Edgar Filing: AMEREN CORP

ameren10q09302008.htm

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, 2008

( ) 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
	(888) 789-2477

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 requirements for the past 90 days. Yes (X) No ( )

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.

	Large Accelerated Filer	Accelerated Filer	Non-Accelerated Filer	Smaller Reporting Company
Ameren Corporation	(X)	( )	( )	( )
Union Electric Company	( )	( )	(X)	( )
Central Illinois Public Service Company	( )	( )	(X)	( )
Ameren Energy Generating Company	( )	( )	(X)	( )
CILCORP Inc.	( )	( )	(X)	( )
Central Illinois Light Company	( )	( )	(X)	( )
Illinois Power Company	( )	( )	(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 October 31, 2008, was as follows:

Ameren Corporation	Common stock, $.01 par value per share - 211,452,854

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 Resources Company, LLC (parent company of the registrant and 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.

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...........................................................................................................................................................................................................	9
Consolidated Balance Sheet......................................................................................................................................................................................................................	10
Consolidated Statement of Cash Flows...................................................................................................................................................................................................	11
Union Electric Company
Consolidated Statement of Income...........................................................................................................................................................................................................	12
Consolidated Balance Sheet......................................................................................................................................................................................................................	13
Consolidated Statement of Cash Flows...................................................................................................................................................................................................	14
Central Illinois Public Service Company
Statement of Income...................................................................................................................................................................................................................................	15
Balance Sheet..............................................................................................................................................................................................................................................	16
Statement of Cash Flows...........................................................................................................................................................................................................................	17
Ameren Energy Generating Company
Consolidated Statement of Income..........................................................................................................................................................................................................	18
Consolidated Balance Sheet.....................................................................................................................................................................................................................	19
Consolidated Statement of Cash Flows..................................................................................................................................................................................................	20
CILCORP Inc.
Consolidated Statement of Income..........................................................................................................................................................................................................	21
Consolidated Balance Sheet.....................................................................................................................................................................................................................	22
Consolidated Statement of Cash Flows..................................................................................................................................................................................................	23
Central Illinois Light Company
Consolidated Statement of Income..........................................................................................................................................................................................................	24
Consolidated Balance Sheet.....................................................................................................................................................................................................................	25
Consolidated Statement of Cash Flows..................................................................................................................................................................................................	26
Illinois Power Company
Consolidated Statement of Income..........................................................................................................................................................................................................	27
Consolidated Balance Sheet.....................................................................................................................................................................................................................	28
Consolidated Statement of Cash Flows..................................................................................................................................................................................................	29

Combined Notes to Financial Statements....................................................................................................................................................................................................	30

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations............................................................................................................	65
Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................................................................................................................................................	94
Item 4 and
Item 4T. Controls and Procedures...............................................................................................................................................................................................................................	99

PART II Other Information

Item 1. Legal Proceedings...........................................................................................................................................................................................................................................	100
Item 1A. Risk Factors......................................................................................................................................................................................................................................................	100
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.................................................................................................................................................................	101
Item 6. Exhibits..............................................................................................................................................................................................................................................................	101

Signatures.........................................................................................................................................................................................................................................................................	104

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 we discuss their various business activities.

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

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

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

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

Ameren Illinois Utilities - CIPS, IP and the rate-regulated electric and gas utility operations of CILCO.

Ameren Services - Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.

ARO - Asset retirement obligations.

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 and natural gas transmission and distribution business and a non-rate-regulated electric generation business through AERG, 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 a non-rate-regulated subsidiary.

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.

CO2 - Carbon dioxide.

COLA - Combined construction and operating license application.

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

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

Development Company - Ameren Energy Development Company, which was an Ameren Energy Resources Company subsidiary, and parent of Genco, Marketing Company, AFS, and Medina Valley. It was eliminated in an internal reorganization in February 2008.

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

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

Dynegy - Dynegy Inc.

EEI - Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary that operates non-rate-regulated electric generation facilities and FERC-regulated transmission facilities in Illinois. Prior to February 29, 2008, EEI was 40% owned by UE and 40% owned by Development Company. On February 29, 2008, UE’s 40% ownership interest and Development Company’s 40% ownership interest were transferred to Resources Company. 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.

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.

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

FIN - FASB Interpretation. A FIN statement is an explanation intended to clarify accounting pronouncements previously issued by the FASB.

Fitch - Fitch Ratings, a credit rating agency.

Form 10-K - The combined Annual Report on Form 10-K for the year ended December 31, 2007, filed by the Ameren Companies with the SEC.

FSP - FASB staff position. A publication that provides application guidance on FASB literature.

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

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

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

Gigawatthour - One thousand megawatthours.

Heating degree-days - The summation of negative differences between the mean daily temperature and a 65- degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter space heating for residential and commercial customers.

ICC - Illinois Commerce Commission, a state agency that regulates Illinois utility businesses, including the rate-regulated operations of CIPS, CILCO and IP.

Illinois Customer Choice Law - Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which provided for electric utility restructuring and introduced competition into the retail supply of electric energy in Illinois.

Illinois electric settlement agreement - A comprehensive settlement of issues in Illinois arising out of the end of ten years of frozen electric rates, as of January 2, 2007. The Illinois electric settlement agreement, which became effective on August 28, 2007, was designed to avoid new rate rollback and freeze legislation and legislation that would impose a tax on electric generation in Illinois. The settlement addresses the issue of future power procurement, and it includes a comprehensive rate relief and customer assistance program.

Illinois EPA - Illinois Environmental Protection Agency, a state government agency.

Illinois Regulated - A financial reporting segment consisting of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO and IP.

IP - Illinois Power Company, an Ameren Corporation subsidiary. 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.

IP SPT - Illinois Power Special Purpose Trust, which was created as a subsidiary of IP LLC to issue TFNs as allowed under the Illinois Customer Choice Law.

IPA - Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and nonresidential customers beginning in June 2009.

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

Lehman - Lehman Brothers Holdings, Inc.

Marketing Company - Ameren Energy Marketing Company, a Resources Company subsidiary that markets power for Genco, AERG and EEI.

Medina Valley - AmerenEnergy Medina Valley Cogen L.L.C., a Resources Company subsidiary, which owns 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 uses market-based pricing, incorporating transmission congestion and line losses, to compensate market participants for power.

Missouri Regulated - A financial reporting segment consisting of UE’s rate-regulated businesses.

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 maintained for rate-regulated and non-rate-regulated business 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 Missouri utility businesses, including the rate-regulated operations of UE.

MW - Megawatt.

Native-load - Wholesale customers and end-use retail customers, whom we are obligated to serve by statute, franchise, contract, or other regulatory requirement.

Non-rate-regulated Generation - A financial reporting segment consisting of the operations or activities of Genco, CILCORP holding company, AERG, EEI, Medina Valley and Marketing Company.

NOx - 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.

Off-system revenues - Revenues from nonnative-load sales.

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

PUHCA 2005 - The Public Utility Holding Company Act of 2005, enacted as part of the Energy Policy Act of 2005, effective February 8, 2006.

Regulatory lag - Adjustments to retail electric and natural gas rates are based on historic cost levels and rate increase requests can take up to 11 months to be granted by the MoPSC and the ICC. As a result, revenue increases authorized by regulators will lag behind changing costs.

Resources Company - Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Genco, Marketing Company, EEI, AFS, and Medina Valley. It is the successor to Ameren Energy Resources Company, which was eliminated in an internal reorganization in February 2008.

RFP - Request for proposal.

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

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.

TFNs - Transitional Funding Trust Notes issued by IP SPT as allowed under the Illinois Customer Choice Law. IP designated a portion of cash received from customer billings to pay the TFNs. The designated funds received by IP were remitted to IP SPT. The designated funds were 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. Therefore, the obligation to IP SPT appears on IP’s

balance sheet as of December 31, 2007. In September 2008, IP redeemed the remaining amount of TFNs.

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 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” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:

·	regulatory or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of the pending UE rate proceeding or future legislative actions that seek to limit or reverse rate increases;

·	uncertainty as to the effect of implementation of the Illinois electric settlement agreement on Ameren, the Ameren Illinois Utilities, Genco and AERG, including implementation of a new power procurement process;

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

·	changes in laws or regulations that adversely affect the ability of electric distribution companies and other purchasers of wholesale electricity to pay their suppliers, including UE and Marketing Company;

·	enactment of legislation taxing electric generators, in Illinois or elsewhere;

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 occurred when the electric rate freeze and power supply contracts expired in Illinois at the end of 2006;

·	the effects of participation in the MISO;

the cost and availability of fuel such as coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power and natural gas for distribution; and the level and volatility of future market prices for such commodities, including the ability to recover the costs for such commodities;

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

·	prices for power in the Midwest, including forward prices;

·	business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products;

·	disruptions of the capital markets or other events that make the Ameren Companies’ access to necessary capital, including short-term credit, more difficult or costly;

·	our assessment of our liquidity;

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

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

·	weather conditions and other natural phenomena;

·	the impact of system outages caused by severe weather conditions or other events;

·	generation plant construction, installation and performance, including costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident and the plant’s future operation;

·	recoverability through insurance of costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident;

·	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, including those related to greenhouse gases, will be introduced over time, which could have a negative financial effect;

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

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

·	the cost and availability of transmission capacity for the energy generated by the Ameren Companies’ facilities or required to satisfy energy sales made by the Ameren Companies;

·	legal and administrative proceedings; and

·	acts of sabotage, war, terrorism or intentionally disruptive acts.

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 update or revise publicly any forward-looking statements to reflect new information or future events.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Operating Revenues:
Electric	$	1,928		$	1,872		$	4,944		$	4,855
Gas		132			125			987			895
Total operating revenues		2,060			1,997			5,931			5,750
Operating Expenses:
Fuel		461			338			963			864
Coal contract settlement		-			-			(60	)		-
Purchased power		371			419			964			1,106
Gas purchased for resale		73			68			697			622
Other operations and maintenance		449			417			1,340			1,230
Depreciation and amortization		180			176			534			534
Taxes other than income taxes		98			97			300			295
Total operating expenses		1,632			1,515			4,738			4,651
Operating Income		428			482			1,193			1,099
Other Income and Expenses:
Miscellaneous income		23			20			61			53
Miscellaneous expense		(10	)		(9	)		(23	)		(19	)
Total other income		13			11			38			34
Interest Charges		113			110			331			316
Income Before Income Taxes, Minority Interest
and Preferred Dividends of Subsidiaries		328			383			900			817
Income Taxes		113			130			319			279
Income Before Minority Interest and Preferred
Dividends of Subsidiaries		215			253			581			538
Minority Interest and Preferred Dividends of Subsidiaries		11			9			33			28
Net Income	$	204		$	244		$	548		$	510
Earnings per Common Share – Basic and Diluted	$	0.97		$	1.18		$	2.61		$	2.46
Dividends per Common Share	$	0.635		$	0.635		$	1.905		$	1.905
Average Common Shares Outstanding		210.3			207.6			209.5			207.1

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,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	206	$	355
Accounts receivable – trade (less allowance for doubtful
accounts of $24 and $22, respectively)		506		570
Unbilled revenue		262		359
Miscellaneous accounts and notes receivable		291		280
Materials and supplies		956		735
Other current assets		326		181
Total current assets		2,547		2,480
Property and Plant, Net		15,977		15,069
Investments and Other Assets:
Nuclear decommissioning trust fund		269		307
Goodwill		831		831
Intangible assets		167		198
Regulatory assets		1,122		1,158
Other assets		566		685
Total investments and other assets		2,955		3,179
TOTAL ASSETS	$	21,479	$	20,728

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	269	$	221
Short-term debt		1,407		1,472
Accounts and wages payable		509		687
Taxes accrued		128		84
Other current liabilities		605		438
Total current liabilities		2,918		2,902
Long-term Debt, Net		6,143		5,691
Preferred Stock of Subsidiary Subject to Mandatory Redemption		-		16
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,072		2,046
Accumulated deferred investment tax credits		102		109
Regulatory liabilities		1,291		1,240
Asset retirement obligations		583		562
Accrued pension and other postretirement benefits		741		839
Other deferred credits and liabilities		367		354
Total deferred credits and other liabilities		5,156		5,150
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption		195		195
Minority Interest in Consolidated Subsidiaries		24		22
Commitments and Contingencies (Notes 2, 8, 9 and 10)
Stockholders' Equity:
Common stock, $.01 par value, 400.0 shares authorized –
shares outstanding of 210.9 and 208.3, respectively		2		2
Other paid-in capital, principally premium on common stock		4,731		4,604
Retained earnings		2,259		2,110
Accumulated other comprehensive income		51		36
Total stockholders’ equity		7,043		6,752
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	21,479	$	20,728

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,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	548		$	510
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sales of emission allowances		(2	)		(7	)
Net mark-to-market gain on derivatives		(42	)		(7	)
Depreciation and amortization		549			557
Amortization of nuclear fuel		31			26
Amortization of debt issuance costs and premium/discounts		14			14
Deferred income taxes and investment tax credits, net		130			18
Minority interest		25			20
Other		(2	)		10
Changes in assets and liabilities:
Receivables		144			(220	)
Materials and supplies		(216	)		(110	)
Accounts and wages payable		(100	)		(113	)
Taxes accrued, net		44			75
Assets, other		46			58
Liabilities, other		142			151
Pension and other postretirement benefit obligations		2			67
Counterparty collateral asset		(2	)		(71	)
Counterparty collateral liability		2			-
Taum Sauk insurance receivable, net		(68	)		(58	)
Net cash provided by operating activities		1,245			920
Cash Flows From Investing Activities:
Capital expenditures		(1,316	)		(1,035	)
Nuclear fuel expenditures		(161	)		(39	)
Purchases of securities – nuclear decommissioning trust fund		(386	)		(110	)
Sales of securities – nuclear decommissioning trust fund		360			98
Purchases of emission allowances		(2	)		(12	)
Sales of emission allowances		2			5
Other		2			-
Net cash used in investing activities		(1,501	)		(1,093	)
Cash Flows From Financing Activities:
Dividends on common stock		(399	)		(395	)
Capital issuance costs		(9	)		(3	)
Short-term debt, net		(65	)		590
Dividends paid to minority interest holder		(23	)		(16	)
Redemptions, repurchases, and maturities:
Long-term debt		(823	)		(465	)
Preferred stock		(16	)		(1	)
Issuances:
Common stock		107			71
Long-term debt		1,335			425
Net cash provided by financing activities		107			206
Net change in cash and cash equivalents		(149	)		33
Cash and cash equivalents at beginning of year		355			137
Cash and cash equivalents at end of period	$	206		$	170

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 September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Operating Revenues:
Electric - excluding off-system	$	742		$	835		$	1,821		$	1,865
Electric - off-system		111			92			409			303
Gas		21			18			139			123
Other		1			-			1			1
Total operating revenues		875			945			2,370			2,292
Operating Expenses:
Fuel		238			179			489			447
Purchased power		45			71			135			140
Gas purchased for resale		11			9			84			73
Other operations and maintenance		234			218			689			667
Depreciation and amortization		83			81			246			252
Taxes other than income taxes		69			70			189			187
Total operating expenses		680			628			1,832			1,766
Operating Income		195			317			538			526
Other Income and Expenses:
Miscellaneous income		17			9			46			28
Miscellaneous expense		(2	)		(5	)		(6	)		(9	)
Total other income		15			4			40			19
Interest Charges		51			49			142			146
Income Before Income Taxes and Equity
in Income of Unconsolidated Investment		159			272			436			399
Income Taxes		60			93			160			132
Income Before Equity in Income
of Unconsolidated Investment		99			179			276			267
Equity in Income of Unconsolidated Investment, Net of Taxes		-			14			11			40
Net Income		99			193			287			307
Preferred Stock Dividends		1			1			4			4
Net Income Available to Common Stockholder	$	98		$	192		$	283		$	303

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,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	185
Accounts receivable – trade (less allowance for doubtful
accounts of $7 and $6, respectively)		193		191
Unbilled revenue		102		118
Miscellaneous accounts and notes receivable		228		213
Advances to money pool		-		15
Accounts receivable – affiliates		6		90
Materials and supplies		351		301
Other current assets		76		50
Total current assets		956		1,163
Property and Plant, Net		8,682		8,189
Investments and Other Assets:
Nuclear decommissioning trust fund		269		307
Intercompany note receivable – affiliate		30		-
Intangible assets		50		56
Regulatory assets		696		697
Other assets		354		491
Total investments and other assets		1,399		1,551
TOTAL ASSETS	$	11,037	$	10,903

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	4	$	152
Short-term debt		-		82
Intercompany note payable – Ameren		17		-
Accounts and wages payable		160		315
Accounts payable – affiliates		104		212
Taxes accrued		138		78
Accrued interest		75		47
Taum Sauk pumped-storage hydroelectric facility liability		28		103
Other current liabilities		79		59
Total current liabilities		605		1,048
Long-term Debt, Net		3,677		3,208
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,336		1,273
Accumulated deferred investment tax credits		81		85
Regulatory liabilities		903		865
Asset retirement obligations		495		476
Accrued pension and other postretirement benefits		229		297
Other deferred credits and liabilities		46		50
Total deferred credits and other liabilities		3,090		3,046
Commitments and Contingencies (Notes 2, 8, 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		1,119		1,119
Retained earnings		1,903		1,855
Accumulated other comprehensive income		19		3
Total stockholders' equity		3,665		3,601
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	11,037	$	10,903

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,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	287		$	307
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sales of emission allowances		(1	)		(5	)
Net mark-to-market gain on derivatives		(10	)		(1	)
Depreciation and amortization		246			252
Amortization of nuclear fuel		31			26
Amortization of debt issuance costs and premium/discounts		5			4
Deferred income taxes and investment tax credits, net		57			19
Other		(19	)		1
Changes in assets and liabilities:
Receivables		79			(82	)
Materials and supplies		(45	)		(49	)
Accounts and wages payable		(226	)		(97	)
Taxes accrued, net		57			140
Assets, other		97			61
Liabilities, other		55			(26	)
Pension and other postretirement benefit obligations		10			27
Taum Sauk insurance receivable, net		(68	)		(58	)
Net cash provided by operating activities		555			519
Cash Flows From Investing Activities:
Capital expenditures		(614	)		(493	)
Nuclear fuel expenditures		(161	)		(39	)
Changes in money pool advances		-			5
Proceeds from intercompany note receivable		6			-
Purchases of securities – nuclear decommissioning trust fund		(386	)		(110	)
Sales of securities – nuclear decommissioning trust fund		360			98
Sales of emission allowances		1			4
Net cash used in investing activities		(794	)		(535	)
Cash Flows From Financing Activities:
Dividends on common stock		(193	)		(246	)
Dividends on preferred stock		(4	)		(4	)
Capital issuance costs		(5	)		(3	)
Short-term debt, net		(82	)		(142	)
Intercompany note payable – Ameren, net		17			(20	)
Redemptions, repurchases, and maturities of long-term debt		(378	)		-
Issuances of long-term debt		699			425
Capital contribution from parent		-			5
Net cash provided by financing activities		54			15
Net change in cash and cash equivalents		(185	)		(1	)
Cash and cash equivalents at beginning of year		185			1
Cash and cash equivalents at end of period	$	-		$	-

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,
	2008		2007			2008			2007
Operating Revenues:
Electric	$	190	$	201		$	539		$	605
Gas		25		22			173			159
Other		2		1			2			3
Total operating revenues		217		224			714			767
Operating Expenses:
Purchased power		117		142			348			416
Gas purchased for resale		13		12			117			107
Other operations and maintenance		49		40			147			124
Depreciation and amortization		16		16			50			49
Taxes other than income taxes		8		6			27			24
Total operating expenses		203		216			689			720
Operating Income		14		8			25			47
Other Income and Expenses:
Miscellaneous income		3		5			9			13
Miscellaneous expense		-		(1	)		(2	)		(2	)
Total other income		3		4			7			11
Interest Charges		8		10			23			28
Income Before Income Taxes		9		2			9			30
Income Taxes		2		1			2			11
Net Income		7		1			7			19
Preferred Stock Dividends		1		1			2			2
Net Income Available to Common Stockholder	$	6	$	-		$	5		$	17

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,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	14	$	26
Accounts receivable – trade (less allowance for doubtful
accounts of $5 and $5, respectively)		64		62
Unbilled revenue		30		66
Miscellaneous accounts and notes receivable		19		19
Accounts receivable – affiliates		19		9
Current portion of intercompany note receivable – Genco		42		39
Current portion of intercompany tax receivable – Genco		9		9
Materials and supplies		91		66
Other current assets		32		16
Total current assets		320		312
Property and Plant, Net		1,194		1,174
Investments and Other Assets:
Intercompany note receivable – Genco		45		87
Intercompany tax receivable – Genco		97		105
Regulatory assets		92		113
Other assets		12		69
Total investments and other assets		246		374
TOTAL ASSETS	$	1,760	$	1,860

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	15	$	15
Short-term debt		96		125
Accounts and wages payable		39		44
Accounts payable – affiliates		19		19
Taxes accrued		11		8
Customer deposits		16		16
Mark-to-market derivative liability		9		1
Mark-to-market derivative liability with affiliate		10		-
Other current liabilities		39		30
Total current liabilities		254		258
Long-term Debt, Net		421		456
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net		260		269
Regulatory liabilities		238		265
Accrued pension and other postretirement benefits		37		67
Other deferred credits and liabilities		28		28
Total deferred credits and other liabilities		563		629
Commitments and Contingencies (Notes 2, 8, and 9)
Stockholders' Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding		-		-
Other paid-in capital		191		191
Preferred stock not subject to mandatory redemption		50		50
Retained earnings		281		276
Total stockholders' equity		522		517
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,760	$	1,860

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

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

	Nine Months Ended
	September 30,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	7		$	19
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		50			49
Amortization of debt issuance costs and premium/discounts		1			1
Deferred income taxes and investment tax credits, net		(2	)		(13	)
Changes in assets and liabilities:
Receivables		32			(36	)
Materials and supplies		(25	)		(7	)
Accounts and wages payable		(6	)		(27	)
Taxes accrued, net		3			(6	)
Assets, other		19			(8	)
Liabilities, other		-			34
Pension and other postretirement benefit obligations		1			5
Net cash provided by operating activities		80			11
Cash Flows From Investing Activities:
Capital expenditures		(65	)		(58	)
Proceeds from intercompany note receivable – Genco		39			37
Changes in money pool advances		-			(94	)
Net cash used in investing activities		(26	)		(115	)
Cash Flows From Financing Activities:
Dividends on preferred stock		(2	)		(2	)
Short-term debt, net		(29	)		100
Redemptions, repurchases, and maturities of long-term debt		(35	)		-
Capital contribution from parent		-			1
Net cash provided by (used in) financing activities		(66	)		99
Net change in cash and cash equivalents		(12	)		(5	)
Cash and cash equivalents at beginning of year		26			6
Cash and cash equivalents at end of period	$	14		$	1

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 September 30,					Nine Months Ended September 30,
	2008			2007		2008			2007

Operating Revenues	$	238		$	221	$	667		$	652
Operating Expenses:
Fuel		131			102		268			257
Coal contract settlement		-			-		(60	)		-
Purchased power		-			1		-			25
Other operations and maintenance		40			39		133			122
Depreciation and amortization		16			18		48			54
Taxes other than income taxes		5			5		16			15
Total operating expenses		192			165		405			473
Operating Income		46			56		262			177
Other Income and Expenses:
Miscellaneous income		-			-		1			-
Miscellaneous expense		(1	)		-		(1	)		-
Total other expenses		(1	)		-		-			-
Interest Charges		14			15		40			43
Income Before Income Taxes		31			41		222			136
Income Taxes		11			16		82			52
Net Income	$	20		$	25	$	140		$	84

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,
	2008			2007
ASSETS
Current Assets:
Cash and cash equivalents	$	2		$	2
Accounts receivable – affiliates		82			93
Miscellaneous accounts and notes receivable		8			12
Advances to money pool		13			-
Materials and supplies		122			93
Other current assets		6			4
Total current assets		233			204
Property and Plant, Net		1,830			1,683
Intangible Assets		45			63
Other Assets		8			18
TOTAL ASSETS	$	2,116		$	1,968

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Short-term debt	$	-		$	100
Current portion of intercompany note payable – CIPS		42			39
Borrowings from money pool		-			54
Accounts and wages payable		35			61
Accounts payable – affiliates		55			57
Current portion of intercompany tax payable – CIPS		9			9
Taxes accrued		13			15
Accrued interest		27			5
Deferred taxes – current		14			7
Other current liabilities		15			18
Total current liabilities		210			365
Long-term Debt, Net		774			474
Intercompany Note Payable – CIPS		45			87
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		157			161
Accumulated deferred investment tax credits		7			7
Intercompany tax payable – CIPS		97			105
Asset retirement obligations		48			47
Accrued pension and other postretirement benefits		31			32
Other deferred credits and liabilities		45			42
Total deferred credits and other liabilities		385			394
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholder's Equity:
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding		-			-
Other paid-in capital		503			503
Retained earnings		223			167
Accumulated other comprehensive loss		(24	)		(22	)
Total stockholder's equity		702			648
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	2,116		$	1,968

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,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	140		$	84
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sales of emission allowances		(1	)		(1	)
Net mark-to-market (gain) loss on derivatives		1			(1	)
Depreciation and amortization		68			79
Deferred income taxes and investment tax credits, net		14			28
Other		-			(1	)
Changes in assets and liabilities:
Receivables		15			(14	)
Materials and supplies		(29	)		(1	)
Accounts and wages payable		(18	)		(12	)
Taxes accrued, net		(5	)		(7	)
Assets, other		12			(11	)
Liabilities, other		11			5
Pension and other postretirement obligations		1			5
Net cash provided by operating activities		209			153
Cash Flows From Investing Activities:
Capital expenditures		(216	)		(131	)
Changes in money pool advances		(13	)		-
Purchases of emission allowances		(2	)		(7	)
Sales of emission allowances		1			1
Net cash used in investing activities		(230	)		(137	)
Cash Flows From Financing Activities:
Dividends on common stock		(84	)		(113	)
Debt issuance costs		(2	)		-
Short-term debt, net		(100	)		75
Changes in money pool borrowings		(54	)		(15	)
Intercompany note payable – CIPS		(39	)		(37	)
Issuances of long-term debt		300			-
Capital contribution from parent		-			75
Net cash provided by (used in) financing activities		21			(15	)
Net change in cash and cash equivalents		-			1
Cash and cash equivalents at beginning of year		2			1
Cash and cash equivalents at end of period	$	2		$	2

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 September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Operating Revenues:
Electric	$	227		$	175		$	584		$	520
Gas		37			36			257			231
Other		-			-			1			1
Total operating revenues		264			211			842			752
Operating Expenses:
Fuel		40			21			93			58
Purchased power		84			80			225			221
Gas purchased for resale		25			21			190			166
Other operations and maintenance		47			46			140			130
Depreciation and amortization		24			22			70			63
Taxes other than income taxes		4			3			18			17
Total operating expenses		224			193			736			655
Operating Income		40			18			106			97
Other Income and Expenses:
Miscellaneous income		1			2			2			4
Miscellaneous expense		(2	)		(1	)		(4	)		(3	)
Total other income (expenses)		(1	)		1			(2	)		1
Interest Charges		13			17			41			46
Income Before Income Taxes and Preferred
Dividends of Subsidiaries		26			2			63			52
Income Taxes		8			1			20			17
Income Before Preferred Dividends of Subsidiaries		18			1			43			35
Preferred Dividends of Subsidiaries		-			-			1			1
Net Income	$	18		$	1		$	42		$	34

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,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	6
Accounts receivable – trade (less allowance for doubtful
accounts of $2 and $2, respectively)		43		52
Unbilled revenue		26		54
Accounts receivable – affiliates		88		47
Advances to money pool		2		1
Note receivable – affiliates		1		1
Materials and supplies		156		110
Income tax receivable		-		16
Other current assets		34		24
Total current assets		350		311
Property and Plant, Net		1,639		1,494
Investments and Other Assets:
Goodwill		542		542
Intangible assets		36		41
Regulatory assets		39		32
Other assets		21		39
Total investments and other assets		638		654
TOTAL ASSETS	$	2,627	$	2,459

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Short-term debt	$	432	$	520
Borrowings from money pool, net		171		-
Intercompany note payable – Ameren		63		2
Accounts and wages payable		68		75
Accounts payable – affiliates		38		34
Taxes accrued		5		3
Other current liabilities		79		54
Total current liabilities		856		688
Long-term Debt, Net		513		537
Preferred Stock of Subsidiary Subject to Mandatory Redemption		-		16
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		203		193
Accumulated deferred investment tax credits		5		6
Regulatory liabilities		86		92
Accrued pension and other postretirement benefits		112		127
Other deferred credits and liabilities		74		66
Total deferred credits and other liabilities		480		484
Preferred Stock of Subsidiary Not Subject to Mandatory Redemption		19		19
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholder's Equity:
Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding		-		-
Other paid-in capital		627		627
Retained earnings		100		58
Accumulated other comprehensive income		32		30
Total stockholder's equity		759		715
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	2,627	$	2,459

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,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	42		$	34
Adjustments to reconcile net income to net cash
provided by operating activities:
Net mark-to-market loss on derivatives		3			-
Depreciation and amortization		71			65
Amortization of debt issuance costs and premium/discounts		-			1
Deferred income taxes and investment tax credits		30			2
Changes in assets and liabilities:
Receivables		(3	)		(38	)
Materials and supplies		(46	)		(18	)
Accounts and wages payable		16			(29	)
Taxes accrued, net		11			(3	)
Assets, other		(14	)		(16	)
Liabilities, other		6			22
Pension and postretirement benefit obligations		(9	)		-
Net cash provided by operating activities		107			20
Cash Flows From Investing Activities:
Capital expenditures		(223	)		(183	)
Changes in money pool advances		(1	)		42
Other		2			-
Net cash used in investing activities		(222	)		(141	)
Cash Flows From Financing Activities:
Short-term debt, net		(88	)		325
Changes in money pool borrowings		171			-
Intercompany note payable – Ameren, net		61			(73	)
Redemptions, repurchases, and maturities of:
Long-term debt		(19	)		(50	)
Preferred stock		(16	)		(1	)
Net cash provided by financing activities		109			201
Net change in cash and cash equivalents		(6	)		80
Cash and cash equivalents at beginning of year		6			4
Cash and cash equivalents at end of period	$	-		$	84

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 September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Operating Revenues:
Electric	$	227		$	175		$	584		$	520
Gas		37			36			257			231
Other		-			-			1			1
Total operating revenues		264			211			842			752
Operating Expenses:
Fuel		39			18			89			52
Purchased power		84			80			225			221
Gas purchased for resale		25			21			190			166
Other operations and maintenance		48			46			145			133
Depreciation and amortization		21			18			62			54
Taxes other than income taxes		4			4			18			17
Total operating expenses		221			187			729			643
Operating Income		43			24			113			109
Other Income and Expenses:
Miscellaneous income		1			2			2			4
Miscellaneous expense		(2	)		(1	)		(3	)		(3	)
Total other income (expenses)		(1	)		1			(1	)		1
Interest Charges		5			8			16			19
Income Before Income Taxes		37			17			96			91
Income Taxes		13			7			34			33
Net Income		24			10			62			58
Preferred Stock Dividends		-			-			1			1
Net Income Available To Common Stockholder	$	24		$	10		$	61		$	57

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
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	6
Accounts receivable – trade (less allowance for doubtful
accounts of $2 and $2, respectively)		43		52
Unbilled revenue		26		54
Accounts receivable – affiliates		86		45
Materials and supplies		156		110
Other current assets		34		27
Total current assets		345		294
Property and Plant, Net		1,638		1,492
Investments and Other Assets:
Intangible assets		1		1
Regulatory assets		39		32
Other assets		25		43
Total investments and other assets		65		76
TOTAL ASSETS	$	2,048	$	1,862

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Short-term debt	$	305	$	345
Borrowings from money pool		171		-
Accounts and wages payable		68		75
Accounts payable – affiliates		37		34
Taxes accrued		10		3
Other current liabilities		62		45
Total current liabilities		653		502
Long-term Debt, Net		129		148
Preferred Stock Subject to Mandatory Redemption		-		16
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		176		155
Accumulated deferred investment tax credits		5		6
Regulatory liabilities		212		220
Accrued pension and other postretirement benefits		112		127
Other deferred credits and liabilities		74		66
Total deferred credits and other liabilities		579		574
Commitments and Contingencies (Notes 2, 8 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		429		429
Retained earnings		233		172
Accumulated other comprehensive income		6		2
Total stockholders' equity		687		622
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	2,048	$	1,862

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,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	62		$	58
Adjustments to reconcile net income to net cash
provided by operating activities:
Net mark-to-market loss on derivatives		3			-
Depreciation and amortization		62			55
Amortization of debt issuance costs and premium/discounts		-			1
Deferred income taxes and investment tax credits, net		30			4
Changes in assets and liabilities:
Receivables		(3	)		(32	)
Materials and supplies		(46	)		(18	)
Accounts and wages payable		15			(17	)
Taxes accrued, net		14			(3	)
Assets, other		(16	)		(21	)
Liabilities, other		(2	)		16
Pension and postretirement benefit obligations		1			5
Net cash provided by operating activities		120			48
Cash Flows From Investing Activities:
Capital expenditures		(223	)		(183	)
Changes in money pool advances		-			42
Other		2			-
Net cash used in investing activities		(221	)		(141	)
Cash Flows From Financing Activities:
Dividends on preferred stock		(1	)		(1	)
Short-term debt, net		(40	)		200
Changes in money pool borrowings		171			-
Redemptions, repurchases, and maturities of:
Long-term debt		(19	)		(50	)
Preferred stock		(16	)		(1	)
Capital contribution from parent		-			14
Net cash provided by financing activities		95			162
Net change in cash and cash equivalents		(6	)		69
Cash and cash equivalents at beginning of year		6			3
Cash and cash equivalents at end of period	$	-		$	72

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)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Operating Revenues:
Electric	$	303		$	307		$	799		$	859
Gas		49			49			414			375
Other		1			-			3			2
Total operating revenues		353			356			1,216			1,236
Operating Expenses:
Purchased power		185			211			499			573
Gas purchased for resale		22			26			298			267
Other operations and maintenance		74			69			217			182
Depreciation and amortization		26			25			77			75
Amortization of regulatory assets		5			4			13			12
Taxes other than income taxes		12			13			48			50
Total operating expenses		324			348			1,152			1,159
Operating Income		29			8			64			77
Other Income and Expenses:
Miscellaneous income		3			4			9			9
Miscellaneous expense		(2	)		(2	)		(5	)		(3	)
Total other income		1			2			4			6
Interest Charges		22			19			72			55
Income (Loss) Before Income Taxes (Benefit)		8			(9	)		(4	)		28
Income Taxes (Benefit)		3			(5	)		(2	)		10
Net Income (Loss)		5			(4	)		(2	)		18
Preferred Stock Dividends		1			1			2			2
Net Income (Loss) Available to Common Stockholder	$	4		$	(5	)	$	(4	)	$	16

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,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	12	$	6
Accounts receivable - trade (less allowance for doubtful
accounts of $9 and $9, respectively)		122		137
Unbilled revenue		59		118
Accounts receivable – affiliates		39		17
Advances to money pool		9		-
Materials and supplies		202		134
Other current assets		74		38
Total current assets		517		450
Property and Plant, Net		2,285		2,220
Investments and Other Assets:
Investment in IP SPT		11		10
Goodwill		214		214
Regulatory assets		305		316
Other assets		46		109
Total investments and other assets		576		649
TOTAL ASSETS	$	3,378	$	3,319

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	251	$	-
Current maturities of long-term debt payable to IP SPT		-		54
Short-term debt		304		175
Accounts and wages payable		96		85
Accounts payable – affiliates		38		36
Taxes accrued		10		7
Customer deposits		49		40
Other current liabilities		109		40
Total current liabilities		857		437
Long-term Debt, Net		757		1,014
Long-term Debt to IP SPT		-		2
Deferred Credits and Other Liabilities:
Regulatory liabilities		86		129
Accrued pension and other postretirement benefits		185		189
Accumulated deferred income taxes		137		148
Other deferred credits and liabilities		98		92
Total deferred credits and other liabilities		506		558
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholders' Equity:
Common stock, no par value, 100.0 shares authorized – 23.0 shares outstanding		-		-
Other paid-in-capital		1,194		1,194
Preferred stock not subject to mandatory redemption		46		46
Retained earnings		14		64
Accumulated other comprehensive income		4		4
Total stockholders' equity		1,258		1,308
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,378	$	3,319

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)

	Nine Months Ended
	September 30,
	2008			2007
Cash Flows From Operating Activities:
Net income (loss)	$	(2	)	$	18
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization		83			78
Amortization of debt issuance costs and premium/discounts		7			6
Deferred income taxes		23			8
Other		-			(1	)
Changes in assets and liabilities:
Receivables		52			(50	)
Materials and supplies		(68	)		(34	)
Accounts and wages payable		13			(45	)
Taxes accrued, net		5			-
Assets, other		(14	)		(16	)
Liabilities, other		31			54
Pension and other postretirement benefit obligations		(10	)		5
Net cash provided by operating activities		120			23
Cash Flows From Investing Activities:
Capital expenditures		(128	)		(132	)
Changes in money pool advances		(9	)		-
Other		(2	)		(1	)
Net cash used in investing activities		(139	)		(133	)
Cash Flows From Financing Activities:
Dividends on common stock		(45	)		-
Dividends on preferred stock		(2	)		(2	)
Capital issuance costs		(2	)		-
Short-term debt, net		129			125
Changes in money pool borrowings, net		-			52
Redemptions, repurchases and maturities of long-term debt		(337	)		-
Issuance of long-term debt		336			-
IP SPT maturities		(54	)		(65	)
Net cash provided by financing activities		25			110
Net change in cash and cash equivalents		6			-
Cash and cash equivalents at beginning of year		6			-
Cash and cash equivalents at end of period	$	12		$	-

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, 2008

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These 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 depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.

·	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.

·	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.

CILCO, or Central Illinois Light Company, also known as AmerenCILCO, is a subsidiary of CILCORP (a holding company). It operates a rate-regulated electric transmission and distribution business, a non-rate-regulated electric generation business (through its subsidiary, AERG) 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 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, which until February 29, 2008, was held 40% by UE and 40% by Development Company. Ameren consolidates EEI for financial reporting purposes, while UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren. See Note 8 - Related Party Transactions for additional information.

The following table presents summarized financial information of EEI for the three months and nine months ended September 30, 2008 and 2007.

	Three Months				Nine Months
	2008		2007		2008		2007
Operating revenues	$	183	$	117	$	430	$	324
Operating income		64		53		196		158
Net income		41		34		123		99

The financial statements of Ameren, Genco, CILCORP and CILCO are prepared on a consolidated basis. CIPS has no subsidiaries and therefore is not consolidated. UE had a subsidiary in 2007 (Union Electric Development Corporation), but in January 2008 this subsidiary was transferred to Ameren in the form of a stock dividend and in March 2008 was merged into an Ameren nonregistrant subsidiary. Accordingly, UE’s financial statements were prepared on a consolidated basis for 2007 only. IP had a subsidiary in 2007 (Illinois Gas Supply Company) that was dissolved on December 31, 2007. Accordingly, IP’s financial statements were prepared on a consolidated basis for 2007 only.

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 that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10K.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three

months and nine months ended September 30, 2008 and 2007. The number of stock options, restricted stock shares, and performance share units outstanding was immaterial.

Long-term Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation Plan

A summary of nonvested shares as of September 30, 2008, under the Long-term Incentive Plan of 1998, as amended, and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

	Performance Share Units		Restricted Shares
	Shares	Weighted-average Fair Value Per Unit	Shares	Weighted-average Fair Value Per Share
Nonvested at January 1, 2008	669,403	$ 57.88	316,768	$ 46.23
Granted(a)	495,847	47.57	-	-
Dividends	-	-	9,319	41.51
Forfeitures	(7,747)	54.39	(2,163)	48.19
Vested(b)	(236,811)	53.50	(114,286)	44.05
Nonvested at September 30, 2008	920,692	$ 53.48	209,638	$ 47.46

(a)	Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in February 2008 under the 2006 Plan.

(b)	Share units vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.

The fair value of each share unit awarded in February 2008 under the 2006 Plan was determined to be $47.57 based on Ameren’s closing common share price of $44.30 per share at the grant date and lattice simulations used to estimate expected share payout based on Ameren’s attainment of certain financial measures relative to the designated peer group. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 2.264%, dividend yields of 2.3% to 5.4% for the peer group, volatility of 14.43% to 21.51% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend over the performance period.

Ameren recorded compensation expense of $7 million and $4 million for the quarters ended September 30, 2008 and 2007, respectively, and a related tax benefit of $3 million and $2 million for the quarters ended September 30, 2008 and 2007, respectively. Ameren recorded compensation expense of $21 million and $13 million for each of the nine-month periods ended September 30, 2008 and 2007, respectively, and a related tax benefit of $8 million and $5 million for the nine-month periods ended September 30, 2008 and 2007, respectively. As of September 30, 2008, total compensation cost of $21 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 22 months.

Accounting Changes and Other Matters

SFAS No. 157, Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and expands required disclosures about fair value measurements. See Note 7 - Fair Value Measurements for additional information on our adoption of SFAS No. 157 in the first quarter of 2008.

FSP 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active

In October 2008, the FASB issued FSP 157-3, which clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP 157-3 was effective upon issuance, and applied, retroactively to periods for which financial statements had not yet been issued. We considered FSP 157-3 in our determination of estimated fair values as of September 30, 2008, and it did not have a material impact on our results of operations, financial condition, or liquidity.

SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities - an amendment of SFAS No. 133

In March 2008, the FASB issued SFAS No. 161, which requires enhanced disclosures for derivative instruments and for hedging activities. SFAS No. 161 is intended to enable investors to better understand the effects of derivative instruments and hedging activities on an entity’s financial position, financial performance and cash flows. SFAS No. 161 will be effective in the first quarter of 2009. The adoption of SFAS No. 161 will not have a material impact on our results of operations, financial position or liquidity since it only provides enhanced disclosure requirements.

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. We evaluate goodwill for impairment in the fourth quarter of each year, or more frequently if events and circumstances indicate that the carrying amount might be impaired. Ameren’s and IP’s goodwill relates to the acquisitions of IP and an additional 20% ownership interest in EEI in 2004, and Ameren’s and CILCORP’s goodwill relates to the acquisitions of CILCORP and Medina Valley in 2003. For the period from January 1, 2008 to September 30, 2008, there were no changes in the carrying amount of goodwill.

Intangible Assets. We evaluate intangible assets for impairment if events and circumstances indicate that their carrying amount might be impaired. See also Note 9 - Commitments and Contingencies. Ameren’s, UE’s, Genco’s, CILCORP’s and CILCO’s intangible assets consisted of emission allowances at September 30, 2008.

The following table presents the SO2 and NOx emission allowances held and the related aggregate SO2 and NOx emission allowance book values that were carried as intangible assets as of September 30, 2008. Emission allowances consist of various individual emission allowance certificates and do not have expiration dates. Emission allowances are charged to fuel expense as they are used in operations.

	SO2 (a)	NOx (b)	Book Value(c)
Ameren(d)	3.067	15,834	$ 167(e)
UE	1.678	5,610	50
Genco	0.723	8,928	45
CILCORP(f)	0.342	135	36
CILCO (AERG)	0.342	135	1
EEI	0.324	1,161	9

(a)	Vintages are from 2008 to 2018. Each company possesses additional allowances for use in periods beyond 2018. Units are in millions of SO2 allowances (currently one allowance equals one ton emitted).

(b)	Vintage is 2008. Units are in NOx allowances (one allowance equals one ton emitted).

(c)	The book value represents SO2 and NOx emission allowances for use in periods through 2031.

(d)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

(e)	Includes $27 million assigned to EEI allowances as a result of purchase accounting.

(f)	Includes fair market value adjustments recorded in connection with Ameren’s acquisition of CILCORP.

The following table presents the amortization expense based on usage of emission allowances, net of gains from emission allowance sales, for Ameren, UE, Genco, and CILCORP during the three months and nine months ended September 30, 2008 and 2007.

	Three Months					Nine Months
	2008		2007			2008			2007
Ameren(a)	$	9	$	7		$	25		$	27
UE		-		(5	)		(1	)		(5	)
Genco		7		8			20			23
CILCORP(b)		2		3			5			6

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

(b)	Includes allowances consumed that were recorded through purchase accounting.

Excise Taxes

Excise taxes imposed on us are reflected on Missouri electric, Missouri gas, and Illinois gas customer bills. They are recorded gross in Operating Revenues and Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. 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, 2008 and 2007:

	Three Months				Nine Months
	2008		2007		2008		2007
Ameren	$	43	$	46	$	130	$	128
UE		36		38		88		88
CIPS		2		2		11		11
CILCORP		1		2		8		8
CILCO		1		2		8		8
IP		4		4		23		21

Coal Contract Settlement

In June 2008, Genco entered into an agreement with a coal mine owner that provided Genco a lump-sum payment of $60 million in July 2008, due to the coal mine owner’s premature closing of a mine and the early termination of a

coal supply contract. The settlement agreement compensates Genco, in total, for higher fuel costs it expects to incur in 2008 and 2009 as a result of the mine closure and contract termination.

Uncertain Tax Positions

The amount of unrecognized tax benefits as of September 30, 2008, was $115 million, $19 million, less than $1 million, $43 million, $21 million, $21 million and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. The total unrecognized tax benefits (detriments) that would impact the effective tax rate, if recognized, for each of the respective companies was as follows: Ameren - $23 million, UE - $3 million, CIPS - none, Genco - ($1 million), CILCORP - less than $1 million, CILCO - less than $1 million, and IP - none.

Ameren is currently under federal income tax examination for years 2005, 2006 and 2007. State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states.

It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits to increase or decrease; however, the Ameren Companies do not believe such increases or decreases would be material to their financial condition or results of operations.

Asset Retirement Obligations

AROs at Ameren and UE increased compared to December 31, 2007, to reflect the accretion of obligations to their fair values.

NOTE 2 - RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

Electric

UE filed a request with the MoPSC in April 2008 to increase its annual revenues for electric service by $251 million. The electric rate increase request proposes an average increase in electric rates of 12.1% and is based on a 10.9% return on equity, a capital structure composed of 51% common equity, a rate base of $5.9 billion and a test year ended March 31, 2008, with updates for known and measurable changes through September 30, 2008. In the filing, UE also requested that the MoPSC approve implementation of a fuel and purchased power cost recovery mechanism.

In August 2008, the MoPSC staff filed a report and direct testimony with the MoPSC recommending an increase in annual revenues for electric service for UE of $51 million based on a 9.5% return on equity. The MoPSC staff opposed UE’s request to implement a fuel and purchased power cost recovery mechanism. The Office of Public Counsel and intervenors also filed testimony with the MoPSC in August 2008 opposing certain aspects of UE’s April 2008 request.

In October 2008, UE filed rebuttal testimony with the MoPSC requesting approval of a mechanism that would permit timely cost recovery of vegetation management and infrastructure inspection and repair costs.

The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, and a decision by the MoPSC in such proceeding is required by March 2009. UE cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, whether the fuel and purchased power cost recovery mechanism and the vegetation management and infrastructure inspection and repair cost recovery mechanism will be approved, or whether any rate increase that may eventually be approved will be sufficient for UE to recover its costs and earn a reasonable return on its investments when the increase goes into effect.

January 2007 Ice Storm Cost Recovery

UE submitted a filing to the MoPSC in November 2007 requesting that operations and maintenance expenses UE incurred as a result of a severe ice storm in January 2007 be deferred as a regulatory asset and, if approved, be amortized over five years beginning with the effective date of electric rates approved in UE’s next rate proceeding. UE incurred $25 million of operations and maintenance expenses in the first quarter of 2007 as a result of the January storm. On April 30, 2008, the MoPSC issued an accounting order that gave UE the ability to seek direct recovery of, and record as a regulatory asset, all or a portion of these storm costs. The appropriate amount to be amortized and the start date of the amortization will be decided in UE’s rate case filed in April 2008. UE recorded a regulatory asset of $13 million in the second quarter of 2008, representing the minimum amount of its storm costs that it expects to recover as a result of this order.

Illinois

Electric and Natural Gas Delivery Service Rate Cases

On September 24, 2008, the ICC issued a consolidated order approving a net increase in annual revenues for electric delivery service of $123 million in the aggregate (CIPS - $22 million increase, CILCO - $3 million decrease, and IP - $104 million increase) and a net increase in annual revenues for natural gas delivery service of $38 million in the aggregate (CIPS - $7 million increase, CILCO - $9 million decrease, and IP - $40 million increase), based on a 10.65% return on equity with respect to electric delivery service and 10.68% return on equity with respect to natural gas delivery service. These rate changes were effective on October 1, 2008. Because of the Ameren Illinois Utilities’ pledge to keep the overall residential electric bill increase resulting from these rate changes to less than 10% for each utility, IP will not recover approximately $10 million in revenue in the first year electric delivery service rates are in effect. Thereafter, residential electric delivery service rates will be adjusted to recover the full increase.

In addition, the ICC changed the depreciable lives used in calculating depreciation expense for the Ameren Illinois Utilities’ electric and natural gas rates. As a result, annual depreciation expense for the Ameren Illinois Utilities will be reduced for financial reporting purposes by a net $13 million in the aggregate (CIPS - $4 million reduction, CILCO - $26 million reduction, and IP - $17 million increase).

The ICC rejected the Ameren Illinois Utilities’ requested rate adjustment mechanisms for electric infrastructure investments. As an alternative to the Ameren Illinois Utilities’ requested decoupling of natural gas revenues from sales volumes, the ICC order approved an increase in the percentage of costs to be recovered through fixed non-volumetric residential and commercial customer charges to 80% from 53%. The ICC also approved an increase in the Supply Cost Adjustment (SCA) factors for the Ameren Illinois Utilities. The SCA is a charge applied only to the bills of customers who take their power supply from the Ameren Illinois Utilities. The change in the SCA factors is expected to result in increased electric revenues of $9.5 million per year in the aggregate (CIPS - $2.6 million, CILCO - $1.6 million, and IP - $5.3 million), covering the increased cost of administering the Ameren Illinois Utilities’ power supply responsibilities.

In October 2008, CIPS, CILCO and IP requested that the ICC rehear its September 2008 consolidated order with respect to its ruling regarding the treatment and level of short-term debt balances in the capital structure. The Ameren Illinois Utilities assert that there is no competent evidence in the record to support the staff position as adopted by the ICC. Also in October 2008, other parties to these rate cases also filed for rehearing of certain aspects of the ICC order. The Ameren Illinois Utilities cannot predict the outcome of such requests for rehearing or, in the event the requests are denied by the ICC, whether court appeals will be filed.

Illinois Electric Settlement Agreement

In 2007, an agreement was reached among key stakeholders in Illinois to avoid rate rollback and freeze legislation and legislation that would impose a tax on electric generation and to address the increase in electric rates and the future power procurement process in Illinois. The terms of the agreement include a comprehensive rate relief and customer assistance program. The Illinois electric settlement agreement provides approximately $1 billion of funding for rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Pursuant to the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and CILCO (AERG) agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco, and $28 million from CILCO (AERG). See Note 9 - Commitments and Contingencies for information on the remaining contributions to be made as of September 30, 2008.

The Ameren Illinois Utilities, Genco and CILCO (AERG) recognize in their financial statements the costs of their respective rate relief contributions and program funding in a manner corresponding with the timing of the funding. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the quarter ended September 30, 2008, of $10 million, $2 million, less than $1 million, $2 million, $4 million, and $2 million, respectively (quarter ended September 30, 2007 - $59 million, $8 million, $5 million, $11 million, $24 million, and $11 million, respectively) and during the nine months ended September 30, 2008, of $32 million, $5 million, $2 million, $6 million, $13 million, and $6 million, respectively (nine months ended September 30, 2007 - $59 million, $8 million, $5 million, $11 million, $24 million, and $11 million, respectively) under the terms of the Illinois electric settlement agreement.

Other electric generators and utilities in Illinois agreed to contribute $851 million to the comprehensive rate relief and customer assistance program. Contributions by the other electric generators (the Generators) and utilities to the comprehensive program are subject to funding agreements. Under these agreements, at the end of each month, the Ameren Illinois Utilities send a bill, due in 30 days, to the Generators and utilities for their proportionate share of that month’s rate relief and assistance. If any escrow funds have been provided by the Generators, these funds will be drawn prior to seeking reimbursement from the Generators. At September 30, 2008, Ameren, CIPS, CILCO (Illinois

Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $15 million, $5 million, $3 million, and $7 million, respectively.

Power Procurement Plan

In September 2008, the IPA, which was established as a part of the Illinois electric settlement agreement, filed an electric power procurement plan with the ICC for both the Ameren Illinois Utilities and Commonwealth Edison Company (Commonwealth Edison), the Illinois electric utility subsidiary of Exelon Corporation. The plan, which requires the approval of the ICC, outlines the wholesale products (capacity, energy swaps and renewable energy credits) that the IPA will procure on behalf of the Ameren Illinois Utilities for the period of June 1, 2009 through May 30, 2014. The products will be procured through a RFP process, which is expected to begin in February 2009, if the plan is approved. A decision is required by the ICC no later than January 2009.

Redesigned Rates

In late 2007, the ICC issued an order, as amended, authorizing redesigned electric rates for CIPS, CILCO and IP that was implemented January 1, 2008. These rates were designed to allow utilities to recover their full costs while reducing seasonal fluctuations for residential customers who use large amounts of electricity. While 2008 quarterly results of operations and cash flows will be impacted, the redesigned rates are not expected to have any impact on annual margins.

Natural Gas Energy Efficiency Plan

In February 2008, the Ameren Illinois Utilities filed a consolidated natural gas energy efficiency plan with the ICC. In October 2008, the ICC issued an order approving the Ameren Illinois Utilities’ natural gas energy efficiency plan as well as the cost recovery mechanism by which the program costs will be recovered. The natural gas energy efficiency plan includes annual reduction targets in natural gas usage as well as spending limits for the 2009, 2010, and 2011 program years of $2 million, $4 million and $6 million, respectively.

ICC Reliability Audit

In August 2007, the ICC retained Liberty Consulting Group to investigate, analyze, and report to the ICC on the Ameren Illinois Utilities’ transmission and distribution systems and reliability following the July 2006 wind storms and a November 2006 ice storm. On October 8, 2008, Liberty Consulting Group presented the ICC with a final report containing recommendations for the Ameren Illinois Utilities to improve their systems and response to emergencies. The ICC approved the report and directed the Ameren Illinois Utilities to prepare and present to the ICC an implementation plan addressing Liberty Consulting Group’s recommendations. The implementation plan was submitted to the ICC on November 8, 2008. Liberty Consulting Group will monitor the Ameren Illinois Utilities’ efforts to implement the recommendations and any initiatives that the Ameren Illinois Utilities undertake. At this time, we are unable to determine the impact such implementation will have on our results of operations, financial position, or liquidity.

Federal

Regional Transmission Organization

As required by the MoPSC, UE filed a study in November 2007 with the MoPSC evaluating the costs and benefits of UE’s participation in MISO. UE’s filing noted that there were a number of uncertainties associated with the cost-benefit study, including issues associated with the UE-MISO service agreement. The service agreement’s primary function was to ensure that the MoPSC continued to set the transmission component of UE’s rates to serve its bundled retail load. In June 2008, a stipulation and agreement among UE, the MoPSC staff, MISO and other parties to the proceeding was filed with the MoPSC, which provides for UE’s continued, conditional MISO participation through April 30, 2012. The stipulation and agreement provides UE the right to seek permission from the MoPSC for early withdrawal from MISO if UE determines that sufficient progress toward mitigating some of the continuing uncertainties respecting its MISO participation is not being made. The MoPSC issued an order, effective September 19, 2008, approving the stipulation and agreement.

FERC Order - MISO Charges

In May 2007, UE, CIPS, CILCO and IP filed with the U.S. Court of Appeals for the District of Columbia Circuit, an appeal of FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants, retroactive to 2005. In August 2007, the court granted FERC’s motion to hold the appeal in abeyance pending completion of the continuing proceedings at FERC regarding the allocation of these costs. Other MISO participants also filed appeals. In November 2007, FERC issued two orders relative to these allocation matters. One of these orders addressed requests for rehearing of prior orders in the proceedings, and one concerned MISO’s compliance with FERC’s orders to date in the proceedings. In December 2007, UE, CIPS, CILCO and IP requested FERC’s clarification or rehearing of its November 2007 order regarding MISO’s compliance with FERC’s orders. UE, CIPS, CILCO, and IP maintained that MISO is required to reallocate certain of MISO’s operational costs among MISO market participants resulting in refunds to UE, CIPS, CILCO, and IP. On November 7, 2008, FERC granted the request for clarification of UE, CIPS, CILCO and IP and directed MISO to

reallocate certain costs and provide refunds. We have not yet determined the impact of this order on UE, CIPS, CILCO and IP, or on Genco and AERG, which are also market participants in MISO.

UE Power Purchase Agreement with Entergy Arkansas, Inc.

In July 2007, as a consequence of a series of orders issued by FERC addressing a complaint filed by the Louisiana Public Service Commission (LPSC) against Entergy Arkansas, Inc. (Entergy) and certain of its affiliates, which alleged unjust and unreasonable cost allocations, Entergy commenced billing UE for additional charges under a 165-megawatt power purchase agreement. Additional charges are expected to continue during the remainder of the term of the power purchase agreement, which expires August 25, 2009. Although UE was not a party to the FERC proceedings that gave rise to these additional charges, UE has intervened in related FERC proceedings and filed a complaint with the FERC against Entergy and Entergy Services, Inc. in April 2008 to challenge the additional charges. In September 2008, the presiding FERC administrative law judge in this matter issued an initial decision finding that Entergy’s allocation of such additional charges to UE is just and reasonable. The FERC is expected to issue an order with respect to the administrative law judge’s initial decision in 2009. UE is unable to predict whether FERC will grant it any relief.

Additionally, LPSC appealed FERC’s orders regarding LPSC’s complaint against Entergy to the U.S. Court of Appeals for the District of Columbia. In April 2008, the court issued a decision ordering further FERC proceedings regarding the LPSC complaint. The court’s decision ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. FERC’s decision on remand of the retroactive impact of these issues could have a financial impact on UE. UE is unable to predict how FERC will respond to the court’s decision. UE estimates that it could incur an additional one-time expense of up to $25 million if FERC orders retroactive application for the years 2001 to 2005. However, UE would contest such an order vigorously. Based on existing facts and circumstances, UE believes that the likelihood of incurring this $25 million expense is not probable, and, thus, no liability has been recorded as of September 30, 2008. UE plans to participate in any proceeding that FERC initiates to address the court’s decision.

Nuclear Combined Construction and Operating License Application

In July 2008, UE filed an application with the NRC for a combined construction and operating license for a potential new 1,600 megawatt nuclear plant at UE’s existing Callaway County, Missouri nuclear plant site. This COLA filing is not a commitment to build another nuclear plant, but it is a necessary step to preserve the option to develop a new nuclear plant in the future. The regulatory process for a COLA involves a comprehensive review, estimated by the NRC to require up to 42 months for completion.

Pumped-storage Hydroelectric Facility Relicensing

In June 2008, UE filed a relicensing application with FERC in order to operate its Taum Sauk pumped-storage hydroelectric facility for another 40 years. The current FERC license expires on June 30, 2010. Approval and relicensure are expected in 2012. Operations are permitted to continue under the current license while the renewal is pending.

NOTE 3 - SHORT-TERM BORROWINGS AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, drawings under $2.15 billion of committed bank credit facilities and commercial paper issuances.

The following table summarizes the borrowing activity and relevant interest rates as of September 30, 2008, under the $1.15 billion credit facility and the 2007 and 2006 $500 million credit facilities:

$1.15 Billion Credit Facility	Ameren (Parent)			UE			Genco			Total
September 30, 2008:
Average daily borrowings outstanding during 2008	$	424		$	169		$	54		$	647
Outstanding short-term debt at period end		275			-			-			275
Weighted-average interest rate during 2008		3.69	%		3.42	%		3.97	%		3.64	%
Peak short-term borrowings during 2008(a)	$	675		$	493		$	150		$	1,068
Peak interest rate during 2008		7.25	%		5.65	%		5.53	%		7.25	%

2007 $500 Million Credit Facility	CIPS			CILCORP (Parent)			CILCO (Parent)			IP			AERG			Total
September 30, 2008:
Average daily borrowings outstanding during 2008	$	-		$	125		$	56		$	161		$	94		$	436
Outstanding short-term debt at period end		-			77			75			175			100			427
Weighted-average interest rate during 2008		-			4.57	%		4.11	%		4.24	%		3.98	%		4.26	%
Peak short-term borrowings during 2008(a)	$	-		$	125		$	75		$	200		$	105		$	500
Peak interest rate during 2008		-			6.66	%		6.47	%		6.15	%		6.22	%		6.66	%
2006 $500 Million Credit Facility
September 30, 2008:
Average daily borrowings outstanding during 2008	$	68		$	50		$	30		$	25		$	172		$	345
Outstanding short-term debt at period end		96			50			75			129			55			405
Weighted-average interest rate during 2008		4.31	%		4.55	%		3.86	%		3.88	%		4.10	%		4.17	%
Peak short-term borrowings during 2008(a)	$	135		$	50		$	75		$	150		$	200		$	465
Peak interest rate during 2008		6.31	%		7.01	%		5.98	%		6.50	%		7.01	%		7.01	%

(a) The simultaneous peak short-term borrowings under all three facilities during 2008 were $1.8 billion.

At September 30, 2008, Ameren and certain of its subsidiaries had $2.15 billion of committed credit facilities, consisting of the three facilities shown above, in the amounts of $1.15 billion, $500 million and $500 million maturing in July 2010, January 2010, and January 2010, respectively. Under the $1.15 billion facility, the termination dates for UE’s and Genco’s direct borrowing sublimits thereunder are subject to an annual 364-day renewal provision. Effective July 10, 2008, the termination date was extended for UE and Genco from July 10, 2008, to July 9, 2009.

On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. As of September 30, 2008, Lehman Brothers Bank, FSB, a subsidiary of Lehman, had lending commitments of $100 million and $21 million under the $1.15 billion credit facility and the 2006 $500 million credit facility, respectively. The $50 million lending commitment of another Lehman subsidiary under the 2007 $500 million credit facility was assigned to a non-Lehman affiliated bank on or about September 17, 2008. At this time, we do not know if Lehman Brothers Bank, FSB will seek to assign to other parties any of its commitments within our credit facilities. Assuming Lehman Brothers Bank, FSB does not fund its pro-rata share of funding or letter of credit issuance requests under these two facilities, and such participations are not assigned or otherwise transferred to other lenders, total amounts accessible by the Ameren companies and AERG will be limited to amounts not less than $1.05 billion under the $1.15 billion credit facility and $479 million under the 2006 $500 million credit facility.

Based on outstanding borrowings under the $1.15 billion credit facility and the 2007 and 2006 $500 million credit facilities (including reductions for a $9 million letter of credit issued under the $1.15 billion credit facility and unfunded Lehman participations under the $1.15 billion credit facility and the 2006 $500 million credit facility), the available amounts under the facilities at September 30, 2008, were $791 million, $73 million, and $81 million, respectively.

Access to the $1.15 billion credit facility, the 2007 $500 million credit facility and the 2006 $500 million credit facility for the Ameren Companies and AERG is subject to reduction as borrowings are made by affiliates. Ameren and UE are limited in their access to the commercial paper market as a result of downgrades in 2006 in their short-term credit ratings.

On June 25, 2008, Ameren entered into a $300 million term loan agreement due June 24, 2009, which was fully drawn on June 26, 2008. In the event Ameren issues capital stock or other equity interests (except for director or employee benefit or dividend reinvestment plan purposes), certain equity-like hybrid securities or certain additional indebtedness in amounts exceeding $25 million, Ameren is required under the term loan agreement to use the resulting net proceeds to prepay amounts borrowed under the agreement. The lenders under the term loan agreement have waived this prepayment requirement to the extent the net proceeds from the issuance of certain funded indebtedness are applied to repurchase or redeem indebtedness of CILCORP. Additionally, if Ameren replaces its $1.15 billion credit facility with one or more credit facilities having a total available commitment in excess of $1.15 billion, Ameren is required under the term loan agreement to prepay amounts borrowed thereunder in an amount equal to the excess of the new commitments over $1.15 billion. Such mandatory prepayments are without premium or penalty (except for any funding indemnity due in respect of Eurodollar loans).

Borrowings under the $300 million term loan agreement will bear interest, at the election of Ameren, at (1) a Eurodollar rate plus a margin, which margin is subject to a floor of 0.90% per annum and a cap of 1.50% per annum, or (2) a rate equal to the higher of the prime rate or the federal funds effective rate plus 0.50% per year. Ameren used the proceeds borrowed under the term loan agreement to reduce amounts borrowed under the $1.15 billion credit facility, which thereby made additional amounts available for borrowing under that credit facility. The average annual interest rate for borrowing under the $300 million term loan agreement was 3.8% from its inception through September 30, 2008. The obligations of Ameren under the term loan agreement are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under, the term loan agreement.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ and AERG’s compliance with indebtedness provisions and other covenants. See Note 4 - Credit Facilities and Liquidity in the Form 10-K for a detailed description of those provisions.

The 2007 $500 million credit facility and 2006 $500 million credit facility limit the amount of CIPS, CILCORP, CILCO and IP common and preferred stock dividend payments to $10 million per year each if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below investment-grade credit rating from either Moody’s or S&P. With respect to AERG, which currently is not rated by Moody’s or S&P, the common and preferred stock dividend restriction will not apply if its ratio of consolidated total debt to consolidated operating cash flow, pursuant to a calculation defined in the facilities, is less than or equal to 3.0 to 1.0. CILCORP’s senior unsecured long-term debt credit ratings from Moody’s and S&P are below investment-grade, causing it to be subject to this dividend payment limitation. As of September 30, 2008, AERG was in compliance with the debt-to-operating cash flow ratio test in the 2007 and 2006 credit facilities and thus was not subject to this limitation. CIPS, CILCO and IP are not currently limited in their dividend payments by this provision of the 2007 or 2006 credit facilities. Ameren’s access to dividends from CILCO and AERG is limited by the dividend payment limitation at CILCORP.

Under the 2007 $500 million and 2006 $500 million credit facilities, each of CIPS, CILCO and IP had been required to reserve future bonding capacity under their respective

mortgage indentures (that is, they agreed to forego the issuance of additional mortgage bonds otherwise permitted under the terms of each mortgage indenture). On March 26, 2008, CIPS, CILCO and IP and other parties to the credit facilities entered into amendments to the credit facilities, which eliminated this requirement.

The $300 million term loan agreement entered into in June 2008 has terms similar to the $1.15 billion credit facility, except that amounts repaid under the term loan agreement may not be reborrowed. The term loan agreement contains nonfinancial covenants including restrictions on the ability to incur liens, dispose of assets and merge with other entities. In addition, the term loan agreement has nonfinancial covenants to limit the ability of Ameren to invest in or transfer assets to other entities, including affiliates. The events of default under the term loan agreement, including a cross default to the occurrence of an event of default under the $1.15 billion credit facility or any other agreement covering indebtedness of Ameren and its subsidiaries in excess of $25 million in the aggregate, are similar to those contained in the $1.15 billion credit facility. Each of CIPS, AERG, CILCORP, CILCO and IP and each of their subsidiaries is excluded from the definition of “subsidiary” under the term loan agreement and accordingly is not subject to certain of the covenants, representations, or warranties under the term loan agreement. The term loan agreement requires Ameren to maintain consolidated indebtedness of not more then 65% of consolidated total capitalization pursuant to a calculation defined in the term loan agreement.

The $1.15 billion credit facility, the 2007 $500 million credit facility, and the 2006 $500 million credit facility also limit the total indebtedness of each borrower to 65% of total consolidated capitalization pursuant to a calculation set forth in the facilities. As of September 30, 2008, the ratios of total indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the $1.15 billion credit facility, were 53%, 48% and 50%, for Ameren, UE and Genco, respectively. The ratios for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the provisions of the 2007 $500 million credit facility and 2006 $500 million credit facility, were 52%, 60%, 48%, 51% and 44%, respectively. The ratio of consolidated indebtedness to consolidated total capitalization for Ameren calculated in accordance with the provisions of the $300 million term loan agreement was 53%.

None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At September 30, 2008, management believes that the Ameren Companies were in compliance with their credit facilities and term loan agreement provisions and covenants.

Money Pools

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 for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.

Utility

Through the utility money pool, the pool participants may access borrowing capacity available under the $1.15 billion, 2007 $500 million, and 2006 $500 million credit facilities. See discussion above for amounts available under the facilities at September 30, 2008. CIPS, CILCO and IP borrow from each other and from Ameren through the utility money pool agreement subject to applicable regulatory short-term borrowing authorizations. Ameren and AERG may participate in the utility money pool only as lenders. The average interest rate for borrowing under the utility money pool for the three months and nine months ended September 30, 2008, was 2.9% and 3.3%, respectively (2007 - 5.4% and 5.7%, respectively).

Non-state-regulated Subsidiaries

Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access borrowing capacity available under Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool. See discussion above for amount available under the $1.15 billion credit facility at September 30, 2008. In addition, Ameren had $89 million of cash at September 30, 2008, which can be loaned into this arrangement. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months and nine months ended September 30, 2008, was 3.5% and 3.7%, respectively (2007 - 5.6% and 5.1%, respectively).

See Note 8 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three months and nine months ended September 30, 2008.

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to an effective SEC Form S-3 registration statement, and under our 401(k) plan, pursuant to an effective SEC Form S-8 registration statement, Ameren issued a total of 0.8 million new shares of common stock

valued at $32 million and 2.5 million new shares valued at $107 million in the three months and nine months ended September 30, 2008, respectively.

In April 2008, UE issued $250 million of 6.00% senior secured notes due April 1, 2018, with interest payable semiannually on April 1 and October 1 of each year, beginning in October 2008. UE received net proceeds of $248 million, which were used to redeem certain of UE’s outstanding auction-rate environmental improvement revenue refunding bonds discussed below and to repay short-term debt. In connection with this issuance of $250 million of senior secured notes, UE agreed, for so long as these senior secured notes are outstanding, that it will not, prior to maturity, cause a first mortgage bond release date to occur. The mortgage bond release date is the date at which the security provided by the pledge under UE’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness.

In April 2008, $63 million of UE’s Series 2000B auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.

In May 2008, $43 million of UE’s Series 1991, $64 million of UE’s Series 2000A and $60 million of UE’s Series 2000C auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest. Also, in May 2008, $148 million of UE’s 6.75% Series first mortgage bonds matured and were retired.

In June 2008, UE issued $450 million of 6.70% senior secured notes due February 1, 2019, with interest payable semiannually on February 1 and August 1 of each year, beginning in February 2009. UE received net proceeds of $446 million, which were used to repay short-term debt, a portion of which was incurred to pay at maturity the 6.75% Series first mortgage bonds noted above. In connection with this issuance of $450 million of senior secured notes, UE agreed, for so long as these senior secured notes are outstanding, that it will not, prior to maturity, cause a first mortgage bond release date to occur.

CIPS

In April 2008, $35 million of CIPS’ Series 2004 auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.

Genco

In April 2008, Genco issued and sold, with registration rights in a private placement, $300 million of 7.00% senior unsecured notes due April 15, 2018, with interest payable semiannually on April 15 and October 15 of each year, beginning in October 2008. Genco received net proceeds of $298 million, which are being used to fund capital expenditures, repay short-term debt and for general corporate purposes.

In July 2008, Genco completed its offer to exchange up to $300 million of its unregistered 7.00% senior unsecured notes due April 15, 2018, for a like amount of registered 7.00% senior unsecured notes due April 15, 2018. The entire aggregate principal amount of unregistered notes was tendered for exchange and not withdrawn prior to the expiration of the exchange offer.

CILCORP

In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $1 million and $4 million (2007 - $1 million and $4 million) for the three months and nine months ended September 30, 2008, respectively, and was included as a reduction to interest expense in the consolidated statements of income of Ameren and CILCORP. See Note 4 - Credit Facilities and Liquidity in the Form 10-K regarding CILCORP’s pledge of the common stock of CILCO as security for its obligations under the 2007 $500 million credit facility and the 2006 $500 million credit facility.

In September 2008, CILCORP commenced a cash tender offer for any and all of its outstanding 8.70% senior notes due 2009 ($123.755 million aggregate principal amount) and 9.375% senior bonds due 2029 ($210.565 million aggregate principal amount), collectively, the “notes.” Concurrent with the tender offer, CILCORP solicited consents from the holders of the notes to certain proposed amendments to the indenture governing these securities. Any holder tendering securities as part of this offer is deemed to consent to the proposed amendments. No consents will be accepted separate from a tender of such holder’s securities. The amendments would eliminate certain restrictive covenants in the indenture and the notes. The total consideration for each $1,000 principal amount of 2009 notes validly tendered on or prior to the current consent and expiration date, which has been extended to November 21, 2008, is $1,057.50. The total consideration includes a consent payment of $40 per $1,000 principal amount of such 2009 notes tendered on or prior to such date. The total consideration for each $1,000 principal amount of 2029 bonds validly tendered on or prior to the current November 21, 2008, consent and expiration date is $1,230, which includes a consent payment of $50 per $1,000 principal amount of such 2029 bonds tendered on or prior to such date. Holders validly tendering and not withdrawing notes on or before the extended consent and expiration date are eligible to receive the applicable total consideration. In

addition, tenders of notes, including previously tendered notes, may be withdrawn (and related consents may be rescinded) at any time prior to November 21, 2008. As of October 31, 2008, CILCORP had received consents, net of those recinded, from the holders of $122.8 million, or 99.3%, of its outstanding 2009 8.70% senior notes and $206.7 million, or 98.2%, of its outstanding 2029 bonds. Consummation of the tender offer and the consent solicitation is subject to a number of conditions, including the absence of certain adverse legal and market developments, as described in the offer to purchase. CILCORP has reserved the right to amend, further extend, terminate, or waive any conditions to the tender offer and the consent solicitation at any time. The impact on CILCORP’s net income of the tender offer is expected to be approximately $3 million, if consummated.

CILCO

In April 2008, $19 million of CILCO’s Series 2004 auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.

In July 2008, CILCO redeemed the remaining 165,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. The redemption completed CILCO’s mandatory redemption obligations for this series of preferred stock.

In conjunction with Ameren’s acquisition of IP, IP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $3 million and $8 million (2007 - $3 million and $9 million) for the three months and nine months ended September 30, 2008, respectively, and was included as a reduction to interest expense in the consolidated statements of income of Ameren and IP.

In April 2008, IP issued and sold, with registration rights in a private placement, $337 million of 6.25% senior secured notes due April 1, 2018, with interest payable semiannually on April 1 and October 1 of each year, beginning in October 2008. IP received net proceeds of $334 million, which were used to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds during May and June 2008 as discussed below. In connection with IP’s April 2008 issuance of $337 million of senior secured notes, IP agreed, for so long as these senior secured notes are outstanding, that it will not, prior to maturity, cause a first mortgage bond release date to occur. The mortgage bond release date is the date at which the security provided by the pledge under IP’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness.

In May 2008, IP redeemed its $112 million Series 2001 Non-AMT, $75 million Series 2001 AMT, $70 million 1997 Series A, and $45 million 1997 Series B auction-rate pollution control revenue bonds at par value plus accrued interest. In June 2008, IP redeemed its $35 million 1997 Series C auction-rate pollution control revenue bonds at par value plus accrued interest.

In June 2008, IP completed its offer to exchange up to $337 million of its unregistered 6.25% senior secured notes due April 1, 2018, for a like amount of registered 6.25% senior secured notes due April 1, 2018. The entire aggregate principal amount of unregistered notes was tendered for exchange and not withdrawn prior to the expiration of the exchange offer.

In September 2008, IP redeemed the remaining portion of its $54 million principal amount 5.65% note payable to IP SPT. Previous redemptions occurred in the first and second quarters of 2008 for $19 million and $20 million, respectively. This was the remaining outstanding amount of $864 million of TFNs issued by the IP SPT in December 1998, as allowed under the Illinois Electric Utility Transition Funding Law.

In October 2008, IP issued and sold, with registration rights in a private placement, $400 million of 9.75% senior secured notes due November 15, 2018, with interest payable semiannually on November 15 and May 15 of each year, beginning in May 2009. IP received net proceeds of $391 million, which were used to repay short-term debt. In connection with IP’s October 2008 issuance of $400 million of senior secured notes, IP agreed, for so long as these senior secured notes are outstanding, that it will not, prior to maturity, cause a first mortgage bond release date to occur.

Indenture Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indenture provisions and other covenants. See Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a detailed description of those provisions.

UE’s, CIPS’, CILCO’s and IP’s indentures and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable based on the 12 months ended September 30, 2008, at an assumed interest and dividend rate of 8%.

	Required Interest Coverage Ratio(a)	Actual Interest Coverage Ratio	Bonds Issuable(b)	Required Dividend Coverage Ratio(c)	Actual Dividend Coverage Ratio	Preferred Stock Issuable
UE	≥ 2.0	3.3	$ 1,703	≥ 2.5	49.6	$ 1,400
CIPS	≥ 2.0	1.2	38	≥ 1.5	1.0	-
CILCO	≥ 2.0(d)	15.3	331	≥ 2.5	49.7	376(e)
IP	≥ 2.0	2.5	873	≥ 1.5	0.9	-

(a)	Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.

(b)

Amount of bonds issuable based on either meeting required coverage ratios or unfunded property additions, whichever is more restrictive. In addition to these tests, UE, CIPS, CILCO and IP have the ability to issue bonds based upon retired bond capacity of $161 million, $38 million, $194 million and $686 million, respectively, which are included in the amounts above. No earnings coverage test is required for bonds issuable on the basis of retired bond capacity.

(c)

Coverage required on the annual interest charges on all long-term debt (CIPS only) and the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. For CILCO, this ratio must be met for a period of 12 consecutive calendar months within the 15 months immediately preceding the issuance.

(d)

In lieu of meeting the interest coverage ratio requirement, CILCO may attempt to meet an earnings requirement of at least 12% of the principal amount of all mortgage bonds outstanding and to be issued. For the nine months ended September 30, 2008, CILCO had earnings equivalent to at least 48% of the principal amount of all mortgage bonds outstanding.

(e)	See Note 4 - Credit Facilities and Liquidity in the Form 10-K for a discussion regarding a restriction on the issuance of preferred stock by CILCO under the 2006 $500 million credit facility and the 2007 $500 million credit facility.

UE’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.9 billion of free and unrestricted retained earnings at September 30, 2008.

CILCO’s articles of incorporation contain certain provisions that prohibit the payment of dividends on its common stock (i) from either paid-in surplus or any surplus created by a reduction of stated capital or capital stock, or (ii) if at the time of dividend declaration, there shall not remain to the credit of earned surplus account (after deducting the amount of such dividends) an amount at least equal to two times the annual dividend requirement on all outstanding shares of CILCO’s preferred stock.

Genco’s and CILCORP’s indentures include provisions that require the companies to maintain certain debt service coverage and/or debt-to-capital ratios in order for the companies to pay dividends, to make certain principal or interest payments, to make certain loans to or investments in affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended September 30, 2008:

	Required Interest Coverage Ratio	Actual Interest Coverage Ratio	Required Debt-to-Capital Ratio	Actual Debt-to-Capital Ratio
Genco (a)	≥1.75(b)	9.3	≤60%	49%
CILCORP(c)	≥2.2	3.8	≤67%	24%

(a)

Interest coverage ratio relates to covenants regarding certain dividends, principal and interest payments on certain subordinated intercompany borrowings and certain investments (collectively, restricted payments). The debt-to-capital ratio relates to a debt incurrence covenant, which also requires an interest coverage ratio of 2.5 for the most recently ended four fiscal quarters.

(b)	Ratio excludes amounts payable under Genco’s intercompany note to CIPS and must be met for both the prior four fiscal quarters and as projected for the succeeding four six-month periods.

(c)	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.

Genco’s debt incurrence-related ratio restrictions and restricted payment limitations under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness. In the event CILCORP is not in compliance with these restrictions, CILCORP may make payments of dividends or intercompany loans if its senior long-term debt rating is at least BB+ from S&P, Baa2 from Moody’s, and BBB from Fitch. At September 30, 2008, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were BB+, Ba2, and BB+, respectively. On October 16, 2008, Fitch upgraded CILCORP’s senior long-term debt rating to BBB. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior notes and bonds and credit facility obligations.

Off-Balance-Sheet Arrangements

At September 30, 2008, 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 5 - OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three months and nine months ended September 30, 2008 and 2007:

	Three Months						Nine Months
	2008			2007			2008			2007
Ameren:(a)
Miscellaneous income:
Interest and dividend income	$	10		$	16		$	35		$	41
Allowance for equity funds used during construction		8			2			19			2
Other		5			2			7			10
Total miscellaneous income	$	23		$	20		$	61		$	53
Miscellaneous expense:
Other	$	(10	)	$	(9	)	$	(23	)	$	(19	)
Total miscellaneous expense	$	(10	)	$	(9	)	$	(23	)	$	(19	)
UE:
Miscellaneous income:
Interest and dividend income	$	8		$	8		$	26		$	24
Allowance for equity funds used during construction		8			1			19			1
Other		1			-			1			3
Total miscellaneous income	$	17		$	9		$	46		$	28
Miscellaneous expense:
Other	$	(2	)	$	(5	)	$	(6	)	$	(9	)
Total miscellaneous expense	$	(2	)	$	(5	)	$	(6	)	$	(9	)
CIPS:
Miscellaneous income:
Interest and dividend income	$	2		$	4		$	7		$	12
Other		1			1			2			1
Total miscellaneous income	$	3		$	5		$	9		$	13
Miscellaneous expense:
Other	$	-		$	(1	)	$	(2	)	$	(2	)
Total miscellaneous expense	$	-		$	(1	)	$	(2	)	$	(2	)
Genco:
Miscellaneous income:
Interest and dividend income	$	-		$	-		$	1		$	-
Total miscellaneous income	$	-		$	-		$	1		$	-
Miscellaneous expense:
Other	$	(1	)	$	-		$	(1	)	$	-
Total miscellaneous expense	$	(1	)	$	-		$	(1	)	$	-
CILCORP:
Miscellaneous income:
Interest and dividend income	$	1		$	1		$	2		$	3
Other		-			1			-			1
Total miscellaneous income	$	1		$	2		$	2		$	4
Miscellaneous expense:
Other	$	(2	)	$	(1	)	$	(4	)	$	(3	)
Total miscellaneous expense	$	(2	)	$	(1	)	$	(4	)	$	(3	)
CILCO:
Miscellaneous income:
Interest and dividend income	$	1		$	1		$	2		$	3
Other		-			1			-			1
Total miscellaneous income	$	1		$	2		$	2		$	4

Miscellaneous expense:
Other	$	(2	)	$	(1	)	$	(3	)	$	(3	)
Total miscellaneous expense	$	(2	)	$	(1	)	$	(3	)	$	(3	)


	Three Months						Nine Months
	2008			2007			2008			2007
IP:
Miscellaneous income:
Interest and dividend income	$	-		$	2		$	4		$	5
Other		3			2			5			4
Total miscellaneous income	$	3		$	4		$	9		$	9
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(5	)	$	(3	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(5	)	$	(3	)

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

The following table presents the pretax net gain (loss) of power hedges and the net change in market value of option and swap transactions used to manage our positions in SO2 allowances, coal, heating oil, FTRs and nonhedge power and gas trading activity for the three months and nine months ended September 30, 2008 and 2007. Certain of these transactions have not been designated as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. The pretax net gain (loss) of power hedges 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 being delivered or settled and is included in Operating Revenues - Electric. The net change in the market value of SO2, coal and heating oil options and swaps is recorded as Operating Expenses - Fuel. The nonhedge power and gas transactions are recorded in Operating Revenues - Electric and Operating Revenues - Gas.

	Three Months						Nine Months
Gains (Losses)	2008			2007			2008			2007
Power hedges:
Ameren	$	77		$	22		$	47		$	35
UE		10			2			5			-
SO2 options and swaps:
Ameren		(1	)		-			(1	)		6
UE		-			-			-			5
Genco		(1	)		-			(1	)		1
Coal options:
Ameren		-			-			-			2
UE		-			-			-			2
Heating oil options:
Ameren		(105	)		-			4			3
UE		(55	)		-			5			-
Genco		(29	)		-			-			-
CILCORP/CILCO		(7	)		-			-			-
FTRs:
Ameren		(10	)		-			4			-
UE		(9	)		-			3			-
Nonhedge power swaps and forwards:
Ameren		8			3			8			(2	)
UE		(1	)		2			1			(2	)
Gas forwards and swaps:
Ameren		(6	)		(2	)		(4	)		-
UE		(4	)		(2	)		(1	)		-
CILCORP/CILCO		(3	)		-			(3	)		-

The following table presents the carrying value of all derivative instruments and the amount of pretax net gains (losses) on derivative instruments in accumulated OCI, regulatory assets, or regulatory liabilities as of September 30, 2008:

	Ameren(a)			UE		CIPS		Genco			CILCORP/ CILCO		IP
Derivative instruments carrying value:
Current assets	$	120		$	49	$	3	$	1		$	2	$	5
Other assets		34			5		8		-			5		14
Current liabilities		92			20		19		2			16		33
Other deferred credits and liabilities(b)		7			3		4		-			2		5
Gains (losses) deferred in accumulated OCI:
Power forwards(c)		46			23		-		-			-		-
Interest rate swaps(d)(e)		(11	)		-		-		(11	)		-		-

Ameren(a)

CIPS

Genco

CILCORP/

CILCO

Gas swaps and futures contracts(f)	(2	)	-		-		-	-		-
Coal options and swaps	7		8		-		-	-		-
Gains (losses) deferred in regulatory assets or liabilities
Gas swaps and futures contracts(f)	(37	)	(3	)	(10	)	-	(9	)	(15	)
Financial contracts(g)	-		-		(2	)	-	(1	)	(3	)

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

(b)	Includes Ameren and UE’s carrying value of fair value foreign currency forward contracts.

(c)	Represents the mark-to-market value for the hedged portion of electricity price exposure for periods of up to three years, including gains of $59 million and $21 million over the next 12 months at Ameren and UE, respectively.

(d)

Includes 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. The carrying value at September 30, 2008, was $2 million.

(e)

Includes a loss associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco’s April 2008 debt issuance. The cumulative loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at September 30, 2008 was a loss of $13 million.

(f)	Represents losses associated with natural gas swaps and futures contracts. The swaps and futures contracts are a partial hedge of our natural gas requirements through 2012 at Ameren, UE, and CIPS, and through 2011 at CILCORP, CILCO and IP.

(g)

Current gains deferred as regulatory liabilities include $3 million at CIPS, $2 million at CILCO, and $5 million at IP that were recorded in other current liabilities at September 30, 2008. Current losses deferred as regulatory assets include $(10) million at CIPS, $(5) million at CILCO, and $(15) million at IP that were recorded in other current assets at September 30, 2008.

As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company. These financial contracts are derivative instruments being accounted for as cash flow hedges at Marketing Company. Consequently, the Ameren Illinois Utilities and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities for the Ameren Illinois Utilities and OCI at Marketing Company. In Ameren’s consolidated financial statements, all financial statement effects of the swap are eliminated. See Note 2 - Rate and Regulatory Matters under Part II, Item 8 in the Form 10-K for additional information on these financial contracts.

During the third quarter ended September 30, 2008, UE entered into foreign currency forward contracts. These derivative instruments are intended to fix the amount of U.S. dollars UE will pay for future equipment deliveries denominated in euros as part of a firm commitment to purchase heavy forgings needed if UE decides to build a second nuclear plant. These forward contracts qualify as fair value hedges and, as a result, both the derivative positions and the foreign currency exposure on the firm commitment are recorded at fair value. The change in the fair value of both the derivative instrument and the hedged item are recorded in earnings. For the quarter ended September 30, 2008, this hedging program was highly effective, resulting in no impact to net income.

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the contracts. In order to mitigate these risks, collateral requirements are established. As of September 30, 2008, Ameren, UE, CIPS, CILCORP, CILCO and IP had collateral postings with external parties of $35 million, $2 million, $7 million, $5 million, $5 million, and $11 million, respectively. The amounts of collateral external counterparties posted with Ameren, UE, CIPS, CILCORP, CILCO, and IP were immaterial at September 30, 2008. See Note 8 - Related Party Transactions for information regarding collateral postings with affiliates.

On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. At that time, UE, CIPS, Genco, IP, Marketing Company and AFS were counterparties with Lehman Brothers Commodity Services Inc. (Lehman Commodity Services) and Eagle Energy Partners I, LP (Eagle Energy), subsidiaries of Lehman, in energy commodity transactions that support their utility and generation businesses. The obligations of Lehman Commodity Services and Eagle Energy are guaranteed by Lehman, and the Lehman bankruptcy filing gives UE, CIPS, Genco, IP, Marketing Company and AFS the right to terminate any open transactions. As of October 31, 2008, Ameren’s and its subsidiaries’ direct exposure to Lehman Commodity Services and Eagle Energy, based on existing transactions and current market prices, was estimated to be less than $1 million before taxes, collectively.

NOTE 7 - FAIR VALUE MEASUREMENTS

SFAS No. 157 provides a framework for measuring fair value for all assets and liabilities that are measured and reported at fair value. This standard was effective and adopted by the Ameren Companies as of January 1, 2008, for financial assets and liabilities. The impact of this adoption of SFAS No. 157 was not material. SFAS No. 157 will be effective in the first quarter of 2009 for all nonfinancial assets and liabilities that are measured and

reported on a fair value basis. The impact of adoption of SFAS No. 157 for nonfinancial assets and liabilities is not expected to be material. SFAS No. 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income and cost approaches. Based on these approaches, we use certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities primarily include exchange-traded derivatives and assets such as U.S. treasury securities and listed equity securities, such as those held in UE’s Nuclear Decommissioning Trust Fund.

Level 2: Market-based inputs corroborated by third party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in UE’s Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed income securities, and certain over-the-counter derivative instruments, including natural gas swaps and financial power transactions. Derivative instruments classified as Level 2 are valued using corroborated observable inputs including those from pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. In order to validate forward prices from outside parties, the pricing is compared to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, the volume of transactions that occurred on certain trading platforms is considered in our reasonableness assessment of the averaged midpoint.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued based on internally-developed models and assumptions or methodologies using significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets where pricing is largely unobservable, including the financial contracts entered into between the Ameren Illinois Utilities and Marketing Company as part of the Illinois electric settlement agreement. We value Level 3 instruments using pricing models with inputs, which are often unobservable in the market, and certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, a review of all sources is performed to identify any anomalies or potential errors.

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities that are subject to SFAS No. 157. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. All assets and liabilities where the fair value measurement is based on significant unobservable inputs are classified as Level 3.

We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g. collateral). SFAS No. 157 also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields and credit ratings. Ameren recorded $2.5 million in losses in the third quarter of 2008 related to valuation adjustments for counterparty default risk. At September 30, 2008, the counterparty default risk valuation adjustment related to net derivative (assets) liabilities totaled $(4) million, $(2) million, and $1 million for Ameren, UE, and IP, respectively.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of September 30, 2008:

		Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren(a)	Other current assets	$	-	$	-	$	16	$	16
	Derivative assets(b)		-		41		113		154
	Nuclear Decommissioning
	Trust Fund(c)		200		83		1		284
UE	Derivative assets		-		24		30		54
	Nuclear Decommissioning
	Trust Fund(c)		200		83		1		284
CIPS	Derivative assets(b)		-		-		11		11
Genco	Derivative assets(b)		-		-		1		1
CILCORP/CILCO	Derivative assets(b)		-		-		7		7
IP	Derivative assets(b)		-		-		19		19
Liabilities:
Ameren(a)	Derivative liabilities(b)	$	6	$	21	$	72	$	99
UE	Derivative liabilities(b)		-		14		9		23
CIPS	Derivative liabilities(b)		-		-		23		23
Genco	Derivative liabilities(b)		-		-		2		2
CILCORP/CILCO	Derivative liabilities(b)		3		-		15		18
IP	Derivative liabilities(b)		-		-		38		38

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

(b)	The derivative asset and liability balances are presented net of counterparty credit considerations.

(c)	Balance excludes $(15) million of receivables, payables, and accrued income, net.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended September 30, 2008:

																							Change in
												Total											Unrealized
				Realized and Unrealized Gains (Losses)								Realized			Purchases,								Gains (Losses)
		Beginning							Included in			and			Issuances,			Net		Ending			Related to
		Balance at							Regulatory			Unrealized			and Other			Transfers In		Balance at			Assets/Liabilities
		July 1,		Included in			Included		Assets/			Gains			Settlements,			and/or (Out)		September 30,			Still Held at
		2008		Earnings(a)			In OCI		Liabilities			(Losses)			Net			of Level 3		2008		September 30, 2008
Other current assets	Ameren	$	-	$	-		$	-	$	-		$	-		$	-		$	16	$	16		$	-
Net derivative	Ameren	$	202	$	(66	)	$	64	$	(161	)	$	(163	)	$	(33	)	$	35	$	41		$	(252	)
contracts	UE		40		(4	)		2		(2	)		(4	)		(26	)		11		21			6
	CIPS		112		(1	)		-		(115	)		(116	)		(8	)		-		(12	)		(31	)
	Genco		4		(5	)		-		-			(5	)		-			-		(1	)		(4	)
	CILCORP/CILCO		77		(6	)		-		(72	)		(78	)		(7	)		-		(8	)		(34	)
	IP		195		(1	)		-		(208	)		(209	)		(5	)		-		(19	)		(77	)
Nuclear	Ameren	$	1	$	-		$	-	$	-		$	-		$	(b	)	$	-	$	1		$	-
Decommissioning	UE		1		-			-		-			-		(b		)		-		1			-
Trust Fund

(a)	Net gains and losses on power options are recorded in Operating Revenues - Electric, while net gains and losses on coal, heating oil, and SO2 options and swaps are recorded as Operating Expenses - Fuel.

(b)	Less than $1 million.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2008:

																							Change in
												Total											Unrealized
				Realized and Unrealized Gains (Losses)								Realized			Purchases,								Gains (Losses)
		Beginning							Included in			and			Issuances,			Net		Ending			Related to
		Balance at							Regulatory			Unrealized			and Other			Transfers In		Balance at			Assets/Liabilities
		January 1,		Included in			Included		Assets/			Gains			Settlements,			and/or (Out)		September 30,			Still Held at
		2008		Earnings(a)			In OCI		Liabilities			(Losses)			Net			of Level 3		2008		September 30, 2008
Other current assets	Ameren	$	-	$	-		$	-	$	-		$	-		$	-		$	16	$	16		$	-
Net derivative	Ameren	$	19	$	26		$	5	$	17		$	48		$	(50	)	$	24	$	41		$	10
contracts	UE		3		7			12		17			36			(30	)		12		21			10
	CIPS		38		-			-		(41	)		(41	)		(9	)		-		(12	)		(36	)
	Genco		1		(1	)		-		-			(1	)		(1	)		-		(1	)		-
	CILCORP/CILCO		21		(7	)		-		(10	)		(17	)		(12	)		-		(8	)		(21	)
	IP		55		(1	)		-		(67	)		(68	)		(6	)		-		(19	)		(59	)
Nuclear	Ameren	$	5	$	-		$	-	$	-		$	-		$	(4	)	$	-	$	1		$	-
Decommissioning	UE		5		-			-		-			-			(4	)		-		1			-
Trust Fund

(a)	Net gains and losses on power options are recorded in Operating Revenues - Electric, while net gains and losses on coal, heating oil, and SO2 options and swaps are recorded as Operating Expenses - Fuel.

Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers between Level 2 and Level 3 were primarily caused by changes in availability of financial power trades observable on electronic exchanges compared to previous periods for the three and nine months ended September 30, 2008. Any reclassifications are reported as transfers in/out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur.

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 12 - Related Party Transactions under Part II, Item 8 of the Form 10-K.

Illinois Electric Settlement Agreement

As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over four years as part of a comprehensive program providing approximately $1 billion of funding for rate relief to certain Illinois electric customers, including customers of the Ameren Illinois Utilities. At September 30, 2008, CIPS, CILCO and IP had receivable balances from Genco for reimbursement of customer rate relief of $1 million, less than $1 million, and $1 million, respectively. Also at September 30, 2008, CIPS, CILCO and IP had receivable balances from AERG for reimbursement of customer rate relief of less than $1 million each. During the three months ended September 30, 2008, Genco incurred charges to earnings of $4 million for customer rate relief contributions and program funding reimbursements to the Ameren Illinois Utilities (CIPS - $1 million, CILCO - $1 million, IP - $2 million), and AERG incurred charges to earnings of $2 million (less than $1 million at CIPS, CILCO and IP, respectively). For the nine months ended September 30, 2008, Genco incurred charges to earnings of $13 million for customer rate relief contributions and program funding reimbursements to the Ameren Illinois Utilities (CIPS -$5 million, CILCO - $2 million, IP - $6 million), and AERG incurred charges to earnings of $6 million (CIPS - $2 million, CILCO - $1 million, IP - $3 million). The Ameren Illinois Utilities recorded most of the reimbursements received as electric revenue, with an immaterial amount recorded as miscellaneous revenue.

In addition, as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company to lock-in energy prices for a portion of their around-the-clock power requirements from 2008 to 2012 at relevant market prices. These financial contracts became effective on August 28, 2007. See Note 6 - Derivative Financial Instruments for additional information on the financial contracts and Note 2 - Rate and Regulatory Matters for additional information on the Illinois electric settlement agreement.

Electric Power Supply and Resource Sharing Agreements

The following table presents the amount of gigawatthour sales under related party electric power supply agreements for the three months and nine months ended September 30, 2008 and 2007:

	Three Months		Nine Months
	2008	2007	2008	2007
Genco sales to Marketing Company	4,276	4,754	12,217	12,711
AERG sales to Marketing Company	1,794	1,270	5,107	3,912
Marketing Company sales to CIPS	463	671	1,557	1,852
Marketing Company sales to CILCO	222	349	702	922
Marketing Company sales to IP	715	1,016	2,217	2,716

In December 2006, Genco and Marketing Company entered into a new power supply agreement (Genco PSA) whereby Genco agreed to sell and Marketing Company agreed to purchase all of the capacity available from Genco’s generation fleet and all the associated energy. On March 28, 2008, Genco and Marketing Company entered into an amendment of the Genco PSA. Under the amendment, Genco is liable to Marketing Company in the event of an unplanned outage or derate (reduction in rated capacity) due to sudden, unanticipated failure or accident within the generating plant site of one or more of its generating units. Genco’s liability in such case will be for the positive difference, if any, between the market price of capacity and/or energy Genco does not deliver and the contract price under the Genco PSA for that capacity and/or energy. Genco has insurance with an affiliate company that covers many, but not all, of these situations, subject to deductibles and policy limits. An unplanned outage or derate that continues for one year or more is an event of default under the Genco PSA. In the event of Marketing Company’s unexcused failure to receive energy under the Genco PSA, Marketing Company would be required to pay Genco the positive difference, if any, between the contract price and the price actually received by Genco, acting in a commercially reasonable manner, to resell the unreceived energy, less any reasonable related transmission, ancillary service, or brokerage costs.

Also in December 2006, AERG and Marketing Company entered into a power supply agreement (AERG PSA) whereby AERG agreed to sell and Marketing Company agreed to purchase all of the capacity available from AERG’s generation fleet and all the associated energy. On March 28, 2008, AERG and Marketing Company entered into an amendment of the AERG PSA that is substantially identical to the amendment to the Genco PSA described above. Under the amendment, AERG is liable to Marketing Company in the event of an unplanned outage or derate due to sudden, unanticipated failure or accident within the generating plant site of one or more of its generating units. AERG’s liability in such case will be for the positive difference, if any, between the market price of capacity and/or energy AERG does not deliver and the contract price under the AERG PSA for that capacity and/or energy. AERG has insurance with an affiliate company that covers many, but not all of these situations, subject to deductibles and policy limits. An unplanned outage or derate that continues for one year or more is an event of default under the AERG PSA. In the event of Marketing Company’s unexcused failure to receive energy under the AERG PSA, Marketing Company would be required to pay AERG the positive difference, if any, between the contract price and the price actually received by AERG, acting in a commercially reasonable manner, to resell the unreceived energy, less any reasonable related transmission, ancillary service, or brokerage costs.

One-third of the Ameren Illinois Utilities’ supply contracts that served the load needs of their fixed-price residential and small commercial customers, and all of the supply contracts that served large commercial and industrial customers, expired on May 31, 2008. To replace a portion of these expired supply contracts, the Ameren Illinois Utilities used RFP processes in early 2008, pursuant to the Illinois electric settlement agreement, to contract for the necessary energy and capacity requirements for the period from June 1, 2008 through May 31, 2009. Marketing Company was one of the winning suppliers in the Ameren Illinois Utilities’ energy and capacity RFPs. Marketing Company entered into financial instruments that fixed the price that the Ameren Illinois Utilities will pay for approximately two million megawatthours at approximately $60 per megawatthour. Marketing Company contracted to supply a portion of the Ameren Illinois Utilities’ capacity for approximately $6 million. In addition, UE contracted to supply a portion of the Ameren Illinois Utilities’ capacity for approximately $1 million.

On June 1, 2008, FERC accepted an electric resource sharing agreement among the Ameren Illinois Utilities for various joint costs of the Ameren Illinois Utilities, including capacity, renewable energy credits, and rate swaps. The purpose of the agreement is to allocate these costs among the Ameren Illinois Utilities in an equitable manner, based on their respective retail loads.

Collateral Postings

Under the terms of the power supply agreements between Marketing Company and the Ameren Illinois Utilities, which were entered into as part of the September 2006 Illinois power procurement auction, cash collateral is required to be posted by Marketing Company under certain market conditions to protect the Ameren Illinois Utilities in

the event of nonperformance by Marketing Company. The collateral postings are unilateral, meaning that Marketing Company as the supplier is the only counterparty required to post collateral. At September 30, 2008, there were no collateral postings by Marketing Company related to the 2006 auction power supply agreements, and at December 31, 2007, Marketing Company had posted $1 million, less than $1 million, and $1 million for the benefit of CIPS, CILCO, and IP, respectively.

In addition, under the terms of the 2008 Illinois power procurement RFPs, cash collateral is required to be posted by Marketing Company and the Ameren Illinois Utilities under certain market conditions. The collateral postings are bilateral, meaning that either counterparty may be required to post collateral. As of September 30, 2008, the Ameren Illinois Utilities had cash collateral postings as follows with Marketing Company: CIPS - $7 million, CILCO - $4 million and IP - $10 million. These bilateral collateral postings were eliminated in consolidation on Ameren’s financial statements.

Intercompany Transfers

On January 1, 2008, UE transferred its interest in Union Electric Development Corporation at book value to Ameren by means of a $3 million dividend-in-kind. On March 31, 2008, Union Electric Development Corporation was merged into Ameren Development Company, with Ameren Development Company surviving the merger.

On February 29, 2008, UE contributed its entire 40% ownership interest in EEI at book value to Resources Company valued at $39 million, in exchange for a 50% interest in Resources Company, and then immediately transferred its interest in Resources Company to Ameren by means of a $39 million dividend-in-kind. Also on February 29, 2008, Development Company, which formerly held a 40% ownership interest in EEI, merged into Ameren Energy Resources Company, which then merged into Resources Company. As a result, Resources Company now has an 80% ownership interest in EEI and consolidates it accordingly.

Money Pools

See Note 3 - Short-term Borrowings and Liquidity for a discussion of affiliate borrowing arrangements.

Intercompany Borrowings

Genco’s subordinated note payable to CIPS associated with the transfer in 2000 of CIPS’ electric generating assets and related liabilities to Genco matures on May 1, 2010. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $2 million (2007 - $2 million) and $6 million (2007 - $7 million) for the three months and nine months ended September 30, 2008 and 2007, respectively.

CILCORP had outstanding borrowings directly from Ameren of $63 million and $2 million at September 30, 2008 and December 31, 2007, respectively. The average interest rate on these borrowings was 3.5% and 3.7% for the three months and nine months ended September 30, 2008, respectively (2007 - not applicable for the three months ended September 30, 2007, and 4.8% for the nine months ended September 30, 2007). CILCORP recorded interest expense of less than $1 million for these borrowings for the three months and nine months ended September 30, 2008, and September 30, 2007.

UE had outstanding borrowings directly from Ameren of $17 million at September 30, 2008, and none at December 31, 2007. The average interest rate on these borrowings was 3.5% and 3.7% for the three months and nine months ended September 30, 2008, respectively (2007 - 5.6% and 5.1%, respectively). UE recorded interest expense of less than $1 million for these borrowings for the three months and nine months ended September 30, 2008, respectively (2007 - less than $1 million and $3 million for the three months and nine months ended September 30, 2007 respectively).

UE had an intercompany note receivable of $30 million from Ameren Development Company at September 30, 2008. This note was transferred to Ameren Development Company from Union Electric Development Corporation in connection with the merger discussed above. The average interest rate on this borrowing was 5.0% and 5.1%, respectively, for the three months and nine months ended September 30, 2008. UE recorded interest revenue of $1 million and $2 million for these borrowings for the three months and nine months ended September 30, 2008, respectively.

The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the three months and nine months ended September 30, 2008 and 2007. It is based primarily on the agreements discussed above and in Note 12 - Related Party Transactions under Part II, Item 8 of the Form 10-K, and the money pool arrangements discussed in Note 3 - Short-term Borrowings and Liquidity of this report.


		Three Months										Nine Months
Agreement		UE		CIPS		Genco		CILCORP(a)		IP		UE		CIPS		Genco		CILCORP(a)		IP
Operating Revenues:
Genco and AERG power supply	2008	$	(b)	$	(b)	$	233	$	99	$	(b)	$	(b)	$	(b)	$	658	$	252	$	(b)
agreements with Marketing Company	2007	(b)		(b)			222		73	(b)		(b)		(b)			615		207	(b)
Ancillary service agreement	2008		3	(b)		(b)		(b)		(b)			9	(b)		(b)		(b)		(b)
with CIPS, CILCO and IP	2007		5	(b)		(b)		(b)		(b)			13	(b)		(b)		(b)		(b)
Genco gas sales to CILCO	2008	(b)		(b)		(c)		(b)		(b)		(b)		(b)			6	(b)		(b)
	2007	(b)		(b)			-	(b)		(b)		(b)		(b)			-	(b)		(b)
UE and Genco gas transportation	2008		1	(b)		(b)		(b)		(b)			1	(b)		(b)		(b)		(b)
agreement	2007	(c)		(b)		(b)		(b)		(b)		(c)		(b)		(b)		(b)		(b)
Total Operating Revenues	2008	$	4	$	(b)	$	233	$	99	$	(b)	$	10	$	(b)	$	664	$	252	$	(b)
	2007		5	(b)			222		73	(b)			13	(b)			615		207		(b)
Fuel and Purchased Power:
CIPS, CILCO and IP agreements with	2008	$	(b)	$	32	$	(b)	$	15	$	49	$	(b)	$	104	$	(b)	$	47	$	148
Marketing Company (2006 auction	2007	(b)			42	(b)			22		64	(b)			120	(b)			60		176
and energy and capacity agreements)
Ancillary service agreement with UE	2008	(b)			1	(b)			1		1	(b)			3	(b)			1		5
	2007	(b)			2	(b)			1		2	(b)			5	(b)			2		6
Ancillary service agreement with	2008	(b)			1	(b)			1		2	(b)			5	(b)			3		8
Marketing Company	2007	(b)			1	(b)			-		2	(b)			3	(b)			1		4
Executory tolling agreement with	2008	(b)		(b)		(b)			8	(b)		(b)		(b)		(b)			30	(b)
Medina Valley	2007	(b)		(b)		(b)			8	(b)		(b)		(b)		(b)			28	(b)
UE and Genco gas transportation	2008	(b)		(b)			1	(b)		(b)		(b)		(b)			1	(b)		(b)
agreement	2007	(b)		(b)		(c)		(b)		(b)		(b)		(b)		(c)		(b)		(b)
Total Fuel and Purchased Power	2008	$	(b)	$	34	$	1	$	25	$	52	$	(b)	$	112	$	1	$	82	$	161
	2007	(b)			45	(c)			31		68	(b)			128	(c)			91		186
Gas Purchased for Resale
CILCO gas purchases from Genco	2008	$	(b)	$	(b)	$	(b)	$	(c)	$	(b)	$	(b)	$	(b)	$	(b)	$	6	$	(b)
	2007	(b)		(b)		(b)			-	(b)		(b)		(b)		(b)			-	(b)
Other Operations and Maintenance Expense:
Ameren Services support services	2008	$	36	$	14	$	7	$	14	$	21	$	110	$	43	$	22	$	43	$	65
agreement	2007		37		14		6		13		21		113		41		19		41		63
Ameren Energy, Inc. support	2008	(e)		(e)		(e)		(e)		(e)		(e)		(e)		(e)		(e)		(e)
services agreement	2007		2	(b)		(c)		(b)		(b)			7	(b)		(c)		(b)		(b)
AFS support services agreement	2008		2		-		1		1		-		5		1		2		2		1
	2007		2		-		1		1		-		5		1		2		2		1
Insurance premiums(d)	2008		2	(b)			1		1	(b)			7	(b)			3		3	(b)
	2007		7	(b)			1		-	(b)			16	(b)			3		1	(b)
Total Other Operations and	2008	$	40	$	14	$	9	$	16	$	21	$	122	$	44	$	27	$	48	$	66
Maintenance Expenses	2007		48		14		8		14		21		141		42		24		44		64
Interest expense on commercial	2008	$	-	$	(b)	$	(b)	$	(b)	$	(b)	$	1	$	(b)	$	(b)	$	(b)	$	(b)
paper held by affiliate	2007		1	(b)		(b)		(b)		(b)			3	(b)		(b)		(b)		(b)
Interest expense (income) from	2008		-	(c)		(c)			1	(c)			-	(c)		(c)			1	(c)
money pool borrowings (advances)	2007		-	(c)			3	(c)		(c)			-	(c)			7	(c)		(c)

(a)	Amounts represent CILCORP and CILCO activity.

(b)	Not applicable.
(c)	Amount less than $1 million.
(d)	Represents insurance expense on affiliate policies for replacement power, property damage and terrorism coverage.
(e)	Ameren Energy, Inc. was eliminated December 31, 2007 through an internal reorganization.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 12 - Related Party Transactions, and Note 13 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 10 - Callaway Nuclear Plant in this report.

Callaway Nuclear Plant

The following table presents insurance coverage at UE’s Callaway nuclear plant at October 29, 2008. The property coverage and the nuclear liability coverage must be renewed on October 1 and January 1, respectively, of each year.

Type and Source of Coverage	Maximum Coverages			Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$	300	(a)	$	-
Pool participation		10,461			117.5	(b)
	$	10,761	(c)	$	117.5
Property damage:
Nuclear Electric Insurance Ltd.	$	2,750	(d)	$	24
Replacement power:
Nuclear Electric Insurance Ltd.	$	490	(e)	$	9
Energy Risk Assurance Company	$	64	(f)	$	-

(a)	Provided through mandatory participation in an industry-wide retrospective premium assessment program.

(b)

Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This is subject to retrospective assessment with respect to a covered loss in excess of $300 million from an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.

(c)	Limit of liability for each incident under Price-Anderson. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.

(d)	Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.

(e)	Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. 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.

(f)

Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 8 - Related Party Transactions for more information on this affiliate transaction.

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. Owners of 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.

After the terrorist attacks on September 11, 2001, Nuclear Electric Insurance Ltd. confirmed that losses resulting from terrorist attacks would be covered under its policies. However, Nuclear Electric Insurance Ltd. imposed an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

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 is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and UE’s results of operations, financial position, or liquidity.

Other Obligations

We have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel to supply a portion of the fuel requirements of our generating plants. 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 Note 13 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

Our commitments for the procurement of coal have materially changed from amounts previously disclosed as of December 31, 2007. The following table presents our total estimated coal purchase commitments at September 30, 2008:

	2008		2009		2010		2011		2012		Thereafter
Ameren(a)	$	126	$	498	$	294	$	148	$	17	$	-
UE		72		293		181		80		-		-
Genco		25		111		44		24		-		-
CILCORP/CILCO		14		42		36		27		17		-

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

Our commitments for the procurement of natural gas have materially changed from amounts previously disclosed as of December 31, 2007. The following table presents our total estimated natural gas purchase commitments at September 30, 2008:

	2008		2009		2010		2011		2012		Thereafter
Ameren(a)	$	178	$	524	$	399	$	249	$	135	$	138
UE		21		86		59		41		27		43
CIPS		37		112		70		63		45		60
Genco		7		10		8		8		5		8
CILCORP/CILCO		43		136		101		52		30		19
IP		67		173		160		85		27		8

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

Our commitments for the procurement of nuclear fuel have materially changed from amounts previously disclosed as of December 31, 2007. The following table presents our total estimated nuclear fuel purchase commitments at September 30, 2008:

	2008		2009		2010		2011		2012		Thereafter
Ameren	$	3	$	68	$	74	$	52	$	67	$	232
UE		3		68		74		52		67		232

UE’s firm commitments to purchase heavy forgings for construction of a potential new nuclear power plant have changed from amounts previously disclosed as of December 31, 2007. The following table presents the total estimated heavy forgings commitments at September 30, 2008:

	2008		2009		2010		2011		2012		Thereafter
Ameren	$	-	$	10	$	35	$	23	$	23	$	-
UE		-		10		35		23		23		-

The Illinois electric settlement agreement provides approximately $1 billion of funding over a four-year period that commenced in 2007 for rate relief for certain electric customers in Illinois. Funding for the settlement will come from electric generators in Illinois and certain Illinois electric utilities. The Ameren Illinois Utilities, Genco and AERG agreed to fund an aggregate of $150 million, of which the following contributions remained to be made at September 30, 2008:

	Ameren		CIPS		CILCO (Illinois Regulated)		IP		Genco		CILCO (AERG)
2008(a)	$	12.2	$	1.9	$	0.9	$	2.7	$	4.6	$	2.1
2009(a)		25.4		3.6		1.8		4.8		10.5		4.7
2010(a)		2.0		0.3		0.1		0.4		0.8		0.4
Total	$	39.6	$	5.8	$	2.8	$	7.9	$	15.9	$	7.2

(a) Estimated.

One-third of the Ameren Illinois Utilities’ supply contracts that served the load needs of their fixed-price residential and small commercial customers expired on May 31, 2008. To replace a portion of these expired supply contracts, the Ameren Illinois Utilities used RFP processes in early 2008, pursuant to the Illinois electric settlement agreement. Specifically, the Ameren Illinois Utilities used RFPs to procure energy swaps, capacity, and renewable energy credits for the period June 1, 2008 through May 31, 2009. The Ameren Illinois Utilities contracted to purchase approximately two million megawatthours of energy swaps at an average price of approximately $60 per megawatthour. As a result of a capacity RFP, the Ameren Illinois Utilities contracted to purchase approximately 1,800 megawatts of capacity at an average price of approximately $50 per MW-day. A renewable energy credits RFP resulted in the Ameren Illinois Utilities contracting to purchase 415,000 credits at an average price of approximately $17 per credit.

Environmental Matters

We are subject to various environmental laws and regulations enforced 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, natural gas storage plants, and natural gas transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, and impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological and 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 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 our operations. The more significant matters are discussed below.

Clean Air Act

Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In May 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule). During 2008, the U.S. Court of Appeals for the District of Columbia issued separate decisions that vacated the federal Clean Air Interstate Rule and the federal Clean Air Mercury Rule. Other federal regulations remain in effect under the Clean Air Act for controlling SO2 and NOx emissions, including the Acid Rain Program and the NOx Budget Trading Program.

In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method used to remove electric generating units from the list of sources subject to the maximum available control technology requirements under the Clean Air Act. The EPA and a group representing the electric utility industry filed petitions for rehearing; however, the court denied those petitions in May 2008. A group representing the electric utility industry and the EPA filed petitions for review of the U.S. Court of Appeals decision with the U.S. Supreme Court in September 2008 and October 2008, respectively.

In July 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Interstate Rule. The court ruled that the regulation contained several fatal flaws, including a regional cap-and-trade program that cannot be used to facilitate the attainment of ambient air quality standards for ozone and fine particulate matter. In September 2008, the EPA as well as several environmental groups, a group representing the electric utility industry and the National Mining Association filed petitions for rehearing with the U.S. Court of Appeals. If the court denies these petitions, remedy could be sought with a petition for review by the U.S. Supreme Court.

We are currently evaluating the impact that these court decisions will have on our environmental compliance strategy. At this time, we are unable to predict the outcome of these legal proceedings, the actions the EPA or U.S. Congress may take in response to these court decisions and the timing of such actions. We also cannot predict at this time the ultimate impact these court decisions and resulting regulatory actions will have on our estimated capital costs for compliance with environmental rules.

Illinois and Missouri regulators will likely need to evaluate the impact of the U.S. Court of Appeals decision to vacate the federal Clean Air Interstate Rule. Both states had relied on the federal Clean Air Interstate Rule when adopting their respective state regulations. Such regulations will remain in effect until appeals relating to the U.S. Court of Appeals decision have been completed and Illinois and Missouri determine whether revisions to their implementing regulations are required.

We do not believe the recent court decisions that vacated the federal Clean Air Interstate Rule and the federal Clean Air Mercury Rule will significantly affect pollution control obligations in Illinois. Illinois regulations incorporate an agreement, which was reached in 2006 among Genco, CILCO (AERG), EEI and the Illinois EPA. Under the agreement, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NOx and SO2 controls. This agreement was codified in Illinois regulations and is referred to as the Multi-Pollutant Standard (MPS) rule. To comply with the rule, in 2009, Genco, CILCO (AERG) and EEI will begin putting into service equipment designed to reduce mercury emissions. This rule, when fully implemented, is expected to reduce mercury emissions 90%, NOx emissions 50%, and SO2 emissions 70% by 2015 in Illinois.

On October 1, 2008, Genco, CILCO (AERG) and EEI submitted a request for a variance from the MPS rule to the Illinois Pollution Control Board. In reparing this request Genco, CILCO (AERG) and EEI worked with the Illinois EPA and agreed to the installation of more stringent SO2 and NOx controls at various stages between 2010 and 2020 in order to make the variance proposal "environmentally neutral." If granted, this variance would allow Genco to defer approximately $500 million of environmental capital expenditures from the 2009-2012 timeframe to the 2013-2015 timeframe. The Illinois Pollution Control Board is expected to render a decision on this variance by January 31, 2009.

The state of Missouri had adopted the Federal Clean Air Interstate Rule for regulating SO2 and NOx emissions from coal-fired power plants in Missouri. The rules were a significant part of Missouri’s plan to attain existing ambient standards for ozone and fine particulates, as well as

meeting the Federal Clean Air Visibility Rule. The state will need to adopt new rules as a result of the U.S. Court of Appeals’ decision. It is anticipated that Missouri will adopt new replacement rules developed by the EPA next year. Currently, we do not anticipate independent state actions that will significantly affect our compliance strategy or compliance costs. However, this could change depending upon how the EPA will require the state to respond to the court’s decision.

The EPA finalized regulations in March 2008 that will lower the ambient standard for ozone. It is expected that areas will be designated as nonattainment in 2009 and that state implementation plans will need to be submitted in 2013 unless Illinois and Missouri seek extensions of various requirement dates. Additional emission reductions may be required as a result of the future state implementation plans. At this time, we are unable to determine the impact such state actions would have on our results of operations, financial position, or liquidity.

The table below presents estimated capital costs that were based on current technology to comply with the now vacated federal Clean Air Interstate Rule and federal Clean Air Mercury Rule and related state implementation plans through 2017 as well as federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility rule. Because of the 2008 U.S. Court of Appeals decisions to vacate the Clean Air Interstate Rule and the Clean Air Mercury Rule, the timing and ultimate amount of the capital costs are under review at this time. The estimates described below could change depending upon additional federal or state requirements, the ultimate outcome of any appeals relative to the Clean Air Interstate Rule and the Clean Air Mercury Rule U.S. Court of Appeals decisions, whether the variance request with respect to the Illinois MPS rule discussed above is granted, new technology, variations in costs of material or labor, or alternative compliance strategies, among other reasons. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with any future rules, thereby deferring capital investment.

	2008	2009 - 2012	2013 - 2017	Total
UE(a)	$ 255	$ 215- $ 295	$ 1,300-$1,700	$ 1,770- $ 2,250
Genco	300	955- 1,210	45- 70	1,300- 1,580
CILCO	170	380- 500	70- 90	620- 760
EEI	30	260- 350	20- 30	310- 410
Ameren	$ 755	$ 1,810- $2,355	$ 1,435-$1,890	$ 4,000- $ 5,000

(a)	UE’s expenditures are expected to be recoverable in rates over time.

Emission Allowances

The Clean Air Act, under the Acid Rain Program and the NOx Budget Trading Program, created marketable commodities called allowances. Currently each allowance gives the owner the right to emit one ton of SO2 or NOx. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. If additional allowances are needed for new generating facilities, they can be purchased from facilities that have excess allowances or from allowance banks. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, through the use of low-sulfur fuels, and through the application of pollution control technology. The NOx Budget Trading Program limits emissions of NOx during the ozone season (May through September). The NOx Budget Trading Program has applied to all electric generating units in Illinois since 2004; it was applied to the eastern third of Missouri, where UE’s coal-fired power plants are located, in 2007. Our generating facilities are expected to comply with the NOx limits through the use and purchase of allowances or through the application of pollution control technology, including low-NOx burners, over-fire air systems, combustion optimization, rich-reagent injection, selective noncatalytic reduction, and selective catalytic reduction systems. See Note 1 - Summary of Significant Accounting Policies for the SO2 and NOx emission allowances held and the related SO2 and NOx emission allowance book values that were carried as intangible assets as of September 30, 2008.

UE, Genco, CILCO and EEI expect to use a substantial portion of their SO2 and NOx allowances for ongoing operations. Environmental regulations, 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.

The federal Clean Air Interstate Rule required a reduction in SO2 emissions by increasing the ratio of Acid Rain Program allowances surrendered for each ton of SO2 emitted. As discussed above, in July 2008 the U.S. Court of Appeals for the District of Columbia vacated the federal Clean Air Interstate Rule and in September 2008, the EPA and other groups petitioned the court for rehearing of its decision. If the U.S. Court of Appeals decision is not reversed, then SO2 allowances will only be used for the Acid Rain Program with the value of one SO2 allowance for each ton emitted. Additionally, the annual NOx trading program under the federal Clean Air Interstate Rule will no longer be required; however, we expect the existing NOx Budget Trading Program to continue. We evaluated the impact of the court’s decision on the recoverability of the carrying amounts of our emission allowances and concluded that our emission allowances were not impaired as a result of the ruling.

Global Climate

Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. In June 2008, the U.S. Senate considered legislation proposed by Senators Lieberman, Warner, and Boxer that would set up a “cap and trade” program for greenhouse gas emissions. That legislation was not approved by the U.S. Senate. In October 2008, the U.S. House of Representatives, Energy and Commerce Committee, Subcommittee on Energy and Air Quality issued a “discussion draft” of climate legislation. The discussion draft proposes establishing an economy-wide cap and trade program. The overarching goal of such legislation is to reduce greenhouse gas emissions to a level that is 6% below 2005 levels by 2020 and 80% below 2005 levels by the year 2050. In addition, individual members of Congress have proposed cap and trade legislation. However, it is unlikely that such legislation will be taken up this year.

In addition, President Bush has supported climate initiatives that would focus on technology development to eliminate the growth in greenhouse gas emissions by 2025, a proposal much more moderate than the Lieberman-Warner-Boxer legislation that was considered in the Senate. In July 2008, the “Group of Eight” (G8) countries, which includes the U.S., issued a statement that they had agreed to consider and adopt a greenhouse gas reduction target of 50% by 2050. This agreement was a significant departure from prior Bush administration policy.

The outcome of these initiatives cannot be determined at this time. However, President-elect Obama has expressed support for a greenhouse gas emissions cap and trade program. Therefore, the likelihood that some form of federal greenhouse gas legislation will become law increases under the next presidential administration.

Ameren believes that currently-proposed legislation can be classified as moderate to extreme depending upon proposed CO2 emission limits, the timing of implementation of those limits, and the method of allocating allowances. The moderate scenarios include provisions for a “safety valve” that provides a ceiling price for emission allowance purchases. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of CO2, a principal greenhouse gas. Ameren’s current analysis shows that under some policy scenarios being considered in Congress, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of the region's reliance on electricity generated by coal-fired power plants. Natural gas emits about half the amount of CO2 that coal emits. As a result, economy-wide shifts favoring natural gas as a fuel source for electric generation also could affect nonelectric transportation, heating for our customers and many industrial processes. Under some policy scenarios being considered by Congress, Ameren believes that wholesale natural gas costs could rise significantly as well. Higher costs for energy could contribute to reduced demand for electricity and natural gas.

Future initiatives regarding greenhouse gas emission and global warming may also be subject to the activities of the Midwest Greenhouse Gas Reduction Accord - an agreement signed by the governors of Illinois, Iowa, Kansas, Michigan, Wisconsin and Minnesota - to develop a strategy to achieve energy security and reduce greenhouse gas emissions through a cap and trade mechanism. It is expected that the advisory group to the midwest governors will provide recommendations on the design of a greenhouse gas reduction program by the third quarter of 2009. However, it is uncertain if legislation to implement the recommendations will be implemented or passed by the state of Illinois.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. The costs to comply with future legislation or regulations could be so expensive that Ameren and other similarly-situated electric power generators may be forced to close some coal-fired facilities. Mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and EEI’s results of operations, financial position, or liquidity.

With regard to greenhouse gas regulation under existing law, in April 2007, the U.S. Supreme Court issued a decision that determined that the EPA has the authority to regulate CO2 and other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. The Supreme Court sent the case back to the EPA, which must conduct a rulemaking process to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” In July 2008, the EPA issued an advance notice of public rulemaking (ANPR) in response to the U.S. Supreme Court’s directive. The ANPR invites public comments on the benefits and ramifications of regulating greenhouse gases under the Clean Air Act. However, in a preface to the ANPR, EPA Administrator, Stephen Johnson, expressed a concern that the Clean Air Act is ill-suited for this purpose and would result in a convoluted and ineffective set of regulations. New regulations resulting from the rulemaking process are not expected this year, but the EPA could begin to regulate greenhouse gas emissions at some point in the future.

Ameren has taken actions to address the global climate issue. These include:

·	seeking partners to develop wind energy for our generation portfolio;

·	participating in DOE-sponsored research into the feasibility of sequestering CO2 underground in the Illinois basin, the Plains sequestration partnership, and a Missouri sequestration project to be conducted in Southwest Missouri;

·	increasing the operating efficiency and capacity of our nuclear and hydroelectric plants to provide more energy to offset fossil generation;

·	participating in the PowerTree Carbon Company, LLC, whose purpose is to reforest acreage in the lower Mississippi valley to sequester carbon;

·	using coal combustion by-products as a direct replacement for cement, thereby reducing carbon emissions at cement kilns;

·	participating in a DOE and state of Missouri Department of Natural Resources project evaluating Missouri wind resources for the next generation of wind turbines;

·	funding a project investigating opportunities to reduce nitrous oxide (N2O), a potent greenhouse gas from agricultural usage and tracking those reductions;

·	participating in “Illinois Clean Energy Community Foundation”, a program that supports energy efficiency, promotes renewable energy, and provides educational opportunities;

·	establishing Pure Power, UE’s voluntary renewable energy program that allows UE’s electric customers to support development of wind farms and other renewable energy facilities in the Midwest; and

·	purchasing Renewable Energy Credits - the Ameren Illinois Utilities purchased 415,000 renewable energy credits in April 2008.

The impact on us of future initiatives related to greenhouse gas emissions and global warming is unknown. Although compliance costs are unlikely in the near future, our costs of complying with any mandated federal or state greenhouse gas program could have a material impact on our future results of operations, financial position, or liquidity.

Clean Water Act

In July 2004, the EPA issued rules under the Clean Water Act that require cooling-water intake structures to have the best technology available for minimizing adverse environmental impacts on aquatic species. These rules pertain to all existing generating facilities that currently employ a cooling-water intake structure whose flow exceeds 50 million gallons per day. The rules may require us to install additional intake screens or other protective measures and to do extensive site-specific study and monitoring. There is also the possibility that the rules may lead to the installation of cooling towers on some of our facilities. In January 2007, the U.S. Court of Appeals for the Second Circuit remanded many provisions of these rules to the EPA for revision. In April 2008, the U.S. Supreme Court agreed to hear an appeal of the lower court ruling. The U.S. Supreme Court is expected to hear the case by the end of 2008. However, the EPA is expected to reissue the rules early in 2009. Until a decision is issued by the Supreme Court, the new rules are adopted and the studies on the power plants are completed, we are unable to estimate the costs of complying with these rules. Such costs are not expected to be incurred prior to 2012.

New Source Review

The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric generators in the United States are subject to New Source Review (NSR) 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 performed.

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. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren’s Illinois coal-fired power plants. We are in the process of responding to this request. We are currently in discussions with the EPA and the state of Illinois regarding resolution of these matters, but we are unable to predict the outcome of these discussions.

In March 2008, Ameren 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 UE’s Labadie, Meramec, Rush Island, and Sioux facilities. All of these facilities are coal-fired power plants. The information request required UE to provide responses to specific EPA questions regarding certain projects and maintenance activities to determine compliance with state and federal regulatory requirements. UE is complying with this information request, but we are unable to predict the outcome of this matter.

Resolution of these matters could have a material adverse impact on the future results of operations, financial position or liquidity of Ameren, UE, Genco, AERG and EEI. A resolution could result in increased capital expenditures for the installation of control technology, increased operations and maintenance expenses, and fines or penalties.

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 degree 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. Some of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and facilities transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS and CILCO have contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of September 30, 2008, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 14, CILCO four, and IP 25. 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 its former MGP sites from its Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred, and costs are subject to annual reconciliation review by the ICC. As of September 30, 2008, estimated obligations were: CIPS - $18 million to $31 million, CILCO - $10 million to $15 million, and IP - $77 million to $145 million. CIPS, CILCO and IP recorded liabilities of $18 million, $10 million and $77 million, respectively, to provide for estimated minimum obligations, as no other amount within the range was a better estimate.

CIPS is also responsible for the cleanup of a former landfill in Coffeen, Illinois. As of September 30, 2008, CIPS estimated its obligation at $0.5 million to $6 million. CIPS recorded a liability of $0.5 million to represent its estimated minimum obligation for this site as no other amount within the range was a better estimate. IP is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of September 30, 2008, IP recorded a liability of $1 million to represent its best estimate of the obligation for these sites.

In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. UE does not currently have in effect in Missouri a rate rider mechanism that permits remediation costs associated with MGP sites to be recovered from utility customers. UE does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs. As of September 30, 2008, UE estimated its obligation at $3 million to $5 million. UE recorded a liability of $3 million to represent its estimated minimum obligation for its MGP sites as no other amount within the range was a better estimate. UE also is responsible for four electric sites in Missouri that have corporate cleanup liability, most as a result of federal agency mandates.

In June 2000, the EPA notified UE and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2. UE 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 (PRPs) to evaluate the extent of potential contamination with respect to Sauget Area 2.

Sauget Area 2 investigation activities under the oversight of the EPA are largely completed, and the results will be submitted to the EPA in June 2009. Following this submission, the EPA will ultimately select a remedy alternative and begin negotiations with various PRPs to implement it. Over the last several years, numerous other parties have joined the PRP group and presumably will participate in the funding of any required remediation. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection. As of September 30, 2008, UE estimated its obligation at $0.8 million to $10 million. UE recorded a liability of $0.8 million to represent its estimated minimum obligation as no other amount within the range was a better estimate.

In March 2008, the EPA issued an administrative order to CIPS requesting that it participate in a portion of an environmental cleanup of a site within Sauget Area 2 previously occupied by Clayton Chemical Company. CIPS was formerly a customer of Clayton Chemical Company that, before its dissolution, was a recycler of waste solvents and oil. Other former customers of Clayton Chemical Company were issued similar orders by the EPA. Pursuant to that order, CIPS and three other PRPs agreed to install an engineered barrier on portions of the Clayton Chemical Company site. This work is expected to be concluded by the first quarter of 2009 or earlier. As of September 30, 2008,

CIPS recorded a liability of $0.25 million to represent its best estimate of its obligation for this site.

In July 2008, the EPA issued an administrative order to UE pertaining to a former coal tar distillery operated by Koppers Company or its predecessor and successor companies. UE is the current owner of the site but did not conduct any of the manufacturing operations involving coal tar or its by-products. UE is currently in negotiations with other PRPs concerning the scope of future site investigations. As of September 30, 2008, UE estimated its obligation at $2 million to $5 million. UE recorded a liability of $2 million to represent its estimated minimum obligation as no other amount within the range was a better estimate.

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 $1 million at September 30, 2008, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort, which involves treating and discharging 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 of 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.

Polychlorinated Biphenyls Information Request

Polychlorinated biphenyls (PCBs) are a blend of chemical compounds that were historically used in a variety of industrial products because of their chemical and thermal stability. In natural gas systems, PCBs were used as a compressor lubricant and a valve sealant before their sale for these applications was banned by the EPA in 1979. During the third quarter of 2007, the Ameren Illinois Utilities received requests from the Illinois attorney general and the EPA for information regarding their experiences with PCBs in their gas distribution systems. The Ameren Illinois Utilities responded to these information requests.

The Ameren Illinois Utilities evaluated their gas distribution systems for the presence of PCBs. They believe that the presence of PCBs is limited to discrete areas and is not widespread throughout their service territories. We cannot predict whether any further actions will be required on the part of the Ameren Illinois Utilities regarding this matter or what the ultimate outcome will be.

Pumped-storage Hydroelectric Facility Breach

UE has settled all state and federal issues associated with the December 2005 Taum Sauk incident. In addition, UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and has begun rebuilding the facility. The estimated cost to rebuild the upper reservoir is in the range of $480 million. UE expects the Taum Sauk plant to be out of service through early 2010.

In December 2006, 10 business owners filed a lawsuit regarding the Taum Sauk breach. The suit, which was filed in the Missouri Circuit Court of Reynolds County and remains pending, contains allegations of negligence, violations of the Missouri Clean Water Act, and various other statutory and common law claims and seeks damages relating to business losses, lost profit, and unspecified punitive damages. UE has filed a motion to dismiss the lawsuit, arguing that Missouri law does not permit the plaintiffs to recover purely economic loss under theories of negligence and strict liability. This motion is currently pending.

At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. UE expects that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the reservoir, will range from $202 million to $222 million. As of September 30, 2008, UE had paid $174 million, including costs resulting from the FERC-approved stipulation and consent agreement, and accrued a $28 million liability while expensing $34 million and recording a $168 million receivable due from insurance companies. As of September 30, 2008, UE had received $79 million from insurance companies, which reduced the insurance receivable balance to $89 million.

As of September 30, 2008, UE had recorded a $263 million receivable due from insurance companies related to the rebuilding of the facility and the reimbursement for replacement power costs. As of September 30, 2008, UE had received $150 million from insurance companies, which reduced the insurance receivable balance as of September 30, 2008, to $113 million.

Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.

In September 2007, the Missouri Coalition for the Environment, the Sierra Club, and American Rivers filed a motion to seek intervention and rehearing and a stay of FERC authorization granted to UE to rebuild the upper reservoir at its Taum Sauk plant. In December 2007, FERC granted intervention, denied rehearing, and dismissed the request for stay. In February 2008, the Missouri Coalition for the Environment and the Missouri Parks Association filed an appeal of FERC’s decision with the U.S. Court of Appeals for the Eighth Circuit. In October 2008, the Court of Appeals denied this appeal.

Until litigation has been resolved and the insurance review is completed, among other things, we are unable to determine the total impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.

Mechanics’ Liens

Approximately 20 mechanics’ liens have been filed by various subcontractors who provided labor or material for a 2007 maintenance outage at the Duck Creek facility of AERG. The total lien claim amount was $26 million plus interest at September 30, 2008. In November 2007, the primary subcontractor on the project filed a complaint for foreclosure of its mechanic’s lien of $19 million plus interest against AERG in the Circuit Court of Fulton County, Illinois. Since that time, various second tier subcontractors of the primary subcontractor have filed for foreclosure of their mechanics’ lien claims against AERG in the Circuit Court of Fulton County, Illinois in addition to filing their claim against the primary subcontractor. These claims were primarily based on additional work outside of the original contract scope and were not approved by AERG. Since the time of the lien filings, the primary subcontractor on the project has paid or has agreed to pay approximately $4 million of the second tier subcontractors’ claims. In addition, AERG has paid approximately $1 million to various parties that have claims against the primary subcontractor. AERG plans to deduct these payments from a contract-allowed holdback of $4 million. AERG has filed its answers to the claims in the foreclosure lawsuits denying the validity of the liens. At this time, we do not believe that the resolution of these liens and lawsuits will have a material impact on CILCO’s or AERG’s results of operations, financial position, or liquidity.

Asbestos-related Litigation

Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case is significant; as many as 161 parties are named in some pending cases and as few as six in others. However, in the cases that were pending as of September 30, 2008, the average number of parties was 67.

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 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 and CILCO have contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages, which, if awarded at trial, typically would be shared among various defendants.

From July 1, 2008, through September 30, 2008, one additional asbestos-related lawsuit was filed against UE, CIPS, CILCO and IP, in the Circuit Court of Madison County, Illinois. Seven lawsuits were dismissed. The following table presents the status as of September 30, 2008, 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	367	33	202	152	2	50	182
Settled	131	-	68	60	-	20	66
Dismissed	171	30	112	61	2	19	82
Pending	65	3	22	31	-	11	34

(a)	Totals do not equal to the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.

As of September 30, 2008, 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.

IP has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms. 90% of cash expenditures in excess of the amount included in base electric rates are recovered by IP from a trust fund established

by IP and financed with contributions of $10 million each by Ameren and Dynegy. At September 30, 2008, the trust fund balance was $23 million, including accumulated interest.

If cash expenditures are less than the amount in base rates, IP will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider.

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.

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 before 2020. 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. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. It is assumed that the Callaway nuclear plant site will be decommissioned based on the immediate dismantlement method and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are charged to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2007, 2006 and 2005. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest cost study was filed in September 2008. The 2008 study included the minor tritium contamination discovered on the Callaway nuclear plant site, which did not result in a significant increase in the decommissioning cost estimate. 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 a regulatory asset or regulatory liability, as appropriate.

See Note 2 - Rate and Regulatory Matters for information on the COLA filed by UE with the NRC for a potential new nuclear plant.

NOTE 11 - 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, 2008 and 2007, is shown below for the Ameren Companies:

	Three Months						Nine Months
	2008			2007			2008			2007
Ameren:(a)
Net income	$	204		$	244		$	548		$	510
Unrealized net gain on derivative hedging instruments, net of taxes of $89, $8, $26 and $6, respectively		157			15			46			10
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $23, $9, $17 and $19, respectively		(40	)		(17	)		(29	)		(33	)
Adjustment to pension and benefit obligation, net of taxes (benefit) of $-, $1, $1 and $(2), respectively		-			1			(2	)		2
Total comprehensive income, net of taxes	$	321		$	243		$	563		$	489


	Three Months						Nine Months
	2008			2007			2008			2007
UE:
Net income	$	99		$	193		$	287		$	307
Unrealized net gain on derivative hedging instruments, net of taxes of $23, $3, $12 and $3, respectively		38			5			21			4
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $2, $1, $3 and $2, respectively		(4	)		(1	)		(5	)		(3	)
Total comprehensive income, net of taxes	$	133		$	197		$	303		$	308
CIPS:
Net income	$	7		$	1		$	7		$	19
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $-, $- and $1, respectively		-			(1	)		-			(1	)
Total comprehensive income, net of taxes	$	7		$	-		$	7		$	18
Genco:
Net income	$	20		$	25		$	140		$	84
Unrealized net (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $-, $- and $(1), respectively		-			-			-			(2	)
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $-, $4 and $-, respectively		-			-			(5	)		-
Adjustment to pension and benefit obligation, net of taxes (benefit) of $-, $1, $(2) and $(1), respectively		-			1			3			(1	)
Total comprehensive income, net of taxes	$	20		$	26		$	138		$	81
CILCORP:
Net income	$	18		$	1		$	42		$	34
Unrealized net (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $(1), $- and $-, respectively		-			(1	)		-			(1	)
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $-, $1 and $1, respectively		-			-			(1	)		(2	)
Adjustment to pension and benefit obligation, net of taxes of $-, $-, $1 and $-, respectively		-			-			3			1
Total comprehensive income, net of taxes	$	18		$	-		$	44		$	32
CILCO:
Net income	$	24		$	10		$	62		$	58
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $-, $- and $1, respectively		-			-			-			(2	)
Adjustment to pension and benefit obligation, net of taxes of $-, $-, $3 and $-, respectively		-			-			4			-
Total comprehensive income, net of taxes	$	24		$	10		$	66		$	56
IP:
Net income (loss)	$	5		$	(4	)	$	(2	)	$	18
Total comprehensive income (loss), net of taxes	$	5		$	(4	)	$	(2	)	$	18

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

NOTE 12 - STOCKHOLDER RIGHTS PLAN

Ameren’s stockholder rights plan expired on October 9, 2008. Ameren’s Board of Directors decided not to renew the plan.

NOTE 13 - RETIREMENT BENEFITS

Ameren's pension and postretirement plans are funded in compliance with income tax regulations, federal funding requirements and state regulatory agreements. In May 2007, the MoPSC issued an electric rate order for UE that allows UE to recover, through customer rates, pension expense incurred under GAAP. Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Based on Ameren's assumptions at December 31, 2007, and declining investment performance in 2008, and reflecting Ameren’s pension funding policy, Ameren expects annual contributions of $50 million to $200 million in each of the next five years. These amounts are estimates and may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association trusts to match the annual postretirement expense.

Ameren made contributions to its pension and postretirement benefit plans of $32 million and $22 million, respectively, during the nine months ended September 30, 2008, as compared to a $26 million contribution to its postretirement plan during the nine months ended September 30, 2007.

The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three months and nine months ended September 30, 2008 and 2007:

	Pension Benefits(a)												Postretirement Benefits(a)
	Three Months						Nine Months						Three Months						Nine Months
	2008			2007			2008			2007			2008			2007			2008			2007
Service cost	$	15		$	16		$	44		$	47		$	5		$	5		$	14		$	15
Interest cost		46			45			139			135			17			18			52			54
Expected return on plan assets		(53	)		(51	)		(159	)		(154	)		(14	)		(13	)		(43	)		(39	)
Amortization of:
Transition obligation		-			-			-			-			1			1			2			2
Prior service cost (benefit)		3			3			9			9			(2	)		(2	)		(6	)		(6	)
Actuarial loss		1			5			2			16			2			6			6			18
Net periodic benefit cost	$	12		$	18		$	35		$	53		$	9		$	15		$	25		$	44

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries.

UE, CIPS, Genco, CILCORP, CILCO and IP are participants in Ameren’s plans and are responsible for their proportional share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three months and nine months ended September 30, 2008 and 2007:

	Pension Costs									Postretirement Costs
	Three Months				Nine Months					Three Months				Nine Months
	2008		2007		2008			2007		2008		2007		2008		2007
Ameren(a)	$	12	$	18	$	35		$	53	$	9	$	15	$	25	$	44
UE		8		10		27			30		4		7		10		22
CIPS		2		2		5			6		-		2		2		5
Genco		1		2		4			4		-		1		1		3
CILCORP		-		2		(2	)		7		2		2		2		5
CILCO		1		2		3			7		3		3		5		8
IP		-		1		(2	)		4		3		2		10		8

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries.

NOTE 14 - SEGMENT INFORMATION

Ameren has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s former 40% interest in EEI and other non-rate regulated activities, which are included in Other. UE’s interest in EEI was transferred to Resources Company on February 29, 2008. The Illinois Regulated segment for Ameren consists of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO, and IP, as described in Note 1 - Summary of Significant Accounting Policies. The Non-rate-regulated Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, and Marketing Company. The category called Other primarily includes Ameren parent company activities and the leasing activities of CILCORP, AERG, Resources Company, and CIPSCO Investment Company. CIPSCO Investment Company was eliminated on March 31, 2008, through an internal reorganization.

UE has one reportable segment: Missouri Regulated. The Missouri Regulated segment for UE includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s former 40% interest in EEI and other non-rate-regulated activities, which are included in Other.

CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP and CILCO consists of the regulated electric and gas transmission and distribution businesses of CILCO. The Non-rate-regulated Generation segment for CILCORP and CILCO consists of the generation business of AERG. For CILCORP and CILCO, Other comprises parent company activity and minor activities not reported in the Illinois Regulated or Non-rate-regulated Generation segments for CILCORP.

The following table presents information about the reported revenues and specified items included in net income of Ameren for the three months and nine months ended September 30, 2008 and 2007, and total assets as of September 30, 2008 and December 31, 2007.

Three Months	Missouri Regulated		Illinois Regulated			Non-rate- regulated Generation		Other			Intersegment Eliminations			Consolidated
2008:
External revenues	$	865	$	724		$	478	$	(7	)	$	-		$	2,060
Intersegment revenues		10		7			114		3			(134	)		-
Net income (loss)(a)		98		13			108		(15	)		-			204
2007:
External revenues	$	934	$	704		$	372	$	(13	)	$	-		$	1,997
Intersegment revenues		11		21			125		10			(167	)		-
Net income (loss)(a)		178		(8	)		71		3			-			244
Nine Months
2008:
External revenues	$	2,340	$	2,487		$	1,110	$	(6	)	$	-		$	5,931
Intersegment revenues		30		30			341		11			(412	)		-
Net income (loss)(a)		272		15			284		(23	)		-			548
2007:
External revenues	$	2,258	$	2,513		$	980	$	(1	)	$	-		$	5,750
Intersegment revenues		34		34			386		30			(484	)		-
Net income(a)		263		45			197		5			-			510
As of September 30, 2008:
Total assets	$	11,037	$	6,363		$	4,269	$	1,037		$	(1,227	)	$	21,479
As of December 31, 2007:
Total assets	$	10,852	$	6,385		$	4,027	$	965		$	(1,501	)	$	20,728

(a)	Represents net income available to common shareholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

The following table presents information about the reported revenues and specified items included in net income of UE for the three months and nine months ended September 30, 2008 and 2007, and total assets as of September 30, 2008 and December 31, 2007.

Three Months	Missouri Regulated		Other (a)		Consolidated UE
2008:
Revenues	$	875	$	-	$	875
Net income(b)		98		-		98
2007:
Revenues	$	945	$	-	$	945
Net income(b)		178		14		192
Nine Months
2008:
Revenues	$	2,370	$	-	$	2,370
Net income(b)		272		11		283
2007:
Revenues	$	2,292	$	-	$	2,292
Net income(b)		263		40		303
As of September 30, 2008:
Total assets	$	11,037	$	-	$	11,037
As of December 31, 2007:
Total assets	$	10,852	$	51	$	10,903

(a)	Included 40% interest in EEI through February 29, 2008.

(b)	Represents net income available to the common shareholder (Ameren).

The following table presents information about the reported revenues and specified items included in net income of CILCORP for the three months and nine months ended September 30, 2008 and 2007, and total assets as of September 30, 2008 and December 31, 2007.

Three Months	Illinois Regulated		Non-rate- regulated Generation		CILCORP Other		Intersegment Eliminations			Consolidated CILCORP
2008:
External revenues	$	162	$	102	$	-	$	-		$	264
Intersegment revenues		1		-		-		(1	)		-
Net income(a)		4		14		-		-			18

2007:
External revenues	$	144		$	67	$	-	$	-		$	211
Intersegment revenues		-			1		-		(1	)		-
Net income (loss)(a)		(4	)		5		-		-			1
Nine Months
2008:
External revenues	$	590		$	252	$	-	$	-		$	842
Intersegment revenues		3			-		-		(3	)		-
Net income(a)		15			27		-		-			42
2007:
External revenues	$	547		$	205	$	-	$	-		$	752
Intersegment revenues		-			3		-		(3	)		-
Net income(a)		11			23		-		-			34
As of September 30, 2008:
Total assets(b)	$	1,231		$	1,616	$	2	$	(222	)	$	2,627
As of December 31, 2007:
Total assets(b)	$	1,202		$	1,455	$	1	$	(199	)	$	2,459

(a)	Represents net income available to the common shareholder (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

(b)	Total assets for Illinois Regulated and Non-rate-regulated Generation include an allocation of goodwill and other purchase accounting amounts related to CILCO that are recorded at CILCORP (parent company).

The following table presents information about the reported revenues and specified items included in net income of CILCO for the three months and nine months ended September 30, 2008 and 2007, and total assets as of September 30, 2008 and December 31, 2007.

Three Months	Illinois Regulated			Non-rate- regulated Generation		CILCO Other		Intersegment Eliminations			Consolidated CILCO
2008:
External revenues	$	162		$	102	$	-	$	-		$	264
Intersegment revenues		1			-		-		(1	)		-
Net income(a)		4			20		-		-			24
2007:
External revenues	$	144		$	67	$	-	$	-		$	211
Intersegment revenues		-			1		-		(1	)		-
Net income (loss)(a)		(4	)		14		-		-			10
Nine Months
2008:
External revenues	$	590		$	252	$	-	$	-		$	842
Intersegment revenues		3			-		-		(3	)		-
Net income(a)		15			46		-		-			61
2007:
External revenues	$	547		$	205	$	-	$	-		$	752
Intersegment revenues		-			3		-		(3	)		-
Net income(a)		11			46		-		-			57
As of September 30, 2008:
Total assets	$	1,042		$	1,007	$	-	$	(1	)	$	2,048
As of December 31, 2007:
Total assets	$	1,012		$	859	$	-	$	(9	)	$	1,862

(a)	Represents net income available to the common shareholder (CILCORP); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

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

The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q as well as Management’s Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors contained in the Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements, and the primary factors that accounted for those changes, as well as how certain accounting principles affect our financial statements. The discussion also provides information about the financial results of the various segments of our business to provide a better understanding of how those segments and their results affect the financial condition and results of operations of Ameren as a whole.

OVERVIEW

Ameren Executive Summary

Ameren’s earnings in the third quarter of 2008 were lower than its earnings in the 2007 comparable period principally because of net unrealized mark-to-market losses from nonqualifying hedges, the negative impacts of milder summer weather, higher fuel prices, increased spending on utility distribution system reliability, and higher other operating expenses. These factors more than offset the positive impacts of the reduced impact in 2008 of the Illinois electric settlement agreement, higher electric margins from Non-rate-regulated Generation’s operations, and the timing benefit of seasonally redesigned electric rates in Illinois.

Ameren’s earnings in the first nine months of 2008 exceeded its earnings in the comparable period in 2007 principally because of the impact of net unrealized mark-to-market gains from nonqualifying hedges; a lump-sum payment in July 2008 from a coal supplier for expected higher fuel costs for our Non-rate-regulated Generation segment in 2009 as a result of the premature closure of a mine in late 2007 and the resulting termination of a contract; the absence of costs in 2008 that were incurred in January 2007 associated with electric outages caused by severe ice storms; the estimated minimum amount of January 2007 storm costs that UE expects to recover, as a result of an accounting order issued by the MoPSC, which was recorded as a regulatory asset in the second quarter of 2008; a March 2007 FERC order that resettled costs among market participants retroactive to 2005; and the reduced impact in 2008 of the Illinois electric settlement agreement.

In September 2008, the ICC authorized increases in electric and natural gas rates for CIPS, CILCO and IP totaling $161 million. The new Illinois rates went into effect on October 1, 2008. These increased rates will improve the earnings and cash flows of the Ameren Illinois Utilities from depressed levels. However, the Ameren Illinois Utilities continue to expect that these rates will not keep pace with the level of costs they are currently experiencing. Consequently, the Ameren Illinois Utilities are evaluating the timing of their next rate case filings in Illinois. The Ameren Illinois Utilities expect to file rate cases more frequently in the future to minimize regulatory lag as well as to make bill increases more manageable for customers.

UE’s pending electric rate case is progressing. UE requested an annual electric revenue increase of approximately $251 million due to higher costs across its business, including fuel and reliability costs, as well as higher infrastructure investments. The MoPSC staff filed in August 2008 a report and direct testimony with the MoPSC recommending a $51 million increase, and the staff did not support UE’s request for a fuel and purchased power cost recovery mechanism. UE expects the MoPSC to issue a rate order in late January or early February 2009, with new rates effective March 1, 2009.

The global financial markets have experienced extreme volatility and disruption in 2008, and in particular, since early September. This disruption has lead to major financial institutions coming under financial duress, significant strains in the capital and credit markets, deteriorating global economic conditions and steep declines in stock prices.

We believe that the extreme disruption in the capital and credit markets has made our ability to access the capital and credit markets to support our operations and refinance short-term debt more challenging. We are proactively taking prudent actions to modify our short-term plans to address the current economic and financial market uncertainties. At October 31, 2008, our available liquidity, which represents our cash on hand and amounts available under our credit facilities, was approximately $1.45 billion, up about $550 million from this same time last year. Despite this solid liquidity position, we are reducing 2009 operating and capital expenditures in our Non-rate-regulated Generation business by a total of $400 million to $500 million. Operating and capital expenditures in 2009 for this business will be approximately $300 million to $400 million below 2008 levels. Other meaningful capital expenditure deferral and reduction opportunities are also under review throughout the rest of our company. We will remain focused on prudently managing our operations and maintaining strong overall liquidity to meet our operating, capital and financing needs, as well as executing our long-term strategic plans.

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.

·	UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.

·	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, a subsidiary of CILCORP (a holding company), operates a rate-regulated electric and natural gas transmission and distribution business and a non-rate-regulated electric generation business (through its subsidiary, AERG) in Illinois.

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

In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps 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 average diluted common shares outstanding during the applicable period. All tabular dollar amounts are in millions, unless otherwise indicated.

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: winter heating and summer cooling demands. The vast majority of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. Non-rate-regulated Generation sales are also 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 global economic and political environment, weather, supply and demand, and many other factors. We do not currently have a fuel and purchased power cost recovery mechanism in Missouri for our electric utility business. We do have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses and purchased power cost recovery mechanisms for our Illinois electric delivery businesses. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, for a discussion of UE’s pending electric rate case, the September 24, 2008 ICC order in the Ameren Illinois Utilities rate proceedings and the Illinois electric settlement agreement. Fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Ameren’s net income decreased to $204 million, or 97 cents per share, in the third quarter of 2008, from $244 million, or $1.18 per share, in the third quarter of 2007. Net income in the third quarter of 2008 increased in the Illinois Regulated and Non-rate-regulated Generation segments by $21 million and $37 million, respectively, from the prior-year period, while net income in the Missouri Regulated segment declined by $80 million from the same period in 2007.

Ameren’s net income increased to $548 million, or $2.61 per share, in the first nine months of 2008, from $510 million, or $2.46 per share, in the first nine months of 2007. Net income increased in the Missouri Regulated and Non-rate-regulated Generation segments by $9 million and $87 million, respectively, in the first nine months of 2008 compared to the prior-year period, while net income in the Illinois Regulated segment decreased by $30 million from the same period in 2007.

Earnings were favorably impacted in the third quarter and first nine months of 2008 as compared with the same periods in 2007 by:

·	the reduced impact in 2008 of the electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities electric customers under the Illinois electric settlement agreement (15 cents per share and 8 cents per share, respectively);

·	the implementation of redesigned seasonal electric delivery service rates at the Ameren Illinois Utilities, which impacts quarterly earnings comparisons in 2008 but is not expected to have an impact on annual margins (11 cents per share and 5 cents per share, respectively); and

·	higher realized electric margins in the Non-rate-regulated Generation segment.

Earnings were negatively impacted in the third quarter and first nine months of 2008 as compared with the same periods in 2007 by:

·	higher fuel and related transportation prices, excluding net mark-to-market losses on fuel-related transactions, (8 cents per share and 25 cents per share, respectively);

·	unfavorable weather conditions (estimated at 18 cents per share in both periods);

·	increased distribution system reliability expenditures (6 cents per share and 20 cents per share, respectively);

·	higher plant operations and maintenance expense (2 cents per share and 10 cents per share, respectively);

·	higher labor and employee benefit costs (3 cents per share and 9 cents per share, respectively);

·	higher bad debt expenses (2 cents per share and 5 cents per share, respectively);

·	increased depreciation and amortization expense (2 cents per share and 5 cents per share, respectively); and

·	higher financing costs (1 cent per share and 7 cents per share, respectively).

In addition to the above items affecting both periods, earnings were favorably impacted in the first nine months of 2008 as compared with the first nine months of 2007 by:

a settlement agreement with a coal mine owner reached in June 2008 that reimbursed Genco, in the form of a lump-sum payment of $60 million, for increased costs for coal and transportation that it is incurring in 2008 ($33 million) and expects to incur in 2009 ($27 million) due to the premature closure of an Illinois mine at the end of 2007 (18 cents per share);

·	the absence of costs in 2008 that were incurred in 2007 relating to a refueling and maintenance outage at UE’s Callaway nuclear plant (16 cents per share);

·	net unrealized mark-to-market gains primarily related to energy-related transactions (6 cents per share);

·	the absence of costs in 2008 that were incurred in January 2007 associated with electric outages caused by severe ice storms (9 cents per share);

·	the minimum amount of January 2007 storm costs that UE expects to recover, as a result of an accounting order issued by the MoPSC, which was recorded as a regulatory asset (4 cents per share);

·	higher electric rates, lower depreciation expense and decreased income tax expense in the Missouri Regulated segment pursuant to the MoPSC electric rate order for UE issued in May 2007 (8 cents per share); and

·	a March 2007 FERC order that resettled costs among market participants retroactive to 2005 (5 cents per share).

Earnings were negatively impacted in the first nine months of 2008 as compared with the first nine months of 2007 by the absence in 2008 of the reversal, recorded in 2007, of the Illinois Customer Elect electric rate increase phase-in plan accrual (5 cents per share) and higher labor and employee benefit costs (4 cents per share).

Earnings were negatively impacted in the third quarter of 2008 as compared with the third quarter of 2007 by net unrealized mark-to-market losses on nonqualifying hedges primarily related to fuel-related transactions (20 cents per share).

The cents per share information presented above is based on average shares outstanding in the third quarter and first nine months of 2007.

Because it is 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, 2008 and 2007:

	Three Months					Nine Months
	2008		2007			2008			2007
Net income (loss):
UE(a)	$	98	$	192		$	283		$	303
CIPS		6		-			5			17
Genco		20		25			140			84
CILCORP		18		1			42			34
IP		4		(5	)		(4	)		16
Other(b)		58		31			82			56
Ameren net income	$	204	$	244		$	548		$	510

(a)	Includes earnings from a non-rate-regulated 40% interest in EEI through February 29, 2008.

(b)

Includes earnings from non-rate-regulated operations and an 80% interest in EEI held by Resources Company since February 29, 2008, as well as corporate general and administrative expenses, and intercompany eliminations. Prior to February 29, 2008, included a 40% interest in EEI held by Development Company, as well as corporate general and administrative expenses and intercompany eliminations.

Below is a table of income statement components by segment for the three months and nine months ended September 30, 2008 and 2007:

	Missouri Regulated			Illinois Regulated			Non-rate- regulated Generation			Other / Intersegment Eliminations			Total
Three Months 2008:
Electric margin	$	570		$	234		$	315		$	(23	)	$	1,096
Gas margin		10			50			-			(1	)		59
Other revenues		1			-			-			(1	)		-
Other operations and maintenance		(234	)		(149	)		(77	)		11			(449	)
Depreciation and amortization		(83	)		(60	)		(29	)		(8	)		(180	)
Taxes other than income taxes		(69	)		(24	)		(6	)		1			(98	)
Other income and (expenses)		15			3			(1	)		(4	)		13
Interest expense		(51	)		(34	)		(24	)		(4	)		(113	)
Income taxes		(60	)		(5	)		(61	)		13			(113	)
Minority interest and preferred dividends		(1	)		(2	)		(9	)		1			(11	)
Net income (loss)	$	98		$	13		$	108		$	(15	)	$	204
Three Months 2007:
Electric margin	$	677		$	186		$	265		$	(13	)	$	1,115
Gas margin		9			49			-			(1	)		57
Other revenues		1			1			-			(2	)		-
Other operations and maintenance		(222	)		(138	)		(77	)		20			(417	)
Depreciation and amortization		(81	)		(59	)		(28	)		(8	)		(176	)
Taxes other than income taxes		(70	)		(23	)		(6	)		2			(97	)
Other income and (expenses)		8			6			1			(4	)		11
Interest expense		(49	)		(35	)		(28	)		2			(110	)
Income taxes		(94	)		7			(49	)		6			(130	)
Minority interest and preferred dividends		(1	)		(2	)		(7	)		1			(9	)
Net income (loss)	$	178		$	(8	)	$	71		$	3		$	244
Nine Months 2008:
Electric margin	$	1,606		$	600		$	911		$	(40	)	$	3,077
Gas margin		55			239			-			(4	)		290
Other revenues		1			-			-			(1	)		-
Other operations and maintenance		(689	)		(446	)		(245	)		40			(1,340	)
Depreciation and amortization		(246	)		(181	)		(86	)		(21	)		(534	)
Taxes other than income taxes		(189	)		(91	)		(20	)		-			(300	)
Other income and (expenses)		40			10			-			(12	)		38
Interest expense		(142	)		(106	)		(74	)		(9	)		(331	)
Income taxes		(160	)		(5	)		(177	)		23			(319	)
Minority interest and preferred dividends		(4	)		(5	)		(25	)		1			(33	)
Net income (loss)	$	272		$	15		$	284		$	(23	)	$	548
Nine Months 2007:
Electric margin	$	1,579		$	572		$	766		$	(32	)	$	2,885
Gas margin		50			227			-			(4	)		273
Other revenues		2			3			-			(5	)		-
Other operations and maintenance		(668	)		(383	)		(234	)		55			(1,230	)
Depreciation and amortization		(252	)		(177	)		(85	)		(20	)		(534	)


	Missouri Regulated			Illinois Regulated			Non-rate- regulated Generation			Other / Intersegment Eliminations			Total
Taxes other than income taxes		(187	)		(89	)		(20	)		1			(295	)
Other income and (expenses)		24			16			3			(9	)		34
Interest expense		(146	)		(97	)		(81	)		8			(316	)
Income taxes		(135	)		(22	)		(132	)		10			(279	)
Minority interest and preferred dividends		(4	)		(5	)		(20	)		1			(28	)
Net income	$	263		$	45		$	197		$	5		$	510

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins for the three months and nine months ended September 30, 2008, compared with the same periods in 2007. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined as gas revenues less gas purchased for resale. We consider electric, interchange, and gas margins useful measures to analyze the change in profitability of our electric and gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these 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 provide elsewhere in this report.

Three Months	Ameren(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Electric revenue change:
Effect of weather (estimate)	$	(76	)	$	(30	)	$	(13	)	$	-		$	(8	)	$	(8	)	$	(25	)
Interchange revenues, excluding estimate weather impact of $44 million		(33	)		(33	)		-			-			-			-			-
Illinois electric settlement agreement, net of reimbursement		43			-			7			17			12			12			10
Illinois rate redesign		46			-			15			-			7			7			24
Net mark-to-market gains (losses) on energy contracts		55			(5	)		-			-			-			-			-
Other, including growth and Illinois customer switching		21			(6	)		(20	)		-			41			41			(13	)
Total electric revenue change	$	56		$	(74	)	$	(11	)	$	17		$	52		$	52		$	(4	)
Fuel and purchased power change:
Fuel:
Generation and other	$	18		$	13		$	-		$	12		$	(7	)	$	(9	)	$	-
Emission allowance sales (costs)		(1	)		(5	)		-			3			-			-			-
Net mark-to-market (losses) on fuel contracts		(111	)		(59	)		-			(30	)		(8	)		(8	)		-
Price		(29	)		(8	)		-			(14	)		(4	)		(4	)		-
Purchased power		57			26			28			1			(3	)		(3	)		31
Illinois rate redesign		(9	)		-			(3	)		-			(1	)		(1	)		(5	)
Total fuel and purchased power change	$	(75	)	$	(33	)	$	25		$	(28	)	$	(23	)	$	(25	)	$	26
Net change in electric margins	$	(19	)	$	(107	)	$	14		$	(11	)	$	29		$	27		$	22
Net change in gas margins	$	2		$	1		$	2		$	-		$	(3	)	$	(3	)	$	4
Nine Months
Electric revenue change:
Effect of weather (estimate)	$	(100	)	$	(35	)	$	(20	)	$	-		$	(11	)	$	(11	)	$	(34	)
UE electric rate increase		16			16			-			-			-			-			-
Interchange revenues, excluding estimated weather impact of $54 million		41			41			-			-			-			-			-
Illinois electric settlement agreement, net of reimbursement		24			-			4			8			6			6			6
FERC-ordered MISO resettlements - March 2007		(16	)		-			-			(12	)		(4	)		(4	)		-
Illinois rate redesign		16			-			5			-			2			2			9
Net mark-to-market gains on energy contracts		48			13			-			-			-			-			-
Other, including growth and Illinois customer switching		60			27			(55	)		19			71			71			(41	)
Total electric revenue change	$	89		$	62		$	(66	)	$	15		$	64		$	64		$	(60	)
Fuel and purchased power change:
Fuel:
Generation and other	$	(1	)	$	7		$	-		$	17		$	(26	)	$	(28	)	$	-


Nine Months	Ameren(a)			UE			CIPS		Genco			CILCORP			CILCO			IP
Emission allowance sales		2			(4	)		-		5			-			-			-
Net mark-to-market (losses) on fuel contracts		(12	)		(5	)		-		(2	)		-			-			-
Price		(88	)		(40	)		-		(31	)		(9	)		(9	)		-
Coal contract settlement		60			-			-		60			-			-			-
Purchased power		108			(6	)		60		25			(8	)		(8	)		63
Illinois rate redesign		2			-			1		-			1			1			-
FERC-ordered MISO resettlements - March 2007		32			11			7		-			3			3			11
Total fuel and purchased power change	$	103		$	(37	)	$	68	$	74		$	(39	)	$	(41	)	$	74
Net change in electric margins	$	192		$	25		$	2	$	89		$	25		$	23		$	14
Net change in gas margins	$	17		$	5		$	4	$	-		$	2		$	2		$	8

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

Ameren

Ameren’s electric margin decreased by $19 million, or 2% for the three months ended September 30, 2008, compared with the same period in 2007. However, Ameren’s electric margin increased by $192 million, or 7%, for the nine months ended September 30, 2008, compared with the same period in 2007. The following items had a favorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	Net mark-to-market gains on energy transactions of $55 million and $48 million for the third quarter and nine months ended September 30, 2008, respectively. These net unrealized gains were primarily related to nonqualifying hedges of changes in market prices for electricity.

Implementation of redesigned seasonal electric delivery service rates at the Ameren Illinois Utilities, effective January 1, 2008, increased electric margin by $37 million and $18 million for the three and nine months ended September 30, 2008, respectively. These redesigned seasonal delivery service rates have an impact on quarterly earnings comparisons but are not expected to impact annual margins.

·	The reduced impact of the Illinois electric settlement agreement increased electric margin by $43 million and $24 million for the three and nine months ended September 30, 2008, respectively.

·	Reduced net MISO purchased power costs of $16 million for the nine months ended September 30, 2008, due to the absence of the March 2007 FERC order that resettled costs in 2007 among market participants retroactive to 2005.

·	Other MISO net purchased power costs, excluding the effect of the March 2007 FERC order, decreased by $17 million and $9 million for the three and nine months ended September 30, 2008, respectively.

An increase in margin on interchange sales of $4 million for the nine months ended September 30, 2008, due to a 13% increase in realized sales prices and increased hydroelectric generation due to improved water levels. Interchange margin decreased $2 million during the third quarter of 2008 due primarily to lower overnight market prices.

Lower fuel expense as a result of Genco’s June 2008 agreement with a coal mine owner to receive a lump-sum payment of $60 million for the early termination of a contract. Genco is incurring incremental fuel costs in 2008 and in 2009 to replace coal from an Illinois mine that was prematurely closed by its owner at the end of 2007.

·	A 38-day planned refueling and maintenance outage at UE’s Callaway nuclear plant in the second quarter of 2007 that did not recur in the nine months ended September 30, 2008.

·	UE’s electric rate increase that went into effect June 4, 2007, which increased electric margin by an estimated $16 million for the nine months ended September 30, 2008.

The following items had an unfavorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

Net mark-to-market losses on fuel-related transactions of $111 million and $12 million for the third quarter and the nine months ended September 30, 2008, respectively. These net unrealized losses were primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

·	Unfavorable weather conditions, as evidenced by a 27% reduction in cooling degree-days for the third quarter and nine months ended September 30, 2008, decreased electric margin by an estimated $54 million and $63 million for the three and nine months ended September 30, 2008, respectively.

·	Excluding the impact of the agreement between Genco and a coal mine owner discussed above, fuel prices

increased 11% and 13% for the third quarter and the nine months of 2008, respectively.

Ameren’s gas margin increased by $2 million, or 4%, and $17 million, or 6%, for the three and nine months ended September 30, 2008, respectively, compared with the same periods in 2007. The following items had a favorable impact on gas margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	A September 24, 2008, ICC rate order concluded that a portion of non-recoverable purchased gas costs should be capitalized, resulting in a one-time increase in margin of $5 million for the third quarter and nine months ended September 30, 2008.

·	Favorable weather conditions, as evidenced by a 12% increase in heating degree-days, increased margin an estimated $8 million for the nine months ended September 30, 2008.

·	UE’s gas rate increase that went into effect April 1, 2007, increased margin by $1 million for the nine months ended September 30, 2008.

Missouri Regulated

UE’s electric margin decreased by $107 million, or 16%, for the three months ended September 30, 2008, compared with the same period in 2007, but increased $25 million, or 2%, for the nine months ended September 30, 2008, compared with the same period in 2007. The following items had a favorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	Reduced MISO purchased power costs of $11 million for the nine months ended September 30, 2008, due to the absence of the March 2007 FERC order.

·	Other MISO net purchased power costs, excluding the effect of the March 2007 FERC order, decreased by $13 million and $7 million for the three and nine months ended September 30, 2008, respectively.

·	A 38-day planned refueling and maintenance outage at Callaway nuclear plant in the second quarter of 2007 that did not recur in the first nine months of 2008.

·	UE’s electric rate increase that went into effect June 4, 2007, which increased electric margin by an estimated $16 million for the nine months ended September 30, 2008.

·	Net mark-to-market gains on energy transactions of $13 million for the nine months ended September 30, 2008. These unrealized gains primarily related to nonqualifying hedges of changes in market prices for electricity.

The following items had an unfavorable impact on electric margin for the three months and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	A 7% and 11% increase in fuel prices for the third quarter and first nine months of 2008, respectively.

·	Unfavorable weather conditions, as evidenced by a 25% and 27% reduction in cooling degree-days for the third quarter and nine months ended September 30, 2008, decreased electric margin by an estimated $38 million and $41 million for the three and nine months ended September 30, 2008, respectively.

Net mark-to-market losses on fuel-related transactions of $59 million and $5 million for the third quarter and the nine months ended September 30, 2008, respectively. These unrealized losses related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

·	Net mark-to-market losses on energy transactions of $5 million for the three months ended September 30, 2008. These unrealized losses related to nonqualifying hedges of changes in market prices for electricity.

UE’s gas margin was comparable for the three months ended September 30, 2008, to the same period in 2007 and increased by $5 million, or 10%, for the nine months ended September 30, 2008, compared to the same period in 2007, due to a gas rate increase that went into effect April 1, 2007, and favorable weather conditions as evidenced by an 11% increase in heating degree-days.

Illinois Regulated

Illinois Regulated’s electric margin increased by $48 million, or 26%, and $28 million, or 5%, for the three months and nine months ended September 30, 2008, respectively, compared with the same periods in 2007. Illinois Regulated’s gas margin was comparable for the three months ended September 30, 2008, with the same period in 2007. Illinois Regulated’s gas margin increased by $12 million, or 5%, for the nine months ended September 30, 2008, compared with the same period in 2007.

CIPS

CIPS’ electric margin increased by $14 million, or 24%, and $2 million, or 1%, for the three and nine months ended September 30, 2008, respectively, compared with the same periods in 2007. The following items had a favorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

The implementation of redesigned seasonal electric delivery service rates increased electric margin by $12 million and $6 million for the three and nine months ended September 30, 2008, respectively. These redesigned seasonal delivery service rates have an impact on quarterly earnings comparisons but are not expected to impact annual margins.

·	The reduced impact of the Illinois electric settlement agreement increased electric margin by $7 million and $4 million for the three and nine months ended September 30, 2008, respectively.

·	Reduced MISO purchased power costs of $7 million for the nine months ended September 30, 2008, due to the absence of the March 2007 FERC order that resettled costs in 2007 among market participants retroactive to 2005.

·	Other MISO net purchased power costs, excluding the effect of the March 2007 FERC order, decreased by $5 million and $6 million for the three and nine months ended September 30, 2008, respectively.

The following items had an unfavorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

Unfavorable weather conditions, as evidenced by a 27% and 28% reduction in cooling degree-days for the third quarter and nine months ended September 30, 2008, respectively, which decreased electric margin by an estimated $5 million and $6 million for the three and nine months ended September 30, 2008, respectively.

·	Decreased delivery service margin of $5 million and $4 million for the three and nine months ended September 30, 2008, respectively, due to ongoing MISO resettlements.

CIPS’ gas margin increased by $2 million, or 20%, and $4 million, or 8%, for the three and nine months ended September 30, 2008, compared with the same periods in 2007, primarily because of favorable weather conditions as evidenced by an 11% increase in year-to-date heating degree-days. In addition, a September 24, 2008, ICC rate order concluded that a portion of non-recoverable purchased gas costs should be capitalized, resulting in a one-time increase in margin of $1 million for CIPS for the third quarter and nine months ended September 30, 2008.

CILCO (Illinois Regulated)

The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for the three and nine months ended September 30, 2008, as compared with the same periods in 2007:

	Three Months		Nine Months
CILCO (Illinois Regulated)	$	14	$	13
CILCO (AERG)		13		10
Total change in electric margin	$	27	$	23

CILCO’s (Illinois Regulated) electric margin increased by $14 million, or 52%, and $13 million, or 14%, for the three and nine months ended September 30, 2008, respectively.

The following items had a favorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

The implementation of redesigned seasonal electric delivery service rates increased electric margin by $6 million and $3 million for the three and nine months ended September 30, 2008, respectively. These redesigned seasonal delivery service rates have an impact on quarterly earnings comparisons but are not expected to impact annual margins.

·	The reduced impact of the Illinois electric settlement agreement increased electric margin by $4 million and $2 million for the three and nine months ended September 30, 2008, respectively.

·	Reduced MISO purchased power costs of $3 million for the nine months ended September 30, 2008, due to the absence of the March 2007 FERC order that resettled costs in 2007 among market participants retroactive to 2005.

Increased delivery service margin of $2 million and $4 million for the three and nine months ended September 30, 2008, respectively, due to the reduced impact of MISO settlements that occurred last year. In addition, generation service margins increased $5 million and $3 million for the three and nine months ended September 30, 2008, respectively. These generation service margins are derived from rate riders, which are designed to offset certain operating expenses.

The favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 25% and 26% reduction in cooling degree-days for the third quarter and nine months ended September 30, 2008, respectively, which decreased electric margin by an estimated $3 million and

$4 million for the three and nine months ended September 30, 2008, respectively.

See Non-rate-regulated Generation below for an explanation of CILCO’s (AERG) change in electric margin for the three and nine months ended September 30, 2008, as compared with the same periods in 2007.

CILCO’s (Illinois Regulated) gas margin decreased $3 million, or 20%, for the three months ended September 30, 2008, compared to the year-ago period due to net mark-to-market losses on natural gas swaps. CILCO’s (Illinois Regulated) gas margin increased by $2 million, or 3%, for the nine months ended September 30, 2008, compared with the same period in 2007 because of favorable weather conditions as evidenced by a 10% increase in year-to-date heating degree-days and increased growth, offset by net mark-to-market losses of $3 million on natural gas swaps.

IP’s electric margin increased by $22 million, or 23%, and $14 million, or 5%, for the three and nine months ended September 30, 2008, respectively, compared with the same periods in 2007. The following items had a favorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

The implementation of redesigned seasonal electric delivery service rates increased electric margin by $19 million and $9 million for the three and nine months ended September 30, 2008, respectively. These redesigned seasonal delivery service rates will impact quarterly earnings comparisons but are not expected to impact annual margins.

·	The reduced impact of the Illinois electric settlement agreement, increased electric margin by $10 million and $6 million for the three and nine months ended September 30, 2008, respectively.

·	Reduced MISO purchased power costs of $11 million for the nine months ended September 30, 2008, due to the absence of the March 2007 FERC order that resettled costs in 2007 among market participants retroactive to 2005.

The following items had an unfavorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

Unfavorable weather conditions, as evidenced by a 33% and 32% reduction in cooling degree-days for the third quarter and nine months ended September 30, 2008, respectively, which decreased electric margin by an estimated $8 million and $12 million for the three and nine months ended September 30, 2008, respectively.

·	Other MISO net purchased power costs, excluding the effect of the March 2007 FERC order, increased by $7 million for the nine months ended September 30, 2008.

IP’s gas margin increased by $4 million, or 17%, and $8 million, or 7%, for the three and nine months ended September 30, 2008, respectively, compared with the same periods in 2007, primarily because of favorable weather conditions as evidenced by a 14% increase in year-to-date heating degree-days. In addition, a September 24, 2008, ICC rate order concluded that a portion of non-recoverable purchased gas costs should be capitalized, resulting in a one-time increase in margin of $4 million for IP for the third quarter and nine months ended September 30, 2008.

Non-rate-regulated Generation

Non-rate-regulated Generation’s electric margin increased by $50 million, or 19%, and $145 million, or 19%, for the three and nine months ended September 30, 2008, respectively, compared with the same periods in 2007.

Genco

Genco’s electric margin decreased by $11 million, or 9%, for the three months ended September 30, 2008, compared to the year-ago period. Genco’s electric margin increased by

$89 million, or 24%, for the nine months ended September 30, 2008, compared to the year-ago period due in part to lower fuel expense as a result of Genco’s June 2008 agreement with a coal mine owner to receive a lump-sum payment of $60 million for the early termination of a contract. Genco is incurring incremental fuel costs in 2008 and expects to incur incremental fuel costs in 2009 to replace coal from an Illinois mine that was closed prematurely at the end of 2007.

The following items also had a favorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	The reduced impact of the Illinois electric settlement agreement, increased electric margin by $17 million and $8 million for the three and nine months ended September 30, 2008, respectively.

·	Gain on the sale of oil and off-system natural gas increased electric margin by $2 million and $6 million for the three and nine months ended September 30, 2008, respectively.

·	Reduced purchased power costs of $17 for the nine months ended September 30, 2008, due to the absence of MISO resettlement costs experienced in early 2007.

Increased revenues allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company for the nine months ended September 30, 2008, compared to the year-ago period. Marketing Company’s average revenue per megawatt hour sold under the Genco PSA increased 9% and 5% for the three and nine months ended September 30, 2008, respectively, compared to the year-ago periods due primarily to re-pricing of wholesale and retail electric power supply agreements. Genco’s allocated revenues also increased 5% for the nine months ended September 30, 2008, compared with the same period in 2007 due to an increase in reimbursable expenses in accordance with the Genco PSA. Genco’s allocated revenues for the third quarter were comparable to the year-ago period.

The following items had an unfavorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	Excluding the impact of the agreement between Genco and a coal mine owner discussed above, fuel prices increased 19% and 16% for the third quarter and the first nine months of 2008, respectively.

Net mark-to-market losses on fuel-related transactions of $30 million and $2 million for the third quarter and nine months ended September 30, 2008, respectively. These unrealized losses related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

·	Reduced MISO-related revenues of $12 million for the nine months ended September 30, 2008, due to the absence of the March 2007 FERC order.

Decreased baseload coal-fired plant availability during the third quarter of 2008 compared to the same period last year primarily due to an outage caused by a transformer fire at one of Genco’s power plants. Genco’s generating plants’ average capacity and equivalent availability factors for the three months ended September 30, 2008, were 75% and 87%, respectively, compared with 80% and 92%, respectively, in the same period in 2007. Genco’s generating plants’ average capacity and equivalent availability factors for the nine months ended September 30, 2008, were comparable with the same periods in 2007.

CILCO (AERG)

AERG’s electric margin increased by $13 million, or 28%, and $10 million, or 7%, for the three and nine months ended September 30, 2008, respectively, compared with the same periods in 2007. The following items had a favorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	The reduced impact of the Illinois electric settlement agreement increased electric margin by $8 million and $4 million for the three and nine months ended September 30, 2008, respectively.

Increased baseload coal-fired plant availability due to the lack of an extended plant outage this year. AERG’s generating plants’ average capacity and equivalent availability factors for the nine months ended September 30, 2008, were 72% and 79%, respectively, in 2008, compared with 54% and 60%, respectively, in 2007.

The following items had an unfavorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods unless otherwise noted:

A 27% and 19% increase in coal prices for the third quarter and the nine months ended September 30, 2008, respectively, due to a greater percentage of higher-cost Illinois coal burned this year. In addition, oil consumed during plant startups increased $4 million for the nine months ended September 30, 2008.

A 2% and a 7% decrease in average sales price per megawatt hour allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company for the three and nine months ended September 30, 2008, respectively, due primarily to a reduction in reimbursable expenses in accordance with the AERG PSA.

Net mark-to-market losses on fuel-related transactions of $8 million for the three months ended September 30, 2008. These unrealized losses primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

·	Reduced MISO-related revenues of $4 million for the nine months ended September 30, 2008, due to the absence of the March 2007 FERC order.

EEI

EEI’s electric margin increased by $11 million, or 16%, and $35 million, or 17% for the three and nine months ended September 30, 2008, respectively, compared with the same periods in 2007. The following items had a favorable impact on electric margin for the three and nine months ended September 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	Net mark-to-market losses on fuel-related transactions of $6 million for the third quarter and net mark-to-market gains on fuel-related transactions of $2 million for the nine months ended September 30, 2008. These

unrealized gains or losses primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

·	A 20% increase in the average sales price for power during the nine months ended September 30, 2008.

The favorable variances were offset by an 8% increase in fuel prices for both the third quarter and the nine months ended September 30, 2008.

Marketing Company

A decrease in market prices during the third quarter of 2008 resulted in nonaffiliated mark-to-market gains on energy transactions of $35 million and $60 million for the three and nine months ended September 30, 2008, respectively. These unrealized gains primarily related to nonqualifying hedges of changes in market prices for electricity.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren

Three months - Other operations and maintenance expenses increased $32 million in the third quarter of 2008 compared with the third quarter of 2007, primarily because of higher distribution system reliability expenditures of $14 million, increased labor costs of $18 million, net unrealized mark-to-market losses of $10 million due to the decline in the cash surrender value of company-owned life insurance policies, and higher bad debt expense. Reducing the unfavorable effect of these items were lower injuries and damages expenses and reduced employee benefit costs.

Nine months - Other operations and maintenance expenses increased $110 million in the first nine months of 2008 compared with the first nine months of 2007, primarily because of higher distribution system reliability expenditures of $36 million, increased plant maintenance expenditures at coal-fired plants of $24 million due to outages, increased information technology costs, higher labor costs and net unrealized mark-to-market losses of $16 million due to the decline in the cash surrender value of company-owned life insurance policies. Bad debt expense also increased $17 million, primarily at the Ameren Illinois Utilities. Additionally, in the first quarter of 2007, a $15 million accrual established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan was reversed due to the termination of the plan, with no similar item in 2008. This plan was replaced with the Illinois electric settlement agreement in August 2007. Reducing the unfavorable effect of these items was the less significant impact of ice storms in the first quarter of 2008, as compared with the same period in 2007. In January 2007, UE and CIPS experienced a severe ice storm in their service territories resulting in system repair expenditures of $28 million, as compared with $18 million in expenditures for minor storms in 2008. Additionally, the absence of a Callaway refueling and maintenance outage in the first nine months of the current year and the effect of a MoPSC storm cost accounting order received in the second quarter of 2008 resulted in decreased operations and maintenance expenses compared to the prior-year period. The MoPSC accounting order resulted in UE reversing previously-recorded expenses of $13 million related to 2007 storms and recording them as a regulatory asset.

Variations in other operations and maintenance expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and nine months ended September 30, 2008, compared with the same periods in 2007, were as follows:

Missouri Regulated

Three months - Other operations and maintenance expenses increased $16 million in the third quarter of 2008 compared with the same period in 2007 primarily because of higher labor costs, net unrealized mark-to-market losses of $6 million due to the decline in the cash surrender value of company-owned life insurance policies, increased distribution system reliability expenditures, and higher bad debt expense.

Nine months - UE’s other operations and maintenance expenses increased $22 million in the first nine months of 2008, as compared with the same period in 2007, primarily because of increased distribution system reliability expenditures, higher labor and employee benefit costs, net unrealized mark-to-market losses of $11 million due to the decline in the cash surrender value of company-owned life insurance policies, and increased plant maintenance expenditures at coal-fired plants. Reducing the effect of these items was the absence of a Callaway refueling and maintenance outage this spring and the effect of the MoPSC storm cost accounting order discussed above. Decreased storm repair expenditures of $7 million in 2008, as compared with $25 million in 2007, further decreased other operations and maintenance expenses compared to the prior-year period.

Illinois Regulated

Other operations and maintenance expenses increased $11 million and $63 million in the Illinois Regulated segment in the three months and nine months ended September 30, 2008, respectively, compared with the same periods in 2007.

CIPS

Three months - Other operations and maintenance expenses increased $9 million in the third quarter of 2008, compared with the same period in 2007, primarily because of higher labor costs, increased distribution system reliability expenditures, and higher bad debt expense.

Nine months - Other operations and maintenance expenses increased $23 million in the first nine months of 2008 compared with the same period in 2007. The increase was partially because of the reversal in the first quarter of 2007 of an accrual of $4 million, established in 2006, for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan, with no similar item in 2008. Additionally, storm repair expenditures in the first nine months of 2008 exceeded the cost of storm repairs in the first nine months of 2007 by $3 million. Other distribution system reliability expenditures and labor costs were also higher than in the prior-year period.

CILCO (Illinois Regulated)

Three months - Other operations and maintenance expenses were comparable between periods.

Nine months - Other operations and maintenance expenses increased $7 million in the first nine months of 2008, as compared with the same period in 2007, primarily because of higher distribution system reliability expenditures. Additionally, in the first quarter of 2007, CILCO (Illinois Regulated) reversed a $3 million accrual established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions, with no similar item in 2008. Lower employee benefit costs reduced the effect of these unfavorable items.

Three months - Other operations and maintenance expenses increased $5 million in the third quarter of 2008 compared with the third quarter of 2007, primarily because of higher distribution system reliability expenditures, partially reduced by a decrease in injuries and damages expenses.

Nine months - Other operations and maintenance expenses increased $35 million in the first nine months of 2008, as compared with the same period in 2007, primarily because of higher distribution system reliability expenditures and increased bad debt expense. Additionally, in the first quarter of 2007, IP reversed an $8 million accrual established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions, with no similar item in 2008.

Non-rate-regulated Generation

Other operations and maintenance expenses were comparable in the third quarter of 2008 with the third quarter of 2007. Other operations and maintenance expenses increased $11 million in the nine months ended September 30, 2008, compared with the same period in 2007.

Genco & CILCO (AERG)

Three months - Other operations and maintenance expenses were comparable between periods.

Nine months - Other operations and maintenance expenses increased $11 million at Genco and $6 million at CILCO (AERG) in the first nine months of 2008, as compared with the same period in 2007, primarily because of higher plant maintenance costs due to scheduled outages. Genco and CILCO (AERG) paid $3 million and $2 million, respectively, to the IPA in the prior year as part of the Illinois electric settlement agreement, with no similar item in 2008, reducing other operations and maintenance expenses between periods.

CILCORP (Parent Company Only)

Three and nine months - Other operations and maintenance expenses were comparable between periods.

EEI

Three months - Other operations and maintenance expenses were comparable between periods.

Nine months - Other operations and maintenance expenses decreased $3 million in the first nine months of 2008, as compared with the same period in 2007, primarily because of reduced plant maintenance costs.

Depreciation and Amortization

Ameren

Three months - Ameren’s depreciation and amortization expenses were comparable between periods.

Nine months - Ameren’s depreciation and amortization expenses were comparable between periods as a reduction in depreciation because of changes in the useful lives of UE’s plants, as discussed below, was offset by increased capital additions over the past year.

Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and nine

months ended September 30, 2008, compared with the same periods in 2007 were as follows:

Missouri Regulated

Three months - Depreciation and amortization expenses were comparable between periods.

Nine months - Depreciation and amortization expenses decreased $6 million in the nine months ended September 30, 2008, compared with the same period in 2007, primarily because of the extension of UE’s nuclear and coal-fired plants’ useful lives for purposes of calculating depreciation expense in conjunction with a MoPSC electric rate order effective June 2007. Reducing the benefit of this item was an increase in capital additions over the past year.

Illinois Regulated

Depreciation and amortization expenses were comparable in the third quarter of 2008 with the third quarter of 2007. Depreciation and amortization expenses increased $4 million in the nine months ended September 30, 2008, compared with the same period in 2007, in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated) and IP, primarily because of capital additions.

Non-rate-regulated Generation

Depreciation and amortization expenses were comparable in the third quarter and first nine months of 2008 with the same periods in 2007 in the Non-rate-regulated Generation segment and for CILCORP (Parent Company Only) and EEI. Depreciation and amortization expenses decreased $2 million and $6 million at Genco in the third quarter and first nine months of 2008, respectively, compared with the same periods in 2007 as a result of a depreciation study completed in September 2007. Depreciation and amortization expenses increased $2 million and $7 million at CILCO (AERG) in the third quarter and first nine months of 2008, respectively, compared with the same periods in 2007 because of capital additions over the past year.

Taxes Other Than Income Taxes

Ameren

Three months - Ameren’s taxes other than income taxes were comparable between periods.

Nine months - Ameren’s taxes other than income taxes increased $5 million in the first nine months of 2008 compared with the same period in 2007 primarily because of higher payroll and gross receipts taxes. Increases in property taxes were partially reduced by invested capital electricity distribution tax credits in the Illinois Regulated segment related to payments made in a previous year.

Variations in taxes other than income taxes in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and nine months ended September 30, 2008, compared with the same periods in 2007 were as follows:

Missouri Regulated

Three and nine months - Taxes other than income taxes were comparable between periods.

Illinois Regulated

Three months - Taxes other than income taxes were comparable between periods in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated) and IP.

Nine months - Taxes other than income taxes were comparable in the Illinois Regulated segment in the first nine months of 2008 with the same period in 2007 as increased property taxes at CIPS were offset by the favorable impact of the invested capital electricity distribution tax credits mentioned above and by reduced excise taxes at IP.

Non-rate-regulated Generation

Taxes other than income taxes were comparable in the three months and nine months ended September 30, 2008, with the same periods in 2007 in the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI.

Other Income and Expenses

Ameren

Three and nine months - Miscellaneous income increased $3 million and $8 million in the third quarter and first nine months of 2008, respectively, compared with the same periods in 2007, primarily because of an increase at UE in allowance for funds used during construction, partially reduced by lower interest income. Miscellaneous expense was comparable in the third quarter of 2008 with the same period in 2007. Miscellaneous expense increased in the first nine months of 2008 compared with the same period in 2007 primarily because of increased expenses associated with energy efficiency and customer assistance programs; in part, under the Illinois electric settlement agreement.

Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and nine months ended September 30, 2008, compared with the same periods in 2007, were as follows:

Missouri Regulated

Three and nine months - Miscellaneous income increased $8 million and $18 million in the three months and nine months ended September 30, 2008, respectively, compared with the same periods in 2007, primarily because of an increase in allowance for funds used during construction. The increase in allowance for funds used during construction resulted from higher rates and increased construction-in-progress balances. Miscellaneous expense decreased $3 million in both the third quarter and first nine months of 2008, as compared with the same periods in 2007, primarily because of charges recorded in the prior year associated with a commodity contract.

Illinois Regulated

Other income and expenses decreased in the third quarter and first nine months of 2008 in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated) and IP, as compared with the same periods in 2007, primarily because of lower interest income.

Non-rate-regulated Generation

Other income and expenses in the Non-rate-regulated Generation segment and at Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI were comparable in the three months and nine months ended September 30, 2008, with the same periods in 2007.

Interest

Ameren

Three months - Interest expense was comparable between periods because increased interest expense resulting from debt issuances at the Ameren Companies as noted below was mitigated by decreased short-term borrowings.

Nine months - Interest expense increased $15 million in the nine months ended September 30, 2008, compared with the same period in 2007. Long-term debt issuances, net of maturities and redemptions, and the cost of refinancing auction-rate environmental improvement and pollution control revenue refunding bonds resulted in increased interest expense in the 2008 period. See Insured Auction-Rate Tax-exempt Bonds under Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk of this report for additional information. These increases were reduced by the reversal of $12 million of interest reserves for uncertain tax positions resulting from a federal tax settlement in the first quarter of 2008.

Variations in interest expense in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and nine months ended September 30, 2008, compared with the same periods in 2007 were as follows:

Missouri Regulated

Three months - Interest expense was comparable between periods as increased interest expense resulting from debt issuances was reduced by decreased short-term borrowings.

Nine months - Interest expense decreased $4 million primarily because of the reversal of $8 million of interest reserves resulting from the federal tax settlement noted above. Interest expense associated with the issuance of senior secured notes for $450 million, $250 million, and $425 million in June 2008, April 2008 and June 2007, respectively, was largely offset by a reduction in short-term borrowings due to the long-term debt financings. The senior secured notes were issued, in part, to refinance auction-rate environmental improvement revenue refunding bonds.

Illinois Regulated

Interest expense was comparable in the third quarter of 2008 with the same period in 2007. Interest expense increased $9 million in the first nine months of 2008, as compared with the same period in the prior year, primarily because of debt issuances at IP as noted below.

CIPS

Three months - Interest expense was comparable between periods.

Nine months - Interest expense decreased $5 million in the first nine months of 2008 compared with the same period in 2007, primarily because of reduced short-term borrowings. Additionally, the reversal of $2 million of interest reserves resulting from the federal tax settlement noted above reduced interest expense.

CILCO (Illinois Regulated)

Three and nine months - Interest expense was comparable between periods.

Three months - Interest expense was comparable between periods.

Nine months - Interest expense increased $17 million in the first nine months of 2008 compared with the same period in 2007, primarily because of the issuance of $250 million of senior secured notes at IP in November 2007 and the cost of refinancing auction-rate pollution control revenue refunding bonds, including the issuance of $337 million of senior secured notes in April 2008.

Non-rate-regulated Generation

Interest expense decreased $4 million in the third quarter of 2008 compared with the third quarter of 2007 and $7 million in the nine months ended September 30, 2008, compared with the same period in 2007.

Genco

Three months - Interest expense was comparable between periods.

Nine months - Interest expense decreased $3 million at Genco in the first nine months of 2008, as compared with the same period in 2007, as increased interest expense resulting from the issuance of $300 million of senior unsecured notes in April 2008 was more than offset by a resulting reduction in short-term borrowings. Additionally, interest expense was reduced by the reversal of $2 million of interest reserves at Genco from the federal tax settlement noted above.

CILCO (AERG)

Three months - Interest expense was comparable between periods.

Nine months - Interest expense decreased $2 million at CILCO (AERG) in the first nine months of 2008, as compared with the same period in 2007, primarily because of reduced short-term borrowings.

CILCORP (Parent Company Only) & EEI

Three and nine months - Interest expense was comparable between periods.

Income Taxes

Ameren

Three and nine months - Ameren’s effective tax rate in the third quarter of 2008 was comparable to the third quarter of 2007. Ameren’s effective tax rate for the first nine months of 2008 was higher than the effective tax rate for the same period in the prior year, due to variations discussed below.

Variations in effective tax rates for Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and nine months ended September 30, 2008, compared with the same periods in 2007 were as follows:

Missouri Regulated

Three and nine months - The effective tax rates for both the third quarter and first nine months of 2008 were higher than the effective tax rates for the same periods in the prior year, primarily because of lower favorable net amortization of property-related regulatory assets and liabilities, along with decreased production activity deductions in the current-year periods.

Illinois Regulated

The effective tax rates for both the third quarter and first nine months of 2008 were lower than the effective tax rates for the same periods in 2007 in the Illinois Regulated segment because of items detailed below.

CIPS

Three and nine months - The effective tax rates for both the third quarter and first nine months of 2008 were lower than the effective tax rates for the same periods in 2007, primarily because of the impact of the net amortization of property-related regulatory assets and liabilities and permanent items in the current year periods as compared with the same periods in 2007.

CILCO (Illinois Regulated)

Three months - The effective tax rate for the third quarter of 2008 was lower than the effective tax rate for the third quarter in 2007, primarily because of the impact of permanent items, net amortization of property-related regulatory assets and liabilities, and amortization of investment tax credit on pretax book income during the current-year period as compared with the impact on a pretax book loss in the third quarter of 2007.

Nine months - The effective tax rate for the first nine months of 2008 was higher than the effective tax rate for the same period in 2007, primarily because of lower estimated tax credits, lower favorable net amortization of property-related regulatory asset and liabilities, and lower favorable permanent benefits related to company-owned life insurance during the current-year period compared to the same period in 2007.

Three months - The effective tax rate for the third quarter of 2008 was lower than the effective tax rate for the same period in 2007, primarily because of the impact of permanent items, the net amortization of property-related regulatory assets and liabilities, and estimated tax credits on pretax book income during the current-year period as compared with the impact on a pretax book loss in the third quarter of 2007.

Nine months - The effective tax rate for the first nine months of 2008 was higher than the effective tax rate for the same period in 2007, primarily because of the impact of the net amortization of property-related regulatory assets and liabilities and estimated tax credits on a pretax book loss during the current-year period as compared with the impact on pretax book income in the same period in 2007.

Non-rate-regulated Generation

The effective tax rates of both the third quarter and first nine months of 2008 were lower than the effective tax rates for the same periods in 2007 in the Non-rate-regulated Generation segment, because of items detailed below.

Genco

Three and nine months - The effective tax rates for both the third quarter and first nine months of 2008 were lower than the effective tax rates for the same periods in the prior year, primarily because of the increased impact of the production activity deductions and research tax credits during the current-year periods.

CILCO (AERG)

Three and nine months - The effective tax rates for both the third quarter and first nine months of 2008 were lower than the effective tax rates for the same periods in 2007, primarily because of the impact of production activity deductions, along with changes to reserves in uncertain tax positions during the current-year periods.

CILCORP (Parent Company Only)

Three and nine months - The effective tax rates for both the third quarter and first nine months of 2008 were higher than the effective tax rates for the same periods in 2007, primarily due to the effect of permanent items on higher consolidated pretax book income in the current-year periods.

EEI

Three months and nine months - The effective tax rate was comparable between periods.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO (Illinois Regulated) and IP) continue to be the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows for Ameren, UE, CIPS, CILCO (Illinois Regulated) and IP. For operating cash flows, Genco and AERG rely on power sales to Marketing Company, which sold power through the September 2006 Illinois power procurement auction, financial contracts that were part of the Illinois electric settlement agreement and the 2008 Illinois RFP process for energy and capacity that was used pursuant to the Illinois electric settlement agreement. Marketing Company is also selling power through other primarily market-based contracts with wholesale and retail customers. In addition to cash flows from operating activities, the Ameren Companies use available cash, credit facilities, money pool or other short-term borrowings from affiliates or commercial paper to support normal operations and other temporary capital requirements. The use of operating cash flows and short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at September 30, 2008, for Ameren, CILCORP, CILCO, and IP. In October 2008 IP issued $400 million in senior secured notes that mitigated its working capital deficit. The Ameren Companies may reduce their short-term borrowings with cash from operations or discretionarily with long-term borrowings, or in the case of Ameren subsidiaries, with equity infusions from Ameren. The Ameren Companies expect to incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Expenditures not funded with operating cash flows are expected to be funded primarily with debt. The global capital and credit markets have been experiencing extreme volatility and disruption in 2008. See Outlook for a discussion of the implications of this volatility and disruption for the Ameren Companies and our plans to address these issues. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a discussion of the Illinois electric settlement agreement and the power procurement plan, which among other

things, has changed the process for power procurement in Illinois and will affect future cash flows of the Ameren Companies, except UE. The settlement resulted in customer refunds and credits during the first nine months of 2008, and it will result in further credits to customers through 2010. The Ameren Illinois Utilities will receive reimbursement for most of these refunds and credits from Illinois power generators, including Genco and AERG.

The following table presents net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2008 and 2007:

	Net Cash Provided By Operating Activities						Net Cash Used In Investing Activities									Net Cash Provided By (Used In) Financing Activities
	2008		2007		Variance		2008			2007			Variance			2008			2007			Variance
Ameren (a)	$	1,245	$	920	$	325	$	(1,501	)	$	(1,093	)	$	(408	)	$	107		$	206		$	(99	)
UE		555		519		36		(794	)		(535	)		(259	)		54			15			39
CIPS		80		11		69		(26	)		(115	)		89			(66	)		99			(165	)
Genco		209		153		56		(230	)		(137	)		(93	)		21			(15	)		36
CILCORP		107		20		87		(222	)		(141	)		(81	)		109			201			(92	)
CILCO		120		48		72		(221	)		(141	)		(80	)		95			162			(67	)
IP		120		23		97		(139	)		(133	)		(6	)		25			110			(85	)

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

Cash Flows from Operating Activities

Ameren’s cash from operating activities increased in the first nine months of 2008, as compared with the first nine months of 2007, primarily due to increased electric and gas margins as discussed in Results of Operations, and a reduction in receivables. In the 2007 period, receivables increased primarily due to the January 2, 2007, electric rate increases at the Ameren Illinois Utilities, related uncertainty surrounding a potential settlement and deterioration of collections. In addition, receivables were higher in the prior year because of initial billings to generators for reimbursements under the Illinois electric settlement agreement. However, in 2008, receivable balances have decreased and past-due balances have improved. Cash flow from operations during the 2008 period was also positively affected compared with the 2007 period by a decrease in income taxes (net of refunds) of $118 million and by the Illinois electric settlement agreement, as reimbursements from generators exceeded credits provided to customers by $17 million. In addition, net collateral postings decreased by $71 million. Factors that reduced cash flows from operations included a larger increase in gas inventories during the first nine months of 2008 compared to the same period in the prior year as both volumes and prices increased, and increased under-recovery under the PGA. In addition, cash payments related to the December 2005 Taum Sauk incident (net of insurance recoveries) increased $10 million in the nine months ended September 30, 2008, as compared with the nine months ended September 30, 2007.

At UE, cash from operating activities increased in the first nine months of 2008, compared with the first nine months of 2007, primarily because of increased electric margins and the lack of a Callaway nuclear plant refueling and maintenance outage as discussed in Results of Operations, the collection of an $85 million affiliate receivable, and a $32 million decrease in payments for storm restorations. Reducing the positive effects mentioned above were a $10 million increase in cash payments (net of insurance recoveries) related to the December 2005 Taum Sauk incident, increased income tax payments (net of refunds) of $13 million, and net decreases in various affiliate payables.

At CIPS, cash from operating activities increased in the first nine months of 2008, compared with the first nine months of 2007, primarily because of a $47 million decrease in income tax payments (net of refunds), increases in electric margins as discussed in Results of Operations, and favorable fluctuations in receivables, including affiliate receivables. In the 2007 period, receivables increased due to the January 2, 2007, electric rate increases at the Ameren Illinois Utilities, related uncertainty surrounding a potential settlement disclosure and deterioration of collections. In addition, receivables were higher in the prior year because of initial billings to generators for reimbursements under the Illinois electric settlement agreement. However, receivable balances at September 30, 2008, were comparable with the balances at December 31, 2007, and past-due balances have improved. In addition, the Illinois electric settlement agreement had a positive effect on cash from operations in the first nine months of 2008. Generator reimbursements under the Illinois electric settlement agreement exceeded credits provided to customers by $6 million. Working capital changes that benefited cash from operations included favorable changes in affiliate accounts payable and in MISO payables compared to the prior year. Partially offsetting these increases in cash from operations was a larger increase in gas inventories during the first nine months of 2008 compared to the same period in the prior year as both volumes and prices increased.

Genco’s cash from operating activities increased in the first nine months of 2008 compared to the 2007 period, primarily because of an increase in electric margins and working capital changes in the ordinary course of business. Partially offsetting these increases in cash from operations

were an increase in fuel inventory and an increase in income tax payments (net of refunds) of $10 million.

Cash from operating activities increased for CILCORP and CILCO in the nine months ended September 30, 2008, compared with the same period in 2007, primarily due to decreases in income tax payments (net of refunds) of $43 million and $49 million at CILCORP and CILCO, respectively, increased electric and gas margins, and favorable fluctuations in receivables. In the 2007 period, receivables increased due to the January 2, 2007, electric rate increases at the Ameren Illinois Utilities, related uncertainty surrounding a potential settlement and deterioration of collections. In addition, receivables were higher in the prior year because of initial billings to generators for reimbursements under the Illinois electric settlement agreement. However, in 2008, receivable balances have decreased and past-due balances have improved. Other increases in cash flow from operations were primarily due to fluctuations in working capital in the normal course of business. Partially offsetting these increases in cash from operations were a larger increase in gas inventories during the first nine months of 2008 compared to the same period in the prior year as both volumes and prices increased and an increase in under-recovery under the PGA.

IP’s cash from operating activities increased in the nine months ended September 30, 2008, compared with the same period in 2007, primarily due to a $45 million decrease in income tax payments (net of refunds), increased electric and gas margins, and a reduction in receivables. In the 2007 period receivables increased due to the January 2, 2007, electric rate increases at the Ameren Illinois Utilities, related uncertainty surrounding a potential settlement and deterioration of collections. In addition, receivables were higher in the prior year because of initial billings to generators for reimbursements under the Illinois electric settlement agreement. However, in 2008, receivable balances have decreased and past-due balances have improved. In addition, net changes in collateral postings were favorable and storm costs were lower in the current period compared to the same period last year. The Illinois electric settlement agreement also had a positive effect on cash from operations in the first nine months of 2008 as generator reimbursements exceeded credits provided to customers by $9 million. Partially offsetting the aforementioned increases in cash from operations was a larger increase in gas inventories during the first nine months of 2008 compared to the same period in the prior year as both volumes and prices increased.

Cash Flows from Investing Activities

Ameren used more cash for investing activities in the first nine months of 2008 than in the first nine months of 2007. Net cash used for capital expenditures increased in 2008 as a result of power plant scrubber projects, upgrades at various power plants, and reliability improvements of the transmission and distribution system. Additionally, increased purchases and higher prices resulted in a $122 million increase in nuclear fuel expenditures.

UE’s cash used in investing activities increased during the nine months ended September 30, 2008, compared to the same period in 2007, principally because of a $122 million increase in nuclear fuel expenditures resulting from increased purchases for future refueling outages and higher prices. Capital expenditures increased $121 million. This increase was a result of increased spending related to a power plant scrubber project, reliability improvements of the transmission and distribution system, and various plant upgrades.

CIPS’ cash used in investing activities during the first nine months of 2008 decreased compared to the same period in 2007. During both periods, cash used for capital expenditures, primarily for reliability improvements of the transmission and distribution system, was offset by similar amounts of proceeds received from an intercompany note. During 2007, CIPS contributed $94 million in net money pool advances, while no such advances occurred in 2008.

Genco’s cash used in investing activities increased in the first nine months of 2008 compared with the same period in 2007. Capital expenditures increased $85 million, principally due to a power plant scrubber project. This increase was offset, in part, by a $5 million decrease in emission allowance purchases.

CILCORP’s and CILCO’s cash used in investing activities increased in the nine months ended September 30, 2008, compared with the same period in 2007. Cash used in investing activities increased as a result of a $40 million increase in capital expenditures, primarily due to a power plant scrubber project and plant upgrades at AERG. The receipt of a $42 million net repayment of prior-year money pool advances reduced cash flows used in investing activities in the 2008 period compared to 2007.

IP’s cash used in investing activities increased in the first nine months of 2008 compared to the same period in 2007. Capital expenditures decreased by $4 million in the first nine months of 2008 from the year-ago period primarily because of a reduction in storm-related capital expenditures. Net money pool advances increased by $9 million in the first nine months of 2008 compared with the prior-year period.

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

We continually review our power supply needs. As a result, we could modify plans 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.

Cash Flows from Financing Activities

During the nine months ended September 30, 2008, the Ameren Companies issued $1.3 billion of senior debt. The proceeds were used to repurchase, redeem, and fund $823 million of long-term debt, reduce short-term borrowings, and fund capital expenditures and other working capital needs at UE, CIPS, Genco, CILCO, and IP. The refinancing activity that occurred during the first nine months of 2008 resulted in a decrease in cash provided by financing activities compared with the year-ago period. The first nine months of 2007 included net borrowings of $590 million of short-term debt that were used to fund maturities of long-term debt, fund working capital needs at Ameren subsidiaries and build liquidity during a period of legislative uncertainty in Illinois. Additionally, CILCO redeemed the remaining shares of its 5.85% Class A preferred stock to complete the mandatory sinking fund redemption requirement resulting in a $16 million use of cash during 2008 compared with 2007. Benefiting the nine months ended September 30, 2008, compared with the year-ago period was a $36 million increase in proceeds from the issuance of Ameren common stock resulting from increased sales through Ameren’s 401(k) plan and DRPlus.

UE’s net cash provided by financing activities increased in the first nine months of 2008, compared with the same period of the prior year. During the nine months ended September 30, 2008, UE used $699 million in proceeds from the issuance of senior secured notes to reduce short-term debt, redeem outstanding auction-rate environmental improvement revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market, and fund the current maturity of UE’s 6.75% first mortgage bonds. Comparably, during the nine months ended September 30, 2007, UE issued $425 million in senior secured notes to fund working capital requirements and reduced short-term debt by $142 million. A net increase in borrowings under an intercompany borrowing arrangement with Ameren also benefited the nine months ended September 30, 2008, compared with the year-ago period.

CIPS had a net use of cash from financing activities in the nine months ended September 30, 2008, compared with a net source of cash in the first nine months of 2007. This change was a result of CIPS using existing cash to fund a net reduction in short-term debt and to redeem $35 million of auction-rate environmental improvement revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market. CIPS had $29 million net repayments of short-term debt in the first nine months of 2008 compared with net borrowings of $100 million in the first nine months of 2007.

Genco issued $300 million of 7.00% senior unsecured notes during the first nine months of 2008 resulting in a net source of cash from financing activities compared with a net use of cash in the year-ago period. The proceeds from the issuance were used to fund capital expenditures and other working capital requirements, including a net reduction in money pool borrowings and $100 million of short-term borrowings during the 2008 period compared with the 2007 period.

CILCORP’s and CILCO’s cash provided by financing activities decreased during the nine months ended September 30, 2008, compared to the 2007 period. This decrease is primarily the result of CILCORP’s and CILCO’s net repayments of short-term borrowings during the nine months ended September 30, 2008, compared with the 2007 period. These repayments were funded by an increase in money pool borrowings of $171 million, primarily at AERG. Partially offsetting this were reduced redemptions and maturities of long-term debt in 2008. During the 2008 period, $19 million of auction-rate environmental improvement revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market were redeemed at CILCO, compared with the maturity of $50 million of CILCO’s 7.50% bonds during the 2007 period. Also benefiting the nine months ended September 30, 2008, were net borrowings of a $61 million direct loan from Ameren at CILCORP compared with $73 million net repayments during the 2007 period. A $14 million capital contribution received by CILCO in the third quarter of 2007 from CILCORP resulted in a positive impact on cash flows at CILCO for the first nine months of 2007.

IP’s cash from financing activities decreased in the first nine months of 2008, compared with the same period in 2007. During the first nine months of 2008, IP issued $336 million of senior secured notes and used the proceeds to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market. Additionally, during the 2008 period, IP funded $45 million of dividends and had net short-term borrowings of $129 million. Comparatively, in the first nine months of 2007, IP paid no dividends and had $125 million of net borrowings under the 2007 credit facility and net money pool borrowings of $52 million. These borrowings were used to fund $65 million of long-term debt maturities and build liquidity in 2007.

Short-term Borrowings and Liquidity

External short-term borrowings typically consist of drawings under committed bank credit facilities and commercial paper issuances. See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for additional information on credit facilities, short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements.

The following table presents the various credit facilities of the Ameren Companies and AERG, and their availability as of September 30, 2008:

Credit Facility	Expiration	Amount Committed	Amount Available(a)
Ameren, UE and Genco:
Multiyear revolving(b)	July 2010	1,150	791(f)
CIPS, CILCORP, CILCO, IP and AERG:
2007 Multiyear revolving(c)(d)	January 2010	500	73
2006 Multiyear revolving(c)(e)	January 2010	500	81

(a)	After excluding unfunded Lehman Brothers Bank, FSB participations, under the $1.15 billion and 2006 $500 million credit facilities.

(b)	Ameren Companies may access this credit facility through intercompany borrowing arrangements.

(c)	See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for discussion of the amendments to these facilities.

(d)

The maximum amount available to each borrower under this facility at September 30, 2008, including for the issuance of letters of credit, was limited as follows: CILCORP - $125 million, CILCO - $75 million, IP - $200 million and AERG - $100 million. CIPS and CILCO have the option of permanently reducing their ability to borrow under the 2006 $500 million credit facility and shifting such capacity, up to the same limits, to the 2007 $500 million credit facility. In July 2007, CILCO shifted $75 million of its sublimit under the 2006 $500 million credit facility to this facility.

(e)

The maximum amount available to each borrower under this facility at September 30, 2008, including for issuance of letters of credit, was limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $75 million, IP - $150 million and AERG - $200 million. In July 2007, CILCO shifted $75 million of its capacity under this facility to the 2007 $500 million credit facility. Accordingly, as of September 30, 2008, CILCO had a sublimit of $75 million under this facility and a $75 million sublimit under the 2007 credit facility.

(f)	In addition to amounts drawn on this facility, the amount available is further reduced by standby letters of credit, which have been issued. The amount of such letters of credit at September 30, 2008, was $9 million.

On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. As of September 30, 2008, Lehman Brothers Bank, FSB, a subsidiary of Lehman, had lending commitments of $100 million and $21 million under the $1.15 billion credit facility and the 2006 $500 million credit facility, respectively. The $50 million lending commitment of another Lehman subsidiary under the 2007 $500 million credit facility was assigned to a non-Lehman affiliated bank on or about September 17, 2008. At this time, we do not know if Lehman Brothers Bank, FSB will seek to assign to other parties any of its commitments within our credit facilities. Assuming Lehman Brothers Bank, FSB does not fund its pro-rata share of funding or letter of credit issuance requests under these two facilities, and such participations are not assigned or otherwise transferred to other lenders, total amounts accessible by the Ameren Companies and AERG will be limited to amounts not less than $1.05 billion under the $1.15 billion credit facility and $479 million under the 2006 $500 million credit facility. The Ameren Companies and AERG do not believe that the potential reduction in available capacity under the credit facilities if Lehman Brothers Bank, FSB does not fund its commitments will have a material impact on their liquidity.

On June 25, 2008, Ameren entered into a $300 million term loan agreement due June 24, 2009, which was fully drawn on June 26, 2008. See Note 3 - Short-term Borrowings and Liquidity for additional information.

A further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents. At September 30, 2008, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP had $206 million, less than $1 million, $14 million, $2 million, less than $1 million, less than $1 million, and $12 million, respectively, of cash and cash equivalents.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 2008, FERC issued an order authorizing the issuance of short-term debt securities subject to the following limits on outstanding balances: UE - $1 billion, CIPS - $250 million, and CILCO - $250 million. The authorization was effective as of April 1, 2008, with an expiration date of March 31, 2010. IP has unlimited short-term debt authorization from FERC.

Genco was authorized by FERC in its March 2008 order to have up to $500 million of short-term debt outstanding at any time. AERG and EEI have unlimited short-term debt authorization from FERC.

The issuance of short-term debt securities by Ameren and CILCORP (parent) is not subject to approval by any regulatory body.

The Ameren Companies continually evaluate the adequacy and appropriateness of their credit arrangements given changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or other short-term borrowing arrangements.

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 (net of any issuance discounts and including any redemption premiums) for the nine months ended September 30, 2008 and 2007, for the Ameren Companies. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.

	Month Issued, Redeemed,	Nine Months
	Repurchased or Matured	2008		2007
Issuances
Long-term debt
UE:
6.00% Senior secured notes due 2018	April	$	250	$	-
6.40% Senior secured notes due 2017	June		-		425
6.70% Senior secured notes due 2019	June		449		-
Genco:
7.00% Senior unsecured notes due 2018	April		300		-
IP:
6.25% Senior secured notes due 2018	April		336		-
Total Ameren long-term debt issuances		$	1,335	$	425
Common stock
Ameren:
DRPlus and 401(k)	Various	$	107	$	71
Total common stock issuances		$	107	$	71
Total Ameren long-term debt and common stock issuances		$	1,442	$	496
Redemptions, Repurchases and Maturities
Long-term debt
Ameren:
2002 5.70% notes due 2007	February	$	-	$	100
Senior notes due 2007	May		-		250
UE:
2000 Series B environmental improvement bonds due 2035	April		63		-
2000 Series A environmental improvement bonds due 2035	May		64		-
2000 Series C environmental improvement bonds due 2035	May		60		-
1991 Series environmental improvement bonds due 2020	May		43		-
6.75% Series first mortgage bonds due 2008	May		148		-
CIPS:
2004 Series pollution control bonds due 2025	April		35		-
CILCO:
7.50% First mortgage bonds due 2007	January		-		50
Series 2004 pollution control bonds due 2039	April		19		-
IP:
Series 2001 Non-AMT bonds due 2028	May		112		-
Series 2001 AMT bonds due 2017	May		75		-
1997 Series A pollution control bonds due 2032	May		70		-
1997 Series B pollution control bonds due 2032	May		45		-
1997 Series C pollution control bonds due 2032	June		35		-
Note payable to IP SPT:
5.65% Series due 2008	Various		54		65
Preferred Stock
CILCO:
5.85% Series	July		16		1
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities		$	839	$	466

The following table presents the authorized amounts under SEC Form S-3 shelf registration statements filed and declared effective for certain Ameren Companies as of September 30, 2008:

	Effective Date	Authorized Amount	Issued	Available
Ameren	June 2004	$ 2,000	$ 459	$ 1,541
UE(a)	June 2008	Not limited	450	Not limited
CIPS	May 2001	250	211	39

(a)

In June 2008, UE, as a well-known seasoned issuer, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in June 2011. In June 2008, UE issued $450 million principal amount of senior secured notes pursuant to this shelf registration statement.

In July 2008, Ameren filed a Form S-3 registration statement with the SEC authorizing the offering of six million additional shares of its common stock under the DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus.

Ameren is also currently selling newly issued shares of its common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan (including a subsidiary plan that is now merged into the Ameren 401(k) plan), Ameren issued a total of 0.8 million new shares of common stock valued at $32 million and 2.5 million new shares valued at $107 million in the three months and nine months ended September 30, 2008, respectively.

Ameren, UE and CIPS may sell all or a portion of the remaining securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale. Any offer and sale will be made only by means of a prospectus that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

Indebtedness Provisions and Other Covenants

See Note 4 - Credit Facilities and Liquidity and Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a discussion of covenants and provisions (and applicable cross-default provisions) contained in our bank credit facilities and in certain of the Ameren Companies’ indenture agreements and articles of incorporation. Also see Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in the $300 million term-loan agreement (including applicable cross-default provisions) and the March 2008 amendments to the 2007 $500 million and 2006 $500 million credit facilities.

At September 30, 2008, the Ameren Companies were in compliance with their credit facility, term loan agreement, indenture, and articles of incorporation provisions and covenants.

We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand 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 or make our access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.

Dividends

Ameren paid to its shareholders common stock dividends totaling $399 million, or $1.905 per share, during the first nine months of 2008 (2007 - $395 million or $1.905 per share). On October 10, 2008, Ameren’s board of directors declared a quarterly common stock dividend of 63.5 cents per share payable on December 31, 2008, to shareholders of record on December 10, 2008.

See Note 4 - Credit Facilities and Liquidity in the Form 10-K for a discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At September 30, 2008, except as discussed below with respect to the 2007 $500 million credit facility and the 2006 $500 million credit facility, none of these circumstances existed at the Ameren Companies and, as a result, they were allowed to pay dividends.

The 2007 $500 million credit facility and 2006 $500 million credit facility limit CIPS, CILCORP, CILCO and IP to common and preferred stock dividend payments of $10 million per year each if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below investment-grade credit rating from either Moody’s or S&P. With respect to AERG, which currently is not rated by Moody’s or S&P, the common and preferred stock dividend restriction will not apply if its ratio of consolidated total debt to consolidated operating cash flow, pursuant to a calculation defined in the facilities, is less than or equal to 3.0 to 1.0. CILCORP’s senior unsecured long-term debt credit ratings from Moody’s and S&P are below investment-grade, causing it to be subject to this dividend payment limitation. As

of September 30, 2008, AERG was in compliance with the debt-to-operating cash flow ratio test in the 2007 and 2006 $500 million credit facilities and thus not subject to this limitation. The other borrowers thereunder are not currently limited in their dividend payments by this provision of the 2007 or 2006 $500 million credit facilities.

The following table presents common stock dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the nine months ended September 30, 2008 and 2007.

	Nine Months
	2008		2007
UE	$	193	$	246
Genco		84		113
IP		45		-
Nonregistrants		77		36
Dividends paid by Ameren	$	399	$	395

Contractual Obligations

For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 13 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K, and Other Obligations in Note 9 - Commitments and Contingencies under Part I, Item 1, of this report. See Note 13 - 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. See also Note 1 - Summary of Significant Accounting Policies to our financial statements under Part I, Item 1, of this report for the unrecognized tax benefits under the provisions of FIN 48.

Subsequent to December 31, 2007, obligations related to the procurement of coal, natural gas, nuclear fuel, and heavy forgings materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $3,293 million, $1,490 million, $387 million, $250 million, $517 million, $517 million and $520 million, respectively. Total other obligations, including the amount of unrecognized tax benefits, at September 30, 2008, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $4,039 million, $1,873 million, $424 million, $293 million, $572 million, $572 million and $653 million, respectively.

As a result of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and $28 million from AERG. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the quarter ended September 30, 2008, of $10 million, $2 million, less than $1 million, $2 million, $4 million, and $2 million, respectively, (quarter ended September 30, 2007 - $59 million, $8 million, $5 million, $11 million, $24 million, and $11 million, respectively) and during the nine months ended September 30, 2008, of $32 million, $5 million, $2 million, $6 million, $13 million, and $6 million, respectively (nine months ended September 30, 2007 - $59 million, $8 million, $5 million, $11 million, $24 million, and $11 million, respectively) under the terms of the Illinois electric settlement agreement. At September 30, 2008, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $15 million, $5 million, $3 million and $7 million, respectively. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for additional information regarding the Illinois electric settlement agreement.

Credit Ratings

The following table presents the principal credit ratings of the Ameren Companies by Moody’s, S&P and Fitch effective on the date of this report:

	Moody’s	S&P	Fitch
Ameren:
Issuer/corporate credit rating	Baa3	BBB-	BBB+
Senior unsecured debt	Baa3	BB+	BBB+
Commercial paper	P-3	A-3	F2
UE:
Issuer/corporate credit rating	Baa2	BBB-	A-
Secured debt	Baa1	BBB	A+
Commercial paper	P-3	A-3	F2
CIPS:
Issuer/corporate credit rating	Ba1	BBB-	BBB-
Secured debt	Baa3	BBB+	BBB+
Senior unsecured debt	Ba1	BBB-	BBB
Genco:
Issuer/corporate credit rating	-	BBB-	BBB+
Senior unsecured debt	Baa3	BBB-	BBB+
CILCORP:
Issuer/corporate credit rating	-	BBB-	BBB-
Senior unsecured debt	Ba2	BB+	BBB-
CILCO:
Issuer/corporate credit rating	Ba1	BBB-	BBB
Secured debt	Baa2	BBB+	A-
IP:
Issuer/corporate credit rating	Ba1	BBB-	BBB-
Secured debt	Baa3	BBB	BBB+

Moody’s Ratings Actions

On February 12, 2008, Moody’s affirmed the ratings of Ameren and Genco but changed their rating outlooks to negative from stable. Moody’s placed the long-term credit ratings of UE under review for possible downgrade and affirmed UE’s commercial paper rating. In addition, Moody’s affirmed the ratings of CIPS, CILCORP, CILCO and IP and maintained a positive rating outlook on these four companies. According to Moody’s, the review of UE’s ratings was prompted by declining cash flow coverage metrics, increased operating costs, higher capital expenditures for environmental

compliance and transmission and distribution system investment, and significant regulatory lag in the recovery of these costs. Moody’s stated that the negative outlook on the credit rating of Genco reflected Genco’s “position as a predominantly coal generating company that is likely to be seriously affected by more stringent environmental regulations, including a potential cap or tax on carbon emissions.” The negative outlook on the ratings of Ameren reflects the factors that impacted its subsidiaries, UE and Genco, according to Moody’s.

On May 21, 2008, Moody's lowered the credit ratings of UE to Baa1 for its senior secured debt and to Baa2 for its issuer rating and changed the rating outlook to stable. In its reasons for these actions, Moody’s reiterated the items noted above, attributing the declining cash flow metrics to increased fuel and purchased power costs, growing capital expenditures for environmental compliance and for transmission system reliability, and higher labor costs. They noted that UE is one of the few utilities in the country operating without fuel, purchased power, and environmental cost recovery mechanisms. Moody’s also placed UE’s commercial paper rating on review for possible downgrade due to its review of Ameren’s short-term rating as noted below. At the same time, the ratings of Ameren and Genco were changed from negative outlook to being on review for possible downgrade.

On August 13, 2008, Moody’s downgraded both the issuer and senior unsecured debt ratings of Ameren and the senior unsecured debt rating of Genco to Baa3 from Baa2. The outlooks on these ratings are now stable. Moody’s also downgraded the commercial paper ratings of Ameren and UE to P-3 from P-2. Moody’s stated that these downgrades were because of declining consolidated coverage ratios over the last several years and the expectation that ongoing cost pressures and the lack of timely regulatory recovery of some costs will prevent ratios from returning to historical levels in the near-term.

S&P Ratings Actions

On March 19, 2008, S&P raised its senior unsecured debt ratings for CIPS to BBB- from B+ and for CILCORP to BB from B+.

On September 11, 2008, S&P upgraded its corporate credit ratings on CILCORP, CILCO, CIPS and IP to BBB- from BB. Senior secured debt ratings at CILCO and CIPS were upgraded to BBB+ from BBB and were upgraded at IP to BBB from BBB-. CILCORP’s senior unsecured debt rating was raised to BB+ from BB. All of Ameren’s other ratings were affirmed and all outlooks are now stable. At the same time, S&P raised the business profiles of CIPS and IP to “strong” from “satisfactory.” The business profiles of CILCORP and CILCO remain “satisfactory.” S&P stated that the ratings upgrades were due to its assessment that the regulatory and political environment in Illinois will be reasonably supportive of investment grade credit quality with regard to the Ameren Illinois Utilities’ then pending rate cases. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for a discussion of the order issued by the ICC in these rate cases on September 24, 2008.

Fitch Ratings Actions

On October 16, 2008, Fitch upgraded its issuer credit ratings on CILCO to BBB from BB+ and on CILCORP, CIPS and IP to BBB- from BB+. The senior secured debt ratings were raised at CIPS and IP to BBB+ from BBB and at CILCO to A- from BBB. Senior unsecured debt ratings were raised at CIPS and IP to BBB from BBB-, at CILCO to BBB+ from BBB-, and at CILCORP to BBB- from BB+. The outlook for each of these entities was changed to stable from rating watch positive. Fitch stated that the ratings upgrades were a result of the expected positive financial impact of electric and gas rate case decisions issued by the ICC in September 2008 and the reduction in business risk associated with the Illinois electric settlement agreement in 2007.

Collateral Postings

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made with external parties at September 30, 2008, were $37 million, $2 million, $7 million, $6 million, $6 million, and $12 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at September 30, 2008, could have resulted in Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to $205 million, $40 million, $32 million, $16 million, $46 million, $46 million, and $64 million, respectively.

In addition, the cost of borrowing under our credit facilities can increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization. See Quantitative and Qualitative Disclosures about Market Risk - Interest Rate Risk under Part I, Item 3, for information on credit rating changes with respect to insured tax-exempt auction-rate bonds.

OUTLOOK

Below are some key events and trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2008 and beyond.

Capital and Credit Markets

The global capital and credit markets have experienced extreme volatility and disruption in 2008, and in particular, since early September. Several factors have driven this situation, including deteriorating global economic conditions and the weakened financial condition of major financial institutions, as evidenced by the bankruptcy of Lehman. These conditions have led governments around the world to establish policies and programs that are designed to strengthen the global financial system, enhance liquidity and restore investor confidence. We believe that these recent events have several implications for the capital and credit markets, the economy and our industry as a whole, including Ameren. They include the following:

Access to Capital Markets - The extreme disruption in the capital markets has limited companies’, including the Ameren Companies’, ability to freely access the capital and credit markets to support their operations and refinance debt. We are unable to predict how long these conditions will persist, but we expect the capital markets to remain uncertain throughout 2009 and potentially longer. However, we believe we will continue to have access to the capital markets on terms commercially acceptable to us, as evidenced by IP's recent sale of $400 million in senior secured notes in October 2008.

·	Cost of Capital - The disruption in the capital and credit markets has led to higher financing costs compared to recent years. We expect this trend to continue while the current level of uncertainty in the financial markets persists.

Credit Facilities - At September 30, 2008, the Ameren Companies had in place revolving bank credit facilities aggregating $2.15 billion. In total, eighteen banks participate in these credit facilities. In January 2010, $1 billion of these facilities expire, and $1.15 billion expire in July 2010. Due to the Lehman bankruptcy filing, the size of our facilities was effectively reduced by up to $121 million. We cannot predict whether other banks that are currently participating in our credit facilities will declare bankruptcy or otherwise fail to honor their commitments thereunder, and thus reduce the level of access we have to our credit facilities. However, as stated previously, governments around the world have taken aggressive actions to provide incremental capital and other assurances to improve the financial condition of, and confidence in, financial institutions, individually and as a whole, including the participants in our credit facilities. We are actively developing plans and strategies to renew these facilities prior to their expiration dates. We are unable to predict whether the size and terms of any new credit facilities will be comparable to the existing facilities.

Economic Conditions - We believe that the disruption in the capital and credit markets will also further weaken global economic conditions as the limited access to capital and higher cost of capital for businesses and consumers will reduce spending, result in job losses, and pressure economic growth for the foreseeable future. These weak economic conditions will likely result in volatility in the power and commodity markets, greater risk of defaults by our counterparties, weaker customer sales growth, higher bad debt expense, and possible impairment of goodwill and long-lived assets, among other things. To date, the level of defaults by counterparties, lower sales growth, and bad debt expense resulting from the weak economy have not significantly impacted the Ameren Companies; however, we are unable to predict the ultimate impact of these weak economic conditions on our results of operations, financial position, or liquidity.

Investment Returns - The disruption in the capital markets, coupled with weak global economic conditions, has adversely affected financial markets. As a result, we expect to experience lower than assumed investment returns in 2008 in our pension and postretirement benefit funds. These lower returns could increase our pension and postretirement expenses, pension funding levels and charges to OCI. Our future expenses and funding levels will also be impacted by future discount rate levels. We are unable to predict what our future returns will be on our investments, as well as future discount rate levels and the resulting impact on our pension and postretirement benefit expense levels and funding.

Operating and Capital Expenditures - The Ameren Companies will continue to make significant levels of investments and incur expenditures for their electric and gas utility infrastructure to improve overall system reliability, comply with environmental regulations and improve plant performance. However, due to the significant recent level of disruption and uncertainties in the capital and credit markets, we are actively evaluating opportunities to defer or reduce planned capital spending and operating expenses to mitigate the risks associated with accessing these uncertain markets. We have already taken actions in this regard by reducing expected 2009 operating and capital expenditures in Ameren’s Non-rate-regulated Generation segment by $400 million to $500 million. Other cost deferral and reduction opportunities have been identified in our regulated businesses and administrative support functions that we will execute in the event of continued disruption of the capital and credit markets. In our regulated businesses and administrative support functions, we have identified $400 million to $500 million

of expected 2009 spending, primarily capital expenditures, which may be deferred to future periods. Separately, because the federal Clean Air Interstate and Mercury Rules were vacated Genco, AERG and UE are seeking a variance from the Illinois Pollution Control Board to an environmental requirement in Illinois that, while "environmentally neutral," would defer approximately $500 million of environmental capital expenditures scheduled for the 2009 - 2012 timeframe to subsequent years. Any expenditure control initiatives would be balanced against our continued long-term commitment to invest in our electric and natural gas infrastructure to provide safe, reliable electric and natural gas delivery services to our customers to meet federal and state environmental, reliability, and other regulations, and the need to maintain a solid overall liquidity and credit ratings profile to meet our operating, capital and financing needs under challenging capital and credit market conditions.

At October 31, 2008, Ameren had available liquidity, which represented its cash on hand and amounts available under its existing credit facilities of approximately $1.45 billion, excluding unfunded Lehman bank facility participation commitments, which was $550 million higher than this same time last year. We expect our available liquidity to remain solid through the end of 2008 and throughout 2009 as we strategically access the capital markets and execute the expenditure control initiatives discussed above. However, we are unable to predict whether significant changes in economic conditions, further disruption in the capital and credit markets or other unforeseen events may occur, which could materially impact our estimate.

While we believe the uncertainty in the capital and credit markets will persist throughout 2009, and potentially longer, we do believe that actions taken by the U.S. government and governments around the world will ultimately help ease the extreme volatility and disruption of these markets. In addition, we believe we will continue to have access to the capital markets on terms commercially acceptable to us. Additional financings are expected through 2009, subject to market conditions. We believe that our expected operating cash flows, capital expenditure and related financing plans (including accessing our existing credit facilities) will provide the necessary liquidity to meet our operating, investing, and financing needs, at a minimum, through the end of 2009. However, there can be no assurance that significant changes in economic conditions, further disruptions in the capital and credit markets or other unforeseen events will not materially impact our ability to execute our expected operating, capital or financing plans.

Current Capital Expenditure Plans

Between 2008 and 2017, Ameren estimated that certain Ameren Companies would be required to invest between $4 billion and $5 billion to retrofit their coal-fired power plants with pollution control equipment. Costs for these types of projects continue to escalate. However, because of the 2008 U.S. Court of Appeals for the District of Columbia decisions to vacate the Clean Air Interstate Rule and the Clean Air Mercury Rule, the timing and ultimate amount of these capital costs are under review at this time. Any pollution control investments will result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 45% of this investment was expected to be in our Regulated Missouri operations, and therefore was expected to be recoverable from ratepayers. The recoverability of amounts expended in Non-rate-regulated Generation operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased environmental costs for generators.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. Excessive costs to comply with future legislation or regulations might force Ameren and other similarly-situated electric power generators to close some coal-fired facilities. Investments to control carbon emissions at Ameren’s coal-fired power plants would significantly increase future capital expenditures and operation and maintenance expenses.

UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. At this time, UE does not expect to require new baseload generation capacity until 2018 to 2020. However, due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. In July 2008, UE filed a COLA with the NRC for a potential new nuclear plant at UE’s existing Callaway County, Missouri nuclear plant site. UE has also signed contracts for certain long lead-time nuclear-plant related equipment. The filing of the COLA and entering into these contracts does not mean a decision has been made to build a nuclear plant. These are only the first steps in the regulatory licensing and procurement process and are necessary actions to preserve the option to develop a new nuclear plant.

·	UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license by twenty years so that the operating license will expire in 2044. UE cannot predict whether or when the NRC will approve the license extension.

Over the next few years, we expect to make significant investments in our electric and gas infrastructure and to incur increased operations and maintenance expenses to improve overall system reliability. We are projecting higher labor and material costs for these capital expenditures. We would expect these costs or investments at our rate-regulated businesses to be ultimately recovered in rates.

·	Increased investments for environmental compliance, reliability improvement, and new baseload capacity will result in higher depreciation and financing costs.

Revenues

The earnings of UE, CIPS, CILCO and IP are largely determined by the regulation of their rates by state agencies. With rising costs, including fuel and related transportation, purchased power, labor, material, depreciation and financing costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, Ameren, UE, CIPS, CILCO and IP expect to experience regulatory lag until requests to increase rates to recover such costs are granted by state regulators. Ameren, UE, CIPS, CILCO and IP expect more frequent rate cases will be necessary in the future. UE agreed not to file a natural gas delivery rate case before March 15, 2010.

The ICC issued a consolidated order in September 2008 approving a net increase in annual revenues for electric delivery service of $123 million in the aggregate (CIPS - $22 million increase, CILCO - $3 million decrease and IP - $104 million increase) and a net increase in annual revenues for natural gas delivery service of $38 million in the aggregate (CIPS - $7 million increase, CILCO - $9 million decrease, and IP - $40 million increase), based on a 10.65% return on equity with respect to electric delivery service and 10.68% return on equity with respect to natural gas delivery service. These rate changes were effective on October 1, 2008. Because of the Ameren Illinois Utilities’ pledge to keep the overall residential electric bill increase resulting from these rate changes to less than 10% for each utility, IP will not recover approximately $10 million in revenue in the first year electric delivery service rates are in effect. Thereafter, residential electric delivery service rates will be adjusted to recover the full increase. In addition, the ICC changed the depreciable lives used in calculating depreciation expense for the Ameren Illinois Utilities’ electric and natural gas rates. As a result, annual depreciation expense for the Ameren Illinois Utilities will be reduced for financial reporting purposes by a net $13 million in the aggregate (CIPS - $4 million reduction, CILCO - $26 million reduction, and IP - $17 million increase). The Ameren Illinois Utilities and some parties to the rate case have requested that the ICC rehear certain aspects of the order.

UE filed an electric rate case with the MoPSC in April 2008 in order to recover rising costs and to earn a reasonable return on its investments. UE’s return on equity was 9% in 2007 and is expected to decrease to 7% in 2008. UE requested to increase its annual electric revenues by $251 million. The electric rate increase is based on a 10.9% return on equity, a capital structure composed of 51% common equity, a rate base of $5.9 billion and a test year ended March 31, 2008, with updates for known and measurable changes through September 30, 2008. In August 2008, the MoPSC staff filed a report and direct testimony with the MoPSC recommending an increase in annual revenues for electric service for UE of $51 million based on a 9.5% return on equity. The Office of Public Counsel and intervenors also filed testimony with the MoPSC in August 2008 opposing certain aspects of UE’s April 2008 request. The MoPSC has until March 2009 to render a decision in this rate case.

In current and future rate cases, UE, CIPS, CILCO and IP will also seek cost recovery mechanisms from their state regulators to reduce regulatory lag. In the ICC consolidated electric and natural gas rate order issued in September 2008, the ICC rejected the Ameren Illinois Utilities’ requested rate adjustment mechanisms for electric infrastructure investments. As an alternative to the Ameren Illinois Utilities’ requested decoupling of natural gas revenues from sales volumes, the ICC order approved an increase in the percentage of costs to be recovered through fixed non-volumetric residential and commercial customer charges to 80% from 53%. The ICC also approved an increase in the Supply Cost Adjustment (SCA) factors for the Ameren Illinois Utilities. The SCA is a charge applied only to the bills of customers who take their power supply from the Ameren Illinois Utilities. The change in the SCA factors is expected to result in increased electric revenues of $9.5 million per year in the aggregate (CIPS - $2.6 million, CILCO - $1.6 million, and IP - $5.3 million) covering the increased cost of administering the Ameren Illinois Utilities’ power supply responsibilities. In its pending electric rate case, UE is requesting the MoPSC approve implementation of a fuel and purchased power cost recovery mechanism and a mechanism that would permit timely cost recovery of vegetation management and infrastructure inspection and repair costs. The MoPSC staff opposed UE’s request to implement a fuel and purchased power cost recovery mechanism in direct testimony filed in August 2008.

·	Average residential electric rates for CIPS, CILCO and IP increased significantly following the expiration of a rate freeze at the end of 2006. Electric rates rose because of the increased cost of power purchased on behalf of the Ameren Illinois Utilities’ customers and an increase in

electric delivery service rates. Due to the magnitude of these increases, the Illinois electric settlement agreement reached in 2007 provides approximately $1 billion over a four-year period that began in 2007 to fund rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Funding for the settlement is coming from electric generators in Illinois and certain Illinois electric utilities. Pursuant to the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to fund an aggregate of $150 million over four years, of which the following contributions remain to be made as of September 30, 2008:

	Ameren		CIPS		CILCO (Illinois Regulated)		IP		Genco		CILCO (AERG)
2008(a)	$	12.2	$	1.9	$	0.9	$	2.7	$	4.6	$	2.1
2009(a)		25.4		3.6		1.8		4.8		10.5		4.7
2010(a)		2.0		0.3		0.1		0.4		0.8		0.4
Total	$	39.6	$	5.8	$	2.8	$	7.9	$	15.9	$	7.2

(a) Estimated.

In September 2008, the IPA filed an electric power procurement plan with the ICC for both the Ameren Illinois Utilities and Commonwealth Edison. The plan, which requires the approval of the ICC, outlines the wholesale products (capacity, energy swaps and renewable energy credits) that the IPA will procure on behalf of the Ameren Illinois Utilities for the period of June 1, 2009 through May 30, 2014. The products will be procured through a RFP process, which is expected to begin in February 2009, if the plan is approved. A decision is required by the ICC no later than January 2009. The impact of the new procurement process in Illinois is uncertain.

As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock-in energy prices for 400 to 1,000 megawatts annually of their around-the-clock power requirements during the period June 1, 2008 to December 31, 2012, at then relevant market prices. These financial contracts do not include capacity, are not load-following products and do not involve the physical delivery of energy.

·	Volatile power prices in the Midwest affect the amount of revenues Ameren, UE, Genco, CILCO (through AERG) and EEI can generate by marketing power into the wholesale and spot markets and influence the cost of power purchased in the spot markets.

The availability and performance of UE’s, Genco’s, AERG’s and EEI’s electric generation fleet can materially impact their revenues. Genco and AERG are seeking to raise the equivalent availability and capacity factors of their power plants over the long-term through greater investments and a process improvement program. The Non-rate-regulated Generation segment expects to generate 31 million megawatthours of baseload power in 2008 (Genco - 16 million, AERG - 7 million, EEI - 8 million), 33 million megawatthours in 2009 (Genco - 17 million, AERG - 8 million, EEI - 8 million) and 30 million megawatthours in 2010 (Genco - 15 million, AERG - 7 million, EEI - 8 million).

All but 5 million megawatthours of Genco’s and AERG’s pre-2006 wholesale and retail electric power supply agreements expired during 2006. In 2007, 1 million megawatthours of these agreements, which had an average embedded selling price of $35 per megawatthour, expired. Another 2 million contracted megawatthours will expire by the end of 2008, which have an average embedded selling price of $33 per megawatthour. These agreements are being replaced with market-based sales.

The marketing strategy for the Non-rate-regulated Generation segment is to optimize generation output in a low risk manner to minimize volatility of earnings and cash flow, while seeking to capitalize on its low-cost generation fleet to provide solid, sustainable returns. To accomplish this strategy, the Non-rate-regulated Generation segment has established hedge targets for near-term years. Through a mix of physical and financial sales contracts, Marketing Company targets to hedge Non-rate-regulated Generation’s expected output by 80% to 90% for the following year, 50% to 70% for two years out, and 30% to 50% for three years out.

·	As of October 31, 2008, Marketing Company had sold approximately 98%, 85%, and 50% of Non-rate regulated Generation’s expected generation in 2008, 2009, and 2010, respectively.

The future development of ancillary services and capacity markets in MISO could increase the electric margins of UE, Genco, AERG and EEI. Ancillary services are services necessary to support the transmission of energy from generation resources to loads while maintaining reliable operation of the transmission provider’s system. MISO is currently in the process of developing a centralized regional wholesale ancillary services market, which is expected to begin in January 2009. We expect Non-rate-regulated Generation’s ancillary services market revenues to increase to $15 million in 2008 from $5 million realized in 2007. Ancillary services market revenues are allocated to Genco and AERG in accordance with their power supply agreements with Marketing Company.

We expect MISO will begin development of a capacity market once its ancillary services market is in place. A capacity market allows participants to purchase or sell capacity products that meet reliability requirements. We expect demand for capacity to strengthen from current levels because of improving market liquidity and decreasing actual reserve margins in MISO. Non-rate-regulated Generation’s capacity revenues are expected

to increase to approximately $40 million in 2008 from $25 million in 2007. EEI receives payment for 100% of its capacity sales under its power supply agreement with Marketing Company. Capacity revenues are allocated to Genco and AERG based on their generation in accordance with their power supply agreements with Marketing Company.

·	Future energy efficiency programs developed by UE, CIPS, CILCO and IP and others could also result in reduced demand for our electric generation and our electric and gas transmission and distribution services.

Fuel and Purchased Power

In 2007, 84% of Ameren’s electric generation (UE - 76%, Genco - 96%, AERG - 99%, EEI - 100%) was supplied by coal-fired power plants. About 94% of the coal used by these plants (UE - 97%, Genco - 88%, AERG - 92%, EEI - 100%) was delivered by railroads from the Powder River Basin in Wyoming. In the past, deliveries from the Powder River Basin have been restricted because of rail maintenance, weather, and derailments. In June and early July 2008, severe Midwest flooding disrupted rail deliveries. However, as of September 30, 2008, coal inventories for UE, Genco, AERG and EEI were adequate and in excess of historical levels. Disruptions in coal deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.

Genco is incurring incremental fuel costs in 2008 and 2009 to replace coal from an Illinois mine that was prematurely closed by its owner at the end of 2007. A settlement agreement with the coal mine owner was reached in June 2008 that fully reimbursed Genco, in the form of a lump-sum payment of $60 million, for increased costs for coal and transportation that it is incurring in 2008 ($33 million) and expects to incur in 2009 ($27 million). Since the entire settlement was recorded in 2008 earnings, Ameren’s and Genco’s earnings in 2009 will be lower than they otherwise would have been.

Ameren’s fuel costs (including transportation) are expected to increase in 2008 and beyond. See Item 3 - Quantitative and Qualitative Disclosures about Market Risk of this report for additional information about the percentage of fuel and transportation requirements that are price-hedged for 2008 through 2012.

Other Costs

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. UE has settled all state and federal issues associated with the December 2005 Taum Sauk incident. In addition, UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and is in the process of rebuilding the facility. The estimated cost to rebuild the upper reservoir is in the range of $480 million. UE expects the Taum Sauk plant to be out of service through early 2010. UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. As a result of this breach, UE is engaged in litigation initiated by certain private parties. We are unable to predict the timing or outcomes of this litigation, or its possible effect on UE’s results of operation, financial position, or liquidity. See Note 2 - Rate and Regulatory Matters and Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a further discussion of Taum Sauk matters.

UE's Callaway nuclear plant had a 28 day scheduled refueling and maintenance outage during the fourth quarter of 2008. UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in the spring of 2010. During a scheduled outage, which occurs every 18 months, 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 rising employee benefit costs as well as higher insurance and security costs associated with additional measures we have taken, or may need to take, at UE’s Callaway nuclear plant and at our other facilities. Insurance premiums may also increase as a result of insurance market conditions and loss experience, among other things.

Other

As required by the MoPSC, UE filed a study in November 2007 with the MoPSC evaluating the costs and benefits of UE’s participation in MISO. UE’s filing noted that there were a number of uncertainties associated with the cost-benefit study, including issues associated with the UE-MISO service agreement. In June 2008, a stipulation and agreement among UE, the MoPSC staff, MISO and other parties to the proceeding was filed with the MoPSC, which provides for UE’s continued, conditional MISO participation through April 30, 2012. The stipulation and agreement provides UE the right to seek permission from the MoPSC for early withdrawal from MISO if UE determines that sufficient progress toward mitigating some of the continuing uncertainties respecting its MISO participation is not being made. In September 2008, the MoPSC issued an order approving the stipulation and agreement.

A ballot initiative was passed by Missouri voters in November 2008 that created a renewable energy portfolio requirement. UE and other Missouri investor-owned utilities will be required to purchase or generate electricity from renewable energy sources equaling at least 2% of native load sales by 2011, with that percentage increasing in subsequent years to at least 15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each portfolio requirement must be derived from solar energy. Detailed rules will need to be issued by the MoPSC. UE has and is continuing to study the possible impacts of this renewable energy requirement, but we expect that any related costs or investments would ultimately be recovered in rates.

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, or 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.

REGULATORY MATTERS

See Note 2 - 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 is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal and operational risks, are not part of the following discussion.

Our risk management objective is to optimize our physical generating assets and pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed of senior-level Ameren officers.

Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Form 10-K. See Item 7A under Part II of the 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 in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable-rate debt outstanding at September 30, 2008:

	Interest Expense		Net Income(a)
Ameren	$	16	$	(10	)
UE		2		(1	)
CIPS		1	(b		)
Genco		-		-
CILCORP		7		(4	)
CILCO		5		(3	)
IP		3		(2	)

(a)	Calculations are based on an effective tax rate of 38%.

(b)	Less than $1 million

The estimated changes above do not consider potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably act to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure.

Insured Auction-Rate Tax-exempt Bonds

Certain auction-rate tax-exempt environmental improvement and pollution control revenue bonds previously issued for the benefit of UE, CIPS, CILCO and IP through governmental authorities were insured by “monoline” bond insurers. See Note 5 - Long-term Debt and Equity Financings under Part II, Item 8 of the Form 10-K for a description and details of this indebtedness. As a result of developments in the capital markets with respect to residential mortgage-backed securities and collateralized debt obligations, the credit rating agencies downgraded the monoline bond insurers’ credit ratings due to their insuring of such securities. As a result, our insured auction-rate bonds were similarly downgraded. We experienced higher interest expense and/or “failed auctions” with respect to a portion of our auction-rate bonds. According to press reports, many other series of auction-rate securities similarly experienced “failed auctions.”

To mitigate the effect of these credit ratings downgrades and the resulting impact on the interest rates of our auction-rate tax-exempt environmental improvement and pollution control revenue bonds, we redeemed all of UE’s, CIPS’, CILCO’s and IP’s outstanding auction-rate bonds except for UE’s 1992 Series and 1998 Series A, B and C bonds, which had an aggregate balance of $207 million at September 30, 2008, and interest rates ranging from 2.678% to 8.54% during the three months ended September 30, 2008 (2.678% to 8.54% during the nine months ended September 30, 2008). In April 2008, UE and IP issued senior secured notes in the principal amount of $250 million and $337 million, respectively, to refinance their auction-rate indebtedness. See Note 4 - Long-term Debt and Equity Financings under Part I, Item 1 of this report for a description of these redemptions and refinancings.

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. In 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 receivable and executory contracts with market risk exposures. 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.

The 2007 increase in electric rates in Illinois, and a related increase in extended payment plan arrangements, resulted in an increase in the Ameren Illinois Utilities’ past-due accounts receivable balances during 2007 and the first quarter of 2008. Such past-due balances have improved during the second and third quarters of 2008, primarily as a result of enhanced collection efforts and an increase in the volume of write-offs of past-due balances deemed uncollectible. The Ameren Illinois Utilities will continue to monitor the impact of increased electric rates on customer collections and make adjustments to their allowances for doubtful accounts, as deemed necessary, to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.

At September 30, 2008, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. UE, CIPS, Genco, CILCO, AERG, IP, AFS and Marketing Company may have credit exposure associated with interchange or wholesale purchase and sale activity with nonaffiliated companies. At September 30, 2008, UE’s, CIPS’, Genco’s, CILCO’s, AERG’s, IP’s, AFS’ and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading counterparties was $1 million, net of collateral (2007 - less than $1 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 before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged lease. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $64 million at September 30, 2008 (2007 - $32 million).

The Ameren Illinois Utilities will be exposed to credit risk in the event of nonperformance by the parties contributing to the Illinois comprehensive rate relief and assistance programs under the Illinois electric settlement agreement, which provides $488 million in rate relief over a four-year period that commenced in 2007 to certain electric customers of the Ameren Illinois Utilities. Under funding agreements among the parties contributing to the rate relief and assistance programs, at the end of each month, the Ameren Illinois Utilities will bill the participating generators for their proportionate share of that month’s rate relief and assistance, which is due in 30 days, or drawn from the funds provided by the generators’ escrow. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for additional information.

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 would be reflected in net income and OCI or regulatory assets, and in the amount of cash required to be contributed to the plans.

Foreign Currency Risk

Ameren and UE are exposed to foreign currency exchange risk from UE’s procurement agreement related to construction of a potential new nuclear plant. This agreement provides a fixed price for heavy forgings as well as consulting services to aid with design certification. The agreement requires UE to pay for goods and services rendered in Euros. UE uses foreign currency forward contracts for the purchase of Euros to mitigate the impact of changes in foreign currency exchange rates, which could affect the amount of U.S. dollars required to satisfy the obligation denominated in Euros. To the extent the value of the U.S. dollar versus the Euro declines, the effect would be reflected in construction work in process within property and plant, net, and subject to routine depreciation and impairment considerations.

Commodity Price Risk

We are exposed to changes in market prices for electricity, fuel, and natural gas. UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are partially hedged through sales agreements. Genco, AERG and EEI also seek to sell power forward to wholesale, municipal and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through structured risk management programs and policies, which include structured forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of UE, Genco, AERG and EEI is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.

The following table shows how Ameren’s cumulative earnings might decrease if power prices were to decrease by 1% on unhedged economic generation for the remainder of 2008 through 2010:

	Net Income(a)
Ameren(b)	$ (12)
UE	(5)
Genco	(3)
CILCO (AERG)	(1)
EEI	(5)

(a)	Calculations are based on an effective tax rate of 38%.

(b)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

Ameren also uses its portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. Due to our physical presence in the market, we are able to identify and pursue opportunities which can generate additional returns through portfolio management and trading activities. All of this activity is performed within a controlled risk management process. We establish value at risk (VaR) and stop-loss limits that are intended to prevent any material negative financial impact.

Similar techniques are used to manage risks associated with changing prices of fuel for generation. Most UE, Genco, AERG and EEI fuel supply contracts are physical forward contracts. UE, Genco, AERG and EEI do not have a provision similar to the PGA clause for electric operations, so UE, Genco, AERG and EEI have entered into long-term contracts with various suppliers to purchase coal and nuclear fuel to manage their exposure to fuel prices. The coal hedging strategy is intended to secure a reliable coal supply while reducing exposure to commodity price volatility. Price and volumetric risk mitigation is accomplished primarily through periodic bid procedures, whereby the amount of coal purchased is determined by the current market prices and the minimum and maximum coal purchase guidelines for the given year. We generally purchase coal up to five years in advance, but we may purchase coal beyond five years to take advantage of favorable deals or market conditions. The strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions.

Transportation costs for coal and natural gas can be a significant portion of fuel costs. We typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. Natural gas transportation expenses for Ameren’s gas distribution utility companies and the gas-fired generation units of UE, Genco, AERG and EEI are regulated by FERC through approved tariffs governing the rates, terms and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements held by

Ameren Companies include rights to extend the contracts prior to the termination of the primary term. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates for our requirements.

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, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of CIPS, CILCO and IP, which own no generation, that are price-hedged over the remainder of 2008 through 2012, as of September 30, 2008. The projected required supply of these commodities could be significantly impacted by changes in our assumptions for such matters as customer demand of our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.

	2008		2009		2010 - 2012
Ameren:
Coal	100	%	98	%	47	%
Coal transportation	100		94		28
Nuclear fuel	100		100		88
Natural gas for generation	84		14		1
Natural gas for distribution(a)	75		22		7
Purchased power for Illinois Regulated(b)	97		80		51
UE:
Coal	100	%	99	%	50	%
Coal transportation	100		96		31
Nuclear fuel	100		100		88
Natural gas for generation	79		16		1
Natural gas for distribution(a)	73		30		9
CIPS:
Natural gas for distribution(a)	82	%	24	%	9	%
Purchased power(b)	97		80		51
Genco:
Coal	99	%	97	%	42	%
Coal transportation	100		98		-
Natural gas for generation	100		-		-
CILCORP/CILCO:
Coal (AERG)	99	%	91	%	41	%
Coal transportation (AERG)	100		70		-
Natural gas for distribution(a)	80		20		5
Purchased power(b)	97		80		51
IP:
Natural gas for distribution(a)	69	%	21	%	6	%
Purchased power(b)	97		80		51
EEI:
Coal	100	%	99	%	49	%
Coal transportation	100		100		100

(a)	Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2008 represents November 2008 through March 2009. The year 2009 represents November 2009 through March 2010. This continues each successive year through March 2013.

(b)

Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than 1 megawatt of demand. Includes the financial contracts that the Ameren Illinois Utilities entered into with Marketing Company, effective August 28, 2007, and additional financial contracts entered into with Marketing Company and other suppliers, effective March 20, 2008, as part of the Illinois electric settlement agreement. Larger customers are purchasing power from the competitive markets. See Note 2 - Rate and Regulatory Matters and Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for a discussion of these financial contracts and the new power procurement process pursuant to the Illinois electric settlement agreement.

The following table shows how our cumulative fuel expense might increase and how our cumulative net income might decrease if coal and coal transportation costs were to increase by 1% on any requirements not currently covered by fixed-price contracts for the period 2008 through 2012.

	Coal					Transportation
	Fuel Expense		Net Income(a)			Fuel Expense			Net Income(a)
Ameren(b)	$	31	$	(19	)	$	18		$	(11	)
UE		12		(7	)		10			(6	)
Genco		12		(7	)		6			(4	)
CILCORP		5		(3	)		2			(1	)
CILCO (AERG)		5		(3	)		2			(1	)
EEI		2		(1	)	(c		)	(c		)

(a)	Calculations are based on an effective tax rate of 38%.

(b)	Includes amounts for Ameren registrant and nonregistrant subsidiaries.

(c)	Amount less than $1 million.

In addition, coal and coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. If diesel fuel costs were to increase or decrease by $0.25 per gallon, Ameren’s fuel expense could increase or decrease by $13 million annually (UE - $7 million, Genco - $3 million, AERG - $1 million and EEI - $2 million). As of September 30, 2008, Ameren had price-hedged approximately 100% of expected fuel surcharges in 2008 and 2009.

In the event of a significant change in coal prices, UE, Genco, AERG and EEI 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, this 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 regarding the long-term commitments for the procurement of coal, natural gas and nuclear fuel.

Fair Value of Contracts

Most of our commodity contracts qualify for treatment as normal purchases and sales. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity, FTRs and emission allowances. 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, 2008. We use various methods to determine the fair value of our contracts. In accordance with SFAS No. 157 hierarchy levels, our sources used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). All of these contracts have maturities of less than five years. See Note 7 - Fair Value Measurements to our financial statements under Part I, Item 1, of this report for further information regarding the methods used to determine the fair value of these contracts.

	Ameren(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Three Months
Fair value of contracts at beginning of period, net	$	123		$	11		$	112		$	4		$	77		$	195
Contracts realized or otherwise settled during the period		(13	)		(6	)		(1	)		(1	)		2			-
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		2			24			(17	)		(2	)		(12	)		(18	)
Other changes in fair value		(57	)		2			(106	)		(2	)		(78	)		(196	)
Fair value of contracts outstanding at end of period, net	$	55		$	31		$	(12	)	$	(1	)	$	(11	)	$	(19	)
Nine Months
Fair value of contracts at beginning of period, net	$	13		$	7		$	38		$	(4	)	$	21		$	55
Contracts realized or otherwise settled during the period		(45	)		(12	)		(4	)		4			(5	)		(4	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		38			21			(10	)		(1	)		(10	)		(15	)
Other changes in fair value		49			15			(36	)		-			(17	)		(55	)
Fair value of contracts outstanding at end of period, net	$	55		$	31		$	(12	)	$	(1	)	$	(11	)	$	(19	)

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

The following table presents maturities of derivative contracts as of September 30, 2008, based on the hierarchy levels used to determine the fair value of the contracts:

Sources of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years		Maturity 4-5 Years		Maturity in Excess of 5 Years		Total Fair Value
Ameren:
Level 1	$	(6	)	$	-	$	-	$	-	$	(6	)
Level 2(a)		20			-		-		-		20
Level 3(b)		14			27		-		-		41
Total	$	28		$	27	$	-	$	-	$	55
UE:
Level 1	$	-		$	-	$	-	$	-	$	-
Level 2(a)		10			-		-		-		10
Level 3(b)		18			3		-		-		21
Total	$	28		$	3	$	-	$	-	$	31
CIPS:
Level 1	$	-		$	-	$	-	$	-	$	-
Level 2(a)		-			-		-		-		-
Level 3(b)		(16	)		4		-		-		(12	)
Total	$	(16	)	$	4	$	-	$	-	$	(12	)
Genco:
Level 1	$	-		$	-	$	-	$	-	$	-
Level 2(a)		-			-		-		-		-
Level 3(b)		(1	)		-		-		-		(1	)
Total	$	(1	)	$	-	$	-	$	-	$	(1	)

CILCORP/CILCO:
Level 1	$	(3	)	$	-	$	-	$	-	$	(3	)
Level 2(a)		-			-		-		-		-
Level 3(b)		(11	)		3		-		-		(8	)
Total	$	(14	)	$	3	$	-	$	-	$	(11	)
IP:
Level 1	$	-		$	-	$	-	$	-	$	-
Level 2(a)		-			-		-		-		-
Level 3(b)		(28	)		8		1		-		(19	)
Total	$	(28	)	$	8	$	1	$	-	$	(19	)

(a)	Principally fixed price for floating over-the-counter power swaps, power forwards and fixed price for floating over-the-counter natural gas swaps.

(b)	Principally coal and SO2 option values based on a Black-Scholes model that includes information from external sources and our estimates. Also includes interruptible power forward and option contract values based on our estimates.

ITEM 4 and ITEM 4T. CONTROLS AND PROCEDURES.

(a)	Evaluation of Disclosure Controls and Procedures

As of September 30, 2008, evaluations were performed, under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of 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 those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.

(b)	Change in Internal Controls

There has been no change in any of 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, each of their internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses.

In October 2008, Caterpillar Inc., in conjunction with other industrial customers as a coalition, filed a request with the ICC for rehearing of its September 2008 consolidated order in the November 2007 rate cases filed by CIPS, CILCO and IP with the ICC to modify their electric and natural gas delivery service rates. Caterpillar Inc., in its filings, asked the ICC to rehear its rulings with respect to return on equity and rate design. Douglas R. Oberhelman is an officer of Caterpillar Inc. and a member of the board of directors of Ameren. Mr. Oberhelman did not participate in Ameren’s board and committee deliberations relating to these matters.

In August and October 2008, The Boeing Company, in conjunction with other industrial customers as a coalition, filed testimony in the MoPSC proceeding relating to UE’s pending request for an increase in its electric service rates. The Boeing Company, in its testimony, opposed UE’s filing on issues regarding rate design, revenue requirements, return on equity and the fuel and purchased power cost recovery mechanism. James C. Johnson is an officer of The Boeing Company and a member of the board of directors of Ameren. Mr. Johnson did not participate in Ameren’s board and committee deliberations relating to this matter.

For additional information on legal and administrative proceedings, see Note 2 - 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.

ITEM 1A. RISK FACTORS.

The Form 10-K includes a detailed discussion of our risk factors. The information presented below updates, and should be read in conjunction with, the risk factors and information disclosed in the Form 10-K.

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.

The global capital and credit markets have experienced extreme volatility and disruption in 2008, and in particular, since early September. Several factors have driven this situation, including deteriorating global economic conditions and the weakened financial condition of major financial institutions, as evidenced by the bankruptcy filing of Lehman. The extreme disruption in the capital markets has limited companies’, including the Ameren Companies’, ability to access the capital and credit markets to support their operations and refinance debt and has led to higher financing costs compared to recent years. At September 30, 2008, the Ameren Companies had in place revolving bank credit facilities aggregating $2.15 billion. In total, eighteen banks, including a Lehman subsidiary, participate in these credit facilities. Due to the Lehman bankruptcy, the size of our credit facilities was effectively reduced by up to $121 million at September 30, 2008.

We use short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied by our operating cash flow, including requirements related to future environmental compliance. As a result of rising costs and increased capital and operations and maintenance expenditures, coupled with near-term regulatory lag, we expect to need more short-term and long-term debt financing. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and to expand our businesses. Our current credit ratings cause us to believe that we will continue to have access to the capital markets. However, events beyond our control, such as the collapse of the subprime mortgage market and the extreme volatility and disruption in global capital and credit markets in 2008, may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets, including the ability to draw on our bank credit facilities. Certain of the Ameren Companies rely, in part, on Ameren for access to capital. Circumstances that limit Ameren’s access to capital, including those relating to its other subsidiaries, could impair its ability to provide those Ameren Companies with needed capital.

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

The following table presents CILCO’s purchases of equity securities reportable under Item 703 of Regulation SK:

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, 2008	165,000	$ 100.00	-	-
August 1 - August 31, 2008	-	-	-	-
September 1 - September 30, 2008	-	-	-	-
Total	165,000	$ 100.00	-	-

(a) CILCO redeemed these remaining shares of its 5.85% Class A preferred stock to complete the mandatory sinking fund redemption requirement for this series of preferred stock. 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, 2008 period.

ITEM 6. EXHIBITS.

The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.

Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
By-Laws
3.1(ii)	Ameren	By-Laws of Ameren as amended October 10, 2008	October 14, 2008 Form 8-K, Exhibit 3.1(ii), File No. 1-14756
Instruments Defining Rights of Securities Holders, Including Indentures
4.1	Ameren IP	IP Company Order dated October 23, 2008, establishing the 9.75% Senior Secured Notes due 2018 (including forms of global and definitive notes)	October 23, 2008 Form 8-K, Exhibit 4.2, File No. 1-3004
4.2	Ameren IP	Supplemental Indenture dated as of October 1, 2008 by and between IP and The Bank of New York Mellon Trust Company, N.A., as Trustee under The General Mortgage Indenture and Deed of Trust dated as of November 1, 1992, related to IP Mortgage Bonds, Senior Notes Series DD securing IP 9.75% Senior Secured Notes due 2018.	October 23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004
Material Contracts
10.1	Ameren	* Summary Sheet of Ameren Corporation Non-Management Director Compensation revised on August 8, 2008
Statement re: Computation of Ratios
12.1	Ameren	Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	UE	UE’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3	CIPS	CIPS’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements

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Exhibit Designation

Registrant(s)

Nature of Exhibit

Previously Filed as Exhibit to:

12.4	Genco	Genco’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.5	CILCORP	CILCORP’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.6	CILCO	CILCO’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.7	IP	IP’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
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 and Principal Financial Officer of Ameren
32.2	UE	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of UE
32.3	CIPS	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CIPS
32.4	Genco	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco

102

Exhibit Designation

Registrant(s)

Nature of Exhibit

Previously Filed as Exhibit to:

32.5	CILCORP	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCORP
32.6	CILCO	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCO
32.7	IP	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of IP

*	Management compensatory plan or arrangement.

103

SIGNATURES

Pursuant to the requirements of the Exchange Act, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.

AMEREN CORPORATION

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Accounting Officer

(Principal Accounting Officer)

UNION ELECTRIC COMPANY

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Accounting Officer

(Principal Accounting Officer)

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Accounting Officer

(Principal Accounting Officer)

AMEREN ENERGY GENERATING COMPANY

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Accounting Officer

(Principal Accounting Officer)

104

CILCORP INC.

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Accounting Officer

(Principal Accounting Officer)

CENTRAL ILLINOIS LIGHT COMPANY

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Accounting Officer

(Principal Accounting Officer)

ILLINOIS POWER COMPANY

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Accounting Officer

(Principal Accounting Officer)

Date: November 10, 2008

105