UNION ELECTRIC CO - Quarter Report: 2009 September (Form 10-Q)

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

for the Quarterly Period Ended September 30, 2009

¨	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.


Ameren Corporation	Yes	x	No	¨
Union Electric Company	Yes	x	No	¨
Central Illinois Public Service Company	Yes	x	No	¨
Ameren Energy Generating Company	Yes	x	No	¨
Central Illinois Light Company	Yes	x	No	¨
Illinois Power Company	Yes	x	No	¨

CILCORP Inc. has voluntarily filed all reports that it would have been required to file if it had been subject to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).


Ameren Corporation	Yes	x	No	¨
Union Electric Company	Yes	¨	No	¨
Central Illinois Public Service Company	Yes	¨	No	¨
Ameren Energy Generating Company	Yes	¨	No	¨
CILCORP Inc.	Yes	¨	No	¨
Central Illinois Light Company	Yes	¨	No	¨
Illinois Power Company	Yes	¨	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 “large accelerated filer,” “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 30, 2009, was as follows:


Ameren Corporation		Common stock, $0.01 par value per share - 236,921,011

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
	Statement of Income	12
	Balance Sheet	13
	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
	Statement of Income	27
	Balance Sheet	28
	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	88
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	130
Item 4 and
Item 4T.	Controls and Procedures	136

PART II	Other Information

Item 1.	Legal Proceedings	136
Item 1A.	Risk Factors	136
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	137
Item 6.	Exhibits	138

Signatures		140

This Form 10-Q contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included on page 7 of this Form 10-Q under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

GLOSSARY OF TERMS AND ABBREVIATIONS

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

AERG - AmerenEnergy Resources Generating Company, a CILCO subsidiary that operates a merchant 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.

AITC - Ameren Illinois Transmission Company, an Ameren Corporation subsidiary that is engaged in the construction and operation of transmission assets in Illinois and is regulated by FERC and the ICC.

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.

Btu - British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.

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

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

CILCORP - CILCORP Inc., an Ameren Corporation subsidiary that operates as a holding company for CILCO and its merchant generation 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 nuclear plant 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.

EEI - Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary that operates merchant 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, a nonaffiliated entity.

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.

FAC - A fuel and purchased power cost recovery mechanism that allows UE to recover through customer rates 95% of changes in fuel (coal, coal transportation, natural gas for generation and nuclear) and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates.

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.

Fitch - Fitch Ratings, a credit rating agency.

Form 10-K - The combined Annual Report on Form 10-K for the year ended December 31, 2008, filed by the Ameren Companies with the SEC.

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 merchant 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 was designed to introduce 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, effective 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 addressed the issue of power procurement, and it included 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 natural gas transmission and distribution businesses of CIPS, CILCO, IP and AITC.

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 was a special-purpose Delaware limited-liability company. It was dissolved in February 2009 because the remaining TFNs, with respect to which this entity was created, were redeemed by IP in September 2008.

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. It was dissolved in February 2009 because the remaining TFNs were redeemed by IP in September 2008.

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.

MACT - Maximum Achievable Control Technology.

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.

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

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.

Mmbtu - One million Btus.

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.

MPS - Multi-Pollutant Standard, an agreement reached in 2006 among Genco, CILCO (AERG), EEI and the Illinois EPA, which was codified in Illinois environmental regulations.

MTM - Mark-to-market.

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.

NO_x - Nitrogen oxide.

Noranda - Noranda Aluminum, Inc.

NPNS - Normal purchases and normal sales.

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

OCI - Other comprehensive income (loss) as defined by GAAP.

Off-system revenues - Revenues from other than native load sales.

OTC - Over-the-counter.

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

PJM - PJM Interconnection LLC.

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. Rate increase requests can take up to 11 months to be acted upon by the MoPSC and the ICC. As a result, revenue changes 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.

RTO - Regional Transmission Organization

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.

SO₂ - Sulfur dioxide.

TFN - 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. After the implementation of authoritative guidance on the consolidation of variable interest entities, IP did not consolidate IP SPT. Therefore, the obligation to IP SPT appeared on IP’s balance sheet as of December 31, 2007. In September 2008, IP redeemed the remaining 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.

VIE - Variable-interest entity.

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 pending UE, CIPS, CILCO and IP rate proceedings, and future rate proceedings or future legislative actions that seek to limit or reverse rate increases;

•

uncertainty as to the continued effectiveness of the Illinois 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;

•

increasing capital expenditure and operating expense requirements and our ability to recover these costs in a timely fashion in light of regulatory lag;

•

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 and liquidity, impossible, more difficult or more costly;

•

our assessment of our liquidity;

•

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

•

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

•

the impact of weather conditions and other natural phenomena on us and our customers;

•

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;

•

impairments of long-lived assets or goodwill;

•

the recovery of costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident and investment in a COLA for a second unit at its Callaway nuclear plant;

•

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 enacted over time, which could limit the operation of our generating units, increase our costs or otherwise have a negative financial effect;

•

labor disputes, workforce reductions, 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, credit facilities 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,
	2009		2008		2009		2008
Operating Revenues:
Electric	$	1,679	$	1,928	$	4,589	$	4,944
Gas		136		132		826		987

Total operating revenues		1,815		2,060		5,415		5,931


Operating Expenses:
Fuel		306		461		867		963
Coal contract settlement		-		-		-		(60)
Purchased power		256		371		708		964
Gas purchased for resale		57		73		523		697
Other operations and maintenance		422		456		1,294		1,361
Depreciation and amortization		185		173		541		513
Taxes other than income taxes		104		98		311		300

Total operating expenses		1,330		1,632		4,244		4,738

Operating Income		485		428		1,171		1,193

Other Income and Expenses:
Miscellaneous income		16		23		49		61
Miscellaneous expense		(3)		(10)		(14)		(23)

Total other income		13		13		35		38

Interest Charges		134		113		376		331

Income Before Income Taxes		364		328		830		900
Income Taxes		135		113		288		319

Net Income		229		215		542		581
Less: Net Income Attributable to Noncontrolling Interests		2		11		9		33

Net Income Attributable to Ameren Corporation	$	227	$	204	$	533	$	548


Earnings per Common Share – Basic and Diluted	$	1.04	$	0.97	$	2.48	$	2.61

Dividends per Common Share	$	0.385	$	0.635	$	1.155	$	1.905
Average Common Shares Outstanding		218.2		210.3		214.9		209.5

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

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions, except per share amounts)


	September 30, 2009		December 31, 2008
ASSETS

Current Assets:
Cash and cash equivalents	$	563	$	92
Accounts receivable – trade (less allowance for doubtful accounts of $29 and $28, respectively)		416		502
Unbilled revenue		250		427
Miscellaneous accounts and notes receivable		182		292
Materials and supplies		857		842
Mark-to-market derivative assets		239		207
Other current assets		273		232

Total current assets		2,780		2,594

Property and Plant, Net		17,272		16,567
Investments and Other Assets:
Nuclear decommissioning trust fund		280		239
Goodwill		831		831
Intangible assets		138		167
Regulatory assets		1,641		1,653
Other assets		652		606

Total investments and other assets		3,542		3,496

TOTAL ASSETS	$	23,594	$	22,657


LIABILITIES AND EQUITY

Current Liabilities:
Current maturities of long-term debt	$	128	$	380
Short-term debt		435		1,174
Accounts and wages payable		443		813
Taxes accrued		135		54
Interest accrued		183		107
Customer deposits		107		126
Mark-to-market derivative liabilities		197		155
Other current liabilities		298		254

Total current liabilities		1,926		3,063

Long-term Debt, Net		7,321		6,554
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,431		2,131
Accumulated deferred investment tax credits		93		100
Regulatory liabilities		1,322		1,291
Asset retirement obligations		423		406
Pension and other postretirement benefits		1,477		1,495
Other deferred credits and liabilities		555		438

Total deferred credits and other liabilities		6,301		5,861

Commitments and Contingencies (Notes 2, 8, 9 and 10)
Ameren Corporation Stockholders’ Equity:
Common stock, $0.01 par value, 400.0 shares authorized – shares outstanding of 236.8 and 212.3, respectively		2		2
Other paid-in capital, principally premium on common stock		5,392		4,780
Retained earnings		2,467		2,181
Accumulated other comprehensive loss		(21)		-

Total Ameren Corporation stockholders’ equity		7,840		6,963

Noncontrolling Interests		206		216

Total equity		8,046		7,179

TOTAL LIABILITIES AND EQUITY	$	23,594	$	22,657

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,
	2009		2008
Cash Flows From Operating Activities:
Net income	$	542	$	581
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sales of emission allowances		-		(2)
Net mark-to-market gain on derivatives		(26)		(42)
Depreciation and amortization		557		528
Amortization of nuclear fuel		40		31
Amortization of debt issuance costs and premium/discounts		16		14
Deferred income taxes and investment tax credits, net		301		130
Other		4		(2)
Changes in assets and liabilities:
Receivables		239		144
Materials and supplies		(11)		(216)
Accounts and wages payable		(241)		(74)
Taxes accrued		81		44
Assets, other		(96)		46
Liabilities, other		134		142
Pension and other postretirement benefits		30		23
Counterparty collateral, net		66		-
Taum Sauk costs, net of insurance recoveries		110		(94)

Net cash provided by operating activities		1,746		1,253

Cash Flows From Investing Activities:
Capital expenditures		(1,295)		(1,316)
Nuclear fuel expenditures		(47)		(161)
Purchases of securities – nuclear decommissioning trust fund		(315)		(386)
Sales of securities – nuclear decommissioning trust fund		315		360
Purchases of emission allowances		(4)		(2)
Sales of emission allowances		-		2
Other		1		2

Net cash used in investing activities		(1,345)		(1,501)

Cash Flows From Financing Activities:
Dividends on common stock		(247)		(399)
Capital issuance costs		(64)		(9)
Dividends paid to noncontrolling interest holders		(19)		(31)
Short-term debt, net		(739)		(65)
Redemptions, repurchases, and maturities:
Long-term debt		(250)		(823)
Preferred stock		-		(16)
Issuances:
Common stock		617		107
Long-term debt		772		1,335

Net cash provided by financing activities		70		99


Net change in cash and cash equivalents		471		(149)
Cash and cash equivalents at beginning of year		92		355

Cash and cash equivalents at end of period	$	563	$	206

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

UNION ELECTRIC COMPANY

STATEMENT OF INCOME

(Unaudited) (In millions)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Operating Revenues:
Electric – excluding off-system	$	738	$	739	$	1,818	$	1,812
Electric – off-system		78		114		302		418
Gas		19		21		120		139
Other		1		1		3		1

Total operating revenues		836		875		2,243		2,370


Operating Expenses:
Fuel		153		238		451		489
Purchased power		27		45		88		135
Gas purchased for resale		8		11		68		84
Other operations and maintenance		229		234		665		689
Depreciation and amortization		90		83		266		246
Taxes other than income taxes		72		69		200		189

Total operating expenses		579		680		1,738		1,832

Operating Income		257		195		505		538

Other Income and Expenses:
Miscellaneous income		15		17		43		46
Miscellaneous expense		(2)		(2)		(6)		(6)

Total other income		13		15		37		40

Interest Charges		61		51		171		142

Income Before Income Taxes and Equity in Income of Unconsolidated Investment		209		159		371		436
Income Taxes		67		60		123		160

Income Before Equity in Income of Unconsolidated Investment		142		99		248		276
Equity in Income of Unconsolidated Investment, Net of Taxes		-		-		-		11

Net Income		142		99		248		287
Preferred Stock Dividends		1		1		4		4

Net Income Available to Common Stockholder	$	141	$	98	$	244	$	283

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

UNION ELECTRIC COMPANY

BALANCE SHEET

(Unaudited) (In millions, except per share amounts)


	September 30, 2009		December 31, 2008
ASSETS

Current Assets:
Cash and cash equivalents	$	229	$	-
Accounts receivable – trade (less allowance for doubtful accounts of $6 and $8, respectively)		201		142
Unbilled revenue		103		111
Miscellaneous accounts and notes receivable		159		261
Accounts receivable – affiliates		140		32
Materials and supplies		367		339
Mark-to-market derivative assets		28		50
Other current assets		81		58

Total current assets		1,308		993

Property and Plant, Net		9,372		8,995
Investments and Other Assets:
Nuclear decommissioning trust fund		280		239
Intangible assets		38		48
Regulatory assets		874		897
Other assets		385		352

Total investments and other assets		1,577		1,536

TOTAL ASSETS	$	12,257	$	11,524


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Current maturities of long-term debt	$	4	$	4
Short-term debt		-		251
Intercompany note payable – Ameren		-		92
Accounts and wages payable		178		360
Accounts payable – affiliates		102		151
Taxes accrued		124		20
Interest accrued		75		56
Other current liabilities		124		121

Total current liabilities		607		1,055

Long-term Debt, Net		4,022		3,673
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,611		1,372
Accumulated deferred investment tax credits		76		80
Regulatory liabilities		934		922
Asset retirement obligations		330		317
Pension and other postretirement benefits		519		494
Other deferred credits and liabilities		111		49

Total deferred credits and other liabilities		3,581		3,234

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
Other paid-in capital, principally premium on common stock		1,555		1,119
Preferred stock not subject to mandatory redemption		113		113
Retained earnings		1,868		1,794
Accumulated other comprehensive income		-		25

Total stockholders’ equity		4,047		3,562

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	12,257	$	11,524

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

UNION ELECTRIC COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Nine Months Ended September 30,
	2009		2008
Cash Flows From Operating Activities:
Net income	$	248	$	287
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sales of emission allowances		-		(1)
Net mark-to-market gain on derivatives		(29)		(10)
Depreciation and amortization		266		246
Amortization of nuclear fuel		40		31
Amortization of debt issuance costs and premium/discounts		7		5
Deferred income taxes and investment tax credits, net		219		57
Other		(15)		(19)
Changes in assets and liabilities:
Receivables		(184)		79
Materials and supplies		(25)		(45)
Accounts and wages payable		(159)		(200)
Taxes accrued		104		57
Assets, other		(1)		97
Liabilities, other		86		55
Pension and other postretirement benefits		13		10
Taum Sauk costs, net of insurance recoveries		110		(94)

Net cash provided by operating activities		680		555

Cash Flows From Investing Activities:
Capital expenditures		(657)		(614)
Nuclear fuel expenditures		(47)		(161)
Proceeds from intercompany note receivable		-		6
Purchases of securities – nuclear decommissioning trust fund		(315)		(386)
Sales of securities – nuclear decommissioning trust fund		315		360
Sales of emission allowances		-		1
Other		(1)		-

Net cash used in investing activities		(705)		(794)

Cash Flows From Financing Activities:
Dividends on common stock		(170)		(193)
Dividends on preferred stock		(4)		(4)
Capital issuance costs		(14)		(5)
Short-term debt, net		(251)		(82)
Intercompany note payable – Ameren, net		(92)		17
Redemptions, repurchases, and maturities of long-term debt		-		(378)
Issuances of long-term debt		349		699
Capital contribution from parent		436		-

Net cash provided by financing activities		254		54


Net change in cash and cash equivalents		229		(185)
Cash and cash equivalents at beginning of year		-		185

Cash and cash equivalents at end of period	$	229	$	-

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

STATEMENT OF INCOME

(Unaudited) (In millions)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Operating Revenues:
Electric	$	180	$	190	$	508	$	539
Gas		27		25		158		173
Other		1		2		3		2

Total operating revenues		208		217		669		714


Operating Expenses:
Purchased power		97		117		297		348
Gas purchased for resale		11		13		100		117
Other operations and maintenance		40		49		138		147
Depreciation and amortization		17		16		51		50
Taxes other than income taxes		8		8		26		27

Total operating expenses		173		203		612		689

Operating Income		35		14		57		25

Other Income and Expenses:
Miscellaneous income		1		3		6		9
Miscellaneous expense		-		-		(1)		(2)

Total other income		1		3		5		7

Interest Charges		8		8		22		23

Income Before Income Taxes		28		9		40		9
Income Taxes		10		2		14		2

Net Income		18		7		26		7
Preferred Stock Dividends		1		1		2		2

Net Income Available to Common Stockholder	$	17	$	6	$	24	$	5

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

BALANCE SHEET

(Unaudited) (In millions)


	September 30, 2009		December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	9	$	-
Accounts receivable – trade (less allowance for doubtful accounts of $5 and $6, respectively)		48		79
Unbilled revenue		45		74
Miscellaneous accounts and notes receivable		1		1
Accounts receivable – affiliates		4		4
Current portion of intercompany note receivable – Genco		45		42
Current portion of intercompany tax receivable – Genco		9		9
Materials and supplies		60		70
Counterparty collateral		5		21
Current portion of regulatory assets		51		31
Deferred taxes		17		5
Other current assets		5		3

Total current assets		299		339

Property and Plant, Net		1,249		1,212
Other Assets:
Intercompany note receivable – Genco		-		45
Intercompany tax receivable – Genco		87		93
Regulatory assets		286		195
Other assets		25		33

Total investments and other assets		398		366

TOTAL ASSETS	$	1,946	$	1,917


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Short-term debt	$	-	$	62
Borrowings from money pool		-		44
Accounts and wages payable		35		48
Accounts payable – affiliates		42		49
Taxes accrued		12		7
Customer deposits		20		16
Mark-to-market derivative liabilities		14		17
Mark-to-market derivative liabilities – affiliates		38		14
Other current liabilities		43		51

Total current liabilities		204		308

Long-term Debt, Net		421		421
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		268		259
Accumulated deferred investment tax credits		8		9
Regulatory liabilities		239		234
Pension and other postretirement benefits		77		79
Other deferred credits and liabilities		175		78

Total deferred credits and other liabilities		767		659

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		204		191
Preferred stock not subject to mandatory redemption		50		50
Retained earnings		300		288

Total stockholders’ equity		554		529

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,946	$	1,917

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Nine Months Ended September 30,
	2009		2008
Cash Flows From Operating Activities:
Net income	$	26	$	7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		51		50
Amortization of debt issuance costs and premium/discounts		1		1
Deferred income taxes and investment tax credits, net		(8)		(2)
Changes in assets and liabilities:
Receivables		66		32
Materials and supplies		10		(25)
Accounts and wages payable		(14)		(6)
Taxes accrued		5		3
Assets, other		26		19
Liabilities, other		(5)		-
Pension and other postretirement benefits		2		1

Net cash provided by operating activities		160		80

Cash Flows From Investing Activities:
Capital expenditures		(83)		(65)
Proceeds from intercompany note receivable – Genco		42		39

Net cash used in investing activities		(41)		(26)

Cash Flows From Financing Activities:
Dividends on common stock		(12)		-
Dividends on preferred stock		(2)		(2)
Capital issuance costs		(3)		-
Short-term debt, net		(62)		(29)
Changes in money pool borrowings, net		(44)		-
Redemptions, repurchases, and maturities of long-term debt		-		(35)
Capital contribution from parent		13		-

Net cash used in financing activities		(110)		(66)


Net change in cash and cash equivalents		9		(12)
Cash and cash equivalents at beginning of year		-		26

Cash and cash equivalents at end of period	$	9	$	14

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

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Operating Revenues	$	212	$	238	$	655	$	667

Operating Expenses:
Fuel		79		131		224		268
Coal contract settlement		-		-		-		(60)
Other operations and maintenance		46		40		127		133
Depreciation and amortization		19		16		52		48
Taxes other than income taxes		5		5		15		16

Total operating expenses		149		192		418		405

Operating Income		63		46		237		262

Other Income and Expenses:
Miscellaneous income		-		-		-		1
Miscellaneous expense		-		(1)		-		(1)

Total other expenses		-		(1)		-		-

Interest Charges		14		14		43		40

Income Before Income Taxes		49		31		194		222
Income Taxes		22		11		74		82

Net Income	$	27	$	20	$	120	$	140

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, 2009		December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	3	$	2
Accounts receivable – affiliates		82		88
Miscellaneous accounts and notes receivable		3		15
Materials and supplies		126		122
Income tax receivable		22		5
Other current assets		1		5

Total current assets		237		237

Property and Plant, Net		2,093		1,950
Intangible Assets		37		49
Other Assets		13		8

TOTAL ASSETS	$	2,380	$	2,244


LIABILITIES AND STOCKHOLDER’S EQUITY

Current Liabilities:
Short-term debt	$	100	$	-
Current portion of intercompany note payable – CIPS		45		42
Borrowings from money pool		37		80
Accounts and wages payable		51		82
Accounts payable – affiliates		52		58
Current portion of intercompany tax payable – CIPS		9		9
Taxes accrued		14		16
Interest accrued		26		12
Deferred taxes		20		15
Other current liabilities		17		16

Total current liabilities		371		330

Long-term Debt, Net		774		774
Intercompany Note Payable – CIPS		-		45
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		182		136
Accumulated deferred investment tax credits		5		6
Intercompany tax payable – CIPS		87		93
Asset retirement obligations		52		49
Pension and other postretirement benefits		69		67
Other deferred credits and liabilities		24		49

Total deferred credits and other liabilities		419		400

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		361		241
Accumulated other comprehensive loss		(48)		(49)

Total stockholder’s equity		816		695

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	2,380	$	2,244

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,
	2009		2008
Cash Flows From Operating Activities:
Net income	$	120	$	140
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sales of emission allowances		-		(1)
Net mark-to-market (gain) loss on derivatives		(8)		1
Depreciation and amortization		65		68
Amortization of debt issuance costs and discounts		1		-
Deferred income taxes and investment tax credits, net		49		14
Other		5		-
Changes in assets and liabilities:
Receivables		18		15
Materials and supplies		(4)		(29)
Accounts and wages payable		(9)		(18)
Taxes accrued		(2)		(2)
Assets, other		(14)		9
Liabilities, other		(15)		11
Pension and other postretirement benefits		2		1

Net cash provided by operating activities		208		209

Cash Flows From Investing Activities:
Capital expenditures		(216)		(216)
Changes in money pool advances		-		(13)
Purchases of emission allowances		(2)		(2)
Sales of emission allowances		-		1

Net cash used in investing activities		(218)		(230)

Cash Flows From Financing Activities:
Dividends on common stock		-		(84)
Capital issuance costs		(4)		(2)
Short-term debt, net		100		(100)
Changes in money pool borrowings, net		(43)		(54)
Intercompany note payable – CIPS		(42)		(39)
Issuances of long-term debt		-		300

Net cash provided by financing activities		11		21


Net change in cash and cash equivalents		1		-
Cash and cash equivalents at beginning of year		2		2

Cash and cash equivalents at end of period	$	3	$	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,
	2009		2008		2009		2008
Operating Revenues:
Electric	$	200	$	227	$	548	$	584
Gas		31		37		188		257
Support services – affiliates		19		-		53		-
Other		1		-		5		1

Total operating revenues		251		264		794		842


Operating Expenses:
Fuel		37		40		85		93
Purchased power		44		84		131		225
Gas purchased for resale		14		25		129		190
Other operations and maintenance		63		49		190		145
Goodwill impairment loss		-		-		462		-
Depreciation and amortization		19		22		55		65
Taxes other than income taxes		6		4		20		18

Total operating expenses		183		224		1,072		736

Operating Income (Loss)		68		40		(278)		106

Other Income and Expenses:
Miscellaneous income		1		1		1		2
Miscellaneous expense		(2)		(2)		(4)		(4)

Total other expenses		(1)		(1)		(3)		(2)
Interest Charges		24		13		55		41

Income (Loss) Before Income Taxes		43		26		(336)		63
Income Taxes		14		8		43		20

Net Income (Loss)		29		18		(379)		43
Less: Net Income Attributable to Noncontrolling Interests		1		-		1		1

Net Income (Loss) Attributable to CILCORP Inc.	$	28	$	18	$	(380)	$	42

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

CILCORP INC.

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions, except shares)


	September 30, 2009		December 31, 2008
ASSETS

Current Assets:
Cash and cash equivalents	$	111	$	-
Accounts receivable – trade (less allowance for doubtful accounts of $9 and $3, respectively)		30		60
Unbilled revenue		17		65
Accounts and notes receivable – affiliates		61		59
Advances to money pool		1		2
Materials and supplies		126		131
Income tax receivable		29		-
Current portion of accumulated deferred income taxes, net		10		24
Current portion of regulatory assets		33		24
Other current assets		10		20

Total current assets		428		385

Property and Plant, Net		1,750		1,710
Investments and Other Assets:
Goodwill		80		542
Intangible assets		32		35
Regulatory assets		193		171
Other assets		26		22

Total investments and other assets		331		770

TOTAL ASSETS	$	2,509	$	2,865


LIABILITIES AND EQUITY

Current Liabilities:
Current maturities of long-term debt	$	124	$	126
Short-term debt		-		286
Borrowings from money pool		-		98
Intercompany note payable – Ameren		552		152
Accounts and wages payable		50		117
Accounts payable – affiliates		60		84
Taxes accrued		4		4
Mark-to-market derivative liabilities		12		21
Mark-to-market derivative liabilities – affiliates		21		7
Other current liabilities		81		69

Total current liabilities		904		964

Long-term Debt, Net		534		536
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		232		212
Accumulated deferred investment tax credits		4		5
Regulatory liabilities		62		59
Pension and other postretirement benefits		229		216
Asset retirement obligations		30		28
Other deferred credits and liabilities		90		76

Total deferred credits and other liabilities		647		596

Commitments and Contingencies (Notes 2, 8 and 9)
CILCORP Inc. Stockholder’s Equity:
Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding		-		-
Other paid-in capital		663		627
Retained earnings (deficit)		(280)		100
Accumulated other comprehensive income		22		23

Total CILCORP Inc. stockholder’s equity		405		750

Noncontrolling Interest		19		19

Total equity		424		769

TOTAL LIABILITIES AND EQUITY	$	2,509	$	2,865

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,
	2009		2008
Cash Flows From Operating Activities:
Net income (loss)	$	(379)	$	43
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net mark-to-market (gain) loss on derivatives		(3)		3
Depreciation and amortization		56		66
Amortization of debt issuance costs and premium/discounts		3		-
Deferred income taxes and investment tax credits, net		30		30
Goodwill impairment loss		462		-
Changes in assets and liabilities:
Receivables		70		(3)
Materials and supplies		5		(46)
Accounts and wages payable		(48)		16
Taxes accrued		-		2
Assets, other		(8)		(5)
Liabilities, other		2		6
Pension and postretirement benefits		11		(4)

Net cash provided by operating activities		201		108

Cash Flows From Investing Activities:
Capital expenditures		(128)		(223)
Money pool advances, net		1		(1)
Purchases of emission allowances		(1)		-
Other		1		2

Net cash used in investing activities		(127)		(222)

Cash Flows From Financing Activities:
Capital issuance costs		(14)		-
Dividends paid to noncontrolling interest holders		(1)		(1)
Short-term debt, net		(286)		(88)
Intercompany note payable – Ameren, net		400		61
Changes in money pool borrowings, net		(98)		171
Redemptions, repurchases, and maturities of:
Long-term debt		-		(19)
Preferred stock		-		(16)
Capital contribution from parent		36		-

Net cash provided by financing activities		37		108


Net change in cash and cash equivalents		111		(6)
Cash and cash equivalents at beginning of year		-		6

Cash and cash equivalents at end of period	$	111	$	-

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,
	2009		2008		2009		2008
Operating Revenues:
Electric	$	200	$	227	$	548	$	584
Gas		31		37		188		257
Support services – affiliates		19		-		53		-
Other		1		-		5		1

Total operating revenues		251		264		794		842


Operating Expenses:
Fuel		35		39		81		89
Purchased power		44		84		131		225
Gas purchased for resale		14		25		129		190
Other operations and maintenance		64		48		193		145
Depreciation and amortization		19		21		53		62
Taxes other than income taxes		6		4		20		18

Total operating expenses		182		221		607		729

Operating Income		69		43		187		113

Other Income and Expenses:
Miscellaneous income		1		1		1		2
Miscellaneous expense		(1)		(2)		(4)		(3)

Total other expenses		-		(1)		(3)		(1)

Interest Charges		13		5		28		16

Income Before Income Taxes		56		37		156		96
Income Taxes		19		13		55		34

Net Income		37		24		101		62
Preferred Stock Dividends		1		-		1		1

Net Income Available to Common Stockholder	$	36	$	24	$	100	$	61

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, 2009		December 31, 2008
ASSETS

Current Assets:
Cash and cash equivalents	$	111	$	-
Accounts receivable – trade (less allowance for doubtful accounts of $9 and $3, respectively)		30		60
Unbilled revenue		17		65
Accounts receivable – affiliates		57		51
Materials and supplies		125		131
Current portion of regulatory assets		33		24
Other current assets		39		35

Total current assets		412		366

Property and Plant, Net		1,777		1,734
Investments and Other Assets:
Intangible assets		1		1
Regulatory assets		193		171
Other assets		20		22

Total investments and other assets		214		194

TOTAL ASSETS	$	2,403	$	2,294


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Short-term debt	$	-	$	236
Borrowings from money pool		-		98
Intercompany note payable – Ameren		334		-
Accounts and wages payable		50		117
Accounts payable – affiliates		57		83
Taxes accrued		4		8
Mark-to-market derivative liabilities		12		21
Mark-to-market derivative liabilities – affiliates		21		7
Other current liabilities		64		60

Total current liabilities		542		630

Long-term Debt, Net		279		279
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		198		171
Accumulated deferred investment tax credits		4		5
Regulatory liabilities		210		206
Pension and other postretirement benefits		229		216
Asset retirement obligations		30		28
Other deferred credits and liabilities		90		75

Total deferred credits and other liabilities		761		701

Commitments and Contingencies (Notes 2, 8 and 9)
Stockholders’ Equity:
Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding		-		-
Other paid-in capital		465		429
Preferred stock not subject to mandatory redemption		19		19
Retained earnings		340		240
Accumulated other comprehensive loss		(3)		(4)

Total stockholders’ equity		821		684

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,403	$	2,294

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,
	2009		2008
Cash Flows From Operating Activities:
Net income	$	101	$	62
Adjustments to reconcile net income to net cash provided by operating activities:
Net mark-to-market (gain) loss on derivatives		(3)		3
Depreciation and amortization		54		62
Amortization of debt issuance costs and premium/discounts		2		-
Deferred income taxes and investment tax credits, net		26		30
Changes in assets and liabilities:
Receivables		66		(3)
Materials and supplies		6		(46)
Accounts and wages payable		(50)		15
Taxes accrued		(4)		7
Assets, other		3		(9)
Liabilities, other		(4)		(2)
Pension and postretirement benefits		14		1

Net cash provided by operating activities		211		120

Cash Flows From Investing Activities:
Capital expenditures		(128)		(223)
Purchases of emission allowances		(1)		-
Other		1		2

Net cash used in investing activities		(128)		(221)

Cash Flows From Financing Activities:
Dividends on preferred stock		(1)		(1)
Capital issuance costs		(7)		-
Short-term debt, net		(236)		(40)
Intercompany note payable – Ameren, net		334		-
Changes in money pool borrowings, net		(98)		171
Redemptions, repurchases, and maturities of:
Long-term debt		-		(19)
Preferred stock		-		(16)
Capital contribution from parent		36		-

Net cash provided by financing activities		28		95


Net change in cash and cash equivalents		111		(6)
Cash and cash equivalents at beginning of year		-		6

Cash and cash equivalents at end of period	$	111	$	-

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

ILLINOIS POWER COMPANY

STATEMENT OF INCOME

(Unaudited) (In millions)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Operating Revenues:
Electric	$	266	$	303	$	765	$	799
Gas		61		49		351		414
Other		2		1		10		3

Total operating revenues		329		353		1,126		1,216


Operating Expenses:
Purchased power		126		185		401		499
Gas purchased for resale		23		22		214		298
Other operations and maintenance		56		79		200		233
Depreciation and amortization		24		21		73		61
Amortization of regulatory assets		5		5		13		13
Taxes other than income taxes		12		12		46		48

Total operating expenses		246		324		947		1,152

Operating Income		83		29		179		64

Other Income and Expenses:
Miscellaneous income		1		3		3		9
Miscellaneous expense		(1)		(2)		(2)		(5)

Total other income		-		1		1		4

Interest Charges		24		22		76		72

Income (Loss) Before Income Taxes		59		8		104		(4)
Income Taxes (Benefit)		24		3		42		(2)

Net Income (Loss)		35		5		62		(2)
Preferred Stock Dividends		1		1		2		2

Net Income (Loss) Available to Common Stockholder	$	34	$	4	$	60	$	(4)

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

ILLINOIS POWER COMPANY

BALANCE SHEET

(Unaudited) (In millions)


	September 30, 2009		December 31, 2008
ASSETS

Current Assets:
Cash and cash equivalents	$	178	$	50
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $12, respectively)		93		152
Unbilled revenue		38		133
Accounts receivable – affiliates		64		23
Advances to money pool		-		44
Materials and supplies		136		144
Counterparty collateral		11		35
Current portion of regulatory assets		84		57
Other current assets		28		21

Total current assets		632		659

Property and Plant, Net		2,379		2,329
Investments and Other Assets:
Goodwill		214		214
Regulatory assets		601		517
Other assets		49		47

Total investments and other assets		864		778

TOTAL ASSETS	$	3,875	$	3,766


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities:
Current maturities of long-term debt	$	-	$	250
Accounts and wages payable		67		94
Accounts payable – affiliates		119		105
Taxes accrued		4		8
Interest accrued		35		21
Customer deposits		46		50
Mark-to-market derivative liabilities		26		36
Mark-to-market derivative liabilities – affiliates		58		20
Other current liabilities		50		64

Total current liabilities		405		648

Long-term Debt, Net		1,146		1,150
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		211		176
Regulatory liabilities		87		76
Pension and other postretirement benefits		297		314
Other deferred credits and liabilities		300		151

Total deferred credits and other liabilities		895		717

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		1,313		1,194
Preferred stock not subject to mandatory redemption		46		46
Retained earnings		67		7
Accumulated other comprehensive income		3		4

Total stockholders’ equity		1,429		1,251

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,875	$	3,766

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

ILLINOIS POWER COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Nine Months Ended September 30,
	2009		2008
Cash Flows From Operating Activities:
Net income (loss)	$	62	$	(2)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		82		67
Amortization of debt issuance costs and premium/discounts		4		7
Deferred income taxes		35		23
Other		(1)		-
Changes in assets and liabilities:
Receivables		116		52
Materials and supplies		8		(68)
Accounts and wages payable		-		13
Taxes accrued		(4)		3
Assets, other		20		(12)
Liabilities, other		23		31
Pension and other postretirement benefits		6		6

Net cash provided by operating activities		351		120

Cash Flows From Investing Activities:
Capital expenditures		(127)		(128)
Changes in money pool advances, net		44		(9)
Other		-		(2)

Net cash used in investing activities		(83)		(139)

Cash Flows From Financing Activities:
Dividends on common stock		-		(45)
Dividends on preferred stock		(2)		(2)
Capital issuance costs		(7)		(2)
Short-term debt, net		-		129
Redemptions, repurchases and maturities of long-term debt		(250)		(337)
Issuance of long-term debt		-		336
Capital contribution from parent		119		-
IP SPT maturities		-		(54)

Net cash provided by (used in) financing activities		(140)		25


Net change in cash and cash equivalents		128		6
Cash and cash equivalents at beginning of year		50		6

Cash and cash equivalents at end of period	$	178	$	12

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

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

AMEREN ENERGY GENERATING COMPANY (Consolidated)

CILCORP INC. (Consolidated)

CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)

ILLINOIS POWER COMPANY

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

September 30, 2009

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 merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by Ameren and CILCORP holding companies 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 merchant 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 merchant electric generation business (through its subsidiary, AERG) and a rate-regulated natural gas transmission and distribution business, all 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. 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.

The financial statements of Ameren, Genco, CILCORP and CILCO are prepared on a consolidated basis. UE, CIPS and IP have no subsidiaries, and therefore their financial statements were not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are 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 10-K.

Management has performed an evaluation of subsequent events through November 6, 2009, which was the date Ameren’s financial statements were issued and the date UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s and IP’s financial statements were available to be issued.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three and nine months ended September 30, 2009 and 2008. The number of stock options, restricted stock shares, and performance share units outstanding had an immaterial impact on earnings per share.

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

A summary of nonvested shares as of September 30, 2009, 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
	Share Units		Weighted-average Fair Value Per Unit		Shares		Weighted-average Fair Value Per Share
Nonvested at January 1, 2009	675,977		$	43.28	213,683		$	47.46
Granted	741,738	^(a)		15.52	-			-
Dividends	-			-	6,116			24.52
Forfeitures	(14,163	)		30.14	(3,645	)		48.30
Vested	(143,610	)^(b)		19.17	(82,277	)		45.15
Nonvested at September 30, 2009	1,259,942		$	29.83	133,877		$	48.92

(a)	Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in March 2009 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 March 2009 under the 2006 Plan was determined to be $15.52 based on Ameren’s closing common share price of $22.20 per share at March 2, 2009, and lattice simulations used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2009. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.24%, volatility of 21.3% to 33.1% for the peer group, and Ameren’s attainment of earnings per share of at least $2.54 during each year of the performance period.

Ameren recorded compensation expense of $4 million and $7 million for the three months ended September 30, 2009 and 2008, respectively, and a related tax benefit of $2 million and $3 million for the three months ended September 30, 2009 and 2008, respectively. Ameren recorded compensation expense of $12 million and $21 million for the nine months ended September 30, 2009 and 2008, respectively, and a related tax benefit of $5 million and $8 million for the nine months ended September 30, 2009 and 2008, respectively. As of September 30, 2009, total compensation expense of $11 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 19 months.

Accounting Changes and Other Matters

Noncontrolling Interests in Consolidated Financial Statements

In December 2007, the FASB issued authoritative guidance that established accounting and reporting standards for minority interests, which were recharacterized as noncontrolling interests. This guidance requires noncontrolling interests to be classified as a component of equity separate from the parent’s equity; purchases or sales of equity interests that do not result in a change in control to be accounted for as equity transactions; net income attributable to the noncontrolling interest to be included in consolidated net income in the statement of income; and upon a loss of control, the interest sold, as well as any interest retained, to be recorded at fair value, with any gain or loss recognized in earnings. We adopted the provisions of this guidance as of the beginning of 2009, which applies prospectively, except for the presentation and disclosure requirements, for which it applies retroactively. This guidance impacts Ameren and CILCORP. See Noncontrolling Interest below for additional information.

Disclosures about Derivative Instruments and Hedging Activities

In March 2008, the FASB issued amended authoritative guidance that requires entities to provide greater transparency in interim and annual financial statements about how and why the entity uses derivative instruments, how the instruments and related hedged items are accounted for, and how the instruments and related hedged items affect the financial position, results of operations, and cash flows of the entity. This guidance requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. Effective for us in the first quarter of 2009, the adoption of this guidance did not have a material impact on our results of operations, financial position, or liquidity because it provided enhanced amended disclosure requirements only. See Note 6 - Derivative Financial Instruments for additional information.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly

In April 2009, the FASB issued additional authoritative guidance regarding the factors that should be considered in estimating fair value when there has been a significant decrease in market activity for an asset or liability. The guidance, which applies to all fair value measurements, does not change the objective of a fair value measurement. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity.

Interim Disclosures about Fair Value of Financial Instruments

In April 2009, the FASB issued amended authoritative guidance to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity, because it provided enhanced disclosure requirements only. See Note 7 - Fair Value Measurements for our interim reporting disclosures.

Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB issued authoritative guidance that established a new method of recognizing and reporting other-than-temporary impairments of debt securities and contains additional annual and interim disclosure requirements related to debt and equity securities.

Under the new guidance, an impairment of debt securities is other-than-temporary if (1) the entity intends to sell the security, (2) it is more likely than not that the entity will be required to sell the security before recovery of its amortized cost basis, or (3) the entity does not expect to recover the security’s entire amortized cost basis. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity.

Subsequent Events

In May 2009, the FASB issued authoritative guidance that established general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The adoption of this guidance, effective for us as of June 30, 2009, did not have a material impact on our results of operations, financial position, or liquidity.

Variable Interest Entities

In June 2009, the FASB issued amended authoritative guidance that significantly changes the consolidation rules for VIEs. The guidance requires an enterprise to qualitatively assess the determination of the primary beneficiary of a VIE based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Further, the guidance requires an ongoing reconsideration of the primary beneficiary. It also amends the events that trigger a reassessment of whether an entity is a VIE. We are in the process of determining the impact the adoption of this guidance, effective for us as of January 1, 2010, will have on our results of operations, financial position, and liquidity, if any.

The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles

In June 2009, the FASB issued the FASB Accounting Standards Codification (the “Codification”), which is the primary source of authoritative GAAP to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification modifies the hierarchy of GAAP to include only two levels: authoritative and nonauthoritative. The Codification supersedes all non-SEC accounting and reporting standards. All other nongrandfathered, non-SEC accounting literature not included in the Codification are nonauthoritative. The adoption of the Codification, effective for us as of July 1, 2009, did not impact our results of operations, financial position, or liquidity.

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. Ameren’s and IP’s goodwill relates to the acquisition of IP in 2004. Ameren’s and CILCORP’s goodwill relates to the acquisition of CILCORP in 2003. Ameren’s goodwill also includes an additional 20% ownership interest in EEI acquired in 2004 as well as the acquisition of Medina Valley in 2003. During the first quarter of 2009, CILCORP recognized a non-cash goodwill impairment loss of $462 million. Ameren and IP did not recognize a goodwill impairment during the first nine months of 2009. See Note 14 - Goodwill Impairment for further information about CILCORP’s goodwill impairment.

Intangible Assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren’s, UE’s, Genco’s, CILCORP’s and CILCO’s intangible assets consisted of emission allowances at September 30, 2009. See also Note 9 - Commitments and Contingencies for additional information on emission allowances.

The following table presents the SO₂ and NO_x emission allowances held and the related aggregate SO₂ and NO_x emission allowance book values that were carried as intangible assets at September 30, 2009. Emission allowances consist of various individual emission allowance certificates and do not expire. Emission allowances are charged to fuel expense as they are used in operations.


SO₂ and NO_x in tons	SO₂^(a)	NO_x^(b)	Book Value^(c)
Ameren^(d)	3,085,000	31,213	$	138	^(e)
UE	1,647,000	15,840		38
Genco	753,000	11,870		37
CILCORP	357,000	758		32	^(f)
CILCO (AERG)	357,000	758		1
EEI	328,000	2,745		7

(a)	Vintages are from 2009 to 2019. Each company possesses additional allowances for use in periods beyond 2019.

(b)	Vintage is 2009.

(c)	The book value represents SO₂ and NO_x emission allowances for use in periods through 2038. The book value at December 31, 2008, for Ameren, UE, Genco, CILCORP, CILCO (AERG), and EEI was $167 million, $48 million, $49 million, $35 million, $1 million, and $9 million, respectively.

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

(e)	Includes $24 million of fair-market value adjustments recorded in connection with Ameren’s 2004 acquisition of an additional 20% ownership interest in EEI.

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

The following table presents amortization expense based on usage of emission allowances, net of gains from emission allowance sales, for Ameren, UE, Genco, CILCORP and CILCO (AERG) during the three and nine months ended September 30, 2009 and 2008.


	Three Months						Nine Months
	2009			2008			2009			2008
Ameren^(a)(b)	$	10		$	9		$	23		$	25
UE		-			-			(c	)		(1	)
Genco		5			7			13			20
CILCORP^(b)		2			2			4			5
CILCO (AERG)		(c	)		(c	)		1			(c	)

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

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

(c)	Less than $1 million.

Employee Separation and Other Charges

In the third quarter of 2009, Ameren initiated a voluntary separation program that provided eligible management employees the opportunity to voluntarily terminate and receive benefits consistent with Ameren’s standard management severance program. This program was offered to eligible management employees at Ameren’s subsidiaries, including UE, CIPS, Genco, CILCORP, CILCO and IP. Additionally, in November 2009, Ameren initiated an involuntary separation program to reduce additional management positions under terms and benefits consistent with Ameren’s standard management severance program. Ameren recorded a pretax charge to earnings of $17.5 million during the quarter ended September 30, 2009, (UE - $9 million, CIPS - $1 million, Genco - $3 million, CILCORP - $3 million, CILCO - $3 million, and IP - $1 million) for the severance costs related to both the voluntary and involuntary separation programs as well as for Merchant Generation staff reductions announced in the third quarter of 2009. This charge was recorded in other operations and maintenance expense in the applicable statements of income. It is anticipated that substantially all of this amount will be paid prior to December 31, 2009. The number of positions eliminated as a result of these separation programs, including the Merchant Generation staff reductions, will total approximately 300. In addition to these programs, Genco recorded a $4 million pretax charge to earnings in the third quarter of 2009 for the retirement of two generating units at its Meredosia power plant and for related obsolete inventory.

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 Operating Expenses - 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 on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the three and nine months ended September 30, 2009 and 2008:


	Three Months				Nine Months
	2009		2008		2009		2008
Ameren	$	44	$	43	$	128	$	130
UE		36		36		89		88
CIPS		2		2		10		11
CILCORP		2		1		8		8
CILCO		2		1		8		8
IP		4		4		21		23

Uncertain Tax Positions

The amount of unrecognized tax benefits as of September 30, 2009, was $136 million, $86 million, less than $1 million, $24 million, $17 million, $17 million, and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. The amount of unrecognized tax benefits (detriments) as of September 30, 2009, that would impact the effective tax rate, if recognized, was $6 million, $2 million, less than $1 million, $(1) million, less than $1 million, less than $1 million, and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively.

Ameren remains subject to U.S. federal income tax examination by the Internal Revenue Service for 2005 and subsequent years. 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. The Ameren Companies do not have material state income tax issues under examination, administrative appeals, or litigation.

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, UE, CIPS, Genco, CILCORP, CILCO and IP increased compared to December 31, 2008, to reflect the accretion of obligations to their fair values.

Noncontrolling Interest

At Ameren, noncontrolling interest comprises the 20% of EEI’s net assets not owned by Ameren and the preferred stock not subject to mandatory redemption of the Ameren subsidiaries. These noncontrolling interests are classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet. At CILCORP, noncontrolling interest comprises the preferred stock not subject to mandatory redemption of its subsidiary, CILCO. This noncontrolling interest is classified as a component of equity separate from CILCORP’s equity in CILCORP’s consolidated balance sheet.

A reconciliation of the equity changes attributable to the noncontrolling interest at Ameren and CILCORP for the three and nine months ended September 30, 2009 and 2008 is shown below:


	Three Months						Nine Months
	2009			2008			2009			2008
Ameren:
Noncontrolling interest, beginning of period	$	207		$	219		$	216		$	217
Net income attributable to noncontrolling interest		2			11			9			33
Dividends paid to noncontrolling interest holders		(3	)		(11	)		(19	)		(31	)
Noncontrolling interest, end of period	$	206		$	219		$	206		$	219
CILCORP:
Noncontrolling interest, beginning of period	$	19		$	19		$	19		$	19
Net income attributable to noncontrolling interest		1			-			1			1
Dividends paid to noncontrolling interest holders		(1	)		-			(1	)		(1	)
Noncontrolling interest, end of period	$	19		$	19		$	19		$	19

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

2009 Electric Rate Order

In January 2009, the MoPSC issued an order approving an increase for UE in annual revenues of approximately $162 million for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. In February 2009, Noranda, UE’s largest electric customer, and the Missouri Office of Public Counsel appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Circuit Court of Cole County, Missouri. In September 2009, the Circuit Court of Pemiscot County granted Noranda’s request to stay the electric rate increase granted by the January 2009 MoPSC order as it applies specifically to Noranda’s electric service account until the court renders its decision on the appeal. The merits of the appeal will be briefed by the parties over the next several months, with a decision likely to be issued by the court in the first half of 2010. During the stay, Noranda will pay into the court registry the contested portion of its monthly billings, approximately $0.5 million per month based on current usage levels. If UE wins the appeal, it will receive those monthly payments plus interest.

Pending Electric Rate Case

UE filed a request with the MoPSC in July 2009 to increase its annual revenues for electric service by $402 million. Included in this increase request was approximately $227 million of anticipated increases in normalized net fuel costs in excess of the net fuel costs included in base rates previously authorized by the MoPSC in its January 2009 electric rate order, which, absent initiation of this general rate proceeding, would have been eligible for recovery through UE’s existing FAC. The balance of the increase request is based primarily on investments made to continue system-wide reliability improvements for customers, increases in costs essential to generating and delivering electricity, and higher financing costs. The electric rate increase request is based on an 11.5% return on equity, a capital structure composed of 47.4% equity, a rate base for UE of $6.0 billion, and a test year ended March 31, 2009, with certain pro-forma adjustments through the anticipated true-up date of January 31, 2010. Following Ameren’s September 2009 common stock issuance, UE received a capital contribution from Ameren of $436 million in September 2009. UE expects to true-up its capital structure in the electric rate case to reflect this capital contribution, among other things. See Note 4 - Long-term Debt and Equity Financings for further information on the Ameren common stock issuance.

UE’s filing included a request for interim rate relief, which would place into effect approximately $37 million of the requested increase prior to completion of the full rate case. The amount of this interim increase request reflected the increased revenue requirement associated with rate base additions made by UE between October 2008 and May 2009. The MoPSC has scheduled a hearing in December 2009 to consider UE’s request for interim rate relief.

As part of its filing, UE also requested the MoPSC to approve the implementation of an environmental cost recovery mechanism and a storm restoration cost tracker. The environmental cost recovery mechanism, if approved, would allow UE to twice each year adjust electric rates outside of general rate proceedings to reflect changes in its prudently incurred costs to comply with federal, state or local environmental laws, regulations or rules greater than or less than the amount set in base rates. Rate adjustments pursuant to this cost recovery mechanism would not be permitted to exceed an annual amount equal to 2.5% of UE’s gross jurisdictional electric revenues and would be subject to prudency reviews of the MoPSC. UE’s request is consistent with the environmental cost recovery rules approved by the MoPSC in April 2009. The storm restoration cost tracker would permit UE a more timely recovery of storm restoration operations and maintenance expenditures.

In addition, UE requested that the MoPSC approve the continued use of the FAC and the vegetation management and infrastructure inspection cost tracking mechanism that the MoPSC previously authorized in its January 2009 electric rate order, and the continued use of the regulatory tracking mechanism for pension and postretirement benefit costs that the MoPSC previously authorized in its May 2007 electric rate order.

UE’s filing with the MoPSC also seeks approval to revise the tariff under which it serves Noranda to prospectively address the significant lost revenues UE can incur due to any future operational issues at Noranda’s smelter plant in southeastern Missouri, such as the revenue losses resulting from the January 2009 storm-related power outage. The tariff change that UE is proposing would permit it to collect from Noranda the revenue authorized by the MoPSC in this rate case regardless of the level at which the Noranda plant is operating prospectively. If the plant is operating at levels less than the levels assumed in rates, Noranda would receive a credit reflecting any revenues received by UE from energy sales resulting from the decrease in actual energy sales to Noranda. The result would be that UE is able to recover its costs without impacting other customers regardless of Noranda’s actual energy use.

The MoPSC proceeding relating to the proposed electric service rate changes (except for the request for interim rate relief as discussed above) will take place over a period of up to 11 months, and a decision by the MoPSC in such proceeding is required by the end of June 2010. Hearings are scheduled for March 2010. UE cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change (interim or final) may go into effect, whether the cost recovery mechanisms and trackers requested will be approved or continued, or whether any rate change that may eventually be approved will be sufficient to enable UE to recover its costs and earn a reasonable return on its investments when the rate change goes into effect.

Missouri Energy Efficiency Investment Act

In July 2009, the Missouri governor signed a law that went into effect in August 2009, which, among other things, allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. Recovery is only permitted if the program is approved by the MoPSC, results in energy savings, and is beneficial to all customers in the class for which the program is proposed. The new law would potentially, among other items, allow UE to earn a return on its energy efficiency programs, which the current model of cost recovery does not permit.

Illinois

Pending Electric and Natural Gas Delivery Service Rate Cases

In June 2009, CIPS, CILCO and IP filed requests with the ICC to increase their annual revenues for electric delivery service. The currently pending requests, as amended, seek to increase annual revenues from electric delivery service by $136 million in the aggregate (CIPS - $41 million, CILCO - $22 million, and IP - $73 million). The electric rate increase requests are based on an 11.3% to 11.7% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.4 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010. In addition, the Ameren Illinois Utilities have requested a rider mechanism that would permit all distribution-related costs incurred to implement reliability recommendations submitted by the Liberty Consulting Group, which are discussed below, to be reflected in electric rates outside of general rate proceedings. The Ameren Illinois Utilities estimate that they will incur distribution-related implementation costs of $15 million (CIPS - $5 million, CILCO - $3 million, and IP - $7 million) in 2010.

CIPS, CILCO and IP also filed requests with the ICC in June 2009 to increase their annual revenues for natural gas delivery service. The currently pending requests, as amended, seek to increase annual revenues for natural gas delivery service by $26 million in the aggregate (CIPS - $7 million, CILCO - $6 million, and IP - $13 million). The natural gas rate increase requests are based on a 10.8% to 11.2% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $1.0 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010.

In September 2009, the ICC staff filed direct testimony in response to the Ameren Illinois Utilities electric and natural gas delivery service rate increase filings. The ICC staff recommended in their testimony a net increase in revenues for electric delivery service for the Ameren Illinois Utilities of $49 million in the aggregate (CIPS - $16 million increase, CILCO - $6 million increase, and IP - $27 million increase) and a net decrease in revenues for natural gas delivery service of $4 million in the aggregate (CIPS - $1 million increase, CILCO - $3 million decrease, and IP - $2 million decrease). The ICC staff position is based on a 10.2% to 10.4% return on equity for electric delivery service and a 9.4% to 9.8% return on equity for natural gas delivery service. Other parties also made recommendations through direct testimony filed in the electric and natural gas delivery service rate cases.

The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes will take place over a period of up to 11 months, and decisions by the ICC in such proceedings are required by May 2010. Hearings are scheduled for December 2009. The Ameren Illinois Utilities cannot predict the level of any delivery service rate changes the ICC may approve, when any rate changes may go into effect, or whether any rate changes that may eventually be approved will be sufficient to enable the Ameren Illinois Utilities to recover their costs and earn a reasonable return on their investments when the rate changes go into effect.

Illinois Electric Settlement Agreement

The Ameren Illinois Utilities, Genco, and CILCO (AERG) recognize in their financial statements the costs of their respective rate relief contributions and program funding under the Illinois electric settlement agreement in a manner corresponding with the timing of the funding. As a result, 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, 2009, of $6 million, $1 million, $1 million, $1 million, $3 million, and $1 million, respectively (quarter ended September 30, 2008 - $10 million, $2 million, less than $1 million, $2 million, $4 million, and $2 million, respectively) and during the nine months ended September 30, 2009, of $18 million, $3 million, $1 million, $4 million, $7 million, and $3 million, respectively (nine months ended September 30, 2008 - $32 million, $5 million, $2 million, $6 million, $13 million, and $6 million, respectively).

Power Procurement Plan

In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. The plan outlined the wholesale products that the IPA procured on behalf of the Ameren Illinois Utilities for the period June 1, 2009, through May 31, 2014. The IPA procured capacity, energy swaps, and renewable energy credits through a RFP process on behalf of the Ameren Illinois Utilities in the second quarter of 2009. See Note 8 - Related Party Transactions and Note 9 - Commitments and Contingencies for further information about the results of the RFPs.

In August 2009, the IPA submitted its plan for procurement of electric power for the Ameren Illinois Utilities and Commonwealth Edison Company for the period June 1, 2010, through May 31, 2015. The plan must be approved or modified by the ICC by December 29, 2009. The IPA is proposing to hold two procurement events in 2010: one in the spring for energy, capacity and renewable energy credits and a second in the fall for demand response resources. The exact dates of each procurement event have not been determined. Once the proposed 2010 procurement events are complete, the Ameren Illinois Utilities will have sufficient capacity and energy hedges in place for 100% of their expected supply obligation for the period June 2010 through May 2011, 70% of their expected supply obligation for the period June 2011 through May 2012, and 44% of their expected supply obligations for the period June 2012 through May 2013. Renewable energy credits will be procured for 2010 only.

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. In October 2008, Liberty Consulting Group presented the ICC with a final report containing recommendations for the Ameren Illinois Utilities to improve their systems and their response to emergencies. The ICC directed the Ameren Illinois Utilities to present to the ICC a plan to implement Liberty Consulting Group’s recommendations. The plan was submitted to the ICC in November 2008. Liberty Consulting Group will monitor the Ameren Illinois Utilities’ efforts to implement the recommendations and any initiatives that the Ameren Illinois Utilities undertake. The Ameren Illinois Utilities expect to incur an estimated $20 million ($15 million for distribution and $5 million for transmission) of capital costs and an estimated $66 million ($50 million for distribution and $16 million for transmission) of cumulative operations and maintenance expenses for the 2009 through 2013 timeframe in order to implement the recommendations. In testimony filed with the ICC in October 2009 as part of the pending electric delivery service rate cases, the Ameren Illinois Utilities requested recovery of all distribution-related costs through the implementation of a rider mechanism that would permit the Ameren Illinois Utilities to reflect these costs in electric rates outside of general rate proceedings. Transmission-related costs will be recoverable through FERC’s ratemaking proceedings.

Illinois 2009 Energy Legislation

In July 2009, a new law became effective in Illinois that, among other things, establishes new energy efficiency targets for Illinois natural gas utilities, develops a percentage of income payment plan for low-income utility customers, and allows electric and gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their rates. The legislation provides utilities the ability to adjust their rates annually through a rate adjustment mechanism that applies to 2008 and subsequent years. During 2008, the Ameren Illinois Utilities incurred approximately $25 million more of bad debt expense (CIPS - $5 million, CILCO - $4 million, and IP - $16 million) than they recovered through rates. In August 2009, the Ameren Illinois Utilities filed with the ICC electric and natural gas rate adjustment clause tariffs to recover bad debt expense not recovered in 2008 and to make corresponding rate adjustments beginning in 2010. The ICC has until February 2010 to approve, or approve as modified, the filed tariffs.

Upon ICC approval of the rate adjustment clause tariffs filed in August 2009, the Ameren Illinois Utilities will be required to make a one-time $10 million donation (CIPS - $3 million, CILCO - $2 million, and IP - $5 million) for customer assistance programs. The amount of the required one-time donation and the impact of the recovery of 2008 bad debt expenses were reflected in earnings during the third quarter of 2009.

Federal

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 unit at UE’s existing Callaway County, Missouri, nuclear plant site. UE had also signed contracts for COLA-related services and certain long lead-time nuclear-unit related equipment (heavy forgings).

In early 2009, the Missouri Clean and Renewable Energy Construction Act was separately introduced in both the Missouri Senate and House of Representatives. These bills were designed to allow the MoPSC to authorize, among other things, utilities to recover the costs of financing and tax payments associated with a new generating plant while that plant was being constructed. Recovery of actual construction costs still could not have begun until a plant was put into service. UE believes legislation allowing timely recovery of financing costs during construction must be enacted in order for it to build a new nuclear unit to meet its baseload generation capacity needs. However, passage of this or other legislation was not a commitment or guarantee that UE would build a new nuclear unit.

In April 2009, senior management of UE announced that they had asked the legislative sponsors of the Missouri Clean and Renewable Energy Construction Act to withdraw the bills from consideration by the Missouri General Assembly. UE believed pursuing the legislation being considered in the Missouri Senate in its then proposed form would not give it the financial and regulatory certainty needed to complete the project. As a result, UE announced that it was suspending its efforts to build a new nuclear unit at its existing Missouri nuclear plant site. In June 2009, UE requested the NRC suspend review of the COLA and all activities related to the COLA. UE will consider all available and feasible generation options to meet future customer requirements as part of an integrated resource plan that UE is due to file with the MoPSC in 2011.

As of September 30, 2009, UE had capitalized approximately $68 million as construction work in progress related to the COLA. The incurred costs will remain capitalized while management assesses all options to maximize the value of its investment in this project. If all efforts are permanently abandoned with respect to the future construction of a new nuclear unit, it is possible that a charge to earnings could be recognized in a future period.

Prior to June 30, 2009, UE made contractual payments to the heavy forgings manufacturer of $14 million and had remaining contractual commitments of $81 million. In July 2009, an agreement was reached with the heavy forgings manufacturer to terminate the heavy forgings procurement agreement, and $5 million of previously-made payments were retained by the manufacturer as a penalty for terminating the contract, which was charged to earnings in June 2009. See Note 9 - Commitments and Contingencies for further information about the contract termination.

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 until the end of the continuing proceedings at FERC regarding these costs. Other MISO participants also filed appeals. On August 10, 2007, UE, CIPS, CILCO, and IP filed a complaint with FERC regarding the MISO tariff’s allocation methodology for these same MISO operational charges. 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 was required to reallocate certain of MISO’s operational costs among MISO market participants, which would result in refunds to UE, CIPS, CILCO, and IP retroactive to April 2006. On November 7, 2008, FERC issued an order granting the request for clarification and directed MISO to reallocate certain MISO operational costs among MISO participants and provide refunds for the period April 2006 to August 2007 (“November 7, 2008 Clarification Order”). On November 10, 2008, FERC granted further relief requested in the complaints filed by UE, CIPS, CILCO, IP and others regarding further reallocation for these same MISO operational charges and directed MISO to calculate refunds for the period from August 10, 2007, forward (“November 10, 2008 Complaint Order”).

Several parties to these proceedings protested MISO’s proposed implementation of these refunds, requested rehearing of FERC’s orders and, in some cases, have appealed FERC’s orders to the courts. In March 2009, MISO began resettling its markets to provide refunds as FERC directed effective on August 10, 2007. On May 6, 2009, FERC issued an order that upheld most of the conclusions of the November 10, 2008 Complaint Order but changed the effective date for refunds such that certain operational costs will be allocated among MISO market participants beginning November 10, 2008, instead of August 10, 2007. In June 2009, UE, CIPS, CILCO and IP filed for rehearing of the May 2009 order regarding the change to the refund effective date. This rehearing request is pending.

With respect to the November 7, 2008 Clarification Order, in June 2009 FERC issued an order dismissing rehearing requests of such clarification order and waiving refunds of amounts billed that were included in the MISO charge under the assumption that there was a rate mismatch for the period April 25, 2006, through November 4, 2007. UE, CIPS, CILCO and IP filed a request for rehearing in July 2009. This rehearing request is pending.

With respect to the two rehearing requests discussed above, UE, CIPS, CILCO and IP do not believe that the ultimate resolution of either request will have a material effect on their results of operations, financial position, or liquidity.

MISO and PJM Dispute Resolution

During 2009, MISO and PJM discovered an error in the calculation quantifying certain transactions between the RTOs. The error originated in April 2005, corresponding with the initiation of the MISO Day Two Energy Market and was corrected prospectively in June 2009. Since discovering the error, MISO and PJM have worked jointly to estimate the financial impact to the respective markets. MISO and PJM are in agreement on the methodology used to recalculate the market flows occurring from June 2007 to June 2009 for the resettlement due from PJM to MISO estimated at $65 million. MISO and PJM are not in agreement on the methodology used to recalculate the market flows occurring from April 2005 to May 2007, nor are they in agreement over the resettlement amount. To

resolve this issue, MISO and PJM have agreed to participate in FERC’s dispute resolution and settlement process to determine a resettlement amount for the entire period from April 2005 to June 2009. In October 2009, an administrative law judge was appointed as mediator, and a settlement conference was held at FERC. A final settlement between MISO and PJM, if and when reached, will be subject to FERC approval. Ameren, and its subsidiaries, may receive a to-be-determined portion of the resettlement amount due from PJM to MISO. Until a settlement has been reached and approved by FERC, we cannot predict the ultimate impact of these proceedings on Ameren’s, UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s and IP’s results of operations, financial position, or liquidity.

NOTE 3 - SHORT-TERM BORROWINGS AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash and drawings under committed bank credit facilities.

Amended and New Credit Facilities

On June 30, 2009, Ameren and certain of its subsidiaries entered into multiyear credit facility agreements with 24 international, national and regional lenders with no single lender providing more than $146 million of credit. These facilities, as described below, cumulatively provide $2.1 billion of credit through July 14, 2010, thereafter reducing to $1.8795 billion through June 30, 2011, and thereafter reducing to $1.0795 billion through July 14, 2011.

2009 Multiyear Credit Agreements

On June 30, 2009, Ameren, UE, and Genco entered into an agreement (the “2009 Multiyear Credit Agreement”) to amend and restate the $1.15 billion five-year revolving credit agreement that was originally entered into as of July 14, 2005, then amended and restated as of July 14, 2006, and due to expire in July 2010 (the “Prior $1.15 Billion Credit Facility”). Ameren, UE, and Genco also entered into a $150 million Supplemental Credit Agreement to the 2009 Multiyear Credit Agreement (the “Supplemental Agreement”), which provides Ameren, UE, and Genco with an additional facility of $150 million with terms and conditions substantially identical to the 2009 Multiyear Credit Agreement. Collectively, these agreements are the “2009 Multiyear Credit Agreements.”

The obligations of each borrower under the 2009 Multiyear Credit Agreements are several and not joint, and except under limited circumstances relating to expenses and indemnities, the obligations of UE or Genco are not guaranteed by Ameren or any other subsidiary of Ameren. The combined maximum amount available to all of the borrowers, collectively, under the 2009 Multiyear Credit Agreements is $1.3 billion, and the combined maximum amount available to each borrower, individually, under the 2009 Multiyear Credit Agreements is limited as follows: Ameren - $1.15 billion, UE - $500 million and Genco - $150 million (such amounts being each borrower’s “Borrowing Sublimit”). CIPS, CILCO, and IP have no borrowing authority or liability under the 2009 Multiyear Credit Agreements.

On July 14, 2010, the Supplemental Agreement will terminate, all commitments and all outstanding amounts under the Supplemental Agreement will be consolidated with those under the 2009 Multiyear Credit Agreement, and the combined maximum amount available to all borrowers will be $1.0795 billion with the UE and Genco Borrowing Sublimits remaining the same noted above and Ameren’s changing to $1.0795 billion. Ameren has the option to seek additional commitments from existing or new lenders to increase the total facility size to $1.3 billion after July 14, 2010. The 2009 Multiyear Credit Agreement will terminate with respect to Ameren on July 14, 2011, representing a one-year extension from the Prior $1.15 Billion Credit Facility. The Borrowing Sublimits

of UE and Genco will continue to be subject to extension on a 364-day basis (but in no event later than July 14, 2011) with the current maturity date of their Borrower Sublimits under the 2009 Multiyear Credit Agreements being June 29, 2010.

The obligations of all borrowers under the 2009 Multiyear Credit Agreements are unsecured. The interest rates applicable to loans under the 2009 Multiyear Credit Agreements will be either ABR (alternate base rate) plus the margin applicable to the particular borrower and/or the Eurodollar rate plus the margin applicable to the particular borrower. The applicable margins will be determined by reference to such borrower’s long-term unsecured credit ratings as in effect from time to time. A competitive bid rate is also available if requested by a borrower. Letters of credit in an aggregate undrawn face amount not to exceed $287.5 million are available for issuance for account of the borrowers under (but within the $1.3 billion overall combined facility limitation) the 2009 Multiyear Credit Agreements.

Under the 2009 Multiyear Credit Agreements, the principal amount of each revolving loan will be due and payable no later than the final maturity of the agreements, in the case of Ameren, and the last day of the then applicable 364-day period in the case of UE and Genco. Ameren, UE and Genco will use the proceeds of any borrowings under the 2009 Multiyear Credit Agreements for general corporate purposes, including for working capital, and to fund loans under the Ameren money pool arrangements.

2009 Illinois Credit Agreement

Also on June 30, 2009, Ameren, CIPS, CILCO, and IP entered into an $800 million multiyear, senior secured credit agreement (the “2009 Illinois Credit Agreement”). The 2009 Illinois Credit Agreement replaces the Ameren Illinois Utilities’ existing $500 million credit facility dated as of July 14, 2006 (the “2006 $500 Million Credit Facility (Terminated)”), and their existing $500 million credit facility dated as of February 9, 2007 (the “2007 $500 Million Credit Facility (Terminated)”), each as previously amended (collectively, the “Terminated Illinois Credit Facilities”), which were terminated contemporaneously with the effectiveness of the 2009 Illinois Credit Agreement.

Ameren was not a borrower under the Terminated Illinois Credit Facilities, but is a borrower under the 2009 Illinois Credit Agreement. CILCORP and AERG were borrowers under the Terminated Illinois Credit Facilities, but are not parties to or borrowers under the 2009 Illinois Credit Agreement. All obligations of CILCORP and AERG under the Terminated Illinois Credit Facilities have been repaid and all liens securing such obligations have been released. CILCORP and AERG expect to meet their external liquidity needs through borrowings under the Ameren non-state-regulated subsidiary money pool arrangements or other liquidity arrangements.

The obligations of each borrower under the 2009 Illinois Credit Agreement are several and not joint, and are not guaranteed by Ameren or any other subsidiary of Ameren. The maximum amount available to each borrower under the facility is limited as follows: Ameren - $300 million, CIPS - $135 million, CILCO - $150 million and IP - $350 million (such amounts being such borrower’s “Borrowing Sublimit”).

The 2009 Illinois Credit Agreement will terminate with respect to all borrowers on June 30, 2011. Each borrowing under the 2009 Illinois Credit Agreement must be repaid no later than 364 days after such borrowing, in each case subject to the right of the applicable borrower on such date to make a new borrowing or convert or continue such borrowing as a new borrowing subject to satisfaction of the applicable conditions to borrowing. The obligations of the Ameren Illinois Utilities under the 2009 Illinois Credit Agreement are secured by the issuance of mortgage bonds, for collateral support, by each such utility under its respective mortgage indenture in an amount equal to its respective Borrowing Sublimit. Ameren’s obligations are unsecured.

Loans are available on a revolving basis under the 2009 Illinois Credit Agreement and may be repaid and, subject to satisfaction of the conditions to borrowing, reborrowed from time to time. At the election of each borrower, the interest rates applicable under the 2009 Illinois Credit Agreement are ABR plus the margin applicable to the particular borrower and/or the Eurodollar rate plus the

margin applicable to the particular borrower. The applicable margins will be determined by reference to, in the case of Ameren, Ameren’s long-term unsecured credit ratings as in effect from time to time, and in the case of the Ameren Illinois Utilities, such utility’s long-term secured credit ratings as in effect from time to time. Letters of credit in an aggregate undrawn face amount not to exceed $200 million are also available for issuance for the account of the borrowers (but within the $800 million overall facility limitation) under the 2009 Illinois Credit Agreement.

Borrowings were made under the 2009 Illinois Credit Agreement to repay amounts owed under the Terminated Illinois Credit Facilities, and the borrowers will use the proceeds of other borrowings for working capital and other general corporate purposes.

The following table summarizes the borrowing activity and relevant interest rates as of September 30, 2009, under the 2009 Multiyear Credit Agreements, the 2009 Illinois Credit Agreement and the Terminated Illinois Credit Facilities (excluding letters of credit issued):


2009 Multiyear Credit Agreement ($1.15 billion)^(a)						Ameren (Parent)			UE			Genco			Total
September 30, 2009:
Average daily borrowings outstanding during 2009						$	252		$	355		$	49		$	656
Outstanding short-term debt at period end							279			-			88			367
Weighted-average interest rate during 2009							1.75	%		1.72	%		2.57	%		1.75	%
Peak short-term borrowings during 2009^(b)						$	484		$	457		$	133		$	940
Peak interest rate during 2009							5.50	%		5.50	%		3.56	%		5.50	%

Supplemental Agreement ($150 million)						Ameren (Parent)			UE			Genco			Total
September 30, 2009:
Average daily borrowings outstanding during 2009						$	8		$	14		$	5		$	27
Outstanding short-term debt at period end							36			-			12			48
Weighted-average interest rate during 2009							3.65	%		3.62	%		3.53	%		3.65	%
Peak short-term borrowings during 2009^(b)						$	56		$	53		$	17		$	109
Peak interest rate during 2009							5.50	%		5.50	%		3.56	%		5.50	%

2009 Illinois Credit Agreement ($800 million)			Ameren (Parent)			CIPS			CILCO (Parent)			IP			Total
September 30, 2009:
Average daily borrowings outstanding during 2009			$	133		$	-		$	-		$	-		$	133
Outstanding short-term debt at period end				-			-			-			-			-
Weighted-average interest rate during 2009				3.54	%		-			-			-			3.54	%
Peak short-term borrowings during 2009^(b)			$	200		$	-		$	-		$	-		$	200
Peak interest rate during 2009				3.56	%		-			-			-			3.56	%

2007 $500 Million Credit Facility (Terminated)	CIPS		CILCORP (Parent)			CILCO (Parent)			IP			AERG			Total
September 30, 2009:
Average daily borrowings outstanding during 2009^(c)	$	-	$	9		$	-		$	-		$	59		$	68
Outstanding short-term debt at period end		-		-			-			-			-			-
Weighted-average interest rate during 2009^(c)		-		1.81	%		-			-			1.42	%		1.47	%
Peak short-term borrowings during 2009^(b)(c)	$	-	$	50		$	-		$	-		$	100		$	135
Peak interest rate during 2009^(c)		-		1.81	%		-			-			3.25	%		3.25	%


2006 $500 Million Credit Facility (Terminated)	CIPS			CILCORP (Parent)			CILCO (Parent)		IP		AERG			Total
September 30, 2009:
Average daily borrowings outstanding during 2009^(c)	$	5		$	49		$	-	$	-	$	96		$	150
Outstanding short-term debt at period end		-			-			-		-		-			-
Weighted-average interest rate during 2009^(c)		2.02	%		1.88	%		-		-		1.34	%		1.54	%
Peak short-term borrowings during 2009^(b)(c)	$	62		$	50		$	-	$	-	$	151		$	263
Peak interest rate during 2009^(c)		2.02	%		3.29	%		-		-		2.72	%		3.29	%

(a)	The 2009 Multiyear Credit Agreement amended and restated the Prior $1.15 Billion Credit Facility and therefore information in this table includes borrowing activity under the Prior $1.15 Billion Credit Facility.

(b)	The timing of peak short-term borrowings varies by company and therefore the amounts presented by company may not equal the total peak short-term borrowings for the period. The simultaneous peak short-term borrowings under all facilities during the first nine months of 2009 were $1 billion.

(c)	Calculated through the termination date.

Based on outstanding borrowings under the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement (including reductions for $11 million of letters of credit issued under the 2009 Multiyear Credit Agreement), the available amounts under the facilities at September 30, 2009, were $874 million and $800 million, respectively.

On January 21, 2009, Ameren entered into a $20 million term loan agreement due January 20, 2010, which was fully drawn on January 21, 2009. The average annual interest rate for borrowing under the $20 million term loan agreement was 1.98% and 2.06% during the three and nine months ended September 30, 2009, respectively.

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. The average annual interest rate for borrowing under the $300 million term loan agreement was 1.98% during the period it was outstanding in 2009. This term loan was repaid at maturity in June 2009 with proceeds from the Ameren $425 million senior unsecured notes due May 2014 issued in May 2009. See Note 4 - Long-term Debt and Equity Financings.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants. See Note 4 - Short-term Borrowings and Liquidity in the Form 10-K for a detailed description of those provisions in the Prior $1.15 Billion Credit Facility, the Terminated Illinois Credit Facilities, the now-terminated 2008 $300 million term loan agreement, and the 2009 $20 million term loan agreement.

The 2009 Multiyear Credit Agreements contain conditions to borrowings and issuances of letters of credit similar to those in the Prior $1.15 Billion Credit Facility, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation) and required regulatory authorizations. The 2009 Multiyear Credit Agreements also contain nonfinancial covenants similar to those in the Prior $1.15 Billion Credit Facility, including restrictions on the ability to incur liens, transact with affiliates, dispose of assets, and merge with other entities. In addition, Ameren and certain subsidiaries are restricted to limited investments in and other transfers to affiliates, including investments in the Ameren Illinois Utilities and their subsidiaries.

The 2009 Multiyear Credit Agreements contain identical default provisions that are, in each case, similar to those in the Prior $1.15 Billion Credit Facility, including a cross default of a borrower to the occurrence of a default by such borrower under any other agreement covering indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and non-material subsidiaries) in excess of $25 million in the aggregate. A default by an Ameren Illinois utility under the 2009 Illinois Credit

Agreement does not constitute a default under the 2009 Multiyear Credit Agreements. Any default of Ameren under the 2009 Illinois Credit Agreement that exists solely as a result of a default by an Ameren Illinois utility thereunder will not constitute a default under either of the 2009 Multiyear Credit Agreements while Ameren is otherwise in compliance with all of its obligations under the 2009 Illinois Credit Agreement.

The 2009 Multiyear Credit Agreements require Ameren, UE and Genco to each maintain consolidated indebtedness of not more than 65% of consolidated total capitalization pursuant to a calculation set forth in the facilities. All of the consolidated subsidiaries of Ameren, including the Ameren Illinois Utilities, are included for purposes of determining compliance with this capitalization test with respect to Ameren. Failure to satisfy the capitalization covenant constitutes a default under the 2009 Multiyear Credit Agreements. As of September 30, 2009, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2009 Multiyear Credit Agreements, were 50%, 48% and 52%, for Ameren, UE and Genco, respectively.

The 2009 Illinois Credit Agreement contains conditions to borrowings and issuance of letters of credit similar to those in the Terminated Illinois Credit Facilities, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding, for so long as ratings conditions shall be satisfied, any representation after the closing date as to the absence of material adverse change and material litigation which exclusion is new to the 2009 Illinois Credit Agreement) and required regulatory authorizations. The rating condition is satisfied if the borrower has a Moody’s rating of Baa3 or higher or an S&P rating of BBB- or higher (in the case of Ameren, with respect to senior unsecured long-term debt, and in the case of the Ameren Illinois Utilities, with respect to senior secured long-term debt). The 2009 Illinois Credit Agreement contains nonfinancial covenants including restrictions on the ability to incur liens, transact with affiliates, dispose of assets, and merge with other entities. The Ameren Illinois Utilities may engage in certain mergers or similar transactions that result in their utility operations being conducted by a single legal entity. In addition, the 2009 Illinois Credit Agreement has nonfinancial covenants limiting the ability of a borrower to invest in or transfer assets to affiliates, covenants regarding the status of the collateral securing the 2009 Illinois Credit Agreement and maintenance of the validity of the security interests therein.

The 2009 Illinois Credit Agreement contains default provisions similar to those in the Terminated Illinois Credit Facilities. Defaults under the 2009 Illinois Credit Agreement apply separately to each borrower; provided that a default by an Ameren Illinois utility will constitute a default by Ameren. Defaults include a cross default of a borrower to the occurrence of a default by such borrower under any other agreement covering indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and non-material subsidiaries) in excess of $25 million in the aggregate. A default by Genco or UE under the 2009 Multiyear Credit Agreements does not constitute an event of default under the 2009 Illinois Credit Agreement. Any default of Ameren under the 2009 Multiyear Credit Agreements that exists solely as a result of a default by UE or Genco thereunder will not constitute a default under the 2009 Illinois Credit Agreement while Ameren is otherwise in compliance with all of its obligations under the 2009 Multiyear Credit Agreements. Furthermore, under the 2009 Illinois Credit Agreement, the occurrence of a default resulting from an event or conditions effecting AERG, shall be deemed to constitute a default with respect to Ameren under the 2009 Illinois Credit Agreement, but shall not in itself constitute a default with respect to CILCO unless the liability that CILCO has in respect of such default or such underlying event or condition giving rise to such default would otherwise constitute a default with respect to CILCO had such underlying event or condition occurred or existed at CILCO.

The 2009 Illinois Credit Agreement requires Ameren and each Ameren Illinois utility to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation. All of the consolidated subsidiaries of Ameren are included for purposes of determining compliance with this capitalization test with respect to Ameren. As of September 30, 2009, the ratios of consolidated indebtedness to total consolidated capitalization for Ameren, CIPS, CILCO and IP, calculated in accordance with the provisions of the 2009 Illinois Credit Agreement, were 50%, 45%, 44%, and 45%, respectively. In addition, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, as of the end of the most recent four fiscal quarters and calculated and subject to adjustment in accordance with the 2009 Illinois Credit Agreement. Ameren’s ratio as of September 30, 2009 was 4.7 to 1. Failure to satisfy these covenants constitutes a default under the 2009 Illinois Credit Agreement.

In addition, the 2009 Illinois Credit Agreement prohibits CILCO from issuing any preferred stock if, after such issuance, the aggregate liquidation value of all CILCO preferred stock issued after June 30, 2009, would exceed $50 million. The 2009 Illinois Credit Agreement does not include the $10 million per year restriction on CIPS, CILCORP, CILCO and IP common and preferred stock dividend payments that was included in the Terminated Illinois Credit Facilities.

Under the $20 million term loan agreement entered into in January 2009, Ameren may elect, for up to three 30-day periods, to pay down and reduce to zero the outstanding principal balance. The term loan agreement requires Ameren to maintain consolidated indebtedness of not more than 65% of consolidated total capitalization pursuant to a calculation defined in the term loan agreement. As of September 30, 2009, the ratio of consolidated indebtedness to consolidated total capitalization for Ameren calculated in accordance with the provisions of the $20 million term loan agreement was 49%.

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, 2009, 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 the committed credit facilities. See discussion above for amounts available under the facilities at September 30, 2009. UE, CIPS, CILCO and IP may borrow from each other 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 primary sources of external funds for the utility money pool are the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement. The average interest rate for borrowing under the utility money pool for the three and nine months ended September 30, 2009, was 0.2% and 0.2%, respectively (2008 - 2.9% and 3.3%, 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 funding from the 2009 Multiyear Credit Agreements through a non-state-regulated subsidiary money pool agreement. In addition, Ameren had available cash balances at September 30, 2009, which can be loaned into this arrangement. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three and nine months ended September 30, 2009, was 2.2% and 1.5%, respectively (2008 - 3.5% and 3.7%, 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 and nine months ended September 30, 2009.

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 0.7 million new shares of common stock valued at $18 million and 2.6 million new shares of common stock valued at $65 million in the three and nine months ended September 30, 2009, respectively.

In May 2009, Ameren issued $425 million of 8.875% senior unsecured notes due May 15, 2014, with interest payable semiannually on May 15 and November 15 of each year, beginning November 15, 2009. Ameren received net proceeds of $420 million, which were used, together with other corporate funds, to repay borrowings under its $300 million term loan agreement and, by way of a capital contribution to CILCORP, providing funds for it to repay its outstanding 8.70% senior notes on their due date of October 15, 2009.

In September 2009, Ameren issued and sold 21.9 million shares of its common stock at $25.25 per share, for proceeds of $535 million, net of $17 million of issuance costs. Ameren used the net offering proceeds to make investments in its rate-regulated utility subsidiaries in the form of equity capital contributions as follows: UE - $436 million, CIPS - $13 million, CILCO - $25 million, and IP - $61 million.

In March 2009, UE issued $350 million of 8.45% senior secured notes due March 15, 2039, with interest payable semiannually on March 15 and September 15 of each year, beginning in September 2009. These notes are secured by first mortgage bonds. UE received net proceeds of $346 million, which were used to repay short-term debt. In connection with this issuance of $350 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 first 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.

CILCORP

In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was increased to fair value by $111 million. Amortization related to fair-value adjustments was $1 million and $4 million (2008 - $1 million and $4 million) for the three and nine months ended September 30, 2009, respectively, and was included in interest expense in the Consolidated Statements of Income of Ameren and CILCORP.

In September 2008, CILCORP commenced a cash tender offer and related consent solicitation for any and all of its then outstanding 8.70% senior notes due 2009 and its 9.375% senior bonds due 2029. In April 2009, CILCORP terminated the tender offer and the consent solicitation related to the then outstanding 8.70% senior notes due 2009. In July 2009, CILCORP terminated the tender offer and the consent solicitation related to the outstanding 9.375% senior bonds due 2029. None of the 2009 notes or the 2029 bonds were purchased in the tender offer and consent solicitation.

In November 2009, CILCORP commenced a cash tender offer for any and all of its outstanding 9.375% senior bonds due 2029 ($210.565 million aggregate principal amount). Concurrent with the tender offer, CILCORP solicited consents from the holders of the bonds to certain proposed amendments to the indenture governing the bonds. Any holder tendering bonds 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 bonds. The amendments would eliminate certain restrictive covenants in the indenture and the bonds. The total consideration for each $1,000 principal amount of bonds validly tendered on or prior to November 17, 2009, the consent date, is $1,210, which includes a consent payment of $50 per $1,000 principal amount of such bonds tendered on or prior to the consent date. Holders validly tendering and not withdrawing bonds on or before the consent date are eligible to receive the total consideration. Holders validly tendering bonds after the consent date but on or before the expiration date, which is scheduled for December 7, 2009, are eligible to receive the total consideration less the consent payment. In addition, tenders of bonds may be withdrawn (and related consents may be rescinded) at any time prior to the consent date. 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, 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 not expected to be material.

In March 2009, IP exchanged all $400 million of its unregistered 9.75% senior secured notes due November 15, 2018, for a like amount of registered 9.75% senior secured notes due November 15, 2018. The unregistered senior secured notes were issued and sold in October 2008 with registration rights in a private placement.

In June 2009, $250 million of IP’s 7.50% series first mortgage bonds matured and were retired.

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 indenture provisions and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. UE, CIPS, CILCO and IP are required to meet certain ratios to issue 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 for the 12 months ended September 30, 2009, 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	³2.0	2.4	$	713	³2.5	35.8	$	988
CIPS	³2.0	4.4		368	³1.5	2.1		154
CILCO	³2.0^(d)	7.5		214	³2.5	124.9		50	^(e)
IP	³2.0	3.2		1,364	³1.5	1.7		135

(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 either on meeting required coverage ratios or unfunded property additions, whichever is more restrictive. These amounts shown also include bonds issuable based on retired bond capacity of $95 million, $18 million, $44 million and $536 million, at UE, CIPS, CILCO and IP, respectively.

(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 three and nine months ended September 30, 2009, CILCO had earnings equivalent to at least 33% of the principal amount of all mortgage bonds outstanding.

(e)	See Note 3 - Short-term Borrowings and Liquidity for a discussion regarding the restriction on the issuance of preferred stock by CILCO under the 2009 Illinois Credit Agreement.

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 $1.8 billion of free and unrestricted retained earnings at September 30, 2009.

CILCO’s articles of incorporation contain certain provisions that prohibit the payment of dividends on its common stock (1) from either paid-in surplus or any surplus created by a reduction of stated capital or capital stock, or (2) 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, 2009:


	Required Interest Coverage Ratio		Actual Interest Coverage Ratio	Required Debt-to- Capital Ratio		Actual Debt-to- Capital Ratio
Genco^(a)	³1.75	^(b)	5.8	£60	%	47	%
CILCORP^(c)	³2.2		3.8	£67	%	39	%

(a)

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

(b)	Ratio excludes amounts payable under Genco’s intercompany note to CIPS. The ratio must be met both for the prior four fiscal quarters and 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 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. Even if CILCORP is not in compliance with these restrictions, CILCORP may still 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, 2009, CILCORP’s senior long-term debt ratings from Moody’s, S&P, and Fitch were Ba1, BB+, and BBB-, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior bonds.

In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At September 30, 2009, 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 and nine months ended September 30, 2009 and 2008:


	Three Months						Nine Months
	2009			2008			2009			2008
Ameren:^(a)
Miscellaneous income:
Interest and dividend income	$	7		$	10		$	22		$	35
Allowance for equity funds used during construction		8			8			22			19
Other		1			5			5			7
Total miscellaneous income	$	16		$	23		$	49		$	61
Miscellaneous expense:
Donations	$	(1	)	$	(4	)	$	(5	)	$	(10	)
Other		(2	)		(6	)		(9	)		(13	)
Total miscellaneous expense	$	(3	)	$	(10	)	$	(14	)	$	(23	)
UE:
Miscellaneous income:
Interest and dividend income	$	8		$	8		$	22		$	26
Allowance for equity funds used during construction		7			8			20			19
Other		-			1			1			1
Total miscellaneous income	$	15		$	17		$	43		$	46
Miscellaneous expense:
Donations	$	-		$	-		$	(3	)	$	(2	)
Other		(2	)		(2	)		(3	)		(4	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(6	)	$	(6	)
CIPS:
Miscellaneous income:
Interest and dividend income	$	1		$	2		$	4		$	7
Other		-			1			2			2
Total miscellaneous income	$	1		$	3		$	6		$	9
Miscellaneous expense:
Donations	$	-		$	-		$	(1	)	$	(1	)
Other		-			-			-			(1	)
Total miscellaneous expense	$	-		$	-		$	(1	)	$	(2	)
Genco:
Miscellaneous income:
Other	$	-		$	-		$	-		$	1
Total miscellaneous income	$	-		$	-		$	-		$	1
Miscellaneous expense:
Other	$	-		$	(1	)	$	-		$	(1	)
Total miscellaneous expense	$	-		$	(1	)	$	-		$	(1	)
CILCORP:
Miscellaneous income:
Interest income	$	1		$	1		$	1		$	2
Total miscellaneous income	$	1		$	1		$	1		$	2


	Three Months						Nine Months
	2009			2008			2009			2008
Miscellaneous expense:
Donations	$	-		$	-		$	(1	)	$	(1	)
Other		(2	)		(2	)		(3	)		(3	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(4	)	$	(4	)
CILCO:
Miscellaneous income:
Interest income	$	1		$	1		$	1		$	2
Total miscellaneous income	$	1		$	1		$	1		$	2
Miscellaneous expense:
Donations	$	-		$	-		$	(1	)	$	(1	)
Other		(1	)		(2	)		(3	)		(2	)
Total miscellaneous expense	$	(1	)	$	(2	)	$	(4	)	$	(3	)
IP:
Miscellaneous income:
Interest income	$	-		$	-		$	-		$	4
Allowance for equity funds used during construction		1			-			2			-
Other		-			3			1			5
Total miscellaneous income	$	1		$	3		$	3		$	9
Miscellaneous expense:
Donations	$	-		$	-		$	(1	)	$	(2	)
Other		(1	)		(2	)		(1	)		(3	)
Total miscellaneous expense	$	(1	)	$	(2	)	$	(2	)	$	(5	)

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

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity, and emission allowances. Such price fluctuations may cause the following:

•

an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

•

market values of fuel and natural gas inventories or emission allowances that differ from the cost of those commodities in inventory; and

•

actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

The following table presents open gross derivative volumes by commodity type as of September 30, 2009:


	Quantity
Commodity	NPNS Contracts^(a)		Cash Flow Hedges^(b)		Other Derivatives^(c)		Derivatives Subject to Regulatory Deferral^(d)
Coal (in tons)
Ameren^(e)	84,560,000		(f	)	(f	)	(f	)
UE	47,016,000		(f	)	(f	)	(f	)
Genco	17,740,000		(f	)	(f	)	(f	)
CILCORP/CILCO	9,926,000		(f	)	(f	)	(f	)
Natural gas (in mmbtu)
Ameren^(e)	182,466,000		(f	)	155,075,000		126,137,000
UE	23,660,000		(f	)	935,000		20,870,000
CIPS	30,727,000		(f	)	(f	)	19,593,000
Genco	(f	)	(f	)	3,700,000		(f	)
CILCORP/CILCO	54,303,000		(f	)	(f	)	31,135,000
IP	73,776,000		(f	)	(f	)	54,539,000
Heating oil (in gallons)
Ameren^(e)	(f	)	(f	)	181,062,000		51,660,000
UE	(f	)	(f	)	(f	)	51,660,000
Power (in megawatthours)
Ameren^(e)	82,584,000		33,007,000		33,534,000		12,738,000
UE	4,577,000		(f	)	706,000		5,341,000
CIPS	(f	)	(f	)	(f	)	11,521,000
CILCORP/CILCO	(f	)	(f	)	(f	)	5,935,000
IP	(f	)	(f	)	(f	)	17,456,000
SO₂ emission allowances (in tons)
Ameren	(f	)	(f	)	1,000		(f	)
Genco	(f	)	(f	)	1,000		(f	)
Uranium (in pounds)
Ameren	(f	)	(f	)	(f	)	250,000
UE	(f	)	(f	)	(f	)	250,000

(a)	Contracts through 2013, 2015, and 2035 for coal, natural gas, and power, respectively.

(b)	Contracts through 2011 for power.

(c)	Contracts through 2009, 2012, 2013, and 2009 for natural gas, heating oil, power, and SO₂ emission allowances, respectively.

(d)	Contracts through 2013, 2012, 2012 and 2011 for natural gas, heating oil, power, and uranium, respectively.

(e)	Includes amounts from Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

(f)	Not applicable.

Authoritative guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 7 - Fair Value Measurements for our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income.

Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value charged or credited to regulatory assets or regulatory liabilities in the period in which the change occurs. Regulatory assets or regulatory liabilities are amortized to the statement of income as related losses and gains are reflected in rates charged to customers.

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs.

The following table presents the carrying value and balance sheet location of all derivative instruments as of September 30, 2009:


	Balance Sheet Location	Ameren^(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Derivative assets designated as hedging instruments
Commodity contracts:
Power	MTM derivative assets	$	43		$	-		$	(b	)	$	(b	)	$	(b	)	$	(b	)
	Other assets		10			-			-			-			-			-
	Total assets	$	53		$	-		$	-		$	-		$	-		$	-
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power	MTM derivative liabilities	$	1		$	(b	)	$	-		$	(b	)	$	-		$	-
	Total liabilities	$	1		$	-		$	-		$	-		$	-		$	-
Derivative assets not designated as hedging instruments
Commodity contracts:
Natural gas	MTM derivative assets	$	53		$	2		$	(b	)	$	(b	)	$	(b	)	$	(b	)
	Other current assets		-			-			1			-			3			2
	Other assets		12			1			1			-			2			4
Heating oil	MTM derivative assets		31			6			(b	)		(b	)		(b	)		(b	)
	Other assets		44			12			-			-			-			-
Power	MTM derivative assets		112			20			(b	)		(b	)		(b	)		(b	)
	Other current assets		-			-			-			-			-			-
	Other assets		17			-			-			-			-			-
	Total assets	$	269		$	41		$	2		$	-		$	5		$	6
Derivative liabilities not designated as hedging instruments
Commodity contracts:
Natural gas	MTM derivative liabilities	$	102		$	(b	)	$	10		$	(b	)	$	10		$	20
	Other current liabilities		-			10			-			1			-			-
	Other deferred credits and liabilities		34			5			6			-			5			14
Heating oil	MTM derivative liabilities		22			(b	)		-			(b	)		-			-
	Other deferred credits and liabilities		15			-			-			-			-			-
Power	MTM derivative liabilities		70			(b	)		4			(b	)		2			6
	MTM derivative liabilities – affiliates		(b	)		(b	)		38			(b	)		21			58
	Other current liabilities		-			7			-			-			-			-
	Other deferred credits and liabilities		8			-			105			-			54			159
Uranium	MTM derivative liabilities		2			(b	)		-			(b	)		-			-
	Other current liabilities		-			2			-			-			-			-
	Total liabilities	$	253		$	24		$	163		$	1		$	92		$	257

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

(b)	Balance sheet line item not applicable to registrant.

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of September 30, 2009:


	Ameren^(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Cumulative gains (losses) deferred in accumulated OCI:
Power forwards^(b)	$	56		$	-		$	-		$	-		$	-		$	-
Interest rate swaps^(c)(d)		(10	)		-			-			(10	)		-			-
Cumulative gains (losses) deferred in regulatory assets or liabilities:
Natural gas swaps and futures contracts^(e)		(65	)		(11	)		(15	)		-			(10	)		(28	)
Financial contracts^(f)		-			14			(146	)		-			(76	)		(222	)
Heating oil options and swaps^(g)		(7	)		(7	)		-			-			-			-
Uranium swaps^(h)		(2	)		(2	)		-			-			-			-

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

(b)	Represents gains associated with power forwards at Ameren as of September 30, 2009. The power forwards are a partial hedge of electricity price exposure through August 2011, including current gains of $45 million at Ameren as of September 30, 2009.

(c)

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 which began in June 2002. The carrying value at September 30, 2009, was $1 million. Over the next twelve months, $0.7 million of the gain will be amortized.

(d)

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 loss on the interest rate swaps is being amortized over a 10-year period which began in April 2008. The carrying value at September 30, 2009, was a loss of $11 million. Over the next twelve months, $1.4 million of the loss will be amortized.

(e)

Represents losses associated with natural gas swaps and futures contracts. The swaps and futures contracts are a partial hedge of natural gas requirements through March 2014 at UE, through October 2014 at CIPS and IP, and through October 2013 at CILCO, in each case as of September 30, 2009. Current gains deferred as regulatory liabilities include $2 million, $1 million, $3 million, and $2 million at UE, CIPS, CILCO and IP, respectively, as of September 30, 2009. Current losses deferred as regulatory assets include $10 million, $10 million, $10 million, and $20 million at UE, CIPS, CILCO and IP, respectively, as of September 30, 2009.

(f)

Represents gains (losses) associated with financial contracts. The financial contracts are a partial hedge of power price exposure through December 2011 at UE and December 2012 at CIPS, CILCO and IP. Current gains deferred as regulatory liabilities include $20 million at UE as of September 30, 2009. Current losses deferred as regulatory assets include $7 million, $42 million, $23 million, and $64 million at UE, CIPS, CILCO and IP, respectively, as of September 30, 2009.

(g)

Represents losses on heating oil options and swaps at UE. The options and swaps are a partial hedge of our transportation costs for coal through December 2013. Current gains deferred as regulatory liabilities include $2 million at UE as of September 30, 2009. Current losses deferred as regulatory assets include $11 million at UE as of September 30, 2009.

(h)	Represents losses on uranium swaps at UE. The swaps are a partial hedge of our uranium requirements through November 2011. Current losses deferred as regulatory assets include $2 million at UE as of September 30, 2009.

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and daily exposure reporting to senior management.

We believe that entering into master trading and netting agreements mitigates the level of financial loss resulting from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) International Swaps and Derivatives Association agreement - a standardized financial natural gas and electric contract, (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association - a standardized contract for the purchase and sale of wholesale power, and (3) North American Energy Standards Board, Inc. agreement - a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of September 30, 2009, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.


	Affiliates		Coal Producers		Electric Utilities		Financial Companies		Commodity Marketing Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Retail Companies		Total
Ameren^(a)	$	622	$	6	$	37	$	147	$	23	$	203	$	11	$	80	$	1,129
UE		46		4		7		26		1		24		-		-		108
CIPS		-		-		-		2		-		-		-		-		2
Genco		-		1		1		2		-		-		1		-		5
CILCORP/CILCO		-		1		-		6		-		-		-		-		7
IP		-		-		-		6		-		-		1		-		7

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

The following table presents the amount of cash collateral held from counterparties, as of September 30, 2009, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:

Affiliates

Coal

Producers

Electric

Utilities

Financial
Companies

Commodity
Marketing

Companies

Municipalities/

Cooperatives

Oil and Gas

Companies

Retail

Companies

Total

Ameren^(a)

(a)	Represents amounts held by Marketing Company. As of September 30, 2009, Ameren registrant subsidiaries held no cash collateral.

The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. Other collateral consisted of letters of credit in the amount of $40 million and $1 million held by Ameren and UE, respectively, as of September 30, 2009. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of September 30, 2009:


	Affiliates		Coal Producers		Electric Utilities		Financial Companies		Commodity Marketing Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Retail Companies		Total
Ameren^(a)	$	622	$	1	$	14	$	101	$	8	$	155	$	9	$	79	$	989
UE		46		1		6		22		-		23		-		-		98
CIPS		-		-		-		-		-		-		-		-		-
Genco		-		-		-		-		-		-		1		-		1
CILCORP/ CILCO		-		-		-		2		-		-		-		-		2
IP		-		-		-		-		-		-		-		-		-

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

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings or a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of September 30, 2009, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral required to be posted with counterparties, based on the net liability position as allowed under the master trading and netting agreements, if the credit risk-related contingent features underlying these agreements were triggered on September 30, 2009, and those counterparties with rights to do so requested collateral:


	Aggregate Fair Value of Derivative Liabilities^(a)		Cash Collateral Posted		Aggregate Amount of Additional Collateral Required^(b)
Ameren^(c)	$	555	$	42	$	413
UE		160		12		157
CIPS		39		8		26
Genco		62		-		53
CILCORP/CILCO		69		3		63
IP		81		17		45

(a)	Prior to consideration of master trading and netting agreements and including NPNS contract exposures.

(b)	As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is after consideration of the effects of such agreements.

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

Cash Flow Hedges

The following table presents the pretax net gain or loss for the three months ended September 30, 2009, associated with derivative instruments designated as cash flow hedges:


Derivatives in Cash Flow Hedging Relationship	Amount of Gain (Loss) Recognized in OCI on Derivatives^(a)		Location of (Gain) Loss Reclassified from Accumulated OCI into Income^(b)	Amount of (Gain) Loss Reclassified from Accumulated OCI into Income^(b)			Location of Gain (Loss) Recognized in Income on Derivatives^(c)	Amount of Gain (Loss) Recognized in Income on Derivatives^(c)
Ameren:^(d)
Power	$	7	Operating Revenues - Electric	$	(19	)	Operating Revenues - Electric	$	(4	)
Interest rate^(e)		-	Interest Charges		(f	)	Interest Charges		-
Genco:
Interest rate^(e)		-	Interest Charges		(f	)	Interest Charges		-

(a)	Effective portion of gain (loss).

(b)	Effective portion of (gain) loss on settlements.

(c)	Ineffective portion of gain (loss) and amount excluded from effectiveness testing.

(d)	Includes amounts from Ameren registrant and nonregistrant subsidiaries.

(e)	Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.

(f)	Less than $1 million.

The following table presents the pretax net gain or loss for the nine months ended September 30, 2009, associated with derivative instruments designated as cash flow hedges:


Derivatives in Cash Flow Hedging Relationship	Amount of Gain (Loss) Recognized in OCI on Derivatives^(a)			Location of (Gain) Loss Reclassified from Accumulated OCI into Income^(b)	Amount of (Gain) Loss Reclassified from Accumulated OCI into Income^(b)			Location of Gain (Loss) Recognized in Income on Derivatives^(c)	Amount of Gain (Loss) Recognized in Income on Derivatives^(c)
Ameren:^(d)
Power	$	54		Operating Revenues - Electric	$	(82	)	Operating Revenues - Electric	$	(20	)
Interest rate^(e)		-		Interest Charges		(f	)	Interest Charges		-
UE:
Power		(21	)	Operating Revenues - Electric - off-system		(19	)	Operating Revenues - Electric - off-system		2
Genco:
Interest rate^(e)		-		Interest Charges		(f	)	Interest Charges		-

(a)	Effective portion of gain (loss).

(b)	Effective portion of (gain) loss on settlements.

(c)	Ineffective portion of gain (loss) and amount excluded from effectiveness testing.

(d)	Includes amounts from Ameren registrants and nonregistrant subsidiaries.

(e)	Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.

(f)	Less than $1 million.

See Note 11 - Other Comprehensive Income for additional information regarding changes in OCI.

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments for the three months ended September 30, 2009:


	Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
Ameren^(a)	Natural gas (generation)	Operating Expenses - Fuel	$	1
	Heating oil	Operating Expenses - Fuel		(1	)
	Power	Operating Revenues - Electric		(26	)
		Total	$	(26	)
UE	Natural gas (generation)	Operating Expenses - Fuel	$	(1	)

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

The following table represents the net change in market value for derivatives not designated as hedging instruments for the nine months ended September 30, 2009:


	Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
Ameren^(a)	Natural gas (generation)	Operating Expenses - Fuel	$	5
	Heating oil	Operating Expenses - Fuel		38
	Power	Operating Revenues - Electric		3
		Total	$	46
UE	Natural gas (generation)	Operating Expenses - Fuel	$	3
	Heating oil	Operating Expenses - Fuel		25
	Power	Operating Revenues - Electric - excluding off-system		(2	)
	Power	Operating Revenues - Electric - off-system		1
		Total	$	27
Genco	Heating oil	Operating Expenses - Fuel	$	8
CILCORP/CILCO	Heating oil	Operating Expenses - Fuel	$	3

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

Derivatives Subject to Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three months ended September 30, 2009:


	Derivatives Subject to Regulatory Deferral	Amount of Gain (Loss) Recognized in Regulatory Assets or Regulatory Liabilities on Derivatives
Ameren^(a)	Natural gas	$	63
	Heating oil		(1	)
	Power		(17	)
	Uranium		(2	)
	Total	$	43
UE	Natural gas	$	10
	Heating oil		(1	)
	Power		(7	)
	Uranium		(2	)
	Total	$	-
CIPS	Natural gas	$	12
	Power		(20	)
	Total	$	(8	)
CILCORP/CILCO	Natural gas	$	16
	Power		(13	)
	Total	$	3
IP	Natural gas	$	25
	Power		(40	)
	Total	$	(15	)

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

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the nine months ended September 30, 2009:


	Derivatives Subject to Regulatory Deferral	Amount of Gain (Loss) Recognized in Regulatory Assets or Regulatory Liabilities on Derivatives
Ameren^(a)	Natural gas	$	53
	Heating oil		(6	)
	Power		(1	)
	Uranium		(2	)
	Total	$	44
UE	Natural gas	$	4
	Heating oil		(6	)
	Power		14
	Uranium		(2	)
	Total	$	10
CIPS	Natural gas	$	13
	Power		(90	)
	Total	$	(77	)
CILCORP/CILCO	Natural gas	$	15
	Power		(47	)
	Total	$	(32	)
IP	Natural gas	$	21
	Power		(137	)
	Total	$	(116	)

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

UE, CIPS, CILCO and IP believe gains and losses on derivatives deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating expenses as related losses and gains are reflected in revenue through rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.

As part of the electric rate order issued by the MoPSC in January 2009, UE was granted permission to implement a FAC, which was effective March 1, 2009. UE utilizes derivatives to mitigate its exposure to changing prices of fuel for generation and related transportation costs, and for power price volatility. In connection with the MoPSC’s approval of the FAC, gains and losses associated with these types of derivatives are considered refundable to, or recoverable from, customers and, thus, represent regulatory liabilities or regulatory assets, respectively. During the first quarter of 2009, UE recorded a net regulatory liability of $5 million associated with the reclassification of unrealized gains and losses previously recorded in accumulated OCI and earnings related to open UE derivative positions with delivery dates subsequent to March 1, 2009. The reclassification of previously recorded unrealized gains associated with the derivatives resulted in a $47 million reduction of accumulated OCI. The reclassification of previously recognized unrealized losses resulted in a $42 million increase in pretax earnings, of which $38 million offset fuel expense and $4 million increased operating revenues. See Note 2 - Rate and Regulatory Matters for additional information on the FAC.

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 while they are being accounted for as derivatives subject to regulatory deferral at the Ameren Illinois Utilities. 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 derivative instruments are eliminated. See Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K for additional information on these financial contracts.

NOTE 7 - FAIR VALUE MEASUREMENTS

The Ameren Companies adopted authoritative accounting guidance for fair value measurements as of the beginning of their 2008 fiscal year for financial assets and liabilities and as of the beginning of their 2009 fiscal year for nonfinancial assets and liabilities, except those already reported at fair value on a recurring basis. The impact of the adoption of this guidance for financial assets and liabilities at January 1, 2008, and for nonfinancial assets and liabilities at January 1, 2009, was not material. Fair value is defined 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. With these approaches, we adopt 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. The guidance 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 including 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, such as 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. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms 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 that use 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 that are often unobservable in the market, as well as 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 subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose 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). The guidance 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 million in losses in the third quarter of 2009 related to valuation adjustments for counterparty default risk. At September 30, 2009, the counterparty default risk valuation adjustment related to net derivative (assets) liabilities totaled $1 million, $- million, $12 million, $- million, $5 million, and $17 million for Ameren, UE, CIPS, Genco, CILCORP/CILCO 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, 2009:


		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	$	-	$	-	$	2	$	2
	Derivative assets^(b)		47		60		215		322
	Nuclear Decommissioning Trust Fund^(c)		224		53		2		279
UE	Derivative assets		-		8		33		41
	Nuclear Decommissioning Trust Fund^(c)		224		53		2		279
CIPS	Derivative assets^(b)		-		-		2		2
Genco	Derivative assets^(b)		-		-		-		-
CILCORP/CILCO	Derivative assets^(b)		-		-		5		5
IP	Derivative assets^(b)		1		-		5		6
Liabilities:
Ameren^(a)	Derivative liabilities^(b)	$	60	$	30	$	164	$	254
UE	Derivative liabilities^(b)		5		3		16		24
CIPS	Derivative liabilities^(b)		1		-		162		163
Genco	Derivative liabilities^(b)		-		-		1		1
CILCORP/CILCO	Derivative liabilities^(b)		-		-		92		92
IP	Derivative liabilities^(b)		-		-		257		257

(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 $1 million of receivables, payables, and accrued income, net.

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 December 31, 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	$	-	$	-	$	6	$	6
	Derivative assets^(b)		1		19		234		254
	Nuclear Decommissioning Trust Fund^(c)		164		81		2		247
UE	Derivative assets		-		14		36		50
	Nuclear Decommissioning Trust Fund^(c)		164		81		2		247
CIPS	Derivative assets^(b)		-		-		-		-
Genco	Derivative assets^(b)		-		-		-		-
CILCORP/CILCO	Derivative assets^(b)		-		-		-		-
IP	Derivative assets^(b)		-		-		-		-
Liabilities:
Ameren^(a)	Derivative liabilities^(b)	$	9	$	6	$	219	$	234
UE	Derivative liabilities^(b)		-		3		31		34
CIPS	Derivative liabilities^(b)		-		-		84		84
Genco	Derivative liabilities^(b)		-		-		1		1
CILCORP/CILCO	Derivative liabilities^(b)		4		-		55		59
IP	Derivative liabilities^(b)		-		-		134		134

(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 ($8) 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, 2009:


					Realized and Unrealized Gains (Losses)								Total Realized			Purchases,									Change in Unrealized Gains (Losses) Related to
		Beginning Balance at July 1, 2009			Included in Earnings^(a)			Included in AOCI		Included in Regulatory Assets/ Liabilities			and Unrealized Gains (Losses)			Issuances, and Other Settlements, Net			Net Transfers Into (Out of) Level 3			Ending Balance at September 30, 2009			Assets/Liabilities Still Held at September 30, 2009
Other current assets	Ameren	$	2		$	-		$	-	$	-		$	-		$	-		$	-		$	2		$	-
Net derivative	Ameren	$	25		$	13		$	4	$	(14	)	$	3		$	27		$	(4	)	$	51		$	(29	)
contracts	UE		13			-			-		7			7			(3	)		-			17			9
	CIPS		(153	)		-			-		(40	)		(40	)		33			-			(160	)		(31	)
	Genco		(1	)		-			-		-			-			-			-			(1	)		-
	CILCORP/CILCO		(89	)		(1	)		-		(23	)		(24	)		26			-			(87	)		(18	)
	IP		(236	)		-			-		(71	)		(71	)		55			-			(252	)		(58	)
Nuclear	Ameren	$	3		$	-		$	-	$	-		$	-		$	(1	)	$	-		$	2		$	-
Decommissioning Trust Fund	UE		3			-			-		-			-			(1	)		-			2			-

(a)	See Note 6 - Derivative Financial Instruments for additional information on the recording of net gains and losses on derivatives to the statement of income.

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, 2009:


				Realized and Unrealized Gains (Losses)									Total Realized			Purchases,									Change in Unrealized Gains (Losses) Related to
		Beginning Balance at January 1, 2009		Included in Earnings^(a)			Included in AOCI			Included in Regulatory Assets/ Liabilities			and Unrealized Gains (Losses)			Issuances, and Other Settlements, Net			Net Transfers Into (Out of) Level 3			Ending Balance at September 30, 2009			Assets/Liabilities Still Held at September 30, 2009
Other current assets	Ameren	$	6	$	-		$	-		$	-		$	-		$	-		$	(4	)	$	2		$	-
Net derivative	Ameren	$	15	$	66		$	61		$	(67	)	$	60		$	34		$	(58	)	$	51		$	20
contracts	UE		5		-			37			4			41			(11	)		(18	)		17			5
	CIPS		(84)		-			(10	)		(148	)		(158	)		82			-			(160	)		(102	)
	Genco		(1)		(1	)		-			-			(1	)		1			-			(1	)		-
	CILCORP/CILCO		(55)		(20	)		(5	)		(70	)		(95	)		63			-			(87	)		(58	)
	IP		(134)		-			(16	)		(237	)		(253	)		135			-			(252	)		(166	)
Nuclear	Ameren	$	2	$	-		$	-		$	-		$	-		$	-		$	-		$	2		$	-
Decommissioning Trust Fund	UE		2		-			-			-			-			-			-			2			-

(a)	See Note 6 - Derivative Financial Instruments for additional information on the recording of net gains and losses on derivatives to the statement of income.

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:


				Realized and Unrealized Gains (Losses)								Total Realized			Purchases,								Change in Unrealized Gains (Losses) Related to
		Beginning Balance at July 1, 2008		Included in Earnings			Included in AOCI		Included in Regulatory Assets/ Liabilities			and Unrealized Gains (Losses)			Issuances, and Other Settlements, Net			Net Transfers Into (Out of) Level 3		Ending Balance at September 30, 2008			Assets/Liabilities Still Held at 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	$	-		$	-	$	-		$	-		$	(a	)	$	-	$	1		$	-
Decommissioning Trust Fund	UE		1		-			-		-			-			(a	)		-		1			-

(a)	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:


				Realized and Unrealized Gains (Losses)								Total Realized			Purchases,								Change in Unrealized Gains (Losses) Related to
		Beginning Balance at January 1, 2008		Included in Earnings			Included in AOCI		Included in Regulatory Assets/ Liabilities			and Unrealized Gains (Losses)			Issuances, and Other Settlements, Net			Net Transfers Into (Out of) Level 3		Ending Balance at September 30, 2008			Assets/Liabilities Still Held at 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 Trust Fund	UE		5		-			-		-			-			(4	)		-		1			-

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 with previous periods for the quarters ended September 30, 2009 and 2008. Any reclassifications are reported as transfers in or out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur.

Related to our nonfinancial assets and liabilities, Note 14 - Goodwill Impairment details the inputs to the valuation of goodwill, which is considered a Level 3 asset, and the goodwill impairment charge recorded by CILCORP in 2009. CILCORP’s goodwill is measured at fair value on a nonrecurring basis and was impaired during the first quarter of 2009. The following table sets forth, by level within the fair value hierarchy, CILCORP’s goodwill as of September 30, 2009:

Quoted Prices in

Active Markets for
Identified Assets

(Level 1)

Significant Other
Observable Inputs

(Level 2)

Significant Other

Unobservable Inputs

(Level 3)

Total

Total Loss

CILCORP

Goodwill^(a)

(462

)

(a)	CILCORP’s goodwill with a carrying amount of $542 million was written down to its implied fair value of $80 million at March 31, 2009, resulting in an impairment charge of $462 million.

The Ameren Companies’ carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings, and accounts payable approximate fair value because of the short-term nature of these instruments. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at September 30, 2009, and December 31, 2008:


	September 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren:^(a)
Long-term debt and capital lease obligations (including current portion)	$	7,449	$	7,908	$	6,934	$	6,144
Preferred stock		195		136		195		100
UE:
Long-term debt and capital lease obligations (including current portion)	$	4,026	$	4,219	$	3,677	$	3,156
Preferred stock		113		86		113		62
CIPS:
Long-term debt (including current portion)	$	421	$	438	$	421	$	371
Preferred stock		50		29		50		22
Genco:
Long-term debt (including current portion)	$	774	$	808	$	774	$	661
CILCORP:
Long-term debt (including current portion)	$	658	$	655	$	662	$	630
Preferred stock		19		14		19		10
CILCO:
Long-term debt (including current portion)	$	279	$	309	$	279	$	255
Preferred stock		19		14		19		10
IP:
Long-term debt (including current portion)	$	1,146	$	1,312	$	1,400	$	1,326
Preferred stock		46		32		46		24

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

NOTE 8 - RELATED PARTY TRANSACTIONS

The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K.

Illinois Electric Settlement Agreement

At September 30, 2009, 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, 2009, CIPS, CILCO and IP had receivable balances from AERG for reimbursement of customer rate relief of less than $1 million each. During the three and nine months ended September 30, 2009, Genco incurred charges to earnings of $2 million and $7 million, respectively, for customer rate relief contributions and program funding reimbursements to the Ameren Illinois Utilities (CIPS - $1 million and $3 million, CILCO - less than $1 million and $1 million, IP - $1 million and $3 million, respectively), and AERG incurred charges to earnings of $1 million and $3 million, respectively (CIPS - less than $1 million and $1 million, CILCO - less than $1 million and $1 million, IP - less than $1 million and $1 million, respectively). The Ameren Illinois Utilities recorded most of the reimbursements received from Genco and AERG as electric revenue with an immaterial amount recorded as miscellaneous revenue.

Electric Power Supply Agreements

The following table presents the amount of physical gigawatthour sales under related party electric power supply agreements for the three and nine months ended September 30, 2009 and 2008:


	Three Months		Nine Months
	2009	2008	2009	2008
Genco sales to Marketing Company^(a)	3,389	4,276	10,347	12,217
AERG sales to Marketing Company^(a)	1,923	1,794	4,898	5,107
Marketing Company sales to CIPS^(b)	226	463	1,044	1,557
Marketing Company sales to CILCO^(b)	96	222	457	702
Marketing Company sales to IP^(b)	282	715	1,409	2,217

(a)	Both Genco and AERG have a power supply agreement with Marketing Company whereby Genco and AERG sell and Marketing Company purchases all the capacity and energy available from Genco’s and AERG’s generation fleets.

(b)	Marketing Company contracted with CIPS, CILCO, and IP to provide power based on the results of the September 2006 Illinois power procurement auction. The values in this table reflect the physical sales volumes provided in that agreement.

Capacity Supply Agreements

CIPS, CILCO and IP, as electric load serving entities, must acquire capacity sufficient to meet their obligations to customers. In 2009, the Ameren Illinois Utilities used a RFP process, administered by the IPA, to contract the necessary capacity for the period from June 1, 2009, through May 31, 2012. Both Marketing Company and UE were winning suppliers in the Ameren Illinois Utilities’ capacity RFP process. In April 2009, Marketing Company contracted to supply capacity to the Ameren Illinois Utilities for $4 million, $9 million, and $8 million for the twelve months ending May 31, 2010, 2011, and 2012, respectively. In April 2009, UE contracted to supply capacity to the Ameren Illinois Utilities for $2 million, $2 million, and $1 million for the twelve months ending May 31, 2010, 2011, and 2012, respectively.

Energy Swaps

CIPS, CILCO and IP, as electric load serving entities, must acquire energy sufficient to meet their obligations to customers. In 2009, the Ameren Illinois Utilities used a RFP process, administered by the IPA, to procure financial energy swaps from June 1, 2009, through May 31, 2011. Marketing Company was a winning supplier in the Ameren Illinois Utilities’ energy swap RFP process. In May 2009, Marketing Company entered into financial instruments that fixed the price that the Ameren Illinois Utilities will pay for approximately 80,000 megawatthours at approximately $48 per megawatthour during the twelve months ending May 31, 2010 and for approximately 89,000 megawatthours at approximately $48 per megawatthour during the twelve months ending May 31, 2011.

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, collateral must 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, 2009, and December 31, 2008, there were no collateral postings necessary by Marketing Company related to the 2006 auction power supply agreements.

Under the terms of the 2009 Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect the Ameren Illinois Utilities in the event of nonperformance. The collateral postings are unilateral, meaning only the suppliers would be required to post collateral. Therefore, UE, as a winning supplier of capacity, and Marketing Company, as a winning supplier of capacity and financial energy swaps, may be required to post collateral. As of September 30, 2009, there were no collateral postings necessary between UE and the Ameren Illinois Utilities or between Marketing Company and the Ameren Illinois Utilities related to the 2009 Illinois power procurement agreements.

Generation Interconnection Agreements

In 2008, Genco and CIPS signed an agreement requiring Genco to fund the cost of certain upgrades to CIPS’ electric transmission system. At September 30, 2009, CIPS had recorded $2 million in Other Deferred Credits and Liabilities, and Genco had recorded $2 million in Other Assets. These transactions were eliminated in consolidation on Ameren’s financial statements.

In September 2009, Marketing Company and CIPS signed an agreement requiring Marketing Company to fund the cost of certain upgrades to CIPS’ electric transmission system. At September 30, 2009, CIPS had recorded $5 million in Other Deferred Credits and Liabilities for the receipt of cash in advance of construction activities. These transactions were eliminated in consolidation on Ameren’s financial statements.

Money Pools

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

CILCO Support Services

On January 1, 2009, approximately 570 Ameren Services employees who provided support services to the Ameren Illinois Utilities were transferred to CILCO (Illinois Regulated). As CILCO employees, they provide services to CIPS and IP as well as to CILCO. The cost of support services provided by CILCO to CIPS and IP, including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred.

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 $1 million and $3 million (2008 - $2 million and $6 million, respectively) for the three and nine months ended September 30, 2009, respectively.

CILCORP (parent company) had outstanding borrowings from Ameren of $218 million and $152 million at September 30, 2009, and December 31, 2008, respectively. The average interest rate on CILCORP’s borrowings from Ameren was 6.5% and 4.3% for the three and nine months ended September 30, 2009, respectively (2008 - 3.5% and 3.7%, respectively). CILCORP recorded interest expense of $4 million and $6 million for these borrowings for the three and nine months ended September 30, 2009, respectively (2008 - less than $1 million for the three and nine months periods).

CILCO (AERG) had outstanding borrowings from Ameren of $334 million at September 30, 2009, and had no outstanding borrowings directly from Ameren at December 31, 2008. The average interest rate on CILCO’s (AERG) borrowings from Ameren was 6.5% and 5.8% for the three and nine months ended September 30, 2009, respectively. CILCO (AERG) recorded interest expense of $6 million and $8 million, respectively for these borrowings for the three and nine months ended September 30, 2009.

UE had no outstanding borrowings directly from Ameren at September 30, 2009, and had outstanding borrowings directly from Ameren of $92 million at December 31, 2008. The average interest rate on UE’s borrowings from Ameren was 0.2% and 1.2% for the three and nine months ended September 30, 2009 (2008 - 3.5% and 3.7%, respectively). UE recorded interest expense of less than $1 million for these borrowings for both the three and nine months ended September 30, 2009 (2008 - less than $1 million for the three and nine-month periods).

The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the three and nine months ended September 30, 2009 and 2008. It is based primarily on the agreements discussed above and in Note 14 - 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	2009	$(b	)	$(b	)	$214		$ 119		$(b	)	$(b	)	$(b	)	$654		$ 317		$(b	)
agreements with Marketing Company	2008	(b	)	(b	)	233		99		(b	)	(b	)	(b	)	658		252		(b	)
Ancillary services and capacity	2009	2		(b	)	(b	)	(b	)	(b	)	3		(b	)	(b	)	(b	)	(b	)
agreements with CIPS, CILCO and IP^(c)	2008	3		(b	)	(b	)	(b	)	(b	)	9		(b	)	(b	)	(b	)	(b	)
Genco gas sales to Medina Valley	2009	(b	)	(b	)	-		(b	)	(b	)	(b	)	(b	)	1		(b	)	(b	)
	2008	(b	)	(b	)	-		(b	)	(b	)	(b	)	(b	)	-		(b	)	(b	)
Genco gas sales to distribution companies	2009	(b	)	(b	)	(e	)	(b	)	(b	)	(b	)	(b	)	1		(b	)	(b	)
	2008	(b	)	(b	)	(e	)	(b	)	(b	)	(b	)	(b	)	6		(b	)	(b	)
CILCO support services^(h)	2009	(b	)	(b	)	(b	)	19		(b	)	(b	)	(b	)	(b	)	53		(b	)
	2008	(b	)	(b	)	(b	)	(b	)	(b	)	(b	)	(b	)	(b	)	(b	)	(b	)
Total Operating Revenues	2009	$2		$(b	)	$214		$ 138		$(b	)	$3		$(b	)	$656		$ 370		$(b	)
	2008	3		(b	)	233		99		(b	)	9		(b	)	664		252		(b	)
Purchased Power:
CIPS, CILCO and IP agreements with	2009	$(b	)	$32		$(b	)	$ 15		$44		$(b	)	$110		$(b	)	$ 51		$155
Marketing Company^(d)	2008	(b	)	32		(b	)	15		49		(b	)	104		(b	)	47		148
Ancillary services and capacity	2009	(b	)	1		(b	)	(e	)	1		(b	)	1		(b	)	(e	)	1
agreements with UE^(c)	2008	(b	)	1		(b	)	1		1		(b	)	3		(b	)	1		5
Ancillary services agreement with	2009	(b	)	-		(b	)	-		-		(b	)	(e	)	(b	)	(e	)	(e	)
Marketing Company	2008	(b	)	1		(b	)	1		2		(b	)	5		(b	)	3		8
Executory tolling agreement with Medina	2009	(b	)	(b	)	(b	)	(f	)	(b	)	(b	)	(b	)	(b	)	(f	)	(b	)
Valley	2008	(b	)	(b	)	(b	)	8		(b	)	(b	)	(b	)	(b	)	30		(b	)
Total Purchased Power	2009	$(b	)	$33		$(b	)	$ 15		$45		$(b	)	$111		$(b	)	$ 51		$156
	2008	(b	)	34		(b	)	25		52		(b	)	112		(b	)	81		161
Gas purchases for resale:
Gas purchases from Genco	2009	$-		$-		$(b	)	$ -		$(e	)	$-		$-		$(b	)	$ 1		$(e	)
	2008	-		-		(b	)	(e	)	-		-		-		(b	)	6		-
Operating Revenues and Purchased Power:
Insurance recoveries	2009	$-		$(b	)	$-		$ -		$(b	)	$-		$(b	)	$-		$ -		$(b	)
	2008	-		(b	)	(5	)	(3	)	(b	)	(e	)	(b	)	(11	)	(4	)	(b	)
Other Operations and Maintenance:
Ameren Services support services agreement	2009	$31		$7		$7		$ 9		$12		$96		$22		$21		$ 28		$36
	2008	35		14		7		14		21		106		42		21		42		63
CILCO support services	2009	(b	)	5		(b	)	(b	)	8		(b	)	16		(b	)	(b	)	23
	2008	(b	)	(b	)	(b	)	(b	)	(b	)	(b	)	(b	)	(b	)	(b	)	(b	)
AFS support services agreement	2009	2		(e	)	(e	)	1		1		6		1		2		2		2
	2008	2		(e	)	1		1		(e	)	5		1		2		2		1
Insurance premiums^(g)	2009	1		(b	)	(e	)	(e	)	(b	)	2		(b	)	1		1		(b	)
	2008	2		(b	)	1		1		(b	)	7		(b	)	3		3		(b	)
Total Other Operations and	2009	$34		$12		$7		$ 10		$21		$104		$39		$24		$ 31		$61
Maintenance Expenses	2008	39		14		9		16		21		118		43		26		47		64
Interest Charges:
Interest expense (income) from money	2009	$-		$(e	)	$(e	)	$ (e	)	$-		$-		$(e	)	$1		$ 1		$(e	)
pool borrowings (advances)	2008	-		(e	)	(e	)	1		(e	)	-		(e	)	(e	)	1		(e	)

(a)	Amounts represent CILCORP and CILCO activity.

(b)	Not applicable.

(c)	Represents ancillary services to the Ameren Illinois Utilities for 2009 and 2008 and capacity to the Ameren Illinois Utilities in 2009.

(d)	Represents power supply costs under agreements entered into as part of the Illinois September 2006 auction, the 2008 energy and capacity RFPs, and the 2009 capacity RFP.

(e)	Amount less than $1 million.

(f)	In January 2009, CILCO transferred the tolling agreement to Marketing Company.

(g)	Represents insurance premiums paid to Energy Risk Assurance Company, an affiliate, for replacement power and property damage.

(h)	Includes revenues relating to property and plant additions during the three months ended September 30, 2009 (CIPS - $2 million and IP - $4 million) and during the nine months ended September 30, 2009 (CIPS - $5 million and IP - $9 million).

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 the 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 14 - Related Party Transactions, and Note 15 - 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 September 30, 2009. 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		12,219	^(b)		118	^(c)
	$	12,519		$	118
Property damage:
Nuclear Electric Insurance Ltd.	$	2,750	^(d)	$	23
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)

Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.

(c)	Retrospective premium under Price-Anderson. 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.

(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 our 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 our 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. 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, and liquidity.

Other Obligations

In September 2009, UE announced an agreement with a landfill owner to install CTs at a landfill site in St. Louis County, Missouri, which would generate approximately 15 MW of electricity by burning methane gas collected from the landfill. Construction of the CTs is expected to begin in 2010, and the CTs are expected to begin generating power in 2011. UE signed a 20-year supply agreement with the landfill owner to purchase methane gas. The obligation information presented below includes total estimated methane gas purchase commitments. Related design and construction commitments associated with this project are included in the Other column in the table below.

UE’s firm commitments to purchase heavy forgings for construction of a potential new nuclear power plant have materially changed from amounts previously disclosed as of December 31, 2008. Prior to June 30, 2009, UE made contractual payments to a heavy forgings manufacturer of $14 million and had remaining contractual commitments of $81 million. In July 2009, an agreement was reached with the heavy forgings manufacturer to terminate the heavy forgings contract, and $5 million of previously-made payments were retained by the manufacturer as a penalty for terminating the contract, which was charged to earnings in June 2009. The remaining $9 million of previously-made payments were retained by the manufacturer as partial payment for UE’s future purchase of other heavy equipment for installation at its existing Callaway nuclear plant. See Note 2 - Rate and Regulatory Matters for further information.

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We also have entered into various long-term commitments for the purchase of electric capacity and natural gas for distribution. The following table presents our estimated fuel, electric capacity, and other commitments at September 30, 2009. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, meter reading services, and an Ameren tax credit obligation at September 30, 2009.


	Coal		Natural Gas		Nuclear		Electric Capacity			Methane Gas		Other		Total
Ameren:^(a)
2009	$	170	$	150	$	35	$	7		$	-	$	35	$	397
2010		990		570		43		22			-		69		1,694
2011		872		453		24		22			1		91		1,463
2012		613		308		55		22			3		75		1,076
2013		189		193		56		22			4		57		521
Thereafter^(b)		794		247		429		230			105		318		2,123
Total	$	3,628	$	1,921	$	642	$	325		$	113	$	645	$	7,274
UE:
2009	$	73	$	19	$	35	$	7		$	-	$	26	$	160
2010		530		81		43		22			-		34		710
2011		443		62		24		22			1		53		605
2012		251		48		55		22			3		43		422
2013		128		38		56		22			4		41		289
Thereafter^(b)		723		65		429		230			105		206		1,758
Total	$	2,148	$	313	$	642	$	325		$	113	$	403	$	3,944
CIPS:
2009	$	-	$	27	$	-	$	(c	)	$	-	$	1	$	28
2010		-		91		-		(c	)		-		2		93
2011		-		71		-		(c	)		-		2		73
2012		-		58		-		(c	)		-		2		60
2013		-		45		-		-			-		2		47
Thereafter^(b)		-		39		-		-			-		14		53
Total	$	-	$	331	$	-	$	-		$	-	$	23	$	354
Genco:
2009	$	42	$	3	$	-	$	-		$	-	$	-	$	45
2010		223		8		-		-			-		2		233
2011		197		8		-		-			-		6		211
2012		162		5		-		-			-		-		167
2013		25		3		-		-			-		-		28
Thereafter^(b)		-		5		-		-			-		-		5
Total	$	649	$	32	$	-	$	-		$	-	$	8	$	689
CILCORP and CILCO:
2009	$	13	$	41	$	-	$	(c	)	$	-	$	1	$	55
2010		92		167		-		(c	)		-		3		262
2011		100		135		-		(c	)		-		3		238
2012		84		96		-		(c	)		-		3		183
2013		32		60		-		-			-		3		95
Thereafter^(b)		71		104		-		-			-		21		196
Total	$	392	$	603	$	-	$	-		$	-	$	34	$	1,029
IP:
2009	$	-	$	58	$	-	$	(c	)	$	-	$	2	$	60
2010		-		217		-		(c	)		-		10		227
2011		-		175		-		(c	)		-		11		186
2012		-		99		-		(c	)		-		11		110
2013		-		47		-		-			-		11		58
Thereafter^(b)		-		34		-		-			-		77		111
Total	$	-	$	630	$	-	$	-		$	-	$	122	$	752

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

(b)	Commitments for natural gas and nuclear fuel are until 2036 and 2020, respectively.

(c)

At September 30, 2009, $53 million of electric capacity contracts were executed for the Ameren Illinois Utilities, comprising less than $1 million, $26 million, $26 million, and $1 million for 2009, 2010, 2011, and 2012, respectively. Approximately 33% of the electric capacity provided under the contracts is dedicated to CIPS, 17% is dedicated to CILCO, and 50% to IP. See below for additional information.

Ameren Illinois Utilities’ Purchased Power Agreements

In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. As a result, in the second quarter of 2009, the IPA procured electric capacity, financial energy swaps, and renewable energy credits through a RFP process on behalf of the Ameren Illinois Utilities. Electric capacity was procured in April 2009 for the period June 1, 2009, through May 31, 2012. The Ameren Illinois Utilities contracted to purchase between 800 and 3,500 MW of capacity per month at an average price of approximately $41 per MW-day over the three-year period. Financial energy swaps were procured in May 2009 for the period June 1, 2009, through May 31, 2011. The Ameren Illinois Utilities contracted to purchase approximately ten million megawatthours of financial energy swaps at an average price of approximately $36 per megawatthour. Renewable energy credits were procured in May 2009 for the period June 1, 2009, through May 31, 2010. The Ameren Illinois Utilities contracted to purchase 720,000 credits at an average price of approximately $16 per credit. The following table presents the Ameren Illinois Utilities’ commitments for these contracts at September 30, 2009:


	2009			2010		2011		2012
Electric capacity	$	(a	)	$	26	$	26	$	1
Financial energy swaps		39			183		56		-
Renewable energy credits		3			6		-		-

(a)	Less than $1 million.

Illinois Electric Settlement Agreement

The Illinois electric settlement agreement provided for approximately $1 billion of funding over a four-year period that commenced in 2007 for rate relief for certain electric customers in Illinois. Electric generators in Illinois and certain Illinois electric utilities agreed to fund the settlement. The Ameren Illinois Utilities, Genco and AERG agreed to fund an aggregate of $150 million, of which the following estimated contributions remained to be made as of September 30, 2009:


	Ameren		CIPS		CILCO (Illinois Regulated)		IP		Genco		CILCO (AERG)
2009	$	7.6	$	1.1	$	0.5	$	1.6	$	3.0	$	1.4
2010		2.4		0.3		0.2		0.5		1.0		0.4
Total	$	10.0	$	1.4	$	0.7	$	2.1	$	4.0	$	1.8

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, 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 SO₂and NO_x emissions that result from burning fossil fuels. In May 2005, the EPA issued regulations with respect to SO₂ and NO_x emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule). The federal Clean Air Interstate Rule requires generating facilities in 28 eastern states, including Missouri and Illinois where our generating facilities are located, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO₂emissions, annual NO_x emissions, and ozone season NO_x emissions. The cap-and-trade program for both annual and ozone season NO_x emissions went into effect on January 1, 2009. The SO₂emissions cap-and-trade program is scheduled to take effect in 2010.

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 it used to remove electric generating units from the list of sources subject to the maximum available control technology requirements under the Clean Air Act. In February 2009, the U.S. Supreme Court denied a petition for review filed by a group representing the electric utility industry. The impact of this decision is that the EPA will move forward with a MACT standard for mercury emissions and other hazardous air pollutants, such as acid gases. The standard is expected to be available in draft form in 2010, and compliance is expected to be required in the 2013 to 2015 timeframe. We cannot predict at this time the estimated capital or operating costs for compliance with such future environmental rules.

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, all filed petitions for rehearing with the U.S. Court of Appeals. In December 2008, the U.S. Court of Appeals essentially reversed its July 2008 decision to vacate the federal Clean Air Interstate Rule. The U.S. Court of Appeals granted the EPA petition for reconsideration and remanded the rule to the EPA for further action to remedy the rule’s flaws in accordance with the U.S. Court of Appeals’ July 2008 opinion in the case. The impact of the decision is that the existing Illinois and Missouri rules to implement the federal Clean Air Interstate Rule will remain in effect until the federal Clean Air Interstate Rule is revised by the EPA, at which point the Illinois and Missouri rules may be subject to change. The EPA has stated that it expects to issue a new proposed version of the Clean Air Interstate Rule in 2010 and a final version in 2011.

The state of Missouri has adopted rules to implement the federal Clean Air Interstate Rule for regulating SO₂ and NO_x emissions from electric generating units. The rules are 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 rules are expected to reduce NO_xemissions by 30% and SO₂ emissions by 75% by 2015. As a result of the Missouri rules, UE will manage allowances and install pollution control equipment. UE’s costs to comply with SO₂ emission reductions required by the Clean Air Interstate Rule could increase materially if the EPA determines that existing allowances granted to sources under the Acid Rain Program cannot be used for compliance with the Clean Air Interstate Rule or if a new allowance program is mandated by revisions to the Clean Air Interstate Rule. Missouri also adopted rules to implement the federal Clean Air Mercury Rule. However, these rules are not enforceable as a result of the U.S. Court of Appeals decision to vacate the federal Clean Air Mercury Rule.

We do not believe that the court decision that vacated the federal Clean Air Mercury Rule will significantly affect pollution control obligations in Illinois in the near term. Under the MPS, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90%, in exchange for accelerated installation of NO_x and SO₂ controls. This rule, when fully implemented, is expected to reduce mercury emissions by 90%, NO_x emissions by 50%, and SO₂ emissions by 70% by 2015 in Illinois. To comply with the rule, Genco, CILCO (AERG) and EEI have begun putting into service equipment designed to reduce mercury emissions. Genco, CILCO (AERG) and EEI will also need to install additional pollution control equipment. Current plans include installing scrubbers for SO₂reduction as well as optimizing operations of selective catalytic reduction (SCR) systems for NO_x reduction at certain coal-fired plants in Illinois.

In October 2008, Genco, CILCO (AERG) and EEI sought to revise certain requirements of the MPS. They proposed to the Illinois Pollution Control Board to lower required SO₂ and NO_x emissions levels in 2010 through 2020 in order to make the proposed revisions to the MPS “environmentally neutral.” In April 2009, the Illinois Pollution Control Board approved revisions to the MPS. After review and approval by the Illinois Joint Committee on Administrative Rules, this rule amendment became final in June 2009. As a result, Genco and CILCO (AERG) collectively are able to defer to subsequent years an estimated $300 million of environmental capital expenditures originally scheduled for 2009 through 2011.

In March 2008, the EPA finalized regulations that will lower the ambient standard for ozone. Illinois and Missouri have each submitted their recommendations to the EPA for designating nonattainment areas. A final action by the EPA to designate nonattainment areas is expected in March 2010. State implementation plans will need to be submitted in 2013 unless Illinois and Missouri seek extensions for various requirement dates. Additional emission reductions may be required as a result of 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 are based on current technology to comply with the federal Clean Air Interstate Rule and related state implementation plans through 2018, as well as federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility rule. The estimates described below could change depending upon additional federal or state requirements, the requirements under a MACT standard, 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. Ameren is in the process of identifying opportunities to defer or reduce planned capital spending, including the estimates provided in the table below. In the second quarter of 2009, Merchant Generation eliminated approximately $1 billion of capital expenditures from its previous estimates for 2010 through 2013. The environmental portion of this reduction is reflected in the table below.


	2009		2010 - 2013	2014 - 2018	Total
UE^(a)	$	100	$ 525 - $ 655	$1,525 - $1,880	$2,150 - $2,635
Genco		275	480 - 615	215 - 310	970 - 1,200
CILCO(AERG)		45	415 - 540	85 - 125	545 - 710
EEI		15	40 - 55	280 - 385	335 - 455
Ameren	$	435	$1,460 - $1,865	$2,105 - $2,700	$4,000 - $5,000

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

Emission Allowances

Both federal and state laws require significant reductions in SO₂ and NO_x emissions that result from burning fossil fuels. The Clean Air Act created marketable commodities called allowances under the Acid Rain Program, the NO_x Budget Trading Program, and the federal Clean Air Interstate Rule. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. NO_x allowances allocated under the NO_x Budget Trading Program can be used for the seasonal NO_x program under the federal Clean Air Interstate Rule. 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. Our generating facilities are expected to comply with the NO_x limits through the use and purchase of allowances or through the application of pollution control technology, including low-NO_x 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 NO_x emission allowances held and the related SO₂ and NO_x emission allowance book values that were carried as intangible assets as of September 30, 2009.

UE, Genco, CILCO (AERG) and EEI expect to use a substantial portion of the SO₂ and NO_x allowances for ongoing operations. Environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment, and the level of operations, will have a significant impact on the number of allowances actually required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO₂ emissions by increasing the ratio of Acid Rain Program allowances surrendered. The current Acid Rain Program requires the surrender of one SO₂ allowance for every ton of SO₂ that is emitted. Unless revised by the EPA as a result of the U.S. Court of Appeals’ remand, the Clean Air Interstate Rule program will require that SO₂ allowances of vintages 2010 through 2014 be surrendered at a ratio of two allowances for every ton of emission. SO₂ allowances with vintages of 2015 and beyond will be required to be surrendered at a ratio of 2.86 allowances for every ton of emission. In order to accommodate this change in surrender ratio and to comply with the federal and state regulations, UE, Genco, CILCO (AERG), and EEI expect to install control technology designed to further reduce SO₂ emissions, as discussed above.

The Clean Air Interstate Rule has both an ozone season program and an annual program for regulating NO_x emissions, with separate allowances issued for each program. The Clean Air Interstate Rule ozone season program replaced the NO_x Budget Trading Program beginning in 2009. Allocations for UE’s Missouri generating facilities for the years 2009 through 2014 were 11,665 tons per ozone season and 26,842 tons annually. Allocations for Genco’s generating facility in Missouri were one ton for the ozone season and three tons annually. Allocations for UE’s, Genco’s, CILCO’s (AERG), and EEI’s Illinois generating facilities for the years 2009 through 2011 were 90, 3,442, 1,368, and 1,758 tons per ozone season, respectively, and 93, 8,300, 3,418, and 4,564 tons annually, respectively.

Global Climate Change

On June 26, 2009, the U.S. House of Representatives passed energy legislation entitled “The American Clean Energy and Security Act of 2009” that, if enacted, would establish an economy-wide cap-and-trade program. The overarching goal of this proposed cap-and-trade program is to reduce greenhouse gas emissions from capped sources, including coal-fired electric generation units, to a level that is 3% below 2005 levels by 2012, 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by the year 2050. The proposed legislation provides an allocation of free emission allowances and greenhouse gas offsets to utilities, as well as certain merchant coal-fired electric generators in competitive markets. This aspect of the proposed legislation would mitigate some of the cost of compliance for the Ameren Companies. However, the amount of free allowances provided declines over time and is ultimately phased out. The proposed legislation also contains, among other things, a federal renewable energy standard of 6% by 2012 that increases over time to 20% by 2020, of which up to 25% of the goal can be met by

energy efficiency. The proposed legislation also establishes performance standards for new coal plants, requires electric utilities to develop plans to support plug-in hybrid vehicles, and requires load-serving entities to reduce peak electric demand through energy efficiency and Smart Grid technologies. On September 30, 2009, Senators Boxer and Kerry introduced climate legislation entitled “The Clean Jobs and American Power Act,” which is similar to that passed by the U.S. House of Representatives in June 2009, although with a slightly greater reduction in greenhouse gas emissions in the year 2020. Leaders in the U.S. Senate have indicated they hope to bring this legislation before the full Senate by the end of 2009.

Potential impacts from proposed legislation could vary, depending upon proposed CO₂ emission limits, the timing of implementation of those limits, the method of allocating allowances, the degree to which offsets are allowed and available, and provisions for cost containment measures, such as a “safety valve” that provides a ceiling price for emission allowance purchases. As a result of our diverse fuel portfolio, our contribution of greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of CO₂, a principal greenhouse gas. Ameren’s analysis shows that if “The American Clean Energy and Security Act of 2009” or “The Clean Jobs and American Power Act” were enacted into law in their current form, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the economy in the Midwest 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 when burned to produce electricity. As a result, economy-wide shifts favoring natural gas as a fuel source for electric generation also could affect the cost of heating for our utility customers and many industrial processes. 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 emissions and global climate change may also arise pursuant to 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 to reduce greenhouse gas emissions through a cap-and-trade mechanism. The advisory group to the Midwest governors provided draft final recommendations on the design of a greenhouse gas reduction program to the governors in June 2009. In October 2009, the Midwestern Governors Association held a forum to review some of the advisory group’s recommendations. The October 2009 forum did not yield any significant updates to the Midwest Greenhouse Gas Reduction Accord’s effort to develop a cap-and-trade mechanism. The recommendations have not been endorsed or approved by the individual state governors. It is uncertain whether legislation to implement the recommendations will be implemented or passed by any of the states, including Illinois.

In April 2007, the U.S. Supreme Court issued a decision that the EPA has the authority to regulate CO₂ and other greenhouse gases from automobiles as “air pollutants” under the existing Clean Air Act. In April 2009, the EPA issued a proposed determination finding that the combination of six greenhouse gases, four of which are emitted by motor vehicle engines, formed air pollution which, through the mechanics of climate change, endangers public health and welfare. Although this “endangerment finding” is in draft form and applies only to greenhouse gas emissions from motor vehicle engines, some of the greenhouse gases that are the subject of the proposed endangerment finding are produced through the combustion of fossil fuels by electric generating units. The comment period on this rulemaking is now closed. The EPA is expected to issue the final endangerment finding by the end of 2009. As a result of the court ruling and the endangerment finding, it is anticipated that the EPA will issue a proposed rule by the end of March 2010 to control greenhouse gas emissions from light-duty vehicles such as automobiles.

On September 30, 2009, the EPA announced a proposed rule that would establish new thresholds for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule would require any source that emits at least 25,000 tons per year of greenhouse gases measured as CO ₂ equivalents (CO₂e) to obtain an operating permit under the Clean Air Act, if it does not already have one. Sources that already have an operating permit would have greenhouse gas-specific provisions added to their permits upon renewal. Currently, all Ameren power plants have operating permits that, depending on the final rule, may be required to be modified to comply with the new rule. In addition, those sources would be “Major Sources” subject to the Clean Air Act’s New Source Review/Prevention of Significant Deterioration program’s requirements. The proposed rule also provides that physical changes or changes in operation at these Major Sources that result in an increase in emissions of greenhouse gases over a threshold that ranges from 10,000 tons to 25,000 tons of CO₂e would be required to obtain a permit under the New Source Review/Prevention of Significant Deterioration program and install best available control technology to control greenhouse gas emissions. New Major Sources also would be required to obtain such a permit and install best available control technology. The EPA has committed to develop guidance

to determine best available control technology for new and modified major sources of greenhouse gas emissions. The rule was published in the Federal Register on October 27, 2009, and will be subject to a 60-day public comment period. A rule is expected to be finalized in early 2010, but any federal climate change legislation that is enacted may pre-empt the proposed rule, particularly as it relates to power plant greenhouse gas emissions. This proposed rule has no immediate impact on Ameren’s, UE’s, Genco’s or CILCO’s (AERG) generating facilities. The extent to which this proposed rule could have a material impact on our generating facilities depends upon future EPA guidance on what constitutes best available control technology for greenhouse gas emissions from power plants, whether physical changes or change in operation subject to the rule would occur at our power plants, and whether federal legislation is passed which pre-empts the proposed rule.

The EPA also finalized regulations in September 2009 that would require certain categories of businesses, including fossil fuel-fired power plants, to monitor and report their annual greenhouse gas emissions beginning in January 2011 for 2010 emissions. CO₂ emissions from fossil fuel-fired power plants have been monitored and reported for over fifteen years. Thus, this new rule covering greenhouse gas emissions is not expected to have a material effect on our operations. It will require additional reporting of greenhouse gas emissions from various gas operations and possibly other minor sources within our system.

Recent federal appellate court decisions have ruled that common law causes of action such as nuisance can be used to redress damages resulting from global climate change. In State of Connecticut v. American Electric Power (“AEP”), the U.S. Court of Appeals for the Second Circuit ruled in September 2009 that public nuisance claims brought by states, New York City and public land trusts could proceed and were not beyond the scope of judicial relief. Ameren’s generating plants were not named in the AEP litigation. In Comer v. Murphy Oil, a Mississippi property owner sued a number of industrial companies alleging that CO₂ emissions created the atmospheric conditions, which resulted in Hurricane Katrina. The U.S. Court of Appeals for the Fifth Circuit issued a ruling in Comer in October 2009 that also permits this cause of action to proceed. Comer is seeking class action certification on behalf of similarly situated property owners. Additional legal challenges and appeals are expected in both Comer and AEP and the rulings in these cases may spur other potential claimants to file suit against greenhouse gas emitters, including Ameren. The courts did not rule on the merits of the lawsuits, only that plaintiffs had standing and could pursue their claims. Under some of the versions of greenhouse gas legislation currently pending in Congress, nuisance claims could be rendered moot. We are unable to predict the outcome of lawsuits seeking damages that litigants claim are attributable to climate change and their impact on our results of operations, financial position or liquidity.

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, which in turn could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force UE, Genco, CILCO (through AERG) and EEI as well as other similarly situated electric power generators to close some coal-fired facilities. As a result, 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.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Although compliance costs are unlikely in the near future, federal legislative, federal regulatory and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, the impact on our coal-fired generation plants and our customers’ costs is unknown, but any impact would likely be negative. 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.

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 utilities 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. It sought detailed operating and maintenance history data with respect to Genco’s Coffeen, Hutsonville, Meredosia and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In 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. In May 2009, we completed our response to the most recent information request, but we are unable to predict the outcome of this matter.

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 coal-fired power plant facilities. The information request required UE to provide responses to specific EPA questions regarding certain projects and maintenance activities in order to determine UE’s compliance with state and federal regulatory requirements. UE has completed this information request. In July 2009, the EPA issued a Section 114(a) request to certain contractors that have performed capital projects at UE’s facilities since 1987. 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.

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 facilities 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 generating facilities. On April 1, 2009, the U.S. Supreme Court ruled that the EPA can compare costs of technology for protecting aquatic species to the benefits of that technology in establishing the “best technology available” standards applicable to the cooling water intake structure at existing power plants under the Clean Water Act. The EPA is expected to propose revised rules in early 2010. Until the EPA reissues the rules, and such 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.

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 their degree of fault, the legality of original disposal, or the 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 (PRP) at several contaminated sites. Several 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, respectively, for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of September 30, 2009, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 15, CILCO has 4, and IP has 25 sites. All of these sites are in various stages of investigation, evaluation and remediation. Ameren currently 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 review by the ICC. As of September 30, 2009, estimated obligations were: CIPS - $56 million to $79 million, CILCO - less than $1 million, and IP - $100 million to $175 million. CIPS, CILCO and IP have liabilities of $56 million, less than $1 million, and $100 million, respectively, recorded to represent estimated minimum obligations, as no other amount within the range was a better estimate. In the third quarter of 2009, CIPS increased its remediation liability based on the completion of site investigations and the selection of remediated actions.

CIPS is also responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of September 30, 2009, 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, 2009, IP recorded a liability of $0.8 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 site 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, 2009, UE estimated its obligation at $3 million to $5 million. UE has a liability of $3 million recorded 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 waste sites in Missouri that have corporate cleanup liability, as a result of federal agency mandates. UE recently concluded cleanups at two of these sites, and no further remediation actions are anticipated at those two sites. One of the remaining waste sites for which UE has corporate clean-up responsibility is a former coal tar distillery located in St. Louis, Missouri. In July 2008, the EPA issued an administrative order to UE pertaining to this 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 byproducts. UE along with two other PRPs have reached an agreement with the EPA as to the scope of the site investigation, which will occur later this year. As of September 30, 2009, UE estimated its obligation at $2 million to $5 million. UE has a liability of $2 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

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 once used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.

Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA and a record of decision is expected in 2010. Once the EPA has selected a remedy alternative, it will 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, 2009, UE estimated its obligation at $0.4 million to $10 million. UE has a liability of $0.4 million recorded 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 requesting that CIPS 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, which 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 was concluded in the first quarter of 2009.

In December 2004, AERG submitted a plan 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, 2009, on their consolidated balance sheets for the estimated cost of the remediation effort, which involves discharging recycle-system water into the Duck Creek reservoir and the eventual closure of ash ponds in order to address these groundwater and surface water issues.

In March 2009, UE and CIPS received from the EPA “Special Notice of Liability” letters with respect to a former transformer repair facility located in Cape Girardeau, Missouri. Both companies are members of a PRP group that sent electrical equipment to the site and previously performed certain soil remediation and investigative work with respect to the site. The EPA is requesting the PRP group to investigate groundwater conditions at the site. The group is in the process of negotiating the terms under which such additional work would occur. UE and CIPS believe that the PRP group presently has adequate financial resources to cover the cost of such work without additional contributions from the companies.

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 whether such practices will result in future environmental commitments or impact our results of operations, financial position, or liquidity.

Ash Ponds

There has been increased activity at both the state and federal level to examine the need for additional regulation of ash pond facilities and coal combustion byproducts (CCB) and wastes. The EPA is considering regulating CCB under the hazardous waste regulations, which could impact future disposal and handling costs at our power plant facilities. We believe it is likely that the EPA will continue to allow some beneficial use, such as recycling, of CCB without classifying them as hazardous wastes. The EPA is considering requiring as part of its proposed regulations that coal-fired power plants engage in the mandatory closure of active surface impoundments used for the management of CCB. In September 2009, the EPA announced that it expects to overhaul federal rules governing wastewater discharges from coal-fired power plants. It is anticipated that some form of additional regulation concerning the integrity of ash ponds, and the handling and disposal of CCB and waste may be proposed in the fourth quarter of 2009. Ameren’s CCB impoundments were not identified in the EPA’s 2009 listing of 44 high hazard potential impoundments containing CCB. In addition, the Illinois EPA has requested that UE, Genco, CILCO (AERG) and EEI establish groundwater monitoring plans for their active and inactive ash impoundments in Illinois. Genco is currently petitioning the Illinois Pollution Control Board to issue a site specific rule approving the closure of an ash pond at its Hutsonville power plant. At this time, we are unable to predict the outcome any such state and federal regulations might have on our results of operations, financial position, or liquidity.

Pumped-storage Hydroelectric Facility Breach

UE has property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance does 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 upper reservoir, will range from $203 million to $210 million. As of September 30, 2009, UE had paid $203 million, including costs resulting from the FERC-approved stipulation and consent agreement. As of September 30, 2009, UE had recorded expense of $35 million, primarily in prior years, for items not covered by insurance and had recorded a $168 million receivable for amounts recoverable from insurance companies under liability coverage. As of September 30, 2009, UE had received $99 million from insurance companies, which reduced the insurance receivable balance subject to liability coverage to $69 million.

UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and is in the process of rebuilding the facility. UE expects the Taum Sauk plant to be out of service until the spring of 2010. The estimated cost to rebuild the upper reservoir is in the range of $490 million. As of September 30, 2009, UE had recorded a $420 million receivable due from insurance companies under property insurance coverage related to the rebuilding of the facility and the reimbursement of replacement power costs. As of September 30, 2009, UE had received $362 million from insurance companies, which reduced the property insurance receivable balance as of September 30, 2009, to $58 million.

Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. In July 2009, three insurance carriers filed a petition against Ameren in the Circuit Court of St. Louis County, Missouri, seeking a declaratory judgment that the property insurance policy does not require these three insurers to indemnify Ameren for their share of the entire cost of construction associated with the facility rebuild design being utilized. The three insurers allege that they, along with the other policy participants, had presented a rebuild design that was consistent with their insurance coverage obligations and that the insurance policy does not require these insurers to pay their share of the costs of construction associated with the design being used. These insurers have estimated a cost of approximately $214 million for their rebuild design compared to the estimated $490 million cost of the design

approved by FERC and being used by Ameren. Ameren has filed an answer and counterclaim in the Circuit Court of St. Louis County, Missouri against these insurers. The counterclaim asserts that the three insurance carriers have breached their obligations under the property insurance policies issued to Ameren and UE. Ameren seeks payment of an amount to-be-determined for all amounts covered by these policies incurred in the facility rebuild, including power replacement costs, interest and attorney’s fees. The insurers that are parties to the litigation represent approximately 40%, on a weighted average basis, of the property insurance policy coverage between the disputed amounts of $214 million and $490 million.

On August 31, 2009, Ameren and the property insurance carriers that are not parties to the above litigation (the “Settling Insurance Companies”) reached a settlement of any and all claims, liabilities, and obligations arising out of, or relating to, coverage under its property insurance policy, including those related to the rebuilding of the facility and the reimbursement of replacement power costs. All payments from the Settling Insurance Companies were received by UE by September 30, 2009.

Until Ameren’s remaining insurance claims and the related litigation are resolved, 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. As a result of the settlement with the Settling Insurance Companies, Ameren and UE now expect to recover, through insurance, 80% to 90% of the total property insurance claim for the Taum Sauk incident. Beyond insurance, the recoverability of any Taum Sauk facility rebuild costs from customers is subject to the terms and conditions set forth in UE’s November 2007 State of Missouri settlement agreement. In that settlement, UE agreed that it would “not attempt to recover from rate payers…costs incurred in the reconstruction… expressly excluding, however… enhancements, costs incurred due to circumstances or conditions that [were not at that time] reasonably foreseeable and costs that would have been incurred absent the [Taum Sauk incident].” Certain costs associated with the Taum Sauk facility not recovered from property insurers may be recoverable from UE’s electric customers through rates established in rate cases filed subsequent to the expected spring 2010 in-service date of the rebuilt facility. As of September 30, 2009, UE had capitalized in property and equipment qualifying Taum Sauk-related costs of $59 million that UE believes qualify for potential recovery in electric rates under the terms of the November 2007 State of Missouri Settlement. The inclusion of such costs in UE’s electric rates is subject to review and approval by the MoPSC in a future rate case. Any amounts not recovered through insurance, in electric rates, or otherwise could result in charges to earnings, which could be material.

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 192 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, 2009, the average number of parties was 73.

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 former parent 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 that, if awarded at trial, typically would be shared among the various defendants.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of September 30, 2009:


Specifically Named as Defendant
Ameren	UE	CIPS	Genco	CILCO	IP	Total^(a)
2	31	30	-	14	40	74

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

As of September 30, 2009, nine 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.

At September 30, 2009, Ameren, UE, CIPS, CILCO and IP had liabilities of $14 million, $4 million, $3 million, $2 million and $5 million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.

IP has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms. Beginning in 2007, 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. At September 30, 2009, the trust fund balance was approximately $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’s last announced date of when it expects a permanent storage facility for spent fuel to be available was 2020, and the DOE continues to evaluate permanent storage alternatives. 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.

UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license from 2024 to 2044. If the Callaway nuclear plant’s license is extended, additional spent fuel storage will be required. UE is evaluating the installation of a dry spent fuel storage facility at its Callaway nuclear plant.

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. 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 2008, 2007, and 2006. 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 and 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 as Nuclear Decommissioning Trust Fund in Ameren’s Consolidated Balance Sheet and UE’s Balance Sheet. This amount is legally restricted and 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.

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 stockholders. A reconciliation of net income to comprehensive income for the three and nine months ended September 30, 2009 and 2008, is shown below for the Ameren Companies:


	Three Months						Nine Months
	2009			2008			2009			2008
Ameren:^(a)
Net income	$	229		$	215		$	542		$	581
Unrealized net gain on derivative hedging instruments, net of taxes of $11, $89, $65 and $26, respectively		21			157			119			46
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $15, $23, $59 and $17, respectively		(29	)		(40	)		(106	)		(29	)
Reclassification adjustment due to implementation of FAC, net of taxes of $-, $-, $18 and $-, respectively		-			-			(29	)		-
Adjustment to pension and benefit obligation, net of taxes of $-, $-, $7 and $1, respectively		-			-			(5	)		(2	)
Total comprehensive income, net of taxes	$	221		$	332		$	521		$	596
Less: Net income attributable to noncontrolling interests, net of taxes		2			11			9			33
Total comprehensive income attributable to Ameren Corporation, net of taxes	$	219		$	321		$	512		$	563
UE:
Net income	$	142		$	99		$	248		$	287
Unrealized net gain on derivative hedging instruments, net of taxes of $-, $23, $11 and $12, respectively		-			38			17			21
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $2, $8 and $3, respectively		-			(4	)		(13	)		(5	)
Reclassification adjustment due to implementation of FAC, net of taxes of $-, $-, $18 and $-, respectively		-			-			(29	)		-
Total comprehensive income, net of taxes	$	142		$	133		$	223		$	303
CIPS:
Net income	$	18		$	7		$	26		$	7
Total comprehensive income, net of taxes	$	18		$	7		$	26		$	7
Genco:
Net income	$	27		$	20		$	120		$	140
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $-, $- and $4, respectively		-			-			-			(5	)
Adjustment to pension and benefit obligation, net of taxes (benefit) of $-, $-, $1 and $(2), respectively		-			-			1			3
Total comprehensive income, net of taxes	$	27		$	20		$	121		$	138
CILCORP:
Net income (loss)	$	29		$	18		$	(379	)	$	43
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $-, $- and $1, respectively		-			-			-			(1	)
Adjustment to pension and benefit obligation, net of taxes of $-, $-, $- and $1, respectively		-			-			(1	)		3
Total comprehensive income (loss), net of taxes	$	29		$	18		$	(380	)	$	45
Less: Net income attributable to noncontrolling interests, net of taxes		1			-			1			1
Total comprehensive income (loss) attributable to CILCORP Inc., net of taxes	$	28		$	18		$	(379	)	$	44
CILCO:
Net income	$	37		$	24		$	101		$	62
Adjustment to pension and benefit obligation, net of taxes of $-, $-, $1 and $3, respectively		-			-			1			4
Total comprehensive income, net of taxes	$	37		$	24		$	102		$	66
IP:
Net income (loss)	$	35		$	5		$	62		$	(2	)
Adjustment to pension and benefit obligation, net of taxes of $-, $-, $-, and $-, respectively		(1	)		-			(1	)		-
Total comprehensive income (loss), net of taxes	$	34		$	5		$	61		$	(2	)

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

NOTE 12 - RETIREMENT BENEFITS

Ameren’s pension and postretirement plans are funded in compliance with income tax regulations and to achieve federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Taking into consideration our assumptions at December 31, 2008, estimated investment performance through September 30, 2009, and our pension funding policy, Ameren expects to make annual contributions of $100 million to $250 million in each of the next five years. These amounts are estimates which may change with actual investment 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 (VEBA) trusts to match the annual postretirement expense.

Ameren made contributions to its pension plan during the first nine months of 2009 and 2008 of $47 million and $32 million, respectively. In October 2009, Ameren made an additional $23 million contribution to its pension plan. Ameren made contributions to its postretirement benefit plans during the first nine months of 2009 and 2008 of $23 million and $22 million, respectively.

The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three and nine months ended September 30, 2009 and 2008:


	Pension Benefits^(a)												Postretirement Benefits^(a)
	Three Months						Nine Months						Three Months						Nine Months
	2009			2008			2009			2008			2009			2008			2009			2008
Service cost	$	17		$	15		$	51		$	44		$	5		$	5		$	15		$	14
Interest cost		47			46			140			139			16			17			49			52
Expected return on plan assets		(52	)		(53	)		(154	)		(159	)		(13	)		(14	)		(40	)		(43	)
Amortization of:
Transition obligation		-			-			-			-			1			1			2			2
Prior service cost (benefit)		2			3			6			9			(2	)		(2	)		(6	)		(6	)
Actuarial loss		6			1			18			2			2			2			6			6
Net periodic benefit cost	$	20		$	12		$	61		$	35		$	9		$	9		$	26		$	25

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

UE, CIPS, Genco, CILCORP, CILCO and IP are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and nine months ended September 30, 2009 and 2008:


	Pension Costs									Postretirement Costs
	Three Months				Nine Months					Three Months				Nine Months
	2009		2008		2009		2008			2009		2008		2009		2008
Ameren^(a)	$	20	$	12	$	61	$	35		$	9	$	9	$	26	$	25
UE		12		8		37		27			4		4		11		10
CIPS		2		2		6		5			1		-		2		2
Genco		2		1		5		4			-		-		1		1
CILCORP		2		-		6		(2	)		-		2		2		2
CILCO		3		1		11		3			1		3		5		5
IP		-		-		1		(2	)		3		3		9		10

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

NOTE 13 - SEGMENT INFORMATION

Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Merchant 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 40% interest in EEI (which in February 2008 was transferred to Resources Company through an internal reorganization). 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 Merchant 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.

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.

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

The following tables present information about the reported revenues and specified items included in net income of Ameren, UE, CILCORP, and CILCO for the three and nine months ended September 30, 2009 and 2008, and total assets as of September 30, 2009, and December 31, 2008.

Ameren


Three Months	Missouri Regulated		Illinois Regulated		Merchant Generation		Other			Intersegment Eliminations			Consolidated
2009:
External revenues	$	829	$	638	$	346	$	2		$	-		$	1,815
Intersegment revenues		7		7		87		4			(105	)		-
Net income (loss) attributable to Ameren Corporation^(a)		141		57		37		(8	)		-			227
2008:
External revenues	$	865	$	724	$	478	$	(7	)	$	-		$	2,060
Intersegment revenues		10		7		114		3			(134	)		-
Net income (loss) attributable to Ameren Corporation^(a)		98		13		108		(15	)		-			204
Nine Months
2009:
External revenues	$	2,222	$	2,184	$	997	$	12		$	-		$	5,415
Intersegment revenues		21		21		309		14			(365	)		-
Net income (loss) attributable to Ameren Corporation^(a)		244		97		205		(13	)		-			533
2008:
External revenues	$	2,340	$	2,487	$	1,110	$	(6	)	$	-		$	5,931
Intersegment revenues		30		30		341		11			(412	)		-
Net income (loss) attributable to Ameren Corporation^(a)		272		15		284		(23	)		-			548
As of September 30, 2009:
Total assets	$	12,257	$	7,302	$	5,054	$	1,226		$	(2,245	)	$	23,594
As of December 31, 2008:
Total assets	$	11,524	$	7,079	$	4,622	$	1,227		$	(1,795	)	$	22,657

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


Three Months	Missouri Regulated		Other^(a)		UE
2009:
Revenues	$	836	$	-	$	836
Net income^(b)		141		-		141
2008:
Revenues	$	875	$	-	$	875
Net income^(b)		98		-		98
Nine Months
2009:
Revenues	$	2,243	$	-	$	2,243
Net income^(b)		244		-		244
2008:
Revenues	$	2,370	$	-	$	2,370
Net income^(b)		272		11		283
As of September 30, 2009:
Total assets	$	12,257	$	-	$	12,257
As of December 31, 2008:
Total assets	$	11,524	$	-	$	11,524

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

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

CILCORP


Three Months	Illinois Regulated			Merchant Generation			CILCORP Other		Intersegment Eliminations			Consolidated CILCORP
2009:
External revenues	$	133		$	118		$	-	$	-		$	251
Intersegment revenues		1			-			-		(1	)		-
Net income^(b)		7			21			-		-			28
2008:
External revenues	$	162		$	102		$	-	$	-		$	264
Intersegment revenues		1			-			-		(1	)		-
Net income^(b)		4			14			-		-			18
Nine Months
2009:
External revenues	$	480		$	314		$	-	$	-		$	794
Intersegment revenues		1			-			-		(1	)		-
Goodwill impairment^(a)		(117	)		(345	)		-		-			(462	)
Net loss^(b)		(102	)		(278	)		-		-			(380	)
2008:
External revenues	$	590		$	252		$	-	$	-		$	842
Intersegment revenues		3			-			-		(3	)		-
Net income^(b)		15			27			-		-			42
As of September 30, 2009:
Total assets	$	1,367		$	1,357		$	2	$	(217	)	$	2,509
As of December 31, 2008:
Total assets	$	1,402		$	1,680		$	2	$	(219	)	$	2,865

(a)	See Note 14 - Goodwill Impairment for further information.

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

CILCO


Three Months	Illinois Regulated		Merchant Generation		CILCO Other		Intersegment Eliminations			Consolidated CILCO
2009:
External revenues	$	133	$	118	$	-	$	-		$	251
Intersegment revenues		1		-		-		(1	)		-
Net income^(a)		7		29		-		-			36
2008:
External revenues	$	162	$	102	$	-	$	-		$	264
Intersegment revenues		1		-		-		(1	)		-
Net income^(a)		4		20		-		-			24
Nine Months
2009:
External revenues	$	480	$	314	$	-	$	-		$	794
Intersegment revenues		1		-		-		(1	)		-
Net income^(a)		15		85		-		-			100
2008:
External revenues	$	590	$	252	$	-	$	-		$	842
Intersegment revenues		3		-		-		(3	)		-
Net income^(a)		15		46		-		-			61
As of September 30, 2009:
Total assets	$	1,294	$	1,109	$	-	$	-		$	2,403
As of December 31, 2008:
Total assets	$	1,212	$	1,081	$	-	$	1		$	2,294

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

NOTE 14 - GOODWILL IMPAIRMENT

We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Goodwill impairment testing is a two-step process. The first step involves a comparison of the estimated fair value of a reporting unit with its carrying amount. If the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired. If the carrying amount of the reporting unit exceeds its estimated fair value, the second step is performed to measure the amount of impairment, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined by allocating the estimated fair value of the reporting unit to the estimated fair value of its existing assets and liabilities in a manner similar to a purchase price allocation. The unallocated portion of the estimated fair value of the reporting unit is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss, equivalent to the difference, is recorded as a reduction of goodwill and a charge to operating expense.

The goodwill impairment test that we performed in the fourth quarter of 2008 did not result in the second step assessment; the test indicated no impairment of Ameren’s, CILCORP’s, or IP’s goodwill. However, the estimated fair values of both of CILCORP’s reporting units (Illinois Regulated and Merchant Generation) exceeded carrying values by a nominal amount. We concluded that events had occurred and circumstances had changed during the first quarter of 2009, which required us to perform an interim goodwill impairment test. The following triggering events resulted in the need for us to perform an impairment test:

•

A significant decline in Ameren’s market capitalization.

•

The continuing decline in market prices for electricity.

•

A decrease in observable industry market multiples.

The fair value of Ameren’s, CILCORP’s and IP’s reporting units was estimated based on a risk-adjusted, probability-weighted discounted cash flow model that considered multiple operating scenarios. Key assumptions in the determination of fair value included the use of an appropriate discount rate, estimated five-year future cash flows, and an exit value based on observable industry market multiples. For the interim test conducted as of March 31, 2009, the discount rate used was 3.8%, based on the 20-year treasury yield. To assess the reasonableness of the estimated fair values, the sum of the estimated fair values of the Ameren reporting units is reconciled to our current market capitalization plus an estimated control premium. We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, the regulatory environment, and operating costs.

CILCORP’s Illinois Regulated reporting unit and CILCORP’s Merchant Generation reporting unit both failed step one of the March 31, 2009, impairment test, as each reporting unit’s carrying value exceeded its estimated fair value. Therefore, in order to measure the amount of any goodwill impairment in step two, we estimated individually the implied fair value of CILCORP’s Illinois Regulated goodwill and CILCORP’s Merchant Generation goodwill. We determined that the implied fair value of goodwill was less than the carrying amount of goodwill for both reporting units, indicating that CILCORP’s Illinois Regulated goodwill and CILCORP’s Merchant Generation goodwill was impaired as of March 31, 2009. Based on the results of step two of the impairment test, CILCORP recorded a noncash impairment charge of $462 million, which represented all of the goodwill assigned to CILCORP’s Merchant Generation reporting unit of $345 million and $117 million assigned to CILCORP’s Illinois Regulated reporting unit. The step two test indicated that the implied fair value of goodwill relating to CILCORP’s Illinois Regulated reporting unit was $80 million.

The goodwill impairment loss recorded by CILCORP was not reflected at the consolidated Ameren level because of the aggregation of reporting units. Ameren’s reporting units and IP’s reporting unit did not require a second step assessment; the results of the step one tests indicated no impairment of goodwill as of March 31, 2009. However, the estimated fair values of Ameren’s Illinois Regulated reporting unit, Ameren’s Merchant Generation reporting unit, and IP’s Illinois Regulated reporting unit exceeded carrying values by a nominal amount as of March 31, 2009. The estimated fair value of Ameren’s Illinois Regulated reporting unit exceeded its carrying value by approximately $210 million, or 5% of its carrying value. The estimated fair value of Ameren’s Merchant Generation reporting unit exceeded its carrying value by approximately $35 million, or 1% of its carrying value. The estimated fair value of IP’s Illinois Regulated reporting unit exceeded its carrying value by approximately $100 million, or 4% of its carrying value. As a result, the failure in the future of any reporting unit to achieve forecasted operating results and cash flows or a further decline of observable industry market multiples may reduce its estimated fair value below its carrying value and would likely result in the recognition of a goodwill impairment charge.

Ameren, CILCORP and IP will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, market prices for electricity and observable industry market multiples of their reporting units for signs of possible declines in estimated fair value and potential goodwill impairment. No triggering events were identified in the third quarter of 2009, and therefore, no interim impairment test was performed.

The following tables detail how goodwill has been assigned to the registrants’ reporting units and changes to the carrying amount of goodwill as of September 30, 2009:

Ameren


	Missouri Regulated		Illinois Regulated		Merchant Generation		Total^(a)
Balance at December 31, 2008	$	-	$	411	$	420	$	831
Impairment loss recorded in first quarter		-		-		-		-
Balance at September 30, 2009	$	-	$	411	$	420	$	831

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

CILCORP


	Missouri Regulated		Illinois Regulated			Merchant Generation			Total
Balance at December 31, 2008	$	-	$	197		$	345		$	542
Impairment loss recorded in first quarter		-		(117	)		(345	)		(462	)
Balance at September 30, 2009	$	-	$	80		$	-		$	80
IP
	Missouri Regulated		Illinois Regulated			Merchant Generation			Total
Balance at December 31, 2008	$	-	$	214		$	-		$	214
Impairment loss recorded in first quarter		-		-			-			-
Balance at September 30, 2009	$	-	$	214		$	-		$	214

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 2009 were higher than its earnings in the 2008 comparable period, while Ameren’s earnings were lower in the first nine months of 2009 than its earnings in the 2008 comparable period. Ameren’s earnings in the three and nine months ended September 30, 2009, were reduced by lower electricity sales in Ameren’s rate-regulated utilities and lower margins in the Merchant Generation segment, as a result of much cooler summer weather and weak economic conditions. Higher interest expense, employee separation programs, and the retirement of two generating units in the Merchant Generation segment, among other items, also decreased earnings in 2009. Offsetting factors in the three and nine months ended September 30, 2009, included utility rate adjustments in Illinois and Missouri, lower operations and maintenance expenses, and favorable unrealized MTM activity on derivatives, among other items.

In the third quarter of 2009, at Ameren’s rate-regulated utilities, much cooler summer weather and the economic slowdown led to a 10% decrease in kilowatthour sales to residential customers and a 3% decrease in kilowatthour sales to commercial customers, compared with the year-ago quarter. These sales changes were more modest on a weather-normalized basis, with residential sales declining an estimated 2% and commercial sales declining an estimated 1%. Cooling degree-days in the third quarter of 2009 were 18% below those of the third quarter of 2008 and 23% below normal. The weak economy continued to affect kilowatthour sales by Ameren’s rate-regulated businesses to their industrial customers. These sales declined 13% from the year-ago quarter, excluding the

impact of reduced sales to Noranda. Noranda’s plant sustained damage because of a power interruption on non-Ameren-owned power lines during a severe January 2009 ice storm. Including Noranda, electric sales to industrial customers declined 18% in the third quarter of 2009, as compared to the year-ago quarter. Noranda announced in September 2009 that it had initiated steps to return operations to full effective capacity. These steps include restarting the third of its three production lines. Ameren expects it will take some time for the third production line to be repaired and returned to full capacity. Ameren expects full year 2009 electricity sales to industrial customers of Ameren’s rate-regulated utilities will be down approximately 11%, excluding Noranda. Ameren currently believes sales declines associated with industrial customers are slowing and expects growth in 2010, though at a pace less than what is typical coming out of an economic recession. On a weather-normalized basis, Ameren expects full year 2009 sales to residential and commercial customers to be down approximately 1% to 2% as compared to 2008. In 2010, Ameren expects a resumption of growth in residential and commercial sales, assuming a moderate economic recovery.

Ameren has rate cases pending in its Illinois and Missouri jurisdictions seeking revenue levels that reflect the significant investments made in electric and gas utility infrastructure to improve reliability, increases in costs essential to generating and delivering electricity, higher financing costs and, in Missouri, rising net fuel costs. The Ameren Illinois Utilities filed requests with the ICC in June 2009 to increase their annual revenues for electric and natural gas delivery services. The currently pending requests, as amended, seek to increase annual revenues from electric and natural gas delivery service by $162 million in the aggregate. In addition, the Ameren Illinois Utilities have requested a rider mechanism that would permit recovery of ICC reliability audit expenditures. The Ameren Illinois Utilities estimate that they will incur distribution-related implementation costs of $15 million (CIPS - $5 million, CILCO - $3 million, and IP - $7 million) in 2010. If approved, the rider mechanism would recover future reliability audit expenditures as well. The ICC is expected to issue an order in time for new rates to be effective in early May 2010. UE filed with the MoPSC for an annual electric revenue increase of $402 million. More than half of the request is for anticipated increases in normalized net fuel costs. These increased net fuel costs would have been eligible for recovery through the FAC absent this filing. As part of its overall request, UE has asked for interim rate relief of $37 million, subject to refund with interest. The MoPSC established a schedule for considering the interim increase request, and a hearing is set for December 2009. In the overall rate case, new rates are expected to be effective in late June 2010.

Ameren is focused on delivering shareholder value in the years to come. In that regard, Ameren has taken several steps to position the Company for future success. Through the rate proceedings discussed above, Ameren is seeking to recover increased costs in Ameren’s rate-regulated businesses to narrow the gap between their earned and allowed returns. Ameren has set operating cost targets for 2010 and has implemented several measures to control costs. Ameren expects its rate-regulated businesses’ 2010 nonfuel operating and maintenance expenses to be at a level consistent with that of 2008. Further, Ameren’s rate-regulated utilities have identified, and are carefully evaluating for possible elimination or deferral, approximately $1 billion of previously planned capital expenditures scheduled for the 2010 through 2013 period. Ameren expects that Merchant Generation’s nonfuel operations and maintenance expenses will decline by 5% to 10% in 2010, as compared to the 2008 level. Merchant Generation also eliminated approximately $1 billion in capital expenditures from the 2010 through 2013 period, as compared to prior plans.

Liquidity

Ameren has taken actions in 2009 to maintain and enhance its liquidity position and credit profile. In June 2009, Ameren and certain of its subsidiaries entered into multiyear credit facility agreements that provide Ameren and its business segments with substantial borrowing capacity through the middle of 2011. These credit facilities cumulatively provide $2.1 billion of credit through July 14, 2010, thereafter reducing to $1.8795 billion through June 30, 2011, and thereafter reducing to $1.0795 billion through July 14, 2011. In September 2009, Ameren issued and sold 21.9 million shares of its common stock for net proceeds of $535 million. Ameren used the net offering proceeds to make investments in its rate-regulated utility subsidiaries in the form of capital contributions.

At September 30, 2009, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under its existing credit facilities, of approximately $2.2 billion, which was approximately $1 billion higher than the same time last year.

General

•

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 merchant electric generation business in Illinois and Missouri.

•

CILCO is a subsidiary of CILCORP (a holding company). It operates a rate-regulated electric transmission and distribution business, a merchant electric generation business (through its subsidiary, AERG) and a rate-regulated natural gas transmission and distribution business, all 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. Merchant Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil for fuel 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 have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery service businesses, purchased power cost recovery mechanisms for our Illinois electric delivery service businesses, and a FAC for our Missouri electric utility business. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, for a discussion of pending rate cases in Missouri and Illinois, including UE’s request for approval to implement an environmental cost recovery mechanism and to continue its FAC. 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 and 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.

Net income attributable to Ameren Corporation increased to $227 million, or $1.04 per share, in the third quarter of 2009, from $204 million, or 97 cents per share, in the third quarter of 2008. Net income attributable to Ameren Corporation in the third quarter of 2009 increased in the Illinois Regulated and Missouri Regulated segments by $44 million and $43 million, respectively, from the prior-year period, while net income attributable to Ameren Corporation in the Merchant Generation segment decreased by $71 million from the same period in 2008.

Net income attributable to Ameren Corporation decreased to $533 million, or $2.48 per share, in the first nine months of 2009 from $548 million, or $2.61 per share, in the first nine months of 2008. Net income attributable to Ameren Corporation increased in the Illinois Regulated segment by $82 million in the first nine months of 2009 compared with the prior-year period, while net income attributable to Ameren Corporation in the Missouri Regulated and Merchant Generation segments decreased by $28 million and $79 million, respectively, from the same period in 2008.

Earnings were negatively impacted in the third quarter and first nine months of 2009 as compared with the same periods in 2008 by:

•

the impact on electric and natural gas margins at our rate-regulated businesses of higher net fuel costs at UE and lower demand (exclusive of weather impacts), among other things (3 cents per share and 38 cents per share, respectively);

•

higher dilution and financing costs (12 cents per share and 21 cents per share, respectively);

•

unfavorable weather conditions (estimated at 12 cents per share and 10 cents per share, respectively);

•

increased depreciation and amortization expense (3 cents per share and 9 cents per share, respectively);

•

reduced sales to Noranda because of an extended storm-related outage (3 cents per share and 9 cents per share, respectively);

•

increased expense related to workforce reductions through voluntary and involuntary separation programs as well as other charges (6 cents per share for each period); and

•

increased taxes other than income taxes primarily because of higher property taxes (2 cents per share and 4 cents per share, respectively).

Earnings were favorably impacted in the third quarter and first nine months of 2009 as compared with the same period in 2008 by:

•

higher electric and natural gas delivery service rates, effective October 1, 2008, in the Illinois Regulated segment pursuant to an ICC consolidated rate order for CIPS, CILCO and IP (14 cents per share and 40 cents per share, respectively);

•

higher electric rates, effective March 1, 2009, in the Missouri Regulated segment pursuant to a MoPSC rate order (16 cents per share and 31 cents per share, respectively);

•

decreased plant operations and maintenance expense (1 cent per share and 13 cents per share, respectively);

•

favorable net unrealized MTM activity on derivatives (13 cents per share and 5 cents per share, respectively); and

•

the reduced impact in 2009 of the electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities electric customers under the Illinois electric settlement agreement (1 cent per share and 4 cents per share, respectively).

In addition to the above items affecting both periods, earnings were negatively impacted in the third quarter of 2009 as compared with the third quarter of 2008 by lower electric margins in the Merchant Generation segment (7 cents per share).

In addition to the above items affecting both periods, earnings were favorably impacted in the third quarter of 2009 as compared with the third quarter of 2008 by the redesigned seasonal natural gas delivery service rates at the Ameren Illinois Utilities (4 cents per share). These redesigned delivery service rates impacted quarterly earnings but did not materially impact annual results.

In addition to the above items affecting both periods, earnings were negatively impacted in the first nine months of 2009 as compared with the first nine months of 2008 by:

•

the absence in 2009 of a settlement agreement reached with a coal mine owner that reimbursed Genco, in the form of a lump-sum payment, for increased costs for coal and transportation incurred in 2008 and expected to be incurred in 2009 due to the premature closure of an Illinois mine at the end of 2007 (18 cents per share);

•

the absence in 2009 of storm costs recorded as a regulatory asset as a result of an accounting order issued by the MoPSC (4 cents per share); and

•

increased distribution system reliability expenditures (3 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 2008.

Because it is a holding company, net income and cash flows attributable to Ameren Corporation 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 net income attributable to Ameren Corporation for the three and nine months ended September 30, 2009 and 2008:


	Three Months					Nine Months
	2009			2008		2009			2008
Net income (loss):
UE	$	141		$	98	$	244		$	283	^(a)
CIPS		17			6		24			5
Genco		27			20		120			140
CILCORP		28			18		(380	)^(b)		42
IP		34			4		60			(4	)
Other^(c)		(20	)		58		465	^(b)		82
Net income attributable to Ameren Corporation	$	227		$	204	$	533		$	548

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

(b)	Includes goodwill impairment loss of $462 million offset by intercompany elimination in Other as no impairment was recognized at the consolidated Ameren level. See Note 14 - Goodwill Impairment under Part I, Item 1, of this report for additional information.

(c)	Includes earnings from EEI, other merchant generation operations, as well as corporate general and administrative expenses, and intercompany eliminations. Includes a 40% interest in EEI through February 29, 2008, and an 80% interest in EEI since that date.

Below is a table of income statement components by segment for the three and nine months ended September 30, 2009 and 2008:


	Missouri Regulated			Illinois Regulated			Merchant Generation			Other / Intersegment Eliminations			Total
Three Months 2009:
Electric margin	$	636		$	260		$	224		$	(3	)	$	1,117
Gas margin		11			69			-			(1	)		79
Other revenues		1			-			-			(1	)		-
Other operations and maintenance		(229	)		(117	)		(86	)		10			(422	)
Depreciation and amortization		(90	)		(55	)		(34	)		(6	)		(185	)
Taxes other than income taxes		(72	)		(26	)		(7	)		1			(104	)
Other income and (expenses)		13			-			1			(1	)		13
Interest expense		(61	)		(37	)		(34	)		(2	)		(134	)
Income taxes		(67	)		(36	)		(28	)		(4	)		(135	)
Net income (loss)		142			58			36			(7	)		229
Noncontrolling interest and preferred dividends		(1	)		(1	)		1			(1	)		(2	)
Net income (loss) attributable to Ameren Corporation		141			57			37			(8	)		227
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	)		(154	)		(79	)		11			(456	)
Depreciation and amortization		(83	)		(55	)		(27	)		(8	)		(173	)
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	)
Net income (loss)		99			15			117			(16	)		215
Noncontrolling interest and preferred dividends		(1	)		(2	)		(9	)		1			(11	)
Net income (loss) attributable to Ameren Corporation		98			13			108			(15	)		204
Nine Months 2009:
Electric margin	$	1,581		$	676		$	770		$	(13	)	$	3,014
Gas margin		52			252			-			(1	)		303
Other revenues		3			4			-			(7	)		-
Other operations and maintenance		(665	)		(406	)		(248	)		25			(1,294	)
Depreciation and amortization		(266	)		(162	)		(93	)		(20	)		(541	)
Taxes other than income taxes		(200	)		(90	)		(21	)		-			(311	)
Other income and (expenses)		37			3			1			(6	)		35
Interest expense		(171	)		(118	)		(82	)		(5	)		(376	)
Income taxes		(123	)		(58	)		(121	)		14			(288	)
Net income (loss)		248			101			206			(13	)		542
Noncontrolling interest and preferred dividends		(4	)		(4	)		(1	)		-			(9	)
Net income (loss) attributable to Ameren Corporation		244			97			205			(13	)		533
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	)		(462	)		(250	)		40			(1,361	)
Depreciation and amortization		(246	)		(165	)		(81	)		(21	)		(513	)
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	)
Net income (loss)		276			20			309			(24	)		581
Noncontrolling interest and preferred dividends		(4	)		(5	)		(25	)		1			(33	)
Net income (loss) attributable to Ameren Corporation		272			15			284			(23	)		548

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins in the three and nine months ended September 30, 2009, compared with the same periods in 2008. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural gas margins are defined as gas revenues less gas purchased for resale. We consider electric and natural gas margins useful measures to analyze the change in profitability of our electric and natural 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)	$	(39	)	$	(25	)	$	(3	)	$	-		$	(4	)	$	(4	)	$	(7	)
Regulated rates:
Changes in base rates		88			55			7			-			(1	)		(1	)		27
Noranda sales		(15	)		(15	)		-			-			-			-			-
Illinois pass-through power costs		(86	)		-			(15	)		-			(24	)		(24	)		(47	)
Merchant Generation sales price changes		25			-			-			40			13			13			-
Off-system revenues		(36	)		(36	)		-			-			-			-			-
Illinois electric settlement agreement, net of reimbursement		3			-			-			1			-			-			1
Net MTM gains (losses)		(91	)		4			-			-			-			-			-
Generation output, load and other		(98	)		(20	)		1			(67	)		(11	)		(11	)		(11	)
Total electric revenue change	$	(249	)	$	(37	)	$	(10	)	$	(26	)	$	(27	)	$	(27	)	$	(37	)
Fuel and purchased power change:
Fuel:
Generation and other	$	59		$	26		$	-		$	27		$	(2	)	$	(1	)	$	-
Lower net MTM losses		110			59			-			29			7			7			-
Price		(14	)		-			-			(4	)		(2	)		(2	)		-
Purchased power		29			18			5			-			16			16			12
Illinois pass-through power costs		86			-			15			-			24			24			47
Total fuel and purchased power change	$	270		$	103		$	20		$	52		$	43		$	44		$	59
Net change in electric margin	$	21		$	66		$	10		$	26		$	16		$	17		$	22
Natural gas margin change:
Changes in base rates	$	9		$	-		$	1		$	-		$	(2	)	$	(2	)	$	10
Illinois seasonal rate redesign		12			-			3			-			3			3			6
Capitalization of non-recoverable gas costs		(5	)		-			(1	)		-			-			-			(4	)
Net MTM losses		3			-			-			-			3			3			-
Other		1			1			1			-			1			1			(1	)
Net change in natural gas margin	$	20		$	1		$	4		$	-		$	5		$	5		$	11
Nine Months
Electric revenue change:
Effect of weather (estimate)	$	(31	)	$	(19	)	$	(2	)	$	-		$	(4	)	$	(4	)	$	(6	)
Regulated rates:
Changes in base rates		193			108			17			-			(2	)		(2	)		70
Noranda sales		(42	)		(42	)		-			-			-			-			-
Illinois pass-through power costs		(184	)		-			(41	)		-			(57	)		(57	)		(86	)
Merchant Generation sales price changes		101			-			-			119			52			52			-
Off-system revenues		(116	)		(116	)		-			-			-			-			-
Illinois electric settlement agreement, net of reimbursement		11			-			1			5			3			3			2
Net MTM losses		(62	)		(5	)		-			-			-			-			-
Generation output, load and other		(225	)		(36	)		(6	)		(136	)		(28	)		(28	)		(14	)
Total electric revenue change	$	(355	)	$	(110	)	$	(31	)	$	(12	)	$	(36	)	$	(36	)	$	(34	)
Fuel and purchased power change:
Fuel:
Generation and other	$	32		$	13		$	-		$	(10	)	$	8		$	8		$	-
Increased net MTM gains		43			25			-			8			3			3			-
Price		(39	)		-			-			(14	)		(3	)		(3	)		-
Purchased power		72			47			10			-			37			37			12
Illinois pass-through power costs		184			-			41			-			57			57			86
Total fuel and purchased power change	$	292		$	85		$	51		$	(16	)	$	102		$	102		$	98
Net change in electric margin	$	(63	)	$	(25	)	$	20		$	(28	)	$	66		$	66		$	64
Natural gas margin change:
Effect of weather (estimate)	$	(5	)	$	-		$	(1	)	$	-		$	(1	)	$	(1	)	$	(3	)
Changes in base rates		34			-			7			-			(7	)		(7	)		34
Capitalization of non-recoverable gas costs		(5	)		-			(1	)		-			-			-			(4	)
Net MTM losses		3			-			-			-			3			3			-
Other		(14	)		(3	)		(3	)		-			(3	)		(3	)		(6	)
Net change in natural gas margin	$	13		$	(3	)	$	2		$	-		$	(8	)	$	(8	)	$	21

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

Ameren

Ameren’s electric margin increased by $21 million, or 2%, in the third quarter of 2009 compared with the year-ago period, but decreased by $63 million, or 2%, in the nine months ended September 30, 2009, compared with the same period in 2008. Electric margins were unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

Higher net fuel expense at UE (as defined in UE’s FAC) of $56 million for the nine months ended September 30, 2009, although net fuel expense was $8 million lower in the third quarter of 2009.

•

Unfavorable net unrealized MTM activity at the Merchant Generation segment on energy transactions primarily related to nonqualifying hedges of changes in market prices for electricity ($95 million and $57 million, respectively).

•

Higher fuel expense at Genco as a result of its June 2008 settlement agreement with a coal mine owner to receive a lump-sum payment of $60 million for the early termination of a coal supply contract, which compensated Genco, in total, for higher fuel costs it incurred throughout 2008 and is incurring throughout 2009. Because the entire settlement was recorded in earnings in the second quarter of 2008, Ameren’s earnings in the first nine months of 2009 were comparatively lower than they otherwise would have been.

•

Excluding the impact of the June 2008 settlement agreement, Merchant Generation segment fuel prices increased by an additional 4% and 5%, respectively.

•

Reduced sales by UE to Noranda due to an extended severe storm-related outage, which lowered electric revenues ($15 million and $42 million, respectively). See Outlook for further information on the Noranda plant outage.

•

Unfavorable weather conditions, as evidenced by an 18% and 5% decrease in cooling degree-days, respectively ($39 million and $31 million, respectively).

•

Excluding the impact of UE’s reduced sales to Noranda, lower weather-normalized end-use retail sales volumes (5% and 4%, respectively), which were largely a result of the economic slowdown ($11 million and $26 million, respectively).

•

Decreased power plant utilization primarily because of lower market prices resulting in fewer opportunities for economic sales and transmission congestion limiting the period when power could be sold. Ameren’s baseload coal-fired generating plants’ equivalent availability factors were 86% in the first nine months of 2009 and 2008; however, the average capacity factor was 71% in the first nine months of 2009 compared with 77% in the same period in 2008.

•

Reduced Callaway nuclear plant availability due to a 12-day unplanned outage in the first quarter of 2009, which decreased electric margin by $7 million for the nine months ended September 30, 2009.

Ameren’s electric margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

Higher electric rates at UE, effective March 1, 2009 ($55 million and $108 million, respectively) and at the Ameren Illinois Utilities, effective October 1, 2008 ($33 million and $85 million, respectively).

•

Favorable net unrealized MTM activity at UE on energy and fuel-related transactions ($63 million and $20 million, respectively). Margin was favorably impacted during the nine months ended September 30, 2009, because UE reversed and deferred as regulatory assets previously recorded net MTM losses of $42 million on energy and fuel-related transactions in the first quarter of 2009 when these costs became probable of recovery because of the FAC. See Note 6 - Derivative Financial Instruments under Part I, Item I, of this report, for additional information.

•

Favorable net unrealized MTM activity at the Merchant Generation segment on fuel-related transactions primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts through 2012 ($43 million and $12 million, respectively).

•

The repricing of wholesale and retail electric power supply agreements and financial swaps settling at higher margins at Merchant Generation.

•

Higher UE wholesale sales margins because of additional customers and higher-priced wholesale sales contracts ($6 million and $16 million, respectively).

•

The recovery of power supply costs incurred by the Ameren Illinois Utilities, including an increase in Supply Cost Adjustment (SCA) factors as approved in the 2008 ICC electric rate order ($1 million and $10 million, respectively).

•

The reduced impact of the Illinois electric settlement agreement ($3 million and $11 million, respectively).

Ameren’s gas margin increased by $20 million, or 34%, and $13 million, or 4%, in the three and nine months ended September 30, 2009, compared with the same periods in 2008. Gas margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

The Ameren Illinois Utilities’ net gas delivery service rate increase, effective October 1, 2008 ($9 million and $34 million, respectively).

•

The redesigned seasonal gas delivery service rates at the Ameren Illinois Utilities, effective October 1, 2008 ($12 million in the three months ended September 30, 2009). These redesigned delivery service rates impact quarterly earnings comparisons but are not expected to materially impact annual margin.

•

The absence of net unrealized MTM losses at CILCO in 2009 on natural gas swaps ($3 million and $3 million, respectively).

Ameren’s gas margins were unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

Unfavorable weather conditions, as evidenced by a 7% reduction in heating degree-days that decreased margin by $5 million in the nine months ended September 30, 2009.

•

10% lower weather-normalized sales volumes, largely a result of the economic slowdown, that decreased margin by $10 million in the nine months ended September 30, 2009.

•

The absence of non-recoverable purchased gas costs that were capitalized in accordance with the September 2008 ICC gas rate order, resulting in a one-time increase in margin of $5 million in the three and nine months ended September 30, 2008.

Missouri Regulated (UE)

UE’s electric margin increased by $66 million, or 12%, in the third quarter of 2009 compared with the year-ago period, but decreased by $25 million, or 2%, in the nine months ended September 30, 2009, compared with the same period in 2008. UE’s electric margin was unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

Higher net fuel expense at UE (as defined in UE’s FAC) of $56 million for the nine months ended September 30, 2009, although net fuel expense was $8 million lower in the third quarter of 2009.

•

Reduced sales to Noranda due to an extended severe storm-related outage, which lowered electric revenues ($15 million and $42 million, respectively). See Outlook for further information on the Noranda plant outage.

•

Unfavorable weather conditions, due to a mild winter and a 13% decrease in cooling degree-days in the third quarter of 2009 ($25 million and $19 million, respectively).

•

Excluding the impact of UE’s reduced sales to Noranda, lower weather-normalized end-use retail sales volumes (4% and 3%, respectively), largely a result of the economic slowdown ($12 million and $24 million, respectively).

•

Reduced Callaway nuclear plant availability due to a 12-day unplanned outage in the first quarter of 2009, which decreased electric margin by $7 million for the nine months ended September 30, 2009.

UE’s electric margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

Higher electric rates, effective March 1, 2009 ($55 million and $108 million, respectively).

•

Favorable net unrealized MTM activity at UE on energy and fuel-related transactions ($63 million and $20 million, respectively). Electric margin was favorably impacted during the nine months ended September 30, 2009, because UE reversed and deferred as regulatory assets previously recorded net MTM losses of $42 million on energy and fuel-related transactions in the first quarter of 2009 when these costs became probable of recovery because of the FAC. See Note 6 - Derivative Financial Instruments under Part I, Item I, of this report, for additional information.

•

Higher wholesale sales margin due to additional customers and higher-priced wholesale sales contracts ($6 million and $16 million, respectively).

UE’s gas margin increased by $1 million, or 10%, in the third quarter of 2009 compared with the year-ago period but decreased by $3 million, or 5%, in the nine months ended September 30, 2009, compared with the same period in 2008. The decrease in gas margin was primarily because of a 7% decrease in weather-normalized sales volumes for the nine months ended September 30, 2009.

Illinois Regulated

Illinois Regulated’s electric margin increased by $26 million, or 11%, and $76 million, or 13%, in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008. Illinois Regulated’s gas margin increased by $19 million, or 38%, and $13 million, or 5%, in the three and nine months ended September 30, 2009, compared with the year-ago periods.

CIPS

CIPS’ electric margin increased by $10 million, or 14%, and $20 million, or 10%, in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008. Electric margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

Higher electric delivery service rates, effective October 1, 2008 ($7 million and $17 million, respectively).

•

The recovery of power supply costs incurred, including an increase in the SCA factors as approved in the 2008 ICC electric rate order ($3 million in the nine months ended September 30, 2009).

•

The reduced impact of the Illinois electric settlement agreement ($1 million in the nine months ended September 30, 2009).

CIPS’ electric margin was unfavorably impacted in the three and nine months ended September 30, 2009, as compared to the year-ago periods, by:

•

Lower net transmission margin primarily related to reduced transmission service rates that were based on lower transmission costs in the prior year ($1 million and $5 million, respectively).

•

Unfavorable weather as evidenced by a 19% and 5% decrease in cooling degree-days, respectively ($3 million and $2 million, respectively).

CIPS’ gas margin increased by $4 million, or 33%, and $2 million, or 4%, in the three and nine months ended September 30, 2009, compared with the year-ago periods. Gas margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

The redesigned seasonal gas delivery service rates, effective October 1, 2008 ($3 million for the three months ended September 30, 2009). The redesigned delivery service rates have an impact on quarterly earnings comparisons but are not expected to materially impact annual margin.

•

The gas delivery service rate increase, effective October 1, 2008, which increased gas margin ($1 million and $7 million, respectively.)

CIPS’ gas margin was unfavorably impacted in the three and nine months ended September 30, 2009, (except where a specific period is referenced) compared to year-ago periods by:

•

The absence of non-recoverable purchased gas costs that were capitalized in accordance with the September 2008 ICC gas rate order, resulting in a one-time increase in margin of $1 million in the three and nine months ended September 30, 2008.

•

Unfavorable weather conditions, as evidenced by an 8% reduction in heating degree-days, decreased margin by $1 million during the nine months ended September 30, 2009.

•

4% lower weather-normalized sales volumes for the first nine months of 2009, largely a result of the economic slowdown, which decreased margin by $1 million.

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 in the three and nine months ended September 30, 2009, as compared with the same periods in 2008:


	Three Months			Nine Months
CILCO (Illinois Regulated)	$	(5	)	$	(7	)
CILCO (AERG)		22			73
Total change in electric margin	$	17		$	66

CILCO’s (Illinois Regulated) electric margin decreased by $5 million, or 11%, and $7 million, or 6%, in the three and nine months ended September 30, 2009, compared with the year-ago periods. CILCO’s (Illinois Regulated) electric margin was unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

Lower electric delivery service rates, effective October 1, 2008 ($2 million in the nine months ended September 30, 2009).

•

Unfavorable weather conditions as evidenced by a 34% and 24% decrease in cooling degree-days, respectively ($4 million and $4 million, respectively).

•

11% lower weather-normalized sales volumes primarily in the lower-margin industrial customer sector, largely a result of the economic slowdown ($1 million for the nine months ended September 30, 2009).

CILCO’s (Illinois Regulated) electric margin was favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared with year-ago periods by:

•

The recovery of power supply costs incurred, including an increase in the SCA factors as approved in the 2008 ICC electric rate order of $1 million in the nine months ended September 30, 2009.

•

The reduced impact of the Illinois electric settlement agreement of $1 million for the nine months ended September 30, 2009.

See Merchant Generation below for an explanation of CILCO’s (AERG) change in electric margin in the three and nine months ended September 30, 2009, as compared with the same periods in 2008.

CILCO’s (Illinois Regulated) gas margin increased by $5 million, or 42%, in the third quarter of 2009 compared with the year-ago period but decreased by $8 million, or 12%, in the nine months ended September 30, 2009, compared with the same period in 2008. CILCO’s gas margins were unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

Lower gas delivery service rates, effective October 1, 2008 ($2 million and $7 million, respectively).

•

Unfavorable weather conditions, as evidenced by a 4% reduction in heating degree-days that decreased margin by $1 million during the nine months ended September 30, 2009.

•

16% lower weather-normalized sales volumes for the first nine months of 2009, largely a result of the economic slowdown (less than $1 million in the nine months ended September 30, 2009).

CILCO’s gas margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared with year-ago periods by:

•

The absence of net realized MTM losses at CILCO in 2009 on natural gas swaps ($3 million and $3 million, respectively).

•

The redesigned seasonal gas delivery service rates, effective October 1, 2008 ($3 million for the three months ended September 30, 2009). These redesigned delivery service rates have an impact on quarterly earnings comparisons but are not expected to materially impact annual margin.

IP’s electric margin increased by $22 million, or 19%, and $64 million, or 21%, in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008. IP’s electric margin was favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

Higher electric delivery service rates, effective October 1, 2008 ($27 million and $70 million, respectively).

•

The reduced impact of MISO settlements in the prior year ($6 million and $4 million, respectively).

•

The recovery of power supply costs incurred, including an increase in the SCA factors as approved in the 2008 ICC electric rate order ($1 million and $6 million, respectively).

•

The reduced impact of the Illinois electric settlement agreement ($1 million and $2 million, respectively).

IP’s electric margin was unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

7% and 6%, respectively, lower weather-normalized sales volumes, largely a result of the economic slowdown, primarily in the lower-margin industrial customer sector ($7 million and $8 million, respectively).

•

Unfavorable weather conditions, as evidenced by a 22% and 10% decrease in cooling degree-days, respectively ($7 million and $6 million, respectively).

IP’s gas margin increased by $11 million, or 41%, and $21 million, or 18%, in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008. IP’s gas margins were favorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to year-ago periods, by:

•

Higher gas delivery service rates, effective October 1, 2008 ($10 million and $34 million, respectively).

•

The redesigned seasonal gas delivery service rates, effective October 1, 2008, ($6 million for the three months ended September 30, 2009). These redesigned delivery service rates have an impact on quarterly earnings comparisons but are not expected to materially impact annual margin.

IP’s gas margin was unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

8% lower weather-normalized sales volumes, largely a result of the economic slowdown, that reduced margin by $5 million in the nine months ended September 30, 2009.

•

Unfavorable weather conditions, as evidenced by a 6% reduction in heating degree-days that decreased margin by $3 million in the nine months ended September 30, 2009.

•

The absence of non-recoverable purchased gas costs that were capitalized in accordance with the September 2008 ICC gas rate order, resulting in a one-time increase in margin of $4 million in the three and nine months ended September 30, 2008.

Merchant Generation

Merchant Generation’s electric margin decreased by $91 million, or 29%, and $141 million, or 15%, in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008.

Genco

Genco’s electric margin increased by $26 million, or 24%, in the third quarter of 2009 compared with the year-ago period, but decreased by $28 million, or 6%, in the nine months ended September 30, 2009, compared with the same period in 2008. Genco’s electric margin was unfavorably impacted in the three and nine months ended September 30, 2009 (except where a specific period is referenced), as compared to the year-ago periods, by:

•

Higher fuel expense as a result of Genco’s June 2008 settlement agreement with a coal mine owner to receive a lump-sum payment of $60 million for the early termination of a coal supply contract, which compensated Genco, in total, for higher fuel costs it incurred throughout 2008 and is incurring throughout 2009. Because the entire settlement was recorded in earnings in the second quarter of 2008, Genco’s earnings in the first nine months of 2009 were comparatively lower than they otherwise would have been.

•

Excluding the impact of the June 2008 settlement agreement, Genco’s fuel prices increased 2% for the nine months ended September 30, 2009.

•

Lower revenues allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company due to lower reimbursable expenses in accordance with the Genco PSA, partially offset by financial swaps settling at higher margins and new higher-priced wholesale and retail electric power supply agreements.

•

Decreased power plant utilization primarily due to lower market prices resulting in fewer opportunities for economic sales and transmission congestion limiting the period when power could be sold. In addition, one of Genco’s coal-fired power plants experienced a transformer fire in September 2009 resulting in two units being out of service for a period of time. This contributed to a reduction in Genco’s baseload coal-fired generating plants’ equivalent availability factor to 81% in the third quarter of 2009 compared with 87% in the same period in 2008. Genco’s average capacity factor also decreased to 59% in the third quarter of 2009 compared with 75% in the comparable period in 2008. Genco’s baseload coal-fired generating plants’ equivalent availability factor was 85% in the first nine months of 2009 compared with 83% in the same period in 2008; however, the average capacity factor was 61% in the first nine months of 2009 compared with 72% in the same period in 2008.

Genco’s electric margin was favorably impacted in the three and nine months ended September 30, 2009, as compared to the year-ago periods, by:

•

Favorable net unrealized MTM activity on fuel-related transactions primarily relating to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts through 2012 ($29 million and $8 million, respectively).

•

Lower emission allowance costs due to lower prices and reduced generation ($2 million and $7 million, respectively).

•

The reduced impact of the Illinois electric settlement agreement ($1 million and $5 million, respectively).

CILCO (AERG)

AERG’s electric margin increased by $22 million, or 36%, and $73 million, or 45%, in the three and nine months ended September 30, 2009, respectively, compared with the same period in 2008. AERG’s electric margin was favorably impacted in the three and nine months ended September 30, 2009, as compared to the year-ago periods, by:

•

Higher revenues allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company due to financial swaps settling at higher margins and new higher-priced wholesale and retail electric power supply agreements.

•

Favorable net unrealized MTM activity on fuel-related transactions primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts through 2012 ($7 million and $3 million, respectively).

•

Lower oil consumption resulting from fewer plant start-ups and lower prices in 2009 ($2 million and $3 million, respectively).

•

The reduced impact of the Illinois electric settlement agreement ($1 million and $2 million, respectively).

AERG’s electric margin was unfavorably impacted in the three and nine months ended September 30, 2009, as compared to the year-ago periods, by decreased power plant availability due, in part, to a planned plant outage and lower market prices. AERG’s baseload coal-fired generating plants’ equivalent availability and average capacity factors were 75% and 67%, respectively, in the first nine months of 2009, compared with 79% and 72%, respectively, in the same period in 2008.

Other Merchant Generation

Electric margin from Ameren’s other Merchant Generation operations, primarily from EEI and Marketing Company, decreased by $139 million, or 94%, and $186 million, or 64%, in the three and nine months ended September 30, 2009, respectively. Other Merchant Generation electric margins were unfavorably impacted, as compared with the year-ago periods, by:

•

The impact of the economic slowdown, which lowered power demand and sales prices. The average sales price for power decreased by 29% and 23%, respectively.

•

Unfavorable net unrealized MTM activity (mostly at Marketing Company) on energy and fuel-related transactions primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts through 2012 and that related to nonqualifying hedges of changes in market prices for electricity ($86 million and $56 million, respectively).

•

Higher fuel prices at EEI (27% and 23%, respectively) due to an increase in transportation costs.

•

Decreased power plant utilization due primarily to plant outages. EEI’s baseload coal-fired generating plant’s equivalent availability and average capacity factors were 84% and 77%, respectively, in the first nine months of 2009, compared with 90% and 89%, respectively, in the same period in 2008.

100

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren

Three months - Other operations and maintenance expenses decreased $34 million. Bad debt expense declined $26 million primarily as a result of the impact of the Illinois bad debt rate adjustment mechanism that became effective in July 2009 (see Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for further information). Additionally, other operations and maintenance expenses decreased $14 million because of a favorable change in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans. Reducing the benefit of these items were severance costs of $17.5 million for employee separation programs recognized in the third quarter of 2009. See Note 1 - Summary of Significant Accounting Policies under Part 1, Item 1, of this report for additional information.

Nine months - Other operations and maintenance expenses decreased $67 million primarily because of reductions in plant maintenance costs of $52 million, reduced bad debt expense of $39 million, including the impact of the Illinois bad debt rate adjustment mechanism, a $25 million favorable change in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans, and lower injuries and damages expenses of $14 million. Reducing the benefit of these items were employee severance costs of $17.5 million recognized in 2009, as noted above, higher labor costs of $17 million and increased storm repair expenditures of $10 million. In the second quarter of 2009, a $5 million charge was incurred for the termination of a heavy forgings contract associated with efforts to build a new nuclear unit at UE’s Callaway nuclear power plant. Also in the second quarter of 2009, $5 million of expense was recognized for the termination of a rail line extension project at a subsidiary of Genco. In the second quarter of 2008, other operations and maintenance expenses were reduced by a MoPSC accounting order, which resulted in UE recording a regulatory asset of $13 million for costs related to 2007 storms that had previously been expensed; no similar item occurred in 2009.

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 and nine months ended September 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

Three months - Other operations and maintenance expenses decreased $5 million primarily because of a favorable change in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans, and reduced plant maintenance costs. Reducing the benefit of these items were severance costs for employee separation programs recognized in 2009, as discussed above.

Nine months - Other operations and maintenance expenses decreased $24 million primarily because of lower plant maintenance costs, reduced employee benefit costs, lower injuries and damages expenses, and a favorable change in unrealized net MTM adjustments between periods, resulting from changes in the market value of investments used to support Ameren’s deferred compensation plans. Reducing the benefit of these items were employee severance costs in 2009, higher labor costs, the charge incurred for the termination of the heavy forgings contract, and the absence of the MoPSC storm cost accounting order, as occurred in the prior year, which reduced other operations and maintenance expenses as described above. Additionally, storm repair expenditures were higher in the first nine months of 2009 as a result of ice storms at the beginning of the year.

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Illinois Regulated

Three and nine months - Other operations and maintenance expenses decreased $37 million and $56 million, respectively, in the Illinois Regulated segment as discussed below.

CIPS

Three and nine months - Other operations and maintenance expenses decreased $9 million in both periods primarily because of reduced bad debt expense, including the impact of the Illinois bad debt rate adjustment mechanism. Increased storm repair expenditures mitigated this benefit in the nine-month period.

CILCO (Illinois Regulated)

Three and nine months - Other operations and maintenance expenses increased $16 million and $53 million, respectively, primarily because of higher labor and employee benefit costs. These increases were primarily a result of work performed on behalf of CIPS and IP as discussed below.

At the beginning of 2009, approximately 570 employees were transferred from Ameren Services to CILCO (Illinois Regulated), which resulted in an increase in other operations and maintenance expenses at CILCO (Illinois Regulated) in the 2009 periods. These CILCO (Illinois Regulated) employees also provide support services to CIPS and IP. CILCO (Illinois Regulated) records reimbursements from CIPS and IP for work performed by its employees on their behalf as Operating Revenues - Support Services - Affiliates on its statement of income, which increased $19 million and $53 million in the three and nine months ended September 30, 2009, respectively. Intercompany revenue and expenses associated with these transactions are eliminated in consolidation within the Illinois Regulated segment. See Note 8 - Related Party Transactions to our financial statements under Part I, Item 1, of this report for further information on CILCO (Illinois Regulated) support services.

Reducing the unfavorable effect of the above items in both periods was a reduction in bad debt expense, including the impact of the Illinois bad debt rate adjustment mechanism.

Three and nine months - Other operations and maintenance expenses decreased $23 million and $33 million, respectively, because of a reduction in bad debt expense, including the impact of the Illinois bad debt rate adjustment mechanism.

Merchant Generation

Three and nine months - Other operations and maintenance expenses increased $7 million in the Merchant Generation segment in the third quarter of 2009 compared with the third quarter of 2008, as discussed below. Other operations and maintenance expenses were comparable in the first nine months of 2009 with the same period in 2008.

Genco

Three months - Other operations and maintenance expenses increased $6 million primarily because of employee severance costs in 2009, as discussed above.

Nine months - Other operations and maintenance expenses decreased $6 million primarily because of lower plant maintenance costs. Employee severance costs recognized in the third quarter of 2009 and expenses recognized in the second quarter of 2009 for termination of the rail line extension project, as noted above, mitigated these benefits.

102

CILCO (AERG)

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

Nine months - Other operations and maintenance expenses decreased $5 million primarily because of lower plant maintenance costs.

EEI

Three and nine months - Other operations and maintenance expenses increased $3 million and $8 million, respectively, primarily because of higher plant maintenance costs.

CILCORP (parent company only)

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

Goodwill Impairment Loss

In the first quarter of 2009, CILCORP recognized a non-cash goodwill impairment charge of $462 million. See Note 14 - Goodwill Impairment under Part I, Item 1, of this report for additional information.

Depreciation and Amortization

Ameren

Ameren’s depreciation and amortization expenses increased $12 million and $28 million in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008, because of items noted below at the Ameren Companies.

Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

Three and nine months - Depreciation and amortization expenses increased $7 million and $20 million, respectively, primarily because of capital additions.

Illinois Regulated

Three and nine months - Depreciation and amortization expenses were comparable in the Illinois Regulated segment in the third quarter of 2009 with the third quarter of 2008. Depreciation and amortization expenses decreased $3 million in the first nine months of 2009 compared with the same period in 2008. As part of the consolidated electric and natural gas rate order issued by the ICC in September 2008, the ICC changed plant asset useful lives, effective October 1, 2008, which resulted in reductions in depreciation expense at CIPS and CILCO (Illinois Regulated) and an increase in depreciation expense at IP. Capital additions partially offset the benefit of the rate order at CIPS and CILCO (Illinois Regulated) and further increased depreciation and amortization expenses at IP. The net effect of the above items was a reduction in depreciation and amortization expenses at CILCO (Illinois Regulated) of $5 million and $17 million and an increase at IP of $3 million and $12 million in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008. Depreciation and amortization expenses at CIPS were comparable between periods.

Merchant Generation

Three and nine months - Depreciation and amortization expenses increased $7 million and $12 million, respectively, in the Merchant Generation segment primarily because of capital additions at CILCO (AERG) and $3 million of expense recorded by Genco in the third quarter of 2009 for the retirement of two generation units at its Meredosia power plant. Depreciation and amortization expenses were comparable at CILCORP (parent company only) and EEI between periods.

103

Taxes Other Than Income Taxes

Ameren

Ameren’s taxes other than income taxes increased $6 million and $11 million in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008, primarily because of higher property taxes. Higher payroll taxes also contributed to the increase in taxes other than income taxes in the nine-month period.

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 and nine months ended September 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

Three and nine months - Taxes other than income taxes increased $3 million and $11 million, respectively, primarily because of higher property taxes. Higher payroll taxes also contributed to the increase in taxes other than income taxes in the nine-month period.

Illinois Regulated

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

Merchant Generation

Three and nine months - Taxes other than income taxes were comparable between periods in the Merchant Generation segment and at Genco, CILCO (AERG), CILCORP (parent company only), and EEI.

Other Income and Expenses

Ameren

Other income and expenses were comparable in the three and nine months ended September 30, 2009, with the same periods in 2008. Miscellaneous expense decreased as expenses associated with energy efficiency and customer assistance programs under the Illinois electric settlement agreement were lower in the current year periods. Additionally, in the third quarter of 2008, Ameren made a contribution to its charitable trust, with no similar contribution in 2009. However, miscellaneous income declined because of reduced interest income, mitigating the above benefits.

Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

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

Illinois Regulated

Three and nine months - Other income and expenses were comparable in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated), and IP in the third quarter of 2009 with the same period in 2008. Other income and expenses decreased $7 million in the Illinois Regulated segment, and decreased at both CIPS and IP, in the nine months ended September 30, 2009, compared with the same period in 2008, primarily because of lower interest income. Other income and expenses at CILCO (Illinois Regulated) were comparable in the nine-month periods of the current and prior years.

104

Merchant Generation

Three and nine months - Other income and expenses were comparable between periods in the Merchant Generation segment and at Genco, CILCO (AERG), CILCORP (parent company only), and EEI.

Interest

Ameren

Ameren’s interest expense increased $21 million and $45 million in the three and nine months ended September 30, 2009, respectively, compared with the same periods in 2008, because of items noted below at the Ameren Companies.

Variations in interest expense in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

Three months - Interest expense increased $10 million primarily because of the issuance of $350 million of senior secured notes in March 2009 and fees recognized for new credit facilities entered into in the second quarter of 2009.

Nine months - Interest expense increased $29 million. Interest expense increased primarily because of the issuance of $350 million, $450 million and $250 million of senior secured notes in March 2009, June 2008 and April 2008, respectively. The recognition of fees related to new credit facilities entered into in the second quarter of 2009 also increased interest expense. Additionally, interest expense increased in the first nine months of 2009, as compared with the prior-year period, because of favorable income tax settlements in the first quarter of 2008. The maturity of $148 million of first mortgage bonds in May 2008 and refinancing of auction rate environmental improvement revenue bonds in the 2008 period mitigated the impact of the above items.

Illinois Regulated

Three and nine months - Interest expense increased $3 million and $12 million, respectively, in the Illinois Regulated segment as discussed below.

CIPS

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

CILCO (Illinois Regulated)

Three and nine months - Interest expense increased $3 million and $7 million, respectively, primarily because of the issuance of senior secured notes of $150 million in December 2008, at a higher rate than the short-term debt it refinanced.

Three months - Interest expense was comparable between periods.

Nine months - Interest expense increased $4 million primarily because of the issuance of senior secured notes of $400 million and $337 million in October 2008 and April 2008, respectively. The unfavorable effect of the debt issuances was mitigated as the proceeds from the senior secured notes were used to refinance auction-rate pollution control revenue refunding bonds, which bore default rates ranging from 12% to 18%, and to reduce short-term borrowings.

Merchant Generation

Three and nine months - Interest expense increased $10 million and $8 million, respectively, in the Merchant Generation segment as discussed below.

105

Genco

Three months - Interest expense was comparable between periods.

Nine months - Interest expense increased $3 million primarily because of the issuance of $300 million of senior unsecured notes in April 2008, reduced by lower short-term borrowings.

CILCO (AERG)

Three and nine months - Interest expense increased $6 million in both the quarter and year-to-date periods primarily because of increased intercompany borrowings.

CILCORP (parent company only) and EEI

Three and nine months - Interest expense was comparable between periods at CILCORP (parent company only) and EEI.

Income Taxes

Ameren

Three months - Ameren’s effective tax rate in the third quarter of 2009 was higher than the effective tax rate for the same period in the prior year, due to variations discussed below.

Nine months - Ameren’s effective tax rate in the first nine months of 2009 was lower 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 and nine months ended September 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

Three and nine months - The effective tax rate in both periods was lower primarily because of higher favorable net amortization of property-related regulatory assets and liabilities.

Illinois Regulated

The effective tax rate for the third quarter and first nine months of 2009 was higher than the effective tax rate for the same periods in 2008 in the Illinois Regulated segment because of items detailed below.

CIPS

Three and nine months - The effective tax rate in both periods was higher primarily because of the decreased impact of net amortization of property-related regulatory assets and liabilities, investment tax credit amortization, and permanent items on higher pretax book income.

CILCO (Illinois Regulated)

Three months - The effective tax rate was higher primarily because of the decreased impact of permanent items, net amortization of property-related regulatory assets and liabilities, and amortization of investment tax credit on higher pretax book income.

Nine months - The effective tax rate was lower primarily because of the increased impact of permanent benefits from company-owned life insurance.

Three months - The effective tax rate was higher primarily because of the impact of permanent items and the net amortization of property-related regulatory assets and liabilities on higher pretax book income.

Nine months - The effective tax rate was lower primarily because of the impact of permanent items and the net amortization of property-related regulatory assets and liabilities on pretax book income during the 2009 period as compared to a pretax book loss in the same period in 2008.

106

Merchant Generation

The effective tax rate for the third quarter and first nine months of 2009 was higher than the effective tax rate for the same periods in 2008 in the Merchant Generation segment because of items detailed below.

Genco

Three and nine months - The effective tax rate in both periods was higher primarily because of the impact of production activity deductions, along with changes to reserves for uncertain tax positions.

CILCO (AERG)

Three and nine months - The effective tax rate was lower primarily because of the increased impact of production activity deductions.

CILCORP (parent company only)

Three months - The effective tax rate was lower primarily because of the effect of permanent items on lower pretax book income.

Nine months - The effective tax rate was lower primarily because of the effect of the goodwill impairment loss of $462 million, which was a permanent item, on a pretax book loss.

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 natural 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, the 2008 Illinois RFP process for energy and capacity that was used pursuant to the Illinois electric settlement agreement, and the 2009 RFP process for capacity and energy administered by the IPA. 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 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, 2009, for Genco, CILCORP, and CILCO. 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 natural gas utility infrastructure to improve overall system reliability. Ameren intends to finance those capital expenditures and investments with a blend of equity and debt so that it maintains a capital structure in its rate-regulated businesses containing approximately 50% to 55% equity. We expect to make equity issuances in the future consistent with this objective, as well as to address any unanticipated events, should the need arise. We plan to implement our long-term financing plans for debt, equity or equity-linked securities in order to appropriately finance our operations, meet scheduled debt maturities and maintain financial strength and flexibility.

107

In 2008, the global capital and credit markets experienced extreme volatility, which continued into 2009. See Outlook for a discussion of the implications of this volatility for our industry as a whole, including the Ameren Companies, and how we addressed these issues.

The following table presents net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2009 and 2008:


	Net Cash Provided By Operating Activities							Net Cash (Used In) Investing Activities									Net Cash Provided By (Used In) Financing Activities
	2009		2008		Variance			2009			2008			Variance			2009			2008			Variance
Ameren^(a)	$	1,746	$	1,253	$	493		$	(1,345	)	$	(1,501	)	$	156		$	70		$	99		$	(29	)
UE		680		555		125			(705	)		(794	)		89			254			54			200
CIPS		160		80		80			(41	)		(26	)		(15	)		(110	)		(66	)		(44	)
Genco		208		209		(1	)		(218	)		(230	)		12			11			21			(10	)
CILCORP		201		108		93			(127	)		(222	)		95			37			108			(71	)
CILCO		211		120		91			(128	)		(221	)		93			28			95			(67	)
IP		351		120		231			(83	)		(139	)		56			(140	)		25			(165	)

(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 2009 compared with the first nine months of 2008. Operating activities associated with the December 2005 Taum Sauk incident resulted in a $204 million increase in cash during the first nine months of 2009, compared with the same period in 2008. The 2009 increase was a result of a $78 million increase in insurance recoveries received as well as a $126 million reduction in cash payments compared with the prior-year period. See Note 9 - Commitments and Contingencies under Part I, Item I, of this report for information about the Taum Sauk property insurance settlement agreement with all but three of the property insurance carriers and the related settlement payment received during the three months ended September 30, 2009. Other factors contributing to the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included a $189 million decrease in the cost of natural gas purchased for inventories because of lower prices, a decrease in income tax payments, net of refunds, of $146 million, a $66 million net reduction in collateral posted with suppliers due in part to improved credit ratings, an increase in electric costs over-recovered from Illinois customers under cost recovery mechanisms, and a $31 million increase in customer advances for construction. Factors reducing the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included lower electric margins as discussed in Results of Operations, a $38 million increase in interest payments, a $16 million increase in pension and postretirement plan contributions, a $15 million increase in cash payments for major storm restoration costs, an increase in annual incentive compensation payments, and an $8 million increase in payments to a real estate development partnership. The price of natural gas has declined during 2009 compared with the increases experienced during 2008. These pricing fluctuations were the principal cause of the net working capital decrease associated with accounts and wages payable.

108

UE’s cash from operating activities increased in the first nine months of 2009 compared with the first nine months of 2008. The increase was primarily due to a $204 million increase in cash from operating activities associated with the December 2005 Taum Sauk incident as discussed above and a $203 million decrease in income tax payments, net of refunds. Other factors contributing to the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included a $21 million decrease in the cost of natural gas inventories because of lower prices and an increase in gas costs over-recovered from customers under the PGA. Factors reducing the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included the collection of an $85 million affiliate receivable in 2008 that did not occur in 2009, lower electric and natural gas margins as discussed in Results of Operations, a $42 million increase in interest payments, a $7 million increase in major storm restoration costs, and a $7 million increase in pension and other postretirement plan contributions.

CIPS’ cash from operating activities increased in the first nine months of 2009 compared with the first nine months of 2008. Factors contributing to the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included a $34 million decrease in the cost of natural gas purchased for inventories because of lower prices, a $32 million net reduction in collateral posted with suppliers due in part to improved credit ratings, an increase in electric costs over-recovered from customers under cost recovery mechanisms, higher electric margins as discussed in Results of Operations, and a $4 million decrease in interest payments. Further, as discussed in Note 8 - Related Party Transactions under Part 1, Item 1, of this report, in September 2009, CIPS received $5 million from Marketing Company for the costs of upgrades to CIPS’ electric transmission system. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Factors reducing the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included a $17 million increase in income tax payments, net of refunds and a decrease in natural gas costs over-recovered from customers under the PGA.

Genco’s cash from operating activities in the first nine months of 2009 was comparable with the first nine months of 2008. Factors contributing to a decrease in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included lower margins as discussed in Results of Operations, a $24 million increase in income tax payments, net of refunds, and a $7 million increase in interest payments. The 2008 operating cash flows were augmented with the receipt of a $60 million lump-sum payment from a coal mine owner for the early termination of a coal supply contract. Factors offsetting the decrease in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included less cash used for fuel purchases as coal inventory levels increased in 2008 but were held constant in 2009, a favorable change in an affiliate’s accounts receivable balance, and an $8 million reduction in funding required by the Illinois electric settlement agreement.

CILCORP’s and CILCO’s cash from operating activities increased in the first nine months of 2009 compared with the first nine months of 2008. Factors contributing to the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included a $60 million decrease in the cost of natural gas purchased for inventories because of lower prices, a $19 million net reduction in collateral posted with suppliers due in part to improved credit ratings, an increase in natural gas costs over-recovered from customers under the PGA, and higher electric margins as discussed in Results of Operations. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007.

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Factors reducing the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included a $40 million increase in income tax payments, net of refunds, for CILCORP and a $43 million increase for CILCO, more cash used for the purchase of coal as inventory levels increased at AERG because of lower-than-expected output, a $5 million increase in pension and other postretirement plan contributions, and an increase in annual incentive compensation payments.

IP’s cash from operating activities increased in the first nine months of 2009 compared with the first nine months of 2008. Factors contributing to the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included higher electric and natural gas margins as discussed in Results of Operations, a $74 million decrease in the cost of natural gas purchased for inventories because of lower prices, a $42 million net decrease in collateral posted with suppliers due in part to improved credit ratings, and an increase in natural gas cost over-recovered from customers under the PGA. Additionally, more cash was collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Factors reducing the increase in cash from operating activities during the first nine months of 2009, compared with the same period in 2008, included a $34 million increase in income tax payments, net of refunds, and a $13 million increase in interest payments.

Cash Flows from Investing Activities

Ameren’s cash used for investing activities decreased during the first nine months of 2009 compared with the first nine months of 2008. The decrease was primarily driven by a $114 million decrease in nuclear fuel expenditures.

UE’s cash used in investing activities decreased during of the first nine months of 2009, compared with the same period in 2008, principally because of a $114 million decrease in nuclear fuel expenditures. Partially offsetting this decrease was a $43 million increase in capital expenditures primarily as a result of increased storm restoration expenditures and Taum Sauk rebuild expenditures.

CIPS’ cash used in investing activities during the first nine months of 2009 increased compared with the same period in 2008. The $18 million increase in capital expenditures was the result of increased storm restoration expenditures during the 2009 period.

Genco’s cash used in investing activities decreased in the first nine months of 2009 compared with the same period in 2008, principally because of a $13 million decrease in net money pool advances.

CILCORP’s and CILCO’s cash used in investing activities decreased in the first nine months of 2009, compared with the same period in 2008, primarily as a result of a $95 million decrease in capital expenditures because of reduced spending related to a power plant scrubber project at AERG.

IP’s cash used in investing activities decreased in the first nine months of 2009, compared with the same period in 2008, principally as a result of the return of money pool advances.

Capital Expenditures

Ameren has identified approximately $2 billion of opportunities to reduce planned capital spending for 2010 through 2013, as compared to earlier plans. Approximately $1 billion of capital expenditures were eliminated from Merchant Generation’s previous estimates for this period. Ameren’s rate-regulated businesses have identified, and are evaluating for possible elimination or deferral, approximately $1 billion of previously planned capital expenditures.

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The following table provides estimates of capital expenditures that are expected to be incurred by the Ameren Companies from 2009 through 2013, including construction expenditures, capitalized interest for our Merchant Generation business and allowance for funds used during construction for our rate-regulated utility businesses, and estimated expenditures for compliance with environmental standards. Although $2 billion of opportunities have been identified to reduce planned capital spending for 2010 through 2013, the table below only reflects the approximately $1 billion of planned capital expenditures eliminated in the Merchant Generation business.


	2009		2010 - 2013				Total
UE	$	835	$	3,335-	$	4,435	$	4,170-	$	5,270
CIPS		90		350-		475		440-		565
Genco		315		515-		675		830-		990
CILCO (Illinois Regulated)		75		250-		340		325-		415
CILCO (AERG)		70		420-		550		490-		620
IP		220		715-		960		935-		1,180
EEI		50		40-		65		90-		115
Other		60		75-		100		135-		160
Ameren^(a)	$	1,715	$	5,700-	$	7,600	$	7,415-	$	9,315

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

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

We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity or power 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

Ameren’s cash provided by financing activities decreased in the first nine months of 2009 compared with the first nine months of 2008 primarily because of a $674 million increase in short-term debt repayments, a $563 million decrease in proceeds from the issuance of long-term debt, and a $55 million increase in capital issuance costs. During the first nine months of 2009, Ameren issued $775 million of senior debt and used the proceeds to repay short-term borrowings and by way of a capital contribution to CILCORP, permitted CILCORP to repay its outstanding senior notes on their October 15, 2009 due date. Comparatively, during the first nine months of 2008, Ameren’s subsidiaries issued $1.3 billion of senior debt and used the proceeds to repurchase, redeem, and fund maturities of $823 million of long-term debt, reduce short-term debt, and fund capital expenditures and other working capital needs at UE, CIPS, Genco, CILCO, and IP. Ameren’s capital issuance costs increased in the first nine months of 2009 as compared to the prior-year period because of $40 million in banking fees associated with the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement and $17 million of capital issuance costs associated with Ameren’s September 2009 common stock issuance, partially offset by a decrease in capital issuance costs associated with long-term debt. Mitigating the decrease in cash from financing activities was a $573 million decrease in long-term debt redemptions, a $510 million increase in net proceeds from the issuance of common stock, and a $152 million decrease in common stock dividends. In September 2009, Ameren received $552 million in gross proceeds from the issuance of its common stock. The proceeds were used to fund equity contributions to its rate-regulated utility subsidiaries. An additional $65 million of common stock was issued through Ameren’s DRPlus and benefit plans. The decrease in dividends paid on Ameren common stock was the result of the reduction of the quarterly dividend rate.

UE’s net cash provided by financing activities increased in the first nine months of 2009, compared with the same period of the prior year, primarily because of a $436 million capital contribution from Ameren funded by the proceeds of Ameren’s September 2009 common stock issuance, a $378 million decrease in redemptions of long-term debt, and a $23 million decrease in common stock dividend payments. The proceeds from the capital contribution were primarily used to reduce outstanding short-term borrowings.

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These benefits in cash from financing activities were partially offset by a $350 million decrease in long-term debt issuances, a $169 million increase in short-term debt repayments and a $109 million increase in repayments under an intercompany borrowing arrangement with Ameren.

CIPS’ net cash used in financing activities increased during the nine months ended September 30, 2009, compared with the first nine months of 2008. This change was a result of CIPS using existing cash to fund a net reduction in short-term debt and money pool borrowings. Additionally, CIPS paid dividends of $12 million to Ameren in 2009 and had a $3 million increase in debt issuance costs as a result of the banking fees associated with the 2009 Illinois Credit Agreement. Benefiting the 2009 period was a $13 million capital contribution from Ameren.

Genco’s cash provided by financing activities decreased during the nine months ended September 30, 2009, compared with the nine months ended September 30, 2008, primarily as a result of a $300 million decrease in long-term debt issuances. Benefits to cash during the 2009 period included a net $100 million increase in short-term borrowings, compared with net repayments of $100 million during the 2008 period, and an $84 million decrease in common stock dividends.

CILCORP’s cash provided by financing activities decreased during the nine months ended September 30, 2009, compared with the same period in 2008, primarily as a result of the change in CILCORP’s money pool borrowings, a $198 million increase in repayments of short-term borrowings and a $14 million increase in capital issuance costs, as a result of banking fees associated with the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement. During the 2009 period, CILCORP repaid a net $98 million to the money pool compared with net borrowings of $171 million in the 2008 period. Partially offsetting these decreases were increased intercompany borrowings that were used to reduce CILCORP’s short-term debt and outstanding money pool borrowings, compared with the 2008 period, and a $36 million capital contribution received from Ameren in 2009.

CILCO’s cash provided by financing activities decreased during the first nine months of 2009 compared with the year-ago period, primarily as a result of the change in CILCO’s money pool borrowings, $196 million increase in repayments of short-term borrowings, and a $7 million increase in capital issuance costs as a result of banking fees associated with the 2009 Illinois Credit Agreement. During the 2009 period CILCO repaid a net $98 million to the money pool compared with receiving $171 million of net borrowings in the 2008 period. Cash from financing activities benefited from a $334 million increase in intercompany borrowings from Ameren during the first nine months of 2009, a $36 million capital contribution from CILCORP and a $35 million decrease in redemptions of long-term debt and preferred stock.

IP had a net use of cash from financing activities during the first nine months of 2009, compared with a net source of cash during the first nine months of 2008, primarily as a result of a $336 million decrease in long-term debt issuances, a $129 million decrease in net short-term debt borrowings, and a $5 million increase in debt issuance costs. During the 2009 period, these decreases to cash from financing activities were offset by a $141 million decrease in redemptions and maturities of long-term debt, including IP SPT, and a $119 million capital contribution received from Ameren. During 2009, IP used existing cash to fund the current maturity of its 7.50% mortgage bonds and to pay $7 million for banking fees associated with the 2009 Illinois Credit Agreement. Comparatively, during the nine months ended September 30, 2008, IP issued of $337 million of senior secured notes to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds, which had adjusted to higher rates as a result of the collapse of the auction-rate securities market, and to fund debt maturities and common stock dividends.

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Short-term Borrowings and Liquidity

External short-term borrowings typically consist of drawings under committed bank credit facilities. See Note 3 - Short-term Borrowings and Liquidity 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 committed bank credit facilities of Ameren and the Ameren Companies, and their availability, as of September 30, 2009:


Credit Facility	Expiration	Amount Committed		Amount Available
Ameren, UE and Genco:
2009 multiyear revolving^(a)(b)	July 2011	$	1,300	$	874	^(d)
Ameren, CIPS, CILCO and IP:
2009 multiyear revolving^(c)	June 2011		800		800

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

(b)

Includes the 2009 Multiyear Credit Agreement and the Supplemental Agreement. The Supplemental Agreement will terminate in July 2010 with all commitments and all outstanding amounts being consolidated with those under the 2009 Multiyear Credit Agreement and the combined maximum amount available to all borrowers being $1.0795 billion with the UE and Genco Borrowing Sublimits remaining the same and Ameren’s changing to $1.0795 billion. The combined maximum amount available to each borrower under both of the agreements at September 30, 2009, including for the issuance of letters of credit, was limited as follows: Ameren - $1.15 billion, UE - $500 million, and Genco - $150 million.

(c)	The maximum amount available to each borrower under this facility at September 30, 2009, including for the issuance of letters of credit, was limited as follows: Ameren - $300 million, CIPS - $135 million, CILCO - $150 million, and IP - $350 million.

(d)	In addition to amounts drawn on these facilities, the amount available is further reduced by standby letters of credit issued under the facilities. The amount of such letters of credit at September 30, 2009, was $11 million.

On January 21, 2009, Ameren entered into a $20 million term loan agreement due January 20, 2010, which was fully drawn on January 21, 2009. See Note 3 - Short-term Borrowings and Liquidity under Part I, Item I, of this report for additional information.

Since CILCORP and AERG are not borrowers under the 2009 Illinois Credit Agreement, CILCORP and AERG expect to meet their external liquidity needs through borrowings under the Ameren non-state-regulated money pool arrangements or other liquidity arrangements.

In addition to committed credit facilities, a further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents. At September 30, 2009, Ameren (on a consolidated basis), UE, CIPS, Genco, CILCORP (on a consolidated basis), CILCO, and IP had $563 million, $229 million, $9 million, $3 million, $111 million, $111 million, and $178 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, and terminates on 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.

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The Ameren Companies continually evaluate the adequacy and appropriateness of their liquidity arrangements given changing business conditions. When business conditions warrant, changes may be made to existing credit facilities 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 and preferred stock (net of any issuance discounts and including any redemption premiums) for the nine months ended September 30, 2009 and 2008, 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 under Part I, Item 1, of this report.


	Month Issued, Redeemed, Repurchased or Matured	Nine Months
	Month Issued, Redeemed, Repurchased or Matured	2009		2008
Issuances
Long-term debt
Ameren:
8.875% Senior unsecured notes due 2014	May	$	423	$	-
UE:
6.00% Senior secured notes due 2018	April		-		250
6.70% Senior secured notes due 2019	June		-		449
8.45% Senior secured notes due 2039	March		349		-
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		$	772	$	1,335
Common stock
Ameren:
21,850,000 shares at $25.25	September	$	552	$	-
DRPlus and 401(k)	Various		65		107
Total common stock issuances		$	617	$	107
Total Ameren long-term debt and common stock issuances		$	1,389	$	1,442
Redemptions, Repurchases and Maturities
Long-term debt
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:
2004 Series 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
7.50% Series mortgage bond due 2009	June		250		-
Preferred stock
CILCO:
5.83% Series	July	$	-	$	16
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities		$	250	$	839

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The following table presents information with respect to the Form S-3 shelf registration statements filed and effective for certain Ameren Companies as of September 30, 2009:


	Effective Date	Authorized Amount
Ameren^(a)	November 2008	Not Limited
UE^(b)	June 2008	Not Limited
CIPS^(a)	November 2008	Not Limited
Genco^(a)	November 2008	Not Limited
CILCO^(a)	November 2008	Not Limited
IP^(a)	November 2008	Not Limited

(a)	In November 2008, Ameren, as a well-known seasoned issuer, along with CIPS, Genco, CILCO and IP, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in November 2011.

(b)	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 September 2009, Ameren issued and sold 21.9 million shares of its common stock at $25.25 per share, for proceeds of $535 million, net of $17 million of issuance costs. Ameren used the net offering proceeds to make investments in its rate-regulated utility subsidiaries in the form of capital contributions as follows: UE - $436 million, CIPS - $13 million, CILCO - $25 million, and IP - $61 million.

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 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, Ameren issued a total of 0.7 million new shares of common stock valued at $18 million and 2.6 million new shares of common stock valued at $65 million in the three and nine months ended September 30, 2009, respectively.

Ameren, UE, CIPS, Genco, CILCO and IP may sell all or a portion of the 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 3 - Short-term Borrowings and Liquidity under Part I, Item 1, of this report for a discussion of covenants and provisions (and applicable cross-default provisions) contained in the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement. See Note 4 - Short-term Borrowings and Liquidity and Note 5 - Long-term Debt and Equity Financings in the Form 10-K for a discussion of covenants and provisions contained in the Prior $1.15 Billion Credit Facility, the 2009 $20 million term loan agreement and in certain of the Ameren Companies’ indenture agreements and articles of incorporation.

At September 30, 2009, 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 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.

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Dividends

Ameren paid to its stockholders common stock dividends totaling $247 million, or 1.155 cents per share, during the first nine months of 2009 (2008 - $399 million or $1.905 per share).

See Note 4 - Long-term Debt and Equity Financings under Part I, Item 1, of this report and Note 4 - Short-term Borrowings and Liquidity and Note 5 - Long-term Debt and Equity Financings 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, 2009, none of these circumstances existed at the Ameren Companies and, as a result, they were allowed to pay dividends.

UE, CIPS, CILCO, IP and Genco as well as other certain nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, CIPS, CILCO and IP may not pay any dividend on their respective stock, unless, among other things, their respective earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless CIPS, CILCO or IP has specific authorization from the ICC.

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, 2009 and 2008:


	Nine Months
	2009		2008
UE	$	170	$	193
CIPS		12		-
Genco		-		84
IP		-		45
Nonregistrants		65		77
Dividends paid by Ameren	$	247	$	399

Contractual Obligations

For a complete listing of our obligations and commitments, see Other Obligations in Note 9 - Commitments and Contingencies under Part I, Item 1 and Contractual Obligations under Part II, Item 7, of this report, and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K. Also see Note 12 - Retirement Benefits under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.

Subsequent to December 31, 2008, obligations related to the procurement of coal, natural gas, nuclear fuel, methane gas, and electric capacity materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $6,629 million, $3,541 million, $331 million, $681 million, $995 million, $995 million, and $630 million, respectively. Total other obligations, including commitments for the purchase of equipment and the unrecognized tax benefits, at September 30, 2009, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $645 million, $403 million, $23 million, $8 million, $34 million, $34 million, and $122 million, respectively.

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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 customers, including customers of the Ameren Illinois Utilities. Of this $150 million, $60 million will come 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, 2009, of $6 million, $1 million, $1 million, $1 million, $3 million, and $1 million, respectively (quarter ended September 30, 2008 - $10 million, $2 million, less than $1 million, $2 million, $4 million, and $2 million, respectively) and during the nine months ended September 30, 2009, of $18 million, $3 million, $1 million, $4 million, $7 million, and $3 million, respectively (nine months ended September 30, 2008 - $32 million, $5 million, $2 million, $6 million, $13 million, and $6 million, respectively) under the terms of the Illinois electric settlement agreement. At September 30, 2009, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $10 million, $3 million, $2 million, and $5 million, respectively. See Outlook and 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	+
UE:
Issuer/corporate credit rating	Baa2	BBB	-	BBB	+
Secured debt	A3	BBB		A
CIPS:
Issuer/corporate credit rating	Baa3	BBB	-	BBB	-
Secured debt	Baa1	BBB	+	BBB	+
Senior unsecured debt	Baa3	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	Ba1	BB	+	BBB	-
CILCO:
Issuer/corporate credit rating	Baa3	BBB	-	BBB
Secured debt	Baa1	BBB	+	A	-
IP:
Issuer/corporate credit rating	Baa3	BBB	-	BBB	-
Secured debt	Baa1	BBB		BBB	+

Moody’s Ratings Actions

On January 29, 2009, Moody’s affirmed the ratings of CIPS, CILCORP, CILCO and IP and changed their rating outlooks to stable from positive. According to Moody’s, the change in the rating outlooks of these four companies was based on the near-term expiration of the 2007 and 2006 $500 million credit facilities in January 2010 and related liquidity concerns. Moody’s also on January 29, 2009, affirmed the ratings of Ameren and UE with a stable outlook based on the January 2009 MoPSC electric rate order approving a rate increase and a FAC for UE. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report for a discussion of the rate order issued by the MoPSC in January 2009.

On February 16, 2009, Moody’s affirmed the ratings of Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP with a stable outlook. The affirmation reflected Moody’s view that Ameren’s announcement to reduce its common stock dividend by 39% was a conservative, prudent, and credit positive action that will conserve cash and support financial coverage metrics. Moody’s stated that the more conservative dividend payout should also help facilitate the renewal of Ameren Companies’ credit facilities that expire in 2010. They stated the dividend reduction should continue to reduce reliance on the credit facilities going forward and will likely be

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viewed favorably by lenders considering renewing or entering into new facilities with Ameren and its subsidiaries, which is important considering currently constrained credit market conditions. According to Moody’s, the stable outlook on Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP reflected recently constructive rate case outcomes at UE, CIPS, CILCO and IP, including the approval of a FAC at UE; the improving regulatory environments for investor-owned utilities in Illinois and Missouri; and Moody’s expectation that financial and cash flow coverage metrics should remain adequate to maintain current rating levels. In addition, Moody’s noted that the recent dividend reduction is supportive of the stable ratings outlooks and provides Ameren and its subsidiaries additional cushion at current rating levels.

On July 1, 2009, Moody’s stated that the successful execution of new two-year bank credit facilities is supportive of the credit quality of Ameren and its utility subsidiaries. However, Moody’s did not make any changes in Ameren’s or its subsidiaries’ ratings or outlooks as a result of this action.

On August 3, 2009, Moody’s upgraded the majority of senior secured debt ratings of investment-grade regulated utilities by one notch. Senior secured debt ratings at UE were upgraded from Baa1 to A3 and were upgraded at CIPS and IP from Baa3 to Baa2. Moody’s stated the rating action widens the notching between most senior secured debt ratings and senior unsecured debt ratings of investment-grade regulated utilities to two notches from one previously. Moody’s noted the wider notching is based on its analysis of the history of regulated utility defaults, which indicates that regulated utilities have defaulted at a lower rate and experienced lower loss given default rates than nonfinancial, nonutility corporate issuers.

On August 13, 2009, Moody’s upgraded the ratings of CIPS, CILCORP, CILCO and IP. Issuer/corporate credit ratings at CIPS, CILCO and IP were upgraded from Ba1 to Baa3. CILCORP’s senior unsecured debt rating was upgraded from Ba2 to Ba1, and the corporate family rating, probability of default rating, and all loss given default ratings of CILCORP were withdrawn as a result of CILCORP’s return to investment grade rating. Moody’s also upgraded the senior secured debt ratings at CIPS, CILCO and IP from Baa2 to Baa1. Moody’s cited the execution of new bank credit facilities and an improved political and regulatory environment in Illinois as the basis for the return to investment grade status of the issuer/corporate ratings. Moody’s also affirmed the ratings of Ameren, UE and Genco and assigned a stable outlook for Ameren and all of its rated subsidiaries.

S&P Ratings Actions

On February 25, 2009, S&P stated that it viewed the reduction in Ameren’s common stock dividend as credit supportive. S&P did not make any changes in Ameren’s or its subsidiaries’ credit ratings or outlooks as a result of this action. S&P raised the business profile of UE to “excellent” from “strong” to reflect the January 2009 electric rate order issued by the MoPSC, which S&P viewed as constructive. S&P lowered the business profile of CILCO to “satisfactory” from “strong” reflecting S&P’s concerns regarding large capital expenditures needed to meet environmental compliance standards, while relying on falling market prices, due to the economic recession, for recovery.

Fitch Ratings Actions

On February 17, 2009, Fitch stated that the reduction in Ameren’s common stock dividend and other cost-cutting measures will be favorable to bondholders and credit quality. Fitch did not make any changes in Ameren’s or its subsidiaries’ ratings or outlooks as a result of this action.

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On March 9, 2009, Fitch lowered the credit ratings of UE by one notch as follows: issuer rating to BBB+, senior secured debt to A, subordinated debt to BBB+, and preferred stock to BBB+. The rating outlook was changed to stable. Fitch stated that these downgrades were because of deteriorating financial measures over the past several years and the expectation that they will not improve materially without further rate support. They noted the financial deterioration is primarily due to increasing fuel and operating costs and a large capital expenditure program.

On July 31, 2009, Fitch affirmed the credit rating of Genco and changed its rating outlook to negative from stable. Additionally, Fitch affirmed the credit ratings of Ameren with a stable outlook. According to Fitch, the change in the credit rating outlook of Genco was based on the unfavorable outlook for wholesale energy prices and the sensitivity of the company’s largely coal-fired generating fleet to greenhouse gas and other environmental regulations. According to Fitch, the affirmation of Ameren’s credit ratings and stable outlook reflects the significant earnings and cash flow contribution derived from regulated utilities, the beneficial impact of recent rate increases in Illinois and Missouri, the savings generated by the February 2009 dividend reduction, and recent steps taken to maintain liquidity, including the renewal of bank credit facilities.

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 natural gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made with external parties at September 30, 2009, were $49 million, $12 million, $8 million, $3 million, $3 million, and $17 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively. The amount of collateral external counterparties posted with Ameren was $14 million at September 30, 2009. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3” from S&P or Moody’s, respectively) at September 30, 2009, 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 $413 million, $157 million, $26 million, $53 million, $63 million, $63 million, and $45 million, respectively.

In addition, changes in commodity prices could trigger additional collateral postings and prepayments at current credit ratings. If market prices were 15% higher than September 30, 2009, levels in the next twelve months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could be required to post additional collateral or other assurances for certain trade obligations up to approximately $169 million, $88 million, $- million, $- million, $17 million, $17 million, and $- million, respectively. If market prices were 15% lower than September 30, 2009, levels in the next twelve months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could be required to post additional collateral or other assurances for certain trade obligations up to approximately $351 million, $201 million, $12 million, $- million, $82 million, $82 million, and $41 million, respectively.

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.

OUTLOOK

Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2009 and beyond.

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Economy and Capital and Credit Markets

In 2008, global capital and credit markets experienced extreme volatility, which continued into 2009. While these markets have improved during 2009, the availability and cost of capital and economic activity continue to be significantly impacted. We believe that these events have several implications for our industry as a whole, including Ameren. They include the following:

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Access to Capital Markets and Cost of Capital - The extreme disruption in the capital markets limited the ability of many companies, including the Ameren Companies, to freely access the capital and credit markets to support their operations and to refinance debt. Ameren and Ameren’s regulated utilities have continued to have access to the capital markets as evidenced by Ameren’s, CILCO’s, IP’s, and UE’s sale of debt securities in late 2008 and 2009, as well as Ameren’s common stock offering in September 2009. This access has been at commercially acceptable, but higher, rates in the case of the issuance of debt securities. Ameren’s access to the capital markets for its Merchant Generation subsidiaries may be more difficult and costly. Ameren currently plans to issue up to approximately $500 million of debt at its Merchant Generation subsidiaries by the end of 2010.

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Credit Facilities - On June 30, 2009, Ameren and certain of its subsidiaries successfully reached definitive multiyear credit facility agreements. These facilities cumulatively provide $2.1 billion of credit through July 14, 2010, thereafter reducing to $1.8795 billion through June 30, 2011, and thereafter reducing to $1.0795 billion through July 14, 2011. The costs of these credit facilities are significantly higher than the facilities they replaced. The costs to enter into the multiyear credit facility agreements were $40 million in the aggregate (UE - $11 million, CIPS - $3 million, Genco - $4 million, CILCORP - $14 million, CILCO - $7 million, and IP - $7 million). The costs will be amortized over the term of the facilities. In addition, borrowing rates under the facilities increased meaningfully, including, in the case of Ameren, from LIBOR plus 0.5%, under the prior credit facilities, to LIBOR plus 2.75%.

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Economic Conditions - The current weak economic conditions have resulted in weaker power and commodity markets, weaker customer sales growth or sales contraction, particularly with respect to industrial sales, higher financing costs, and the impairment of goodwill at CILCORP, among other things. Weak economic conditions also expose the Ameren Companies to greater risk of default by counterparties, potentially higher bad debt expenses and the risk of possible impairment of goodwill and long-lived assets, among other things. Due to a significant decline in Ameren’s market capitalization, the decline in market prices for electricity, and a decrease in observable industry market multiples, CILCORP’s Illinois Regulated and CILCORP’s Merchant Generation reporting units recorded a non-cash goodwill impairment charge of $462 million, in the aggregate, in the first quarter of 2009. Ameren’s reporting units and IP’s reporting unit did not require an impairment of goodwill in the first quarter of 2009. However, the estimated fair values of Ameren’s Illinois Regulated reporting unit, Ameren’s Merchant Generation reporting unit, and IP’s Illinois Regulated reporting unit exceeded their carrying values by nominal amounts as of March 31, 2009. As a result, the failure in the future of any reporting unit to achieve forecasted operating results and cash flows or a further decline of observable industry market multiples may reduce its estimated fair value below its carrying value and would likely result in the recognition of a goodwill impairment charge. Ameren, CILCORP and IP will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, market prices for electricity and observable industry market multiples of their reporting units for signs of possible declines in estimated fair value and potential goodwill impairment. No triggering events were identified in the third quarter of 2009, and therefore, no interim impairment test was performed. We are unable to predict the ultimate impact of the weak economy on our results of operations, financial position, or liquidity.

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Investment Returns - The disruption in the capital markets, coupled with weak global economic conditions, has adversely affected financial markets. As a result, we experienced lower than assumed investment returns in 2008 in our pension and postretirement benefit plans. These lower returns will increase our future pension and postretirement expenses and pension funding levels. Our future expenses and funding levels will be affected by future investment returns and future discount rate levels. Based on Ameren’s assumptions at December 31, 2008, estimated investment performance through September 30, 2009, and reflecting Ameren’s pension funding policy, Ameren expects to make annual contributions of $100 million to $250 million in each of the next five years. During 2009, the actual return on investment of the pension plan assets was lower than the expected investment return while the actual return on investment of postretirement benefit assets exceeded the expected return.

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Operating and Capital Expenditures - The Ameren Companies will continue to make significant levels of investments and incur expenditures for their electric and natural gas utility infrastructure in order to improve overall system reliability, comply with environmental regulations, and improve plant performance. However, due to the significant level of disruption and uncertainties in the capital and credit markets, we have identified approximately $2 billion of opportunities to reduce Ameren consolidated planned capital expenditures for 2010 through 2013, as compared to earlier plans. In our Merchant Generation business, we have eliminated approximately $1 billion of planned capital expenditures from our previous estimates for this period. In our rate-regulated businesses, we have identified and are evaluating projects that may be eliminated or deferred to help our customers manage their energy costs and further strengthen our financial profile. We are also reviewing planned operations and maintenance expenditures across our organization, but especially in the Merchant Generation business and business support functions. We are managing power plant outages and labor costs, among other things. We expect that actions being taken to address costs in the Merchant Generation segment will result in 2010 nonfuel operations and maintenance expenses that are 5% to 10% lower than 2008 levels. Our rate-regulated businesses are also evaluating opportunities to reduce 2010 nonfuel operations and maintenance expenses to a level that is currently expected to be consistent with their 2008 levels of nonfuel operations and maintenance expenses. Any expenditure control initiatives will be balanced against a 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.

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Liquidity - At September 30, 2009, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under its existing credit facilities, of approximately $2.2 billion, which was approximately $1 billion higher than the same time last year.

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Dividend - In February 2009, Ameren’s board of directors reduced Ameren’s common stock dividend. At the time of the board of directors’ decision, this dividend reduction was consistent with an annual dividend level that would allow Ameren to retain approximately $215 million of cash annually, which would provide incremental funds to enhance reliability to meet our customers’ expectations; satisfy federal and state environmental requirements; reduce our reliance on dilutive equity and high cost debt financings; and enhance our access to the capital and credit markets.

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We believe that our expected operating cash flows, capital expenditures, and related financing plans (including accessing our existing credit facilities) will provide the necessary liquidity to meet our operating, investing, and financing needs for at least the next year. 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

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Between 2009 and 2018, Ameren expects that certain Ameren Companies will be required to invest between $4.0 billion and $5.0 billion, in the aggregate, to retrofit their coal-fired power plants with pollution control equipment in compliance with emissions-related environmental laws and regulations. Any pollution control investments will result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 50% of this investment is expected to be in our Missouri Regulated operations, and it is therefore expected to be recoverable from ratepayers. The recoverability of amounts expended in Merchant Generation operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased environmental costs for coal-fired generators.

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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 to comply with future legislation or regulations would significantly increase future capital expenditures and operations and maintenance expenses.

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UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. UE’s integrated resource plan filed with the MoPSC in February 2008 included the expectation that new baseload generation capacity would be required in the 2018 to 2020 timeframe. Due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE continues to study future plant alternatives, including energy efficiency programs that could help defer new plant construction. In its pending electric rate case filed in July 2009, UE announced several energy efficiency programs. The goal of these recently announced and future UE energy efficiency programs is to reduce electric usage by 540 megawatts by 2025, which is the equivalent of a medium-sized coal-fired power plant.

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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 unit at UE’s existing Callaway County, Missouri nuclear plant site. UE also signed contracts for COLA services. In June 2009, UE requested the NRC suspend the review of the COLA and all activities related to the COLA.

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UE will consider all available and feasible generation options to meet future customer requirements as part of an integrated resource plan that UE is due to file with the MoPSC in 2011.

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UE intends to submit a license extension application with the NRC to extend its existing Callaway nuclear plant’s operating license by 20 years so that the operating license will expire in 2044. UE cannot predict whether or when the NRC will approve the license extension.

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Over the next few years, we expect to make significant investments in our electric and natural 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 expect these costs or investments at our rate-regulated businesses to be ultimately recovered in rates, although regulatory lag could materially impact our cash flows and related financing needs.

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

Revenues

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

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In current and future rate cases, UE, CIPS, CILCO and IP will continue to seek cost recovery and tracking mechanisms from their state regulators to reduce regulatory lag.

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In July 2009, a new law became effective in Illinois that allows electric and natural gas utilities to recover through a rate adjustment the difference between their actual bad debt expense and the bad debt expense included in their rates. The legislation provides utilities the ability to adjust their rates annually through a rate adjustment mechanism that applies to 2008 and subsequent years. During 2008, the Ameren Illinois Utilities incurred approximately $25 million more of bad debt expense (CIPS - $5 million, CILCO - $4 million, and IP - $16 million) than it recovered through rates. In August 2009, the Ameren Illinois Utilities filed with the ICC electric and natural gas rate adjustment clause tariffs to recover bad debt expense not recovered in 2008 and to make corresponding rate adjustments beginning in 2010. The ICC has until February 2010 to approve, or approve as modified, the filed tariffs. Upon ICC approval of the rate adjustment clause tariffs filed in August 2009, the Ameren Illinois Utilities will be required to make a one-time donation of $10 million (CIPS - $3 million, CILCO - $2 million, and IP - $5 million) for customer assistance programs. The amount of the required one-time donation and the impact of the recovery of 2008 bad debt expenses were reflected in earnings during the third quarter of 2009.

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CIPS, CILCO, and IP filed requests with the ICC in June 2009 to increase their annual revenues for electric and natural gas delivery services. The currently pending requests, as amended, seek to increase annual revenues from electric delivery service by $136 million in the aggregate (CIPS - $41 million, CILCO - $22 million, and IP - $73 million). The electric rate increase requests are based on an 11.3% to 11.7% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.4 billion, and a test year ended December 31, 2008, with certain known and

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measurable adjustments through May 2010. The Ameren Illinois Utilities have requested a rider mechanism that would permit all distribution-related costs incurred to implement reliability recommendations submitted to the ICC by the Liberty Consulting Group to be reflected in electric rates outside of general rate proceedings. The Ameren Illinois Utilities estimate that they will incur distribution-related implementation costs of $15 million (CIPS - $5 million, CILCO - $3 million, and IP - $7 million) in 2010. CIPS, CILCO and IP also filed requests with the ICC in June 2009 to increase their annual revenues for natural gas delivery service. The currently pending requests, as amended, seek to increase annual revenues for natural gas delivery service by $26 million in the aggregate (CIPS - $7 million, CILCO - $6 million, and IP - $13 million). The natural gas rate increase requests are based on a 10.8% to 11.2% return on equity, a capital structure composed of 44% to 49% equity, an aggregate rate base for the Ameren Illinois Utilities of $1.0 billion, and a test year ended December 31, 2008, with certain known and measurable adjustments through May 2010. The ICC staff recommended in their testimony filed in September 2009 a net increase in revenues for electric delivery service for the Ameren Illinois Utilities of $49 million in the aggregate (CIPS - $16 million, CILCO - $6 million, and IP - $26 million) and a net decrease in revenues for natural gas delivery service of $4 million in the aggregate (CIPS - $1 million increase, CILCO - $3 million decrease, and IP - $2 million decrease). The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes will take place over a period of up to 11 months, and decisions by the ICC in such proceedings are required by May 2010.

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UE filed a request with the MoPSC in July 2009 to increase its annual revenues for electric service by $402 million. Included in this increase request was approximately $227 million of anticipated increases in normalized net fuel costs in excess of the net fuel costs included in base rates previously authorized by the MoPSC in its January 2009 electric rate order which, absent initiation of this general rate proceeding, would have been eligible for recovery through UE’s existing FAC. The electric rate increase is based on an 11.5% return on equity, a capital structure composed of 47.4% equity, a rate base for UE of $6.0 billion, and a test year ended March 31, 2009, with certain pro-forma adjustments through the anticipated true-up date of January 31, 2010. Following Ameren’s September 2009 common stock issuance, UE received a capital contribution from Ameren of $436 million in September 2009. UE expects to true-up its capital structure in the electric rate case to reflect this capital contribution, among other things. UE’s filing included a request for interim rate relief, which would place into effect approximately $37 million of the requested increase prior to completion of the full rate case. The amount of this interim increase request reflected the increased revenue requirement associated with rate base additions made by UE between October 2008 and May 2009. The MoPSC has scheduled an evidentiary hearing in December 2009 to deliberate UE’s request for interim rate relief. The MoPSC proceeding relating to the proposed electric service rate changes (except for the request for interim rate relief as discussed above) will take place over a period of up to 11 months, and a decision by the MoPSC in such proceeding is required by the end of June 2010.

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As part of its filing, UE also requested the MoPSC to approve the implementation of an environmental cost recovery mechanism and a storm restoration cost tracker as well as the continued use of the FAC that the MoPSC previously authorized in its January 2009 electric rate order. The environmental cost recovery mechanism, if approved, would allow UE to periodically adjust electric rates outside of general rate proceedings to reflect changes in its prudently incurred costs to comply with

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federal, state or local environmental laws, regulations or rules greater than or less than the amount set in base rates. Rate adjustments pursuant to this cost recovery mechanism would not be permitted to exceed an annual amount equal to 2.5% of UE’s gross jurisdictional electric revenues and would be subject to prudency reviews of the MoPSC. The storm restoration cost tracker would permit UE a more timely recovery of storm restoration operations and maintenance expenditures.

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The MoPSC issued an electric rate order in January 2009 approving an increase in annual electric revenues of approximately $162 million. New rates were effective March 1, 2009. In addition, pursuant to the accounting order issued by the MoPSC in April 2008, the rate order concluded that the $25 million of operations and maintenance expenses incurred as a result of a severe ice storm in January 2007 should be amortized and recovered over a five-year period starting March 1, 2009. The MoPSC also allowed recovery of $12 million of costs associated with a March 2007 FERC order that resettled costs among MISO market participants. UE recorded a regulatory asset for these costs at December 31, 2008, which will be amortized and recovered over a two-year period beginning March 1, 2009.

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In the MoPSC electric rate order issued in January 2009, the MoPSC approved UE’s implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism. The FAC allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates, subject to MoPSC prudency review. The vegetation management and infrastructure inspection cost tracking mechanism provides for the tracking of expenditures that are greater or less than amounts provided for in UE’s annual revenues for electric service in a particular year, subject to a 10% limitation on increases in any one year. The tracked amounts may be reflected in rates set in future rate cases.

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UE provides power to Noranda’s smelter plant in New Madrid, Missouri, which has historically used approximately four million megawatthours of power annually, making Noranda UE’s single largest customer. As a result of a major winter ice storm in January 2009, Noranda’s smelter plant experienced a power outage related to non-UE lines delivering power to the substation serving the plant. Noranda stated in its Annual Report on Form 10-K for the year ended December 31, 2008, that the outage affected approximately 75% of the smelter plant’s capacity. In a September 30, 2009, press release, Noranda stated that its smelter plant had initiated steps to return operations to full capacity. These steps include restarting the third of its three production lines. Ameren expects it will take some time for the third production line to be repaired and returned to full capacity. To the extent UE’s sales to Noranda are reduced, UE’s margins may be reduced. UE estimates its electric margin from sales to Noranda was $11 million and $30 million lower during the third quarter and first nine months, respectively, of 2009, compared with the same periods in 2008, as a result of the outage. UE’s July 2009 electric rate case filing with the MoPSC seeks approval to revise the tariff under which it serves Noranda to prospectively address the significant lost revenues UE can incur due to any future operational issues at Noranda’s smelter plant in southeastern Missouri, like the revenue losses resulting from the January 2009 storm-related power outage. The tariff change that UE is proposing would permit it to collect from Noranda the revenue authorized by the MoPSC in this rate case regardless of the level at which the Noranda plant is operating at prospectively. If the plant is operating at levels less than the levels assumed in rates, Noranda would receive a credit reflecting any revenues received by UE from energy sales resulting from the decrease in actual energy sales to Noranda. The result would be that UE is able to recover its costs without impacting other customers regardless of Noranda’s actual energy use.

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The Illinois electric settlement agreement reached in 2007 provided 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. The Ameren Illinois Utilities, Genco, and AERG agreed to fund an aggregate of $150 million, of which the following estimated contributions remained to be made at September 30, 2009:


	Ameren		CIPS		CILCO (Illinois Regulated)		IP		Genco		CILCO (AERG)
2009	$	7.6	$	1.1	$	0.5	$	1.6	$	3.0	$	1.4
2010		2.4		0.3		0.2		0.5		1.0		0.4
Total	$	10.0	$	1.4	$	0.7	$	2.1	$	4.0	$	1.8

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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 round-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. Under the terms of the Illinois electric settlement agreement, these financial contracts are deemed prudent, and the Ameren Illinois Utilities are permitted full recovery of their costs in rates.

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Volatile power prices in the Midwest can affect the amount of revenues Ameren, Genco, CILCO (through AERG) and EEI generate by marketing power into the wholesale and spot markets and can influence the cost of power purchased in the spot markets. Spot power prices in the MISO were lower during the third quarter and during the first nine months of 2009 compared with the same periods in 2008, and will be significantly impacted by any prospect of global economic recovery, among other things.

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The availability and performance of Genco’s, AERG’s and EEI’s electric generation fleet can materially impact their revenues. The Merchant Generation segment expects to generate 27 million megawatthours of power from its coal-fired plants in 2009 (Genco - 13 million, AERG - 7 million, EEI - 7 million) based on expected power prices in 2009. Should power prices rise more than expected in the remainder of 2009 or in future years, the Merchant Generation segment has the capacity and availability to sell more generation.

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With few scheduled outages in 2010 and 2011, the Merchant Generation segment expects to have available generation of 35 million megawatthours in each year. However, the Merchant Generation segment’s actual generation levels in 2010 and 2011 will be significantly impacted by market prices for power in those years, among other things.

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The marketing strategy for the Merchant 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 Merchant Generation segment has established hedge targets for near-term years. Through a mix of physical and financial sales contracts, Marketing Company targets to hedge Merchant 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 September 30, 2009, Marketing Company had sold 100% of Merchant Generation’s expected 2009 generation, at an average price of $54 per megawatthour. For 2010, Marketing Company had hedged approximately 24 million megawatthours of Merchant Generation’s forecasted generation sales at an average price of $48 per megawatthour. For 2011, Marketing Company had hedged approximately 17 million megawatthours of Merchant Generation’s forecasted generation sales at an average price

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of $50 per megawatthour. Marketing Company has also entered into capacity-only sales contracts for 2010 and 2011 resulting in expected capacity-only revenues related to these contracts of $65 million and $45 million, respectively. Any unhedged sales will be exposed to relevant market prices at the time of the sale.

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The development of ancillary services and capacity markets in MISO could increase the electric margins of 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. A capacity requirement obligates a load serving entity to acquire capacity sufficient to meet its obligations.

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MISO’s regional wholesale ancillary services market began in January 2009. MISO continues to refine its treatment of capacity supply and obligations, but development of a true capacity market could still be several years away.

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Current and future energy efficiency programs developed by UE, CIPS, CILCO and IP and others could result in reduced demand for our electric generation and our electric and natural gas transmission and distribution services. Our regulated operations will seek a regulatory framework that allows either a return on these programs or recovery of their costs.

Fuel and Purchased Power

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In 2008, 85% of Ameren’s electric generation (UE - 77%, Genco - 99%, AERG - 99%, EEI - 100%) was supplied by coal-fired power plants. About 96% of the coal used by these plants (UE - 97%, Genco - 98%, AERG - 77%, EEI - 100%) was delivered by rail 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. As of September 30, 2009, coal inventories for UE, Genco, AERG and EEI were at targeted 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.

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

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The annual NO_x trading program under the federal Clean Air Interstate Rule was reinstated by the U.S. Court of Appeals for the District of Columbia in December 2008. At this time, Genco believes it has sufficient NO_x allowances to meet 2009 obligations under the annual NO_x trading program. AERG may not have sufficient NO_x allowances to meet forecasted 2009 obligations under the annual NO_x trading program. The costs of these allowances would depend on market prices at the time these allowances are purchased. AERG currently estimates that it could incur additional fuel expense in 2009 of $0.5 million to purchase additional NO_x allowances to comply with the program.

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Ameren’s fuel costs (including transportation) are expected to increase in 2009 and beyond. As of September 30, 2009, Merchant Generation’s baseload hedged fuel costs, which include coal, transportation, diesel fuel surcharges, and other charges, had increased from an average cost of approximately $20.25 per megawatthour in 2009 to approximately $23.25 per megawatthour in 2010 and $25.50 per megawatthour in 2011. 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 2009 through 2013.

Other Costs

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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 settled with the FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. UE has property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance does not cover lost electric margins and penalties paid to FERC. UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and is in the process of rebuilding the facility. UE expects the Taum Sauk plant to be out of service until the spring of 2010. The estimated cost to rebuild the upper reservoir is in the range of $490 million. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. In July 2009, three insurance carriers filed a petition against Ameren in the Circuit Court of St. Louis County, Missouri, seeking a declaratory judgment that the property insurance policy does not require these three insurers to indemnify Ameren for their share of the entire cost of construction associated with the facility rebuild design being utilized. Ameren has filed an answer and counterclaim in the Circuit Court of St. Louis County, Missouri against these insurers. The counterclaim asserts that the three insurance carriers have breached their obligations under the property insurance policies issued to Ameren and UE. The insurers that are parties to the litigation represent approximately 40%, on a weighted average basis, of the property insurance policy coverage between the disputed amounts of $214 million and $490 million. On August 31, 2009, Ameren and the property insurance carriers that are not parties to the above litigation reached a settlement of any and all claims, liabilities, and obligations arising out of, or relating to, coverage under its property insurance policy, including those related to the rebuilding of the facility and the reimbursement of replacement power costs. All payments from the Settling Insurance Companies were received by UE by September 30, 2009. Until Ameren’s remaining insurance claims and the related litigation are resolved, 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. As a result of the settlement with the Settling Insurance Companies, Ameren and UE now expect to recover, through insurance, 80% to 90% of the total property insurance claim for the Taum Sauk incident. Beyond insurance, the recoverability of any Taum Sauk facility rebuild costs from customers is subject to the terms and conditions set forth in UE’s November 2007 State of Missouri settlement agreement. Certain costs associated with the Taum Sauk facility not recovered from property insurers may be recoverable from UE’s electric customers through rates established in rate cases filed subsequent to the expected spring 2010 in-service date of the rebuilt facility. Any amounts not recovered through insurance, in electric rates or otherwise, could result in charges to earnings, which could be material. See Note 9 - Commitments and Contingencies under Part I, Item 1, of this report for further discussion of Taum Sauk matters.

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•

UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage in the spring of 2010 is expected to last 35 days. 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.

•

On February 20, 2009, the Illinois Supreme Court handed down its decision in Exelon Corporation v. The Department of Revenue, which concluded that an electric utility in Illinois qualifies for the Illinois investment tax credit. In July 2009, the Illinois Supreme Court denied a petition for rehearing filed by the Illinois Department of Revenue and modified its decision to make it prospective only. In September 2009, the Illinois Supreme Court denied a petition for rehearing filed by Exelon. The Ameren Companies do not expect the decision to have a material impact on their results of operations, financial position or liquidity.

•

Over the next few years, we expect rising employee benefit costs, as well as higher insurance premiums as a result of insurance market conditions and loss experience, among other things.

•

In the spring of 2009, Genco discussed with several parties the possible sale of three smaller plants. Those discussions did not result in offers that Genco found acceptable. In the third quarter of 2009, Genco announced operational changes and staff reductions at each of those three generating facilities. The affected three plants were the primarily coal-fired Meredosia plant, the natural gas-fired combined cycle Grand Tower plant, and the coal-fired Hutsonville plant. Genco will retire two of the four units at its Meredosia plant. The retirement resulted in a $4 million pretax charge to earnings during the third quarter of 2009. The Grand Tower plant will be operated seasonally from May through September with a very limited staff to maintain the plant in the other months. As a result of the staff reductions at these three plants as well as the workforce staff reductions through the voluntary and involuntary separation programs discussed in Results of Operations, Genco plans to reduce its workforce by approximately 80 positions. See Note 1 - Summary of Significant Accounting Policies under Part 1, Item 1, of this report for additional information.

Other

•

A ballot initiative passed by Missouri voters in November 2008 created a renewable energy portfolio standard. 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 standard must be derived from solar energy. Compliance with the renewable energy portfolio standard can be achieved through the procurement of renewable energy or renewable energy credits. Rules implementing the renewable energy portfolio standard are expected to be issued by the MoPSC in 2009. UE expects that any related costs or investments would ultimately be recovered in rates.

•

Recently, the U.S. Congress has considered legislation that would require additional government regulation of derivative and OTC transactions and that would expand collateral requirements. Legislation of this nature, if finalized and signed into law by the President, could reduce the effectiveness of hedging, increasing the volatility of earnings, and could require increased collateral postings.

•

Resources Company, as part of an internal reorganization, is evaluating the transfer of its 80% stock ownership interest in EEI to Genco, through a capital contribution, that could take place later this year or in 2010.

•

UE and the Ameren Illinois Utilities applied for three grants under DOE’s Smart Grid Investment Program, which is part of the American Recovery and Reinvestment Act of 2009. In October 2009, the DOE notified UE and the Ameren Illinois Utilities that they were not awarded a grant.

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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 stockholder 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 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, 2009:


	Interest Expense			Net Income^(a)
Ameren^(b)	$	7		$	(4	)
UE		2			(1	)
CIPS		(c	)		(c	)
Genco		1			(1	)
CILCORP		6			(3	)
CILCO		3			(2	)
IP		(c	)		(c	)

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

(b)	Includes intercompany eliminations.

(c)	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.

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Credit Risk

Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges 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. See Note 6 - Derivative Financial Instruments under Part I, Item 1, of this report for information on the potential loss on counterparty exposure as of September 30, 2009.

Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. 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. At September 30, 2009, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. UE and the Ameren Illinois Utilities continue to monitor the impact of increasing rates and a weak economic environment on customer collections. UE and the Ameren Illinois Utilities make adjustments to their allowance for doubtful accounts as deemed necessary, to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.

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, 2009, 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 $4 million, net of collateral (2008 - $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 $13 million at September 30, 2009 (2008 - $64 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. The agreement provided $488 million in rate relief over a four-year period that commenced in 2007. Under funding agreements among the parties contributing to the rate relief and assistance programs, the Ameren Illinois Utilities will bill the participating generators at the end of each month, 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 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.

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 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.

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The following table presents how Ameren’s cumulative net income might decrease if power prices were to decrease by 1% on unhedged economic generation for the remainder of 2009 through 2012:


	Net Income^(a)
Ameren^(b)	$	(15	)
UE		(7	)
Genco		(4	)
CILCO (AERG)		(1	)
EEI		(4	)

(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.

We manage risks associated with changing prices of fuel for generation using similar techniques as those used to manage risks associated with changing market prices for electricity. Most UE, Genco, AERG and EEI fuel supply contracts are physical forward contracts. Genco, AERG and EEI do not have the ability to pass through higher fuel costs to their customers for electric operations. Prior to March 2009, UE did not have this ability either except through a general rate proceeding. As a part of the January 2009 MoPSC electric rate order, UE was granted permission to put a FAC in place, which became effective March 1, 2009. The FAC allows UE to recover directly from its electric customers 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates, subject to MoPSC prudency review. Thus, UE remains exposed to 5% of changes in its fuel and purchased power costs, net of off-system revenues. UE is seeking authorization from the MoPSC in its pending electric rate case to continue use of the FAC. See Note 2 - Rate and Regulatory Matters under Part I, Item 1 of this report for additional information. UE, Genco, AERG and EEI have entered into long-term contracts with various suppliers to purchase coal 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. UE, Genco, AERG and EEI generally purchase coal up to five years in advance, but we may purchase coal beyond five years to take advantage of favorable opportunities or market conditions. The strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions.

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Transportation costs for coal and natural gas can represent a significant portion of fuel costs. UE, Genco, AERG and EEI 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 the 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 2009, 2010, and 2011 through 2013, as of September 30, 2009. The projected required supply of these commodities could be significantly impacted by changes in our assumptions for such matters as customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.


	2009		2010		2011 - 2013
Ameren:
Coal	100	%	97	%	30	%
Coal transportation	100		100		61
Nuclear fuel	100		100		89
Natural gas for generation	100		26		-
Natural gas for distribution^(a)	85		45		18
Purchased power for Illinois Regulated^(b)	100		82		35
UE:
Coal	100	%	97	%	29	%
Coal transportation	100		100		63
Nuclear fuel	100		100		89
Natural gas for generation	100		43		-
Natural gas for distribution^(a)	86		47		25
CIPS:
Natural gas for distribution^(a)	84	%	40	%	15	%
Purchased power^(b)	100		82		35
Genco:
Coal	100	%	97	%	32	%
Coal transportation	100		100		46
Natural gas for generation	100		-		-
CILCORP/CILCO:
Coal (AERG)	100	%	96	%	34	%
Coal transportation (AERG)	100		100		79
Natural gas for distribution^(a)	85		47		18
Purchased power^(b)	100		82		35
IP:
Natural gas for distribution^(a)	86	%	46	%	17	%
Purchased power^(b)	100		82		35
EEI:
Coal	100	%	96	%	29	%
Coal transportation	100		100		67

(a)	Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2009 represents November 2009 through March 2010. The year 2010 represents November 2010 through March 2011. This continues each successive year through March 2014.

(b)

Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand. 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 the Illinois power procurement process and for additional information on the Ameren Illinois Utilities’ purchased power commitments.

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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 2009 through 2013.


	Coal					Transportation
	Fuel Expense		Net Income^(a)			Fuel Expense		Net Income^(a)
Ameren^(b)	$	14	$	(9	)	$	11	$	(7	)
UE		8		(5	)		5		(3	)
Genco		3		(2	)		4		(3	)
CILCORP		1		(1	)		1		(c	)
CILCO (AERG)		1		(1	)		1		(c	)
EEI		2		(1	)		1		(1	)

(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. Ameren utilizes a combination of swaps and purchased call options to price cap and price hedge this exposure. If diesel fuel costs were to increase or decrease by $0.25/gallon, Ameren’s fuel expense could increase or decrease by $14 million annually for 2009 (UE - $8 million, Genco - $3 million, AERG - $1 million and EEI - $2 million). As of September 30, 2009, Ameren had a price cap for 100% of expected fuel surcharges in 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.

With regard to exposure for commodity price risk for nuclear fuel, UE has fixed-priced and base-price-with- escalation agreements, or it uses inventories that provide some price hedge to fulfill its Callaway nuclear plant needs for uranium, conversion, enrichment, and fabrication services. There is no fuel reloading scheduled for 2009 or 2012. UE has price hedges for 92% of its 2010 to 2013 nuclear fuel requirements.

Nuclear fuel market prices remain subject to an unpredictable supply and demand environment. UE has continued to follow a strategy of managing inventory of nuclear fuel as an inherent price hedge. New long-term uranium contracts are almost exclusively market-price-related with an escalating price floor. New long-term enrichment contracts usually have some market-price-related component. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the Callaway nuclear plant, at prices which cannot now be accurately predicted. Unlike the electricity and natural gas markets, nuclear fuel markets have limited financial instruments available for price hedging, so most hedging is done through inventories and forward contracts, if they are available.

See Note 9 - Commitments and Contingencies 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 that meet the definition of derivatives qualify for treatment as NPNS. 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

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three and nine months ended September 30, 2009. We use various methods to determine the fair value of our contracts. In accordance with authoritative guidance for fair value 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 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 Ended September 30, 2009
Fair value of contracts at beginning of period, net	$	70		$	19		$	(153	)	$	(1	)	$	(89	)	$	(236	)
Contracts realized or otherwise settled during the period		40			8			12			-			14			24
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		(6	)		(4	)		(1	)		-			2			1
Other changes in fair value		(36	)		(6	)		(19	)		-			(14	)		(40	)
Fair value of contracts outstanding at end of period, net	$	68		$	17		$	(161	)	$	(1	)	$	(87	)	$	(251	)


	Ameren^(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Nine Months Ended September 30, 2009
Fair value of contracts at beginning of period, net	$	20		$	16		$	(84	)	$	(1	)	$	(59	)	$	(134	)
Contracts realized or otherwise settled during the period		52			(9	)		42			1			48			81
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		51			20			(3	)		-			2			(6	)
Other changes in fair value		(55	)		(10	)		(116	)		(1	)		(78	)		(192	)
Fair value of contracts outstanding at end of period, net	$	68		$	17		$	(161	)	$	(1	)	$	(87	)	$	(251	)

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

The following table presents maturities of derivative contracts as of September 30, 2009, 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	$	(11	)	$	(2	)	$	-		$	-	$	(13	)
Level 2^(a)		30			-			-			-		30
Level 3^(b)		25			26			-			-		51
Total	$	44		$	24		$	-		$	-	$	68
UE:
Level 1	$	(3	)	$	(2	)	$	-		$	-	$	(5	)
Level 2^(a)		5			-			-			-		5
Level 3^(b)		8			9			-			-		17
Total	$	10		$	7		$	-		$	-	$	17
CIPS:
Level 1	$	(1	)	$	-		$	-		$	-	$	(1	)
Level 2^(a)		-			-			-			-		-
Level 3^(b)		(49	)		(99	)		(12	)		-		(160	)
Total	$	(50	)	$	(99	)	$	(12	)	$	-	$	(161	)
Genco:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2^(a)		-			-			-			-		-
Level 3^(b)		(1	)		-			-			-		(1	)
Total	$	(1	)	$	-		$	-		$	-	$	(1	)
CILCORP/CILCO:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2^(a)		-			-			-			-		-
Level 3^(b)		(30	)		(51	)		(6	)		-		(87	)
Total	$	(30	)	$	(51	)	$	(6	)	$	-	$	(87	)
IP:
Level 1	$	-		$	1		$	-		$	-	$	1
Level 2^(a)		-			-			-			-		-
Level 3^(b)		(82	)		(151	)		(19	)		-		(252	)
Total	$	(82	)	$	(150	)	$	(19	)	$	-	$	(251	)

(a)	Principally fixed price for floating OTC power swaps, power forwards and fixed price for floating OTC 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.

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ITEM 4 and ITEM 4T. CONTROLS AND PROCEDURES.

(a)	Evaluation of Disclosure Controls and Procedures

As of September 30, 2009, 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 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.

For additional information on legal and administrative proceedings, see Note 2 - Rate and Regulatory Matters and Note 9 - Commitments and Contingencies under Part I, Item 1 of this report.

ITEM 1A.

RISK FACTORS.

There have been no material changes to the risk factors disclosed in Item 1A. Risk Factors in the Form 10-K.

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ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:


Period	(a) Total Number of Shares (or Units) Purchased^(a)	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1 - July 31, 2009	-	$	-	-	-
August 1 - August 31, 2009	2,407		26.35	-	-
September 1 - September 30, 2009	-		-	-	-
Total	2,407	$	26.35	-	-

(a)

Included in August were 2,407 shares of Ameren common stock purchased by Ameren in an open-market transaction pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligation to distribute shares of common stock for vested performance share units held by employees whose employment terminated. Ameren does not have any publicly announced equity securities repurchase plans or programs.

None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the period from July 1, 2009 to September 30, 2009.

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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:
Material Contracts
10.1	Ameren Companies	*Ameren’s Deferred Compensation Plan as amended and restated effective January 1, 2010	October 14, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756
10.2	Ameren Companies	*First Amendment, dated October 12, 2009, to the Second Amended and Restated Ameren Change of Control Severance Plan	October 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756
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
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

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Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
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
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
XBRL - Related Documents
101.INS**	Ameren	XBRL Instance Document
101.SCH**	Ameren	XBRL Taxonomy Extension Schema Document
101.CAL**	Ameren	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**	Ameren	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	Ameren	XBRL Taxonomy Extension Presentation Linkbase Document

*	Management compensatory plan or arrangement.

Attached as Exhibit 101 to this report is the following financial information from Ameren’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statement of Income for the three and nine months ended September 30, 2009 and 2008, (ii) the Consolidated Balance Sheet at September 30, 2009, and December 31, 2008, (iii) the Consolidated Statement of Cash Flows for the nine months ended September 30, 2009 and 2008, and (iv) the Combined Notes to the Financial Statements for the nine months ended September 30, 2009, tagged as blocks of text. These Exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.

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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 Financial Officer

(Principal Financial and Accounting Officer)

UNION ELECTRIC COMPANY

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

AMEREN ENERGY GENERATING COMPANY

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

140

CILCORP INC.

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

CENTRAL ILLINOIS LIGHT COMPANY

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

ILLINOIS POWER COMPANY

(Registrant)

/s/ Martin J. Lyons

Martin J. Lyons

Senior Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

Date: November 9, 2009

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