2), $3, and $(1), respectively		(2	)		5		(5	)		1
Total comprehensive income, net of taxes	$	293		$	247	$	614		$	464
UE:
Net income	$	164		$	182	$	353		$	349
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(2), $1, $-, and $3, respectively		(4	)		2		(1	)		5
Reclassification adjustments for (gains) included in net income, net of taxes (benefit) of $-, $-, $- and $-, respectively		(1	)		-		(1	)		-
Total comprehensive income, net of taxes$	$	159		$	184	$	351		$	354
CIPS:
Net income	$	31		$	23	$	46		$	41
Unrealized gain on derivative hedging instruments, net of taxes of $4, $2, $7, and $4, respectively		7			2		11			6
Reclassification adjustments for (gains) losses included in net income, net of taxes of $1, $-, $1 and $-, respectively		(1	)		1		(2	)		-
Total comprehensive income, net of taxes	$	37		$	26	$	55		$	47
Genco:
Net income	$	32		$	29	$	94		$	75
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $(3), $-, $(3), and $(1), respectively		(5	)		-		(6	)		(1	)
Reclassification adjustments for (gains) included in net income, net of taxes of $-, $-, $-, and $-, respectively		-			-		-			(1	)
Total comprehensive income, net of taxes	$	27		$	29	$	88		$	73
CILCORP:
Net income	$	5		$	2	$	16		$	2
Unrealized gain on derivative hedging instruments, net of taxes of $13, $6, $19, and $7, respectively		19			7		31			12
Reclassification adjustments for (gains) losses included in net income, net of taxes (benefit) of $-, $(1), $-, and $-, respectively		(1	)		2		-			-
Total comprehensive income, net of taxes	$	23		$	11	$	47		$	14
CILCO:
Net income	$	11		$	9	$	37		$	18
Unrealized gain on derivative hedging instruments, net of taxes of $13, $6, $20, and $8, respectively		19			7		30			13
Reclassification adjustments for (gains) loss included in net income, net of taxes of $-, $-, $1, and $-, respectively		(1	)		1		(1	)		(1	)
Total comprehensive income, net of taxes	$	29		$	17	$	66		$	30
IP:^(b)
Net income	$	54		$	51	$	91			112
Minimum pension liability adjustment, net of taxes of $-, $-, $- and $-, respectively		-			-		-			1
Total comprehensive income, net of taxes	$	54		$	51	$	91		$	113

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

(b)	Includes predecessor information for 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 and assuming continuation of the current federal interest rate relief beyond 2005, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2009 at which time we would expect a required contribution of approximately $300 million. 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 the cash contributions made to our defined benefit retirement plan qualified trusts in the third quarter of 2005 and 2004:


	2005		2004
Ameren^(a)	$	88	$	295
UE		56		186
CIPS		10		33
Genco		9		29
CILCORP		11		41
CILCO		11		41

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

The following table presents the cash contributions made to our postretirement plan in the nine months ended September 30, 2005 and 2004:


	2005		2004
Ameren^(a)	$	35	$	32
UE		23		23
CIPS		4		4
Genco		1		1
CILCORP		3		4
CILCO		3		4
IP		4		-

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

The following table presents Ameren’s net periodic benefit costs and the components of those costs for pension and other postretirement benefits (expensed and capitalized) for the three months and nine months ended September 30, 2005 and 2004:


	Pension Benefits^(a)
	Three Months						Nine Months
	2005			2004			2005			2004
Service cost	$	14		$	10		$	43		$	31
Interest cost		41			33			124			96
Expected return on plan assets		(45	)		(30	)		(136	)		(89	)
Amortization cost:
Prior service cost		3			3			8			9
Losses		9			6			28			18
Net periodic benefit cost	$	22		$	22		$	67		$	65

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


	Postretirement Benefits^(a)
	Three Months						Nine Months
	2005			2004			2005			2004
Service cost	$	5		$	3		$	16		$	10
Interest cost		17			13			53			41
Expected return on plan assets		(11	)		(7	)		(34	)		(23	)
Amortization cost:
Transition obligation		1			1			2			3
Prior service cost		(2	)		(1	)		(4	)		(3	)
Losses		9			7			28			24
Net periodic benefit cost	$	19		$	16		$	61		$	52

(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 and nine months ended September 30, 2005 and 2004:


	Pension Benefits
	Three Months				Nine Months
	2005		2004		2005		2004
UE	$	13	$	15	$	39	$	40
CIPS		3		3		9		9
Genco		2		2		6		6
CILCORP		3		2		9		8
CILCO		5		4		14		13
IP^(a)		1		-		4		-

(a)	Includes predecessor information for 2004.


	Postretirement Benefits
	Three Months				Nine Months
	2005		2004		2005		2004
UE	$	11	$	10	$	33	$	31
CIPS		3		2		9		7
Genco		1		1		3		3
CILCORP		2		3		8		8
CILCO		3		5		12		14
IP^(a)		3		-		9		-

(a)	Includes predecessor information for 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 natural 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 and nine months ended September 30, 2005 and 2004:


	Utility Operations		Other			Reconciling Items^(a)			Total
Three Months 2005:
Operating revenues	$	2,289	$	-		$	(421	)	$	1,868
Net income		280		-			-			280
Three Months 2004:⁽^b⁾
Operating revenues	$	1,596	$	-		$	(289	)	$	1,307
Net income		247		(15	)		-			232
Nine Months 2005:
Operating revenues	$	6,185	$	-		$	(1,106	)	$	5,079
Net income		591		(5	)		-			586
Nine Months 2004:⁽^b⁾
Operating revenues	$	4,536	$	-		$	(878	)	$	3,658
Net income		459		(12	)		-			447

(a)	Elimination of intercompany revenues.

(b)	Excludes 2004 amounts for IP.

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

OVERVIEW

Ameren Executive Summary

Significantly warmer summer weather and earnings from IP, acquired on September 30, 2004, drove an increase in year-over-year per share earnings in the third quarter of 2005. These increases were offset, in part, by higher fuel and purchased power costs, and higher operating expenses at UE’s Callaway nuclear plant due to the start of a 70 to 75-day scheduled outage on September 17, 2005. Ameren’s earnings for the first nine months of 2005 also benefited from stronger interchange power sales margins and less impact from UE’s Callaway nuclear plant refueling and maintenance outages. The plant had only 13 days of the fall 2005 outage in the first nine months of 2005 compared to 64 days for the spring 2004 outage in the first nine months of 2004.

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 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 distribution 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 and nine months ended September 30, 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 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

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.

Acquisition Accounting

The amortization of noncash purchase accounting fair value adjustments at IP and Ameren increased Ameren’s and IP’s net income by $14 million and $10 million, respectively, for the three months, and $40 million and $29 million, respectively, for the nine months ended September 30, 2005. 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 DYPM to supply IP 2,800 megawatts of electricity 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 at year end 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 and nine months ended September 30, 2005:


	Three Months						Nine Months
	Ameren			IP			Ameren			IP
Statement of Income line item:
Other operations and maintenance^(a)	$	7		$	7		$	20		$	20
Interest^(b)		3			3			13			13
Purchased power^(c)		13			7			33			15
Income taxes^(d)		(9	)		(7	)		(26	)		(19	)
Impact on net income	$	14		$	10		$	40		$	29

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

(b)

Related to the adjustment to fair value of 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 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 on power supply contracts.

(d)	Tax effect of the 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, was related to plant in service, emission credits and a power supply agreement with IP that expires at year end 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 and nine months ended September 30, 2005:


	Three Months			Nine Months
Statement of Income line item:
Interchange revenues^(a)	$	1		$	3
Fuel and purchased power^(b)		(2	)		(4	)
Depreciation and amortization^(c)		-			(1	)
Impact on net income	$	(1	)	$	(2	)

(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.

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 electric rates 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 $48 million to $280 million, or $1.37 per share, in the third quarter of 2005 from $232 million, or $1.20 per share, in the third quarter of 2004. Ameren’s net income increased $139 million to $586 million, or $2.94 per share, for the nine months ended September 30, 2005, compared to year-ago earnings of $447 million, or $2.44 per share, in the first nine months of 2004. The change in net income for the three months and nine months ended September 30, 2005 was primarily due to the inclusion of IP results in the current year, warmer weather in the summer of the current year compared to unusually mild conditions in the same period in 2004, and the timing of the refueling and maintenance outages at UE’s Callaway nuclear plant between the current year and prior year. The Callaway nuclear plant had a 64-day refueling and maintenance outage in the second quarter of 2004. A refueling and maintenance outage began in mid-September of 2005. The timing of the refueling and maintenance outage also contributed to improved power plant availability and the opportunity for increased interchange sales and margins in the first nine months of 2005. Partially offsetting these increases to net income were incremental costs of operating in the MISO Day Two Energy Market, decreased emission allowance sales and increased fuel, labor and depreciation costs in the current-year periods. In the third quarter of 2005, unscheduled plant outages at AERG also reduced net income as compared to the 2004 period. In addition, the net income for the nine months ended September 30, 2004, benefited from a FERC-ordered refund of $18 million in exit fees, which had been previously paid by UE and CIPS to the MISO, upon their re-entry into the MISO.

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 and nine months ended September 30, 2005 and 2004:


	Three Months						Nine Months
	2005			2004			2005			2004
Net income:
UE^(a)	$	163		$	181		$	349		$	345
CIPS		30			22			44			39
Genco^(a)		32			29			94			75
CILCORP^(a)		5			2			16			2
IP^(b)		53			-			89			-
Other^(c)		(3	)		(2	)		(6	)		(14	)
Ameren net income	$	280		$	232		$	586		$	447

(a)

Includes earnings from unregulated interchange power sales that provided $16 million and $67 million of UE’s net income in the three months and nine months ended September 30, 2005, respectively (2004 - third quarter - $14 million; year-to-date - $46 million), $8 million and $38 million of Genco’s net income in the three months and nine months ended September 30, 2005, respectively (2004 - third quarter - $6 million; year-to-date - $23 million), and $2 million and $11 million of CILCORP’s net income in the three months and nine months ended September 30, 2005, respectively.

(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.

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 and nine months ended September 30, 2005, from the comparable periods 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 and nine months ended September 30, 2005, as a separate line item, which facilitates comparison of other margin components. IP’s electric margins in 2005 include purchase accounting adjustments and are compared with the same periods in 2004 when Ameren did not own IP and it did not contribute to Ameren’s electric margins.


	Ameren^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP^(b)
Three Months
Electric revenue change:
IP	$	358		$	-		$	-		$	-		$	-		$	-		$	-
Effect of weather (estimate)		87			56			18			-			13			13			42
Growth and other (estimate)		50			25			59			36			5			5			(11	)
Interchange revenues		(3	)		27			1			18			(10	)		(10	)		-
Total	$	492		$	108		$	78		$	54		$	8		$	8		$	31
Fuel and purchased power change:
IP	$	(187	)	$	-		$	-		$	-		$	-		$	-		$	-
Fuel:
Generation and other		(78	)		(52	)		-			(3	)		(5	)		(6	)		-
Price		(15	)		(14	)		-			(6	)		5			5			-
Purchased power		(21	)		(47	)		(55	)		(46	)		(15	)		(15	)		4
Total	$	(301	)	$	(113	)	$	(55	)	$	(55	)	$	(15	)	$	(16	)	$	4
Net change in electric margins	$	191		$	(5	)	$	23		$	(1	)	$	(7	)	$	(8	)	$	35
Nine Months
Electric revenue change:
IP	$	861		$	-		$	-		$	-		$	-		$	-		$	-
Effect of weather (estimate)		95			61			20			-			14			14			49
Growth and other (estimate)		76			25			91			70			4			4			(20	)
Rate reductions		(7	)		(7	)		-			-			-			-			-
Interchange revenues		77			98			(1	)		52			(4	)		(4	)		-
Total	$	1,102		$	177		$	110		$	122		$	14		$	14		$	29
Fuel and purchased power change:
IP	$	(509	)	$	-		$	-		$	-		$	-		$	-		$	-
Fuel:
Generation and other		(112	)		(95	)		-			8			(11	)		(9	)		-
Price		(38	)		(22	)		-			(25	)		9			8			-
Purchased power		(2	)		(49	)		(87	)		(89	)		(7	)		(7	)		(13	)
Total	$	(661	)	$	(166	)	$	(87	)	$	(106	)	$	(9	)	$	(8	)	$	(13	)
Net change in electric margins	$	441		$	11		$	23		$	16		$	5		$	6		$	16

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

(b)	Compared to predecessor information for the three months and nine months ended September 30, 2004.

Ameren

Ameren’s electric margin increased $191 million for the three months and $441 million for the nine months ended September 30, 2005, compared with the same periods in 2004. The acquisition of IP added electric margins of $171 million and $352 million in the three months and nine months, respectively. Electric margin also increased due to higher interchange margins and favorable weather conditions in 2005, as discussed below, along with organic growth. Partially offsetting these increases to electric margin were incremental costs of operating in the MISO Day Two Energy Market incurred in the current year periods, increased purchased power due to unscheduled coal-fired plant outages at AERG and reduced industrial sales to unregulated markets outside of our core service territory. Fuel costs increased as a result of higher fuel prices and the use of higher-cost CT generation to meet increased weather-driven demand. Increased emission allowance utilization costs at Genco and AERG were partially offset by a reduction of fuel costs at Genco resulting from trading emission allowances for different vintage years as discussed below. Emission credit sales at UE decreased $9 million and $29 million for the third quarter and first nine months of 2005, respectively, as compared with the same periods in 2004, as UE continues to evaluate options for complying with the Clean Air Interstate Rule, which includes the possibility of using emission credits for compliance purposes. Electric 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 $3 million for the three months and $65 million for the nine months ended September 30, 2005, as compared with the same periods in 2004, principally because of higher power prices.

Average realized power prices on interchange sales increased to approximately $46 and $40 per megawatthour in the third quarter and first nine months of 2005, respectively, from approximately $28 and $29 per megawatthour in the comparable periods of 2004. High natural gas, emission allowance and coal prices in 2005 contributed to higher power prices. Increased availability of low-cost generation resulting from improved power plant availability, including the timing of the Callaway nuclear plant refueling and maintenance outages in the current and prior years, also contributed to increased interchange margins for the nine-month period. The MISO Day Two Energy Market also resulted in an increase in margins on interchange sales by an estimated $21 million in the first nine months of 2005, as compared to the year-ago period. In the third quarter of 2005, there was less excess power available for sale due to the warmer weather, the current year Callaway refueling and maintenance outage, and the addition of Noranda, as discussed below. Ameren’s baseload electric generating plants’ average capacity factors were approximately 82% and 79% for the third quarter and first nine months of 2005, respectively, compared with 81% and 76% for the same periods in 2004. Equivalent availability factors were 92% and 87% for the third quarter and first nine months of 2005, respectively, compared with 94% and 85% for the prior-year periods. Third quarter availability in the current year was negatively impacted by the Callaway refueling and maintenance outage and unscheduled coal-fired plant outages at AERG.

Warmer summer weather this year, as compared to abnormally mild conditions in the prior year, resulted in an increase in cooling degree-days of 53% in the third quarter of 2005 compared to the prior-year period. Cooling degree-days increased 16% from normal conditions in the third quarter of 2005. Excluding IP sales, weather-sensitive residential and commercial sales were up 22% and 8% for the third quarter of 2005, compared with the third quarter of 2004.

Industrial sales, excluding IP sales in the current year, decreased 3% in the nine months ended September 30, 2005, primarily as a result of the expiration and non-renewal of low-margin non-rate-regulated power sales contracts to customers outside of our core service territory along with decreased resale of power to the DOE by EEI under a power supply contract which expires at the end of 2005. Partially offsetting these decreases were sales to Noranda - a significant new UE customer in 2005 as discussed below, which drove an increase in industrial sales in the third quarter of 2005.

Ameren’s fuel and purchased power costs, excluding the IP results, increased $114 million in the three months and $152 million in the nine months ended September 30, 2005, compared with the same periods of 2004, primarily because of MISO Day Two Energy Market costs, increased fuel and purchased power prices, unscheduled coal-fired plant outages, increased CT generation as a result of the warmer weather in the current year, and increased emission allowance utilization at Genco and AERG. MISO costs included in purchased power, excluding IP, were $41 million and $59 million for the three and nine months ended September 30, 2005, respectively. MISO costs were greater due to higher than anticipated line losses, congestion charges and charges associated with deviations of actual from forecasted loads. We attribute some of these higher costs to the relative infancy of the MISO Day Two Energy Market. Emission allowance utilization increased $12 million and $43 million for the third quarter and nine months ended September 30, 2005, respectively. These increases in fuel and purchased power costs more than offset the effect of reduced purchased power costs related to the Callaway plant refueling and maintenance outage in the second quarter of the prior year. Purchased power costs incurred for the prior year refueling and maintenance outage were $24 million. The current year refueling and maintenance outage began in mid-September and has not resulted in a significant amount of power purchases from outside sources as of the end of the third quarter. Fuel and purchased power costs were reduced in the current year by a $21 million gain at Genco resulting from the nonmonetary swap of certain earlier vintage year SO₂ emission allowances for later vintage year allowances. See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further information.

UE’s electric margin decreased $5 million for the third quarter of 2005, but increased $11 million for the nine months ended September 30, 2005, compared with the same periods in 2004. Increased interchange margins and favorable weather conditions in the summer of the current year added to margins for the three- and nine-month periods in 2005. Margins on interchange sales with non-affiliates increased $3 million and $33 million in the third quarter and first nine months of 2005, respectively, compared with the same periods of 2004, primarily because of higher power prices and the MISO Day Two Energy Market. Margins on sales to affiliates for the first nine months of 2005 also increased over the prior year period because of increased sales to Genco under the joint dispatch agreement resulting from a major power plant maintenance outage at Genco in 2005. Residential and commercial sales increased 17% and 4% in the third quarter of 2005, compared with the third quarter of 2004, primarily as a result of favorable weather conditions.

Offsetting these increases to margin were the transfer of UE’s Illinois service territory to CIPS, rate reductions in

the first quarter of the current year, and decreased emission credit sales. On May 2, 2005, following the receipt of all required regulatory approvals, UE completed the transfer of its Illinois service territory, including its Illinois-based electric utility, to CIPS. The transfer resulted in an estimated decrease in electric margin of $35 million and $58 million in the third quarter and first nine months of 2005, respectively. Emission credit sales decreased $9 million and $29 million for the third quarter and first nine months of 2005, respectively, as compared with the same periods in 2004.

Effective June 1, 2005, UE commenced supplying approximately 470 megawatts (peak load) of electric service (or approximately 5% of UE’s generating capability, including currently committed purchases) to Noranda’s primary aluminum smelter in southeast Missouri under a 15-year agreement. The additional sales to Noranda increased electric margin by $25 million and $34 million in the third quarter and first nine months of 2005, respectively. This increase in industrial sales was partially offset by the effect of the transfer of UE’s Illinois service territory to CIPS.

Fuel and purchased power increased in the third quarter and first nine months of 2005, as compared with the same periods in 2004, primarily because of MISO Day Two Energy Market costs, increased fuel and purchased power prices, and increased generation to serve increased demand. MISO costs included in purchased power were $28 million and $40 million for the three and nine months ended September 30, 2005, respectively. The current year Callaway refueling and maintenance outage began in mid-September, as compared to the prior year refueling and maintenance outage which was completed in the second quarter of 2004. As a result, purchased power costs of $24 million were incurred in the prior year due to the Callaway refueling and maintenance outage. The current year refueling and maintenance outage resulted in power purchases of $4 million as of the end of the third quarter.

CIPS

CIPS’ electric margin increased $23 million in both the three months and nine months ended September 30, 2005, as compared with the same periods in 2004. The increases were primarily due to favorable weather conditions, increased industrial sales as a result of the transfer to CIPS of UE’s Illinois service territory, and customers switching to CIPS from Marketing Company. The transfer resulted in an estimated increase in electric margin of $18 million and $27 million in the third quarter and first nine months of 2005, respectively. Partially offsetting these margin increases were increased purchased power costs related to UE’s Illinois service territory transfer and customer switching, and MISO costs. MISO costs included in purchased power were $7 million and $10 million for the three and nine months ended September 30, 2005, respectively.

Genco

Genco’s electric margin was comparable in the third quarter of 2005 with the same period in 2004, but increased $16 million in the nine months ended September 30, 2005. Interchange margins increased $3 million in the three months and $23 million in the nine months ended September 30, 2005, compared with the same periods of 2004, primarily because of higher power prices and the MISO Day Two Energy Market. Wholesale margins decreased during the current quarter primarily due to purchasing higher cost power to serve greater load. The increase in load was due to Genco’s power supply agreement with Marketing Company serving increased volume from the transfer of UE’s Illinois service territory and warmer than normal weather. A loss of $6 million due to the settlement of SO₂ emission allowance options was recognized in the first quarter of 2005. Increased purchased power, principally from UE under the joint dispatch agreement, was the result of a major power plant maintenance outage, which occurred primarily during the first quarter of 2005. Emission allowance utilization increased fuel and purchased power costs by $10 million and $29 million for the third quarter and nine months ended September 30, 2005, respectively. Fuel and purchased power costs were reduced in the current year by a gain of $21 million resulting from the nonmonetary swap of certain earlier vintage year SO₂ emission allowances for later vintage year allowances.

CILCORP and CILCO

Electric margin decreased $7 million and $8 million at CILCORP and CILCO, respectively, in the three months ended September 30, 2005, but increased $5 million and $6 million, respectively, in the nine months ended September 30, 2005, compared with the same periods of 2004. Increases in electric margin for the nine-month period were primarily due to increased interchange margins and the use of lower cost coal at one of AERG’s power plants, along with the effect of favorable weather in the summer of the current year. The decrease in third quarter margins was primarily due to increased purchased power costs as a result of MISO costs and suboptimal plant performance in the current year quarter, partially offset by increased interchange margins and favorable weather. MISO costs included in purchased power were $3 million and $5 million for the three and nine months ended September 30, 2005, respectively. Emission allowance utilization decreased margins by $5 million and $15 million in the three months and nine months ended September 30, 2005, respectively, as compared to the same prior year periods.

IP’s electric margin increased $35 million and $16 million in the three months and nine months ended September 30, 2005, respectively, compared to the same periods in the prior year, primarily due to favorable weather conditions. Offsetting this increase to electric margins was reduced industrial revenues in the third quarter and first nine months of 2005 due to customers choosing alternative suppliers. In addition, purchased power costs increased in 2005 due to higher net power prices and MISO costs. While power costs decreased in 2005 under IP’s power supply agreement with DYPM, costs on remaining power purchase contracts were higher than in the same periods of the prior year. MISO costs included in purchased power were $3 million and $5 million for the three and nine months ended September 30, 2005, respectively.

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 and nine months ended September 30, 2005, from the comparable periods 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			Nine Months
Ameren^(a)	$	28		$	106
UE		5			9
CIPS		(1	)		(5	)
CILCORP		1			(1	)
CILCO		1			(c	)
IP^(b)		1			(2	)

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

(b)	Compared to predecessor information for the three months and nine months ended September 30, 2004.

(c)	Less than $1 million.

Ameren’s gas margin increased $28 million for the quarter and $106 million for the nine months ended September 30, 2005, as compared with the same prior year periods, primarily due to the inclusion of IP results in the current year. Excluding the IP results, gas margin was comparable for the three-month and nine-month periods. For the first nine months of 2005, rate increases at UE and IP along with increased transportation revenues offset the negative effect of mild winter weather. Ameren’s gas sales in the first nine months of 2005 increased almost 41%, due to the IP acquisition, while gas sales in Ameren’s preacquisition service territory were down 18% in the same period due to the mild winter weather. UE’s gas margin increased for the nine months ended September 30, 2005, as compared with the same period in the prior year, primarily due to the effect of rate increases in the first quarter of 2005. CIPS’ gas margin decreased for the first nine months of 2005 primarily due to unfavorable winter weather conditions and decreased in the third quarter of 2005 compared to the year-ago period primarily due to gas storage field losses. The transfer of UE’s Illinois service territory to CIPS resulted in an increase of $1 million and $2 million in CIPS’ gas margin for the three and nine months ended September 30, 2005, respectively, with an equivalent decrease in UE’s gas margin. CILCORP’s and CILCO’s gas margins were comparable for the three and nine months ended September 30, 2005, with the same periods in the prior year. IP’s gas margin decreased for the first nine months of the current year due to unfavorable winter weather in the first quarter of 2005, partially offset by the effects of a rate increase effective in May 2005 of $4 million. IP’s gas margin was comparable in the three months ended September 30, 2005, to the same period in the prior year.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren’s other operations and maintenance expenses increased $77 million for the three months and $153 million for the nine months ended September 30, 2005, compared with the same periods in 2004. The IP results in the current year added other operations and maintenance expenses of $64 million in the third quarter and $166 million in the first nine months. Excluding the IP results, other operations and maintenance expenses decreased in the nine-month period primarily due to decreased power plant maintenance costs of $29 million, primarily as a result of the refueling and maintenance outage at UE’s Callaway nuclear plant completed during the second quarter of 2004. Maintenance costs for the prior year outage were $31 million while maintenance costs for the current year outage were $3 million in the nine-month period. The current year refueling and maintenance outage began September 17, 2005, and is expected to last 70 to 75 days, longer than the typical outage, as UE is performing upgrades to steam generators and replacements of turbine rotors in addition to normal maintenance procedures. The plant is expected to gain approximately 60 megawatts of additional generating capacity as a result of efficiency improvements achieved through these upgrades. Ameren, UE and CIPS received a refund of previously paid exit fees of $18 million upon their re-entry into the MISO during the second quarter of 2004. This refund did not recur in 2005 and, therefore, other

operations and maintenance expenses increased for the first nine months of 2005 relative to 2004 for this item. An impairment of $10 million was recorded in the third quarter of 2005 related to our investment in a leveraged lease of an aircraft to Delta Air Lines, Inc. due to its Chapter 11 bankruptcy filing in September 2005. Labor costs, storm repair expenditures, and uncollectible reserves increased in the three and nine months ended September 30, 2005, as compared to the same periods in the prior year.

Other operations and maintenance expenses at UE increased $2 million in the three months, but decreased $17 million in the nine months, ended September 30, 2005, compared with the same periods of 2004. The decrease in the first nine months was primarily due to decreased power plant maintenance costs at Callaway as a result of the timing of the current year versus prior year refueling and maintenance outages as discussed above, and an unscheduled outage at Callaway in the first quarter of 2004. Offsetting this favorable variance was the receipt of a $12 million MISO exit fee refund during the second quarter of the prior year. Storm repair expenditures and uncollectible reserves increased in the third quarter and first nine months of the current year, as compared to the same periods in the prior year. Labor costs increased in the third quarter of 2005, partially due to the current year Callaway refueling and maintenance outage, but were comparable for the nine-month period. The transfer of UE’s Illinois service territory to CIPS resulted in decreased other operations and maintenance expenses of $6 million and $10 million in the three and nine months ended September 30, 2005.

Other operations and maintenance expenses at CIPS were comparable in the three months ended September 30, 2005, with the same period in 2004. For the nine-month period, CIPS’ portion of the MISO exit fee refund in the prior year of $5 million was more than offset by decreases in various other operations and maintenance expenses in the current year. The transfer of UE’s Illinois service territory to CIPS resulted in an increase in other operations and maintenance expenses of $6 million and $10 million for the three and nine months ended September 30, 2005.

Genco’s other operations and maintenance expenses were comparable in the three months ended September 30, 2005, with the same period in 2004. Genco’s other operations and maintenance expenses increased $5 million in the first nine months of 2005 primarily due to a major power plant maintenance outage in the first quarter of 2005.

Other operations and maintenance expenses at both CILCORP and CILCO decreased $12 million in the third quarter of 2005 and decreased $21 million and $23 million, respectively, for the nine months ended September 30, 2005, as compared with the same periods in 2004. Other operations and maintenance expenses decreased primarily due to the settlement in the prior year of a litigation claim with Enron Power Marketing, Inc. The AES Corporation indemnified Ameren, and Ameren assigned the indemnification to CILCORP and CILCO, for the $13 million after-tax cost of the $21 million claim settlement. As a result, other operations and maintenance expenses in the third quarter of 2004 reflected the net cost of $8 million while income taxes reflected a tax benefit of $8 million.

Other operations and maintenance expenses at IP increased $20 million for the third quarter and $23 million for the first nine months of 2005, respectively, as compared to the same periods in 2004, primarily due to the receipt of a refund of previously paid exit fees of $9 million from MISO during the third quarter of the prior year. Other operations and maintenance expenses also increased due to higher overhead and labor costs associated with the integration of systems and operations with Ameren.

Depreciation and Amortization

Ameren’s depreciation and amortization expenses increased $22 million in the three months and $74 million in the nine months ended September 30, 2005, compared with the same periods of 2004, principally because of the acquisition of IP, which added $19 million and $59 million to each period, respectively. Capital additions also resulted in increased depreciation expenses in the current year.

Depreciation and amortization expenses at UE increased $17 million in the three months and $23 million in the first nine months of the current year compared with the same periods of 2004. The increases were primarily due to capital additions and depreciation on CTs transferred from Genco in May 2005, partially offset by reduced depreciation on property transferred to CIPS in the Illinois service territory transfer in May 2005.

CIPS’ depreciation and amortization expense increased $4 million in the third quarter and $9 million in the nine-month period ended September 30, 2005, compared with the same periods of 2004, because of depreciation on property transferred from UE in the Illinois service territory transfer and capital additions.

Depreciation and amortization expenses at Genco decreased $1 million in the three months and $2 million in the nine months ended September 30, 2005, compared with the same periods of 2004, because of the transfer of CTs from Genco to UE in May 2005.

Depreciation and amortization expenses at CILCORP and CILCO were comparable for the third quarter of 2005, but increased $3 million and $2 million, respectively, in the

nine months ended September 30, 2005, compared with the same periods of 2004, because of capital additions.

IP’s depreciation and amortization expenses, excluding the amortization of regulatory assets, were comparable in the three months and nine months ended September 30, 2005, with the same periods of 2004. Amortization of regulatory assets at IP decreased $11 million in the three months and $32 million for the nine months ended September 30, 2005, as compared with the same periods of 2004. The transition cost regulatory asset was eliminated in conjunction with Ameren’s acquisition of IP in September 2005.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $21 million in the third quarter and $53 million in the nine months of the current year, compared with the same periods of 2004, principally because of the acquisition of IP, which added $14 million and $54 million, respectively. Excluding IP in the current year, taxes other than income taxes at Ameren increased $7 million for the third quarter of 2005 over the year-ago period primarily because of higher gross receipts taxes, but were comparable for the first nine months of 2005.

UE’s taxes other than income taxes increased in the third quarter of 2005, compared with the same period of the prior year, primarily because of increased gross receipts taxes resulting from increased sales. Taxes other than income taxes increased in the first nine months of 2005, compared to the same period of the prior year, primarily because of increased property taxes due to higher assessments. Property taxes were partially reduced in 2005 by the transfer of UE’s Illinois service territory to CIPS.

Taxes other than income taxes at CIPS increased for the three and nine months ended September 30, 2005, compared to the same periods in the prior year, primarily because of increased property taxes resulting from the transfer to CIPS of UE’s Illinois service territory.

Genco’s taxes other than income taxes were comparable in the three months, but decreased $9 million in the nine months, ended September 30, 2005, compared with the same periods of 2004, due to a favorable property tax court decision in the first quarter of 2005.

Both CILCORP’s and CILCO’s taxes other than income taxes were comparable for the third quarter of 2005 compared with the same period in 2004, but decreased in the first nine months of 2005, compared with the first nine months of 2004, primarily because of reduced gross receipts taxes related to transfers of customers to Marketing Company.

Taxes other than income taxes at IP were comparable in the three months and nine months ended September 30, 2005, with the same periods of 2004.

Other Income and Deductions

Other income and deductions decreased $4 million in the third quarter and $7 million in the first nine months of the current year, compared with the same periods of 2004. Excluding IP, other income and deductions at Ameren decreased $6 million in the three months and $12 million in the first nine months of 2005, compared to the year-ago periods. Other income and deductions decreased primarily due to reduced interest income resulting from the investment of equity issuance proceeds in the prior year and other items discussed below with respect to the other Ameren Companies.

Other income and deductions at UE and Genco were comparable in the three months and nine months ended September 30, 2005, with the same periods in 2004.

CIPS’ other income and deductions decreased $3 million and $10 million in the third quarter and first nine months of 2005, respectively, as compared with the same prior-year periods, primarily because of reduced interest income on the intercompany note receivable from Genco.

Other income and deductions at CILCORP and CILCO were comparable in the three months, but decreased $3 million and $2 million, respectively, in the nine months ended September 30, 2005, compared with the same periods in 2004, primarily because of the write-off of unrecoverable natural gas costs.

Other income and deductions at IP decreased $45 million in the third quarter and $138 million in the nine months ended September 30, 2005, compared with the same periods 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 on September 30, 2004.

Interest

Interest expense increased at Ameren in the three months and nine months ended September 30, 2005, compared with the same periods of 2004, principally due to the acquisition of IP, which added $11 million for the third quarter and $32 million for the first nine months of 2005. Excluding the IP results in the current year, interest expense was comparable with the same periods in 2004.

UE’s interest expense increased in the third quarter and first nine months of 2005 primarily because of the issuance of $300 million of senior secured notes in July of 2005.

Genco’s interest expense decreased $8 million in the three months and $15 million in the nine months ended September 30, 2005, compared with the same periods of 2004, primarily because of a reduction in principal amounts outstanding on intercompany promissory notes to CIPS and Ameren.

Interest expense at IP decreased $24 million in the three months and $82 million in the nine months ended September 30, 2005, compared with the same periods of 2004, primarily because of redemptions and repurchases of indebtedness of $700 million in the fourth quarter of 2004 and $70 million in early 2005 and reductions in notes payable to IP SPT.

Interest expense at CIPS, CILCORP and CILCO in the three months and nine months ended September 30, 2005, was comparable to the same periods of 2004.

Income Taxes

Income tax expense at Ameren increased $36 million in the third quarter and $88 million in the first nine months of the current year, compared with the same periods of 2004, because of higher pretax income primarily due to the inclusion of IP results in 2005. IP added income tax expenses of $36 million and $60 million to the three months and nine months ended September 30, 2005, respectively. Partially offsetting these increases was the recognition in 2005 of a deduction allowed under the Jobs Creation Act of $1 million and $3 million for the three- and nine-month periods, respectively. During the third quarter of 2004, a tax benefit was realized related to CILCO’s settlement of its litigation claim with Enron Power Marketing, Inc. This tax benefit resulted in lower tax expense during the third quarter of 2004 as compared to the third quarter of 2005. UE’s income tax expense was lower in the third quarter of 2005 due to lower pretax income. UE’s income tax expense was partially reduced in the current year by the recognition of the Jobs Creation Act deduction. Income tax expense increased at CIPS in the third quarter of 2005 due to higher pretax income, but decreased in the nine months ended September 30, 2005, compared with the same periods of 2004, because of the effect of tax credits and other permanent items. Income tax expense was higher at CILCORP and CILCO in the third quarter and nine months, compared with the same periods in 2004, due to higher pretax income and the tax benefit in the third quarter of the prior year related to CILCO’s settlement of its litigation claim with Enron Power Marketing, Inc. Income tax expense at Genco increased for the three and nine months ended September 30, 2005, due to higher pretax income. IP’s income tax expense was higher in the third quarter of 2005 due to higher pretax income, but lower for the nine-month period as net income decreased from the prior year.

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 provide a reasonably predictable source of cash flows. For cash flows from operating activities, Genco principally relies on power 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 nine months ended September 30, 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)	$	1,089	$	736	$	353		$	(648	)	$	(977	)	$	329		$	(232	)	$	777		$	(1,009	)
UE		714		529		185			(635	)		(381	)		(254	)		(126	)		(150	)		24
CIPS		148		79		69			(40	)		17			(57	)		(110	)		(108	)		(2	)
Genco		135		115		20			124			(37	)		161			(260	)		(80	)		(180	)
CILCORP		57		100		(43	)		(67	)		(91	)		24			7			(11	)		18
CILCO		81		84		(3	)		(71	)		(94	)		23			(10	)		7			(17	)
IP^(b)		207		158		49			(4	)		(96	)		92			(203	)		(28	)		(175	)

(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, CIPS, Genco and IP in the nine months ended September 30, 2005, compared with the same period of 2004. Ameren’s increase of $353 million was primarily attributable to $207 million of cash flow from operations of IP, which was acquired on September 30, 2004. Excluding the impact of IP, Ameren’s increase in electric margins of $89 million also contributed to the increase in cash flow from operations. In addition, decreased pension and other postretirement benefit contributions of $204 million contributed to the favorable variance in cash flow from operations. Partially offsetting the positive variance in 2005 were increased tax payments of $131 million, additional SO₂ emission allowance purchases in 2005 of $41 million (net of allowances expensed), and the absence in 2005 of $28 million of cash from the UE coal contract settlement received in 2004. Other working capital changes were primarily the result of timing differences.

At UE, decreased pension and postretirement benefit contributions of $142 million and higher electric margins and reduced other operations and maintenance expenses totaling $28 million, as discussed under Results of Operations, contributed to the favorable variance in cash flow from operations. In 2005, increased tax payments of $80 million and the lack of coal contract settlement payments mentioned above partially offset the positive factors. Timing differences related to working capital also contributed to UE’s cash flows for the nine months ended September 30, 2005, compared to the same period last year.

CIPS’ increase in cash flows from operating activities in the nine months ended September 30, 2005, was principally due to a reduction of $25 million in pension and postretirement benefits compared to the same period last year, and timing differences related to working capital for the nine months ended September 30, 2005, compared to the same period last year.

Cash flows provided by operating activities increased for Genco in the nine months ended September 30, 2005, compared with the same period in 2004 due to decreased pension and other postretirement benefit contributions of $21 million, and timing differences in accounts and wages payable. These increases were partially offset by a $56 million increase in cash used for materials and supplies inventory, which included $48 million of SO₂ emissions allowance purchases.

Cash flows from operating activities decreased for CILCORP and CILCO in the nine months ended September 30, 2005, compared with the same period in 2004. Contributing to the reduction in cash flows from operating activities were purchases of SO₂ emission allowances of $7 million and increased tax payments of $40 million for CILCO and $24 million for CILCORP. Differences in the timing and amount of accounts and wages payable and accounts receivable also contributed to CILCORP’s and CILCO’s decrease in cash flows from operating activities. These decreases were partially offset by a decrease in pension and other postretirement contributions of $33 million, and increased electric margins as discussed under Results of Operations.

IP had a $49 million increase in cash flows from operating activities for the first nine months of 2005, as compared to the first nine months of 2004. Cash flows from operating activities in the 2005 period benefited from the receipt of income tax refunds, compared to tax payments of $160 million in the year-ago period. The increase in cash from operations in 2005 was partially offset by the absence of interest income from a former affiliate that is included in the year-ago period.

Cash Flows from Investing Activities

Cash flows used in investing activities increased for UE and decreased for Ameren, CILCORP, CILCO and IP for the nine months ended September 30, 2005, compared with the same period in 2004. Investing activities were a source of cash for Genco in the first nine months of 2005, as compared to a use of cash in the first nine months of 2004. Investing activities were a use of cash for CIPS in the first nine months of 2005 as compared to a source of cash in the first nine months of 2004.

Ameren’s decrease in cash used in investing activities was primarily due to a use of cash of $451 million related to the acquisition of IP. In 2005, Ameren’s net decrease in cash used in investing activities was partially offset by capital expenditures of $95 million at IP.

UE’s cash flows used in investing activities increased primarily due to increased capital expenditures. UE’s capital expenditures included $241 million for 550 megawatts of CTs purchased from Genco in May 2005, and $59 million at the Callaway nuclear plant for upgrades during a refueling and maintenance outage. In addition, capital expenditures included $25 million for a 117 megawatt CT from Development Company and $2 million for related equipment from Resources Company. Otherwise, UE’s capital expenditures decreased $72 million.

CIPS’ increase in cash flows used in investing activities for the nine months ended September 30, 2005, compared to the year-ago period was primarily due to a $51 million advance to the utility money pool and a $9 million increase in capital expenditures. The increased capital expenditures were used to improve the reliability of the transmission and distribution systems.

Genco’s cash flows provided by investing activities increased in the nine months ended September 30, 2005, compared with the same period in 2004, because of the sale of 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois to UE for $241 million. These proceeds were partially offset by increased capital expenditures and net advances to the non-state-regulated subsidiary money pool. Genco’s higher capital expenditures were attributed to upgrades at one of its power plants in the first quarter of 2005.

CILCORP’s and CILCO’s cash flows used in investing activities decreased in the nine months ended September 30, 2005, compared with the same period in 2004 primarily because of reduced capital expenditures. In 2004, AERG made capital expenditures for significant power plant upgrades to increase fuel supply flexibility for power generation.

IP’s decrease in cash flows used in investing activities for the nine months ended September 30, 2005, was primarily because of $90 million of cash received for repayment of prior period utility money pool advances.

Intercompany Transfer of Illinois Service Territory

On May 2, 2005, UE completed the transfer of its Illinois-based electric and natural gas service territory to CIPS, at a net book value of $133 million. UE transferred 50% of the assets directly to CIPS in consideration for a CIPS subordinated promissory note in the principal amount of approximately $67 million and 50% 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.

We continually review our generation port-folio 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 discussion of environmental matters.

Cash Flows from Financing Activities

Cash flows from financing activities decreased for Ameren in the nine months ended September 30, 2005, as compared with the same period of 2004, primarily because of the receipt of $1,418 million related to common stock issuances in the first nine months of 2004. These proceeds were principally used to fund the acquisition of IP and Dynegy’s 20% interest in EEI on September 30, 2004, and to redeem certain IP indebtedness subsequent to the acquisition. In 2005, total common stock proceeds of $430 million included $345 million from the issuance of 7.4 million shares of common stock related to the settlement of a stock purchase obligation in Ameren’s adjustable conversion-rate equity security units. In 2005, increased short-term debt redemptions of $264 million contributed to the net use of cash for financing activities. Decreased long-term debt redemptions of $189 million and the absence in 2005 of a 2004 $67 million UE nuclear fuel lease payment partially offset the decrease in cash from financing activities in 2005.

UE’s cash flows used in financing activities decreased $24 million in the nine months ended September 30, 2005, compared with the same period of 2004. This decrease was caused, in part, by lower redemptions of long-term debt, a decrease in the payment of dividends to Ameren and the absence of a nuclear fuel lease payment that was made in the first three months of 2004. These decreases in cash used in financing activities were partially offset by higher redemptions of short-term debt, lower issuances of long-term debt, and a net decrease in utility money pool borrowings.

CIPS’ cash flows used in financing activities increased slightly in the nine months ended September 30, 2005, as compared with the same period of 2004. A $25 million cash benefit from reduced dividends paid to Ameren was offset by increased redemptions of long-term debt of $20 million, and a net increase in utility money pool borrowings of $8 million.

Genco’s cash flows used in financing activities increased in the nine months ended September 30, 2005, as compared with the same period of 2004, primarily because of a net increase in non-state-regulated subsidiary money pool repayments of $71 million, incremental payments of $34 million on its note payable to Ameren, and payment of $52 million on its note payable to CIPS. The funds for these note repayments came from the $241 million in proceeds from the May 2005 sale of 550 megawatts of CTs to UE. Net cash used in financing activities also increased due to a decrease in capital contributions of $74 million. Genco has $225 million of 7.75% senior notes that mature on November 1, 2005, that Genco intends to repay with cash.

Effective May 1, 2005, Genco and CIPS amended certain terms of Genco’s subordinated affiliate note payable to CIPS 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.

CILCORP’s cash flows from financing activities increased by $18 million, and CILCO’s cash flows from financing activities decreased by $17 million in the nine months ended September 30, 2005, compared with the same period of 2004. CILCORP’s net increase in the use of cash for

money pool borrowings of $131 million for the first nine months of 2005 compared to the same period in 2004 was partially offset by an increase in capital contributions from Ameren in the amount of $26 million. There were no significant debt redemptions in 2005 compared to 2004 debt redemptions of $123 million and $100 million at CILCORP and CILCO, respectively. Dividend payments to Ameren increased $12 million and $10 million for CILCORP and CILCO, respectively, and CILCORP’s proceeds from intercompany notes with Ameren increased $18 million for the first nine months of 2005 compared to the same period in 2004.

IP’s cash flows used in financing activities increased in the nine months ended September 30, 2005, compared with the same period of 2004 primarily because of incremental redemptions, repurchases and maturities of long-term debt of $70 million and dividend payments of $60 million made to Ameren in 2005, partially offset by the absence in 2005 of prepaid interest on the note receivable from a former affiliate of $43 million.

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 committed bank credit facilities of Ameren and EEI as of September 30, 2005. See Note 4 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for additional information concerning these credit facilities.


Credit Facility	Expiration	Amount Committed		Amount Available
Ameren:^(a)
Multiyear revolving^(b)	July 2010	$	1,150	$	1,150
Multiyear revolving	July 2010		350		350
EEI:
One bank credit facility	April 2006		20		-
Total		$	1,520	$	1,500

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

(b)	UE, CIPS, CILCO, Genco and IP are also direct borrowers under this agreement.

In addition to committed credit facilities, a further source of liquidity for Ameren from time to time is available cash and cash equivalents. At September 30, 2005, Ameren had $278million of cash and cash equivalents.

See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for information concerning PUHCA repeal.

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 nine months ended September 30, 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		Nine Months
			2005		2004
Issuances
Long-term debt
UE:
5.30% Senior secured notes due 2037		July	$	297	$	-
5.00% Senior secured notes due 2020		January		85		-
5.10% Senior secured notes due 2019		September		-		300
5.50% Senior secured notes due 2014		May		-		104
Total Ameren long-term debt issuances			$	382	$	404


	Month Issued, Redeemed, Repurchased or Matured		Nine Months
			2005		2004
Common stock
Ameren:
7,402,320 Shares at $46.61^(a)		May	$	345	$	-
10,925,000 Shares at $42.00…..		July		-		459
19,063,181 Shares at $45.90…..		February		-		875
DRPlus and 401(k)^(b)		Various		85		84
Total common stock issuances			$	430	$	1,418
Total Ameren long-term debt and common stock issuances			$	812	$	1,822
Redemptions, Repurchases and Maturities
Long-term debt
Ameren:
Senior notes due 2007^(c)		February	$	95	$	-
UE:
6.87% First mortgage bonds due 2004…………………….……………………….. 7.00% First mortgage bonds due 2024		August June		- -		188 100
CIPS:
6.49% First mortgage bonds due 2005		June		20		-
CILCORP:
8.70% Senior notes due 2009		May		6		-
9.375% Senior bonds due 2029		Various		-		23
CILCO:
5.85% Series preferred stock Secured bank term loan		July February		1 -		1 100
EEI:
2000 Bank term loan, 7.61% due 2004		June		-		40
IP:
6.75% First mortgage bonds due 2005		March		70		-
Note payable to IP SPT
5.38% Series due 2005		Various		71		65
Less: IP activity prior to acquisition date				-		(65	)
Total Ameren long-term debt redemptions, repurchases and maturities			$	263	$	452

(a)	Shares issued upon settlement of the purchase contracts, which were 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.

(b)	Includes issuances of common stock of 1.6 million shares during the nine months ended September 30, 2005, under DRPlus and 401(k) plans.

(c)	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 shelf registration statements filed and declared effective for certain of the Ameren Companies as of September 30, 2005:


	Effective Date	Authorized Amount		Issued		Available
Debt:
Ameren	July 2004	$	2,000	$	459	$	1,541
UE^(a)	September 2003		1,000		989		11
CIPS	May 2001		250		150		100

(a)	On October 20, 2005, the SEC declared effective a Form S-3 shelf registration statement filed by UE covering the offering from time to time of up to $1 billion in various forms of long-term debt and preferred securities.

Ameren also has approximately 5.7 million shares of common stock available for issuance under various other SEC effective registration statements applicable to our DRPlus and 401(k) plans as of September 30, 2005.

Ameren, UE and CIPS may sell all or a portion of the remaining securities registered under the 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.

Our credit agreements contain indebtedness cross-default provisions that could trigger a default under the facilities. In the event Ameren’s subsidiaries (subject to the definition in the underlying credit agreements), other than certain project finance subsidiaries, default in indebtedness of

$50 million or greater, fail to pay the amounts drawn (as a direct borrower) under an Ameren credit facility, or enter bankruptcy proceedings, a default under the Ameren credit facilities would occur. A CILCO bankruptcy would also cause a default under CILCORP’s debt agreements. In addition, a default of $50 million or greater or a bankruptcy would cause a default under the agreements supporting $100 million of Ameren LIBOR swaps.

At September 30, 2005, the Ameren Companies were in compliance with their credit agreement, indenture 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 shareholders during the first nine months of 2005 totaled $383 million, or $1.905 per share (2004 - $356 million or $1.905 per share).

UE’s preferred stock dividends are payable November 15, 2005, to shareholders of record on October 20, 2005. CIPS’ preferred stock dividends are payable December 30, 2005, to shareholders of record on December 8, 2005. CILCO’s preferred stock dividend is payable January 3, 2006, to shareholders of record on December 5, 2005. CILCO paid a preferred stock dividend of less than $1 million on October 3, 2005. IP paid a preferred stock dividend of approximately $1 million on November 1, 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 September 30, 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 nine months ended September 30, 2005 and 2004:


	Nine Months
	2005		2004
UE	$	209	$	230
CIPS		21		46
Genco		59		57
CILCORP^(a)		30		18
IP^(b)		60		-
Non-Registrants		4		5
Dividends paid by Ameren	$	383	$	356

(a)	CILCO paid dividends of $20 million and $10 million for the nine months ended September 30, 2005 and 2004, respectively.

(b)	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 and therefore 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 - Retirement 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 and natural gas increased at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $6,041 million, $2,376 million, $299 million, $1,433 million, $974 million, $974 million and $452 million, respectively, as of September 30, 2005. Total other obligations at December 31, 2004, updated for material changes since year-end through September 30, 2005, at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $6,464 million, $2,531 million, $543 million, $1,433 million, $999 million, $999 million and $753 million, respectively.

Credit Ratings

The following table presents the principal credit ratings of the Ameren Companies by Moody’s, S&P and Fitch effective as of the date of this report and subsequent to the rating changes issued October 3, 2005 as discussed below:


	Moody’s	S&P	Fitch
Ameren:
Issuer/corporate credit rating	A3	BBB+	N/A
Unsecured debt	A3	BBB	A-
Commercial paper	P-2	A-2	F2
UE:
Secured debt	A1	BBB+	A+
Commercial paper	P-1	A-2	F1
CIPS:
Secured debt	A1	A-	A
Genco:
Unsecured debt	A3/Baa2	BBB+	BBB+
CILCORP:
Unsecured debt	Baa2	BBB	BBB+
CILCO:
Secured debt	A2	A-	A
IP:
Secured debt	Baa1	BBB+	BBB

On October 3, 2005, S&P downgraded the Ameren Companies’ corporate secured debt credit ratings from A- to BBB+ and downgraded secured debt ratings one notch at UE and IP principally as a result of recent unfavorable actions by the Illinois governor with respect to CIPS, CILCO and IP electric rates in 2007. S&P also placed the Ameren Companies’ ratings on negative credit watch. On September 30, 2005, Moody’s placed long-term ratings of Ameren, CIPS, CILCORP, CILCO and IP under review for possible downgrade due to concerns similar to those expressed by S&P. Fitch has not made any changes to ratings or outlook at this time. See Note 3 - Rate and Regulatory Matters for a more detailed discussion of actions by the Illinois governor.

On March 31, 2005, Moody’s upgraded IP’s credit ratings. IP’s senior secured debt rating was upgraded from Baa3 to Baa1.

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and/or increase the cost of borrowings and power supply, among other things, resulting in a negative impact on earnings. At September 30, 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 $84 million, $41 million, $1 million, $3 million, less than $1 million, less than $1 million, and $1 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

Below are some key trends that may impact the Ameren Companies’ financial condition, results of operations or liquidity in 2005 and beyond:

Revenues

·	By the end of 2006, electric rates for Ameren’s operating subsidiaries will have been fixed or declining for periods ranging from 15 years to 25 years. In 2006, electric rate adjustment moratoriums and 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 October 2005. CIPS, CILCO and IP made filings with the ICC in 2005, outlining, among other things, a proposed framework for power procurement after 2006 through an auction process.

·	In September 2005, the Illinois attorney general and other parties filed a lawsuit against the ICC seeking a declaratory judgment that the ICC lacks authority to approve market-based rates for electric service that have not been “declared competitive” pursuant to Illinois law

and seeking injunctive relief prohibiting ICC approval of the proposed power procurement auction process. Additionally, the governor of Illinois sent a letter to the ICC expressing his view that rate increases are unjustified, his opposition to the proposed auction process and his contention that the ICC lacks authority to approve such market-based rates. Both the Illinois governor's letter and the Illinois attorney general's lawsuit assert that the energy component of the Ameren Illinois utilities' retail rates for electricity should not be based on their cost to procure energy and capacity in the wholesale market. We intervened in the Illinois attorney general’s lawsuit to seek a determination that the ICC is acting within its authority in the rate approval process. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from our electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren.

The Ameren Illinois utilities intend to file revised tariffs with the ICC by the end of 2005 that would modify their electric delivery service rates effective January 2, 2007. In March 2005 legislative hearings, Ameren indicated it expected that 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 market prices for power, which were based on 2005 prices at that time, the type of power supply product to be procured, future auction results, ratemaking outcomes and various other factors. Since that time, fuel prices have increased. As such, in September 2005, Ameren revised its estimate of the potential rate increase to 20% to 35%, with power prices representing around 70% of the increase. Actual results 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.

Based on the results of a cost of service study that will be submitted by UE by January 1, 2006 and the status of the environmental and fuel cost recovery rulemaking proceedings outlined below, UE will determine what course of action it believes should be taken in resetting electric rates for Missouri. The MoPSC staff and other stakeholders will also review the study and, based upon their analyses, may also make rate recommendations.

·	We expect continued economic growth in our service territory to benefit electric demand in 2005. However, higher prices for energy could result in reduced demand from consumers.

·	UE, Genco and CILCO are seeking to raise the equivalent availability and capacity factors of their power plants from 2004 levels through a process improvement program.

In 2005, we expect natural gas and coal prices to support power prices in excess of 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.

On April 1, 2005, the MISO Day Two Energy Market began operating. The Day Two market presents an opportunity for increased power sales from UE, Genco and CILCO power plants and improved access to power for UE, CIPS, CILCO and IP. The MISO Day Two Energy Market also presents the risk of significantly higher MISO-related costs. Due to the MISO Day Two Energy Market, we have incurred higher operating expenses. In part, these higher charges were due to volatile summer weather patterns and related loads. In addition, we attribute some of these higher charges to the relative infancy of the MISO Day Two Energy Market, suboptimal dispatching of power plants and price volatility. We will continue to fine tune our operations and work closely with MISO to insure that the MISO Day Two Energy Market operates more efficiently and effectively in the future.

Fuel and Purchased Power

In 2004, 86% of Ameren’s electric generation (UE-80%, Genco-93%, CILCO-99%) was supplied by its coal-fired power plants and approximately 85% of the coal used by these plants (UE-97%, Genco-66%, CILCO-26%) was delivered by railroads from the Powder River Basin (“PRB”) in Wyoming. In May 2005, the joint Burlington Northern-Union Pacific rail line in the PRB suffered two derailments due to unstable track conditions. As a result, the Federal Rail Administration placed slow orders, or speed restrictions, on sections of the line until the track could be made safe. In addition, large sections of track on a Union Pacific rail line were damaged by heavy rains near Topeka, Kansas in October 2005. These actions reduced deliveries of coal from PRB mines. Because of the railroad delivery problems, UE, Genco, and CILCO expect to receive about 80 to 90% of scheduled deliveries of PRB coal until track repairs are complete and the slow orders are removed. The railroads are projecting that maintenance of the joint rail line will be completed in December 2005 and normal deliveries should resume at that time. The tracks on the Union Pacific rail line near Topeka, Kansas have been temporarily repaired, but significant levels of congestion have resulted. Ameren, UE, Genco and CILCO believe they have sufficient coal inventories to reliably maintain generation through the maintenance period at the projected delivery levels. In order to reduce coal inventory shortage risk should other variations in deliveries occur, Ameren, UE, Genco and CILCO are implementing a coal management strategy. This strategy

includes reducing sales of power during low-margin periods and purchasing economically available coal in the spot market. Actual power plant performance, power market conditions, weather-induced demand for power, availability of alternative coal supplies and the actual time required for the railroads to resume normal deliveries of PRB coal could have a significant impact on the effectiveness of these strategie

Ameren’s coal and related transportation costs are expected to increase 3% to 5% in 2005, an additional 5% to 10% in 2006, and to increase again by 10% to 15% in 2007. Recent coal delivery disruptions could negatively impact these estimates. See Item 3 - Quantitative and Qualitative Disclosures about Market Risk for information about the percentage of coal and transportation requirements that are price-hedged for 2005 through 2009.

In July 2005, a new law was enacted that will enable the MoPSC to put in place fuel, purchased power and environmental cost recovery mechanisms for Missouri’s utilities. The legislation also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental recovery mechanism and prudency reviews, among other things. Detailed rules for these mechanisms are expected to be issued by the MoPSC in 2006.

Other Costs

UE’s Callaway nuclear plant is undergoing a refueling and maintenance outage that began in September 2005, and is expected to last 70 to 75 days. During this outage, major capital equipment will be replaced and upgraded providing an expected 60 megawatt increase in the generating capacity of the plant. As a result, the outage will last longer than a typical refueling and maintenance outage, which usually lasts 30 to 35 days and occurs approximately every 18 months. During an 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.

Capital Expenditures

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 whether market prices for power adjust as a result of this increased investment.

In June 2005, UE issued a request for proposal for the purchase of 500 to 800 megawatts of capacity and associated energy starting in 2006 through the acquisition of gas-fired, simple-cycle or combined-cycle electric generating resources currently operating in the MISO. UE is also evaluating its longer-term needs for new baseload and peaking electric generation capacity.

Affiliate Transactions

Due to the MoPSC order approving UE’s Illinois service territory transfer to CIPS or future regulatory proceedings, there could be changes to the agreement between UE and Genco to jointly dispatch electric generation or changes to the effect of that agreement on revenues and/or electric margins. Such changes could affect the pricing or availability of power transferred between Genco and UE. Based on operating performance for the past year, such changes would likely result in a transfer of electric margins from Genco to UE. The ultimate impact of any modifications to the joint dispatch agreement will be determined by future native load demand, the availability of electric generation from UE and Genco and market prices, among other things, but such impact could be material. Ameren’s earnings could be affected if electric rates for UE are adjusted by the MoPSC to reflect the provisions of the MoPSC order approving the service territory transfer and/or other changes to the joint dispatch agreement. See Note 3 - Rate and Regulatory Matters to our financial statements in Part 1, Item 1 of this report for a discussion of modifications to the joint dispatch agreement ordered by the MoPSC.

Recent Acquisitions

·	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.

Other

·	In August 2005, the president signed into law the Energy Policy Act of 2005. This legislation includes several provisions that impact the Ameren Companies, including,

among others, the repeal of the PUHCA effective in February 2006, under which Ameren is registered, and tax incentives for investments in pollution control equipment, electric transmission property, clean coal facilities and natural gas distribution lines. The Energy Policy Act of 2005 also extends the Price-Anderson nuclear plant liability provisions under the Atomic Energy Act of 1954.

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. If Ameren is unable to integrate its businesses effectively or to achieve the benefits anticipated, its results of operations, financial position, or 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 until its repeal becomes effective in February 2006. Decisions made by these regulators could have a material impact on our results of operations, financial position, or 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. 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. 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. The ICC conducted workshops seeking input from interested parties on the framework to be used for retail rate determination and for power procurement by customers after the current Illinois rate freeze and power supply contracts end in 2006. In February, 2005, CIPS, CILCO and IP made filings with the ICC outlining a proposed framework for a power procurement auction and a rate mechanism to pass generation costs through to customers, among other things. In September 2005, the Illinois attorney general and other parties filed a lawsuit against the ICC seeking a declaratory judgment that the ICC lacks authority to approve market-based rates for electric service that have not been “declared competitive” pursuant to Illinois law and seeking injunctive relief prohibiting ICC approval of the proposed power procurement auction. Additionally, the governor of Illinois sent a letter to the ICC expressing his opposition to the proposed auction process and his contention that the ICC lacks authority to approve such market-based rates. Both the Illinois governor's letter and the attorney general's lawsuit assert that the energy component of the Ameren Illinois utilities' retail rates for electricity should not be based on their cost to procure energy and capacity in the wholesale market. We have intervened in the attorney general’s lawsuit to seek a determination that the ICC is acting within its authority in the rate approval process. Any decision or action that impairs our ability to fully recover purchased power costs from our electric customers in a timely manner could result in material adverse consequences, including a significant drop in credit ratings potentially to below investment grade status, a loss of access to capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, reduced customer service, job losses and financial insolvency. See the Credit Ratings section in Liquidity and Capital Resources

above for a discussion of the credit rating changes recently issued in response to actions in Illinois.

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. 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 2, 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 currently have in either Missouri or Illinois a fuel adjustment clause for their electric operations that would allow them to recover from customers, the 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. See the Outlook section above for a discussion of Missouri legislation enabling a fuel adjustment clause.

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.

Principally because of rate reductions and rate moratoriums that affect certain Ameren Companies, increased costs and investments have resulted in decreased returns in Ameren’s distribution utility businesses. In 2005, Ameren began 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. 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, including phase-in plans, any and all of which could have a significant adverse affect on our results of operations, financial position, or liquidity.

Increased federal and state environmental regulation will 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. Although these new rules are being challenged in the courts, 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.

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 is fully complying 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 Energy Market.

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 its acquisition by Ameren. Ameren, UE, CIPS, CILCO and IP may be required to incur expenses or 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 fiscal year ended December 31, 2004.

The MISO Day Two Energy 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, the market has incurred significant price volatility and sub-optimal dispatching of power plants. In addition, the sale of power in this market-based environment has resulted in unanticipated transmission congestion, and other settlement charges.

Until we achieve some degree of operational experience participating in the MISO, including the MISO Day Two Energy 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, or 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. Based on our assumptions at December 31, 2004 and assuming continuation of the current federal interest rate relief beyond 2005, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2009 at which time we would expect a required contribution of approximately $300 million. However, in the meantime we may continue our practice of making voluntary contributions to maintain more prudent funded levels than minimally required. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in government regulations.

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;

·	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 September 30, 2005, Genco and CILCO, through AERG, owned 4,200 megawatts and 1,100 megawatts, respectively, of non-rate-regulated electric generating facilities. Of these non-rate-regulated electric generating facilities, approximately 3,500 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 and in filings made with the ICC in February 2005 by CIPS, CILCO and IP, 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 power supply contracts end in 2006. Genco and AERG, through Marketing Company, would probably participate in this auction, but with a proposed limit of 35% on the maximum amount of power that any single supplier 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 for a discussion of the pending ICC proceeding relating to the adoption of a power procurement auction process, including the lawsuit which has been filed by the Illinois attorney general and others against the adoption of such auction process and the Illinois governor’s letter to the ICC in opposition to it.

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 service territory to CIPS, certain terms of the joint dispatch agreement were ordered to be modified. Due to this MoPSC order or future regulatory proceedings, there could be changes to the joint dispatch agreement that would affect revenues and/or electric margins. Such changes could affect the pricing or availability of power transferred between Genco and UE. Based on operating performance for the past year, such changes would likely result in a transfer of electric margins from Genco to UE. The ultimate impact of any modifications to the joint dispatch agreement will be determined by future native load demand, the availability of electric generation from UE and Genco and market prices, among other things, but such impact could be material. Ameren’s earnings could be affected if electric rates for UE are adjusted by the MoPSC to reflect the provisions of the MoPSC order approving the service territory transfer and/or other changes to the joint dispatch agreement. See Note 3 - Rate and Regulatory Matters to our financial statements in Part 1, Item 1 of this report for a discussion of modifications to the joint dispatch agreement ordered by the MoPSC.

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 13% 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, or 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 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, or 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, we 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, or 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. See the Credit Ratings section in Liquidity and Capital Resources above for a discussion of the credit rating changes recently issued in response to the controversy in Illinois over the proposed future power procurement process.

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, commodity prices and equity security prices. 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 is comprised of senior-level Ameren officers.

Except as discussed below, there were no material changes from the disclosures in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2004. See the 2004 Form 10-K for a more detailed discussion of our market risks.

Interest Rate Risk

We are exposed to market risk through 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 September 30, 2005:


	Interest Expense			Net Income^(a)
Ameren	$	9		$	(6	)
UE		5			(3	)
CIPS		(b	)		(b	)
Genco		(b	)		(b	)
CILCORP		2			(1	)
CILCO		1			(1	)
IP		3			(2	)

(a)	Calculations are based on an effective tax rate of 36%.

(b)	Less than $1 million.

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 September 30, 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 power sales. At September 30, 2005, UE’s, Genco’s and Marketing Company’s combined credit exposure to non-investment-grade counterparties related to interchange sales was $83 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 Energy Market on April 1, 2005. At September 30, 2005, we estimate this credit exposure to be $4 million.

Equity Price Risk

Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. To the extent the value of plan assets declines, the effect could be reflected in net income and OCI, and the amount of cash required to be contributed to the plans.

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.

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	100%	100%	79%
Coal transportation^(a)	100	97	84
Nuclear fuel	100	64	25
Natural gas for generation	100	14	3
Natural gas for distribution^(b)	n/a	65	7
UE:
Coal	100%	100%	75%
Coal transportation^(a)	100	100	85
Nuclear fuel	100	64	25
Natural gas for generation	98	6	3
Natural gas for distribution^(b)	n/a	79	10
CIPS:
Natural gas for distribution^(b)	n/a	72%	13%
Genco:
Coal	100%	100%	91%
Coal transportation^(a)	100	98	71
Natural gas for generation	100	13	4
CILCORP:
Coal	100%	100%	76%
Coal transportation^(a)	100	72	64
Natural gas for distribution^(b)	n/a	67	11
CILCO:
Coal	100%	100%	76%
Coal transportation^(a)	100	72	64
Natural gas for distribution^(b)	n/a	67	11
IP:
Natural gas for distribution^(b)	n/a	57%	1%

(a)	Excludes rail fuel surcharges for period 2006-2009.

(b)

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 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	$	5		$	(3	)	$	3		$	(2	)
UE		3			(2	)		(b	)		(b	)
Genco		1			(1	)		1			(1	)
CILCORP		(b	)		(b	)		1			(1	)
CILCO		(b	)		(b	)		1			(1	)

(a)	Calculations are based on an effective tax rate of 36%.

(b)	Less than $1 million.

In the event of a significant increase 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. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three months and nine months ended September 30, 2005. The sources used to determine the fair value of these contracts were other external sources. All of these contracts have maturities of less than three years.


	Ameren^(a)			UE			CIPS			CILCORP			CILCO
Three Months Fair value of contracts at beginning of period, net	$	41		$	(7	)	$	12		$	30		$	30
Contracts realized or otherwise settled during the period		(4	)		(1	)		(1	)		(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		26			(10	)		10			30			30
Fair value of contracts outstanding at end of period, net	$	63		$	(18	)	$	21		$	59		$	59
Nine Months Fair value of contracts at beginning of period, net	$	21		$	(10	)	$	6		$	14		$	14
Contracts realized or otherwise settled during the period		(13	)		(1	)		(3	)		(2	)		(2	)
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		55			(7	)		18			47			47
Fair value of contracts outstanding at end of period, net	$	63		$	(18	)	$	21		$	59		$	59

(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 September 30, 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 and are effective in ensuring that information required to be disclosed in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

(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. In the fourth quarter of 2005, Ameren converted IP’s billing system to Ameren’s billing system. In that regard, certain aspects of IP’s accounting and financial reporting processes were modified to conform to the existing Ameren internal controls. Also in the fourth quarter, the Ameren Companies completed the implementation of a new fixed asset application system. Internal controls over financial reporting were modified to accommodate this new application system. The Ameren Companies expect this new system to enhance their internal controls over the fixed asset accounting process.

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.

The following table presents Ameren Corporation’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
July 1 - July 31, 2005	4,000	$55.04	-	-
August 1 - August 31, 2005	-	-	-	-
September 1 - September 30, 2005	1,000	56.03	-	-
Total	5,000	$55.24	-	-

(a)

These shares of Ameren common stock were purchased by Ameren in open-market transactions in satisfaction of Ameren’s obligations upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998. Ameren does not have any publicly announced equity securities repurchase plans or programs.

The following table presents CILCO’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
July 1 - July 31, 2005	11,000	$100.00	-	-
August 1 - August 31, 2005	-	-	-	-
September 1 - September 30, 2005	-	-	-	-
Total	11,000	$100.00	-	-

(a)	CILCO redeemed these shares of its 5.85% Class A preferred stock to satisfy the mandatory sinking fund redemption requirement for this series of preferred stock for 2005. CILCO 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 July 1 to September 30, 2005, period.

ITEM 5. OTHER INFORMATION.

The 2006 annual meeting of shareholders of Ameren, UE, CIPS, CILCO and IP will be held on May 2, 2006, rather than on April 25, 2006, as previously reported. Any shareholder proposal intended for inclusion in the proxy or information statement material for the 2006 annual shareholders meetings must be received by the secretary of the applicable company on or before November 15, 2005.

Effective August 28, 2005, Ameren’s board of directors amended Ameren’s Policy Regarding Nominations of Directors to require all directors standing for re-election to agree that in the event any director fails to obtain the required majority vote at an annual meeting of shareholders, such director shall tender his or her resignation as a director for consideration by Ameren’s Nominating and Corporate Governance Committee and recommendation to Ameren’s board. This policy, as amended, is applicable to Ameren, UE, CIPS, CILCO and IP and can be found in the Investors’ section of Ameren’s website at http://www.ameren.com.

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
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: November 9, 2005