Ameren Illinois Co - Quarter Report: 2009 June (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 June 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 July 31, 2009, was as follows:


Ameren Corporation		Common stock, $.01 par value per share - 214,372,742

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	74
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	105
Item 4 and
Item 4T.	Controls and Procedures	110

PART II	Other Information

Item 1.	Legal Proceedings	110
Item 1A.	Risk Factors	110
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	110
Item 4.	Submission of Matters to a Vote of Security Holders	111
Item 6.	Exhibits	113

Signatures		116

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

GLOSSARY OF TERMS AND ABBREVIATIONS

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

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

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

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 the 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.

APB - Accounting Principles Board.

ARB - Accounting Research Bulletin.

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 non-rate-regulated electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business, all in Illinois, as AmerenCILCO. CILCO owns all of the common stock of AERG.

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

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

CO₂ - Carbon dioxide.

COLA - Combined 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 non-rate-regulated electric generation facilities and FERC-regulated transmission facilities in Illinois. Prior to February 29, 2008, EEI was 40% owned by UE and 40% owned by Development Company. On February 29, 2008, UE’s 40% ownership interest and Development Company’s 40% ownership interest were transferred to Resources Company. The remaining 20% is owned by Kentucky Utilities Company.

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

Equivalent availability factor - A measure that indicates the percentage of time an electric power generating unit was available for service during a period.

Exchange Act - Securities Exchange Act of 1934, as amended.

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.

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

Fitch - Fitch Ratings, a credit rating agency.

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

FSP - FASB Staff Position, a publication that provides application guidance on FASB literature.

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

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

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

Gigawatthour - One thousand megawatthours.

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

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

Illinois Customer Choice Law - Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which provided for electric utility restructuring and 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.

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.

Non-rate-regulated Generation - A financial reporting segment consisting of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, Medina Valley, and Marketing Company. Also referred to as our Merchant Generation segment.

NO_x - Nitrogen oxide.

Noranda - Noranda Aluminum, Inc.

NPNS - Normal purchases and normal sales.

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

NYMEX - New York Mercantile Exchange.

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

Off-system revenues - Revenues from 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.

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 increases authorized by regulators will lag behind changing costs.

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

RFP - Request for proposal.

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

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

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

SO₂ - Sulfur dioxide.

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. Since the application of FIN 46R, IP did not consolidate IP SPT. Therefore, the obligation to IP SPT appears on IP’s balance sheet as of December 31, 2007. In September 2008, IP redeemed the remaining 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 standards 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 or otherwise have a negative financial effect;

•

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

•

the inability of our counterparties and affiliates to meet their obligations with respect to contracts, 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 June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Operating Revenues:
Electric	$	1,515	$	1,547	$	2,910	$	3,016
Gas		169		243		690		855

Total operating revenues		1,684		1,790		3,600		3,871


Operating Expenses:
Fuel		287		200		561		502
Coal contract settlement		-		(60)		-		(60)
Purchased power		219		306		452		593
Gas purchased for resale		83		165		466		624
Other operations and maintenance		451		476		872		905
Depreciation and amortization		182		171		356		340
Taxes other than income taxes		97		89		207		202

Total operating expenses		1,319		1,347		2,914		3,106

Operating Income		365		443		686		765

Other Income and Expenses:
Miscellaneous income		17		19		33		38
Miscellaneous expense		(7)		(8)		(11)		(13)

Total other income		10		11		22		25

Interest Charges		124		118		242		218

Income Before Income Taxes		251		336		466		572
Income Taxes		83		119		153		206

Net Income		168		217		313		366
Less: Net Income Attributable to Noncontrolling Interests		3		11		7		22

Net Income Attributable to Ameren Corporation	$	165	$	206	$	306	$	344


Earnings per Common Share – Basic and Diluted	$	0.77	$	0.98	$	1.43	$	1.64

Dividends per Common Share	$	0.385	$	0.635	$	0.770	$	1.270
Average Common Shares Outstanding		213.6		209.5		213.1		209.1

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

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

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


	June 30, 2009		December 31, 2008
ASSETS

Current Assets:
Cash and cash equivalents	$	251	$	92
Accounts receivable – trade (less allowance for doubtful accounts of $35 and $28, respectively)		450		502
Unbilled revenue		365		427
Miscellaneous accounts and notes receivable		337		292
Materials and supplies		733		842
Mark-to-market derivative assets		277		207
Other current assets		251		232

Total current assets		2,664		2,594

Property and Plant, Net		17,006		16,567
Investments and Other Assets:
Nuclear decommissioning trust fund		249		239
Goodwill		831		831
Intangible assets		150		167
Regulatory assets		1,616		1,653
Other assets		674		606

Total investments and other assets		3,520		3,496

TOTAL ASSETS	$	23,190	$	22,657


LIABILITIES AND EQUITY

Current Liabilities:
Current maturities of long-term debt	$	129	$	380
Short-term debt		965		1,174
Accounts and wages payable		523		813
Taxes accrued		131		54
Interest accrued		126		107
Mark-to-market derivative liabilities		234		155
Other current liabilities		437		380

Total current liabilities		2,545		3,063

Long-term Debt, Net		7,321		6,554
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,194		2,131
Accumulated deferred investment tax credits		95		100
Regulatory liabilities		1,307		1,291
Asset retirement obligations		418		406
Pension and other postretirement benefits		1,486		1,495
Other deferred credits and liabilities		470		438

Total deferred credits and other liabilities		5,970		5,861

Commitments and Contingencies (Notes 2, 8, 9 and 10)
Ameren Corporation Stockholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 214.2 and 212.3, respectively		2		2
Other paid-in capital, principally premium on common stock		4,835		4,780
Retained earnings		2,323		2,181
Accumulated other comprehensive income (loss)		(13)		-

Total Ameren Corporation stockholders’ equity		7,147		6,963

Noncontrolling Interests		207		216

Total equity		7,354		7,179

TOTAL LIABILITIES AND EQUITY	$	23,190	$	22,657

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

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Six Months Ended June 30,
	2009		2008
Cash Flows From Operating Activities:
Net income	$	313	$	366
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		(56)		(94)
Coal contract settlement		-		(60)
Depreciation and amortization		364		350
Amortization of nuclear fuel		25		20
Amortization of debt issuance costs and premium/discounts		7		8
Deferred income taxes and investment tax credits, net		77		107
Other		11		4
Changes in assets and liabilities:
Receivables		93		15
Materials and supplies		109		16
Accounts and wages payable		(204)		(38)
Taxes accrued		77		(58)
Assets, other		53		32
Liabilities, other		68		65
Pension and other postretirement benefits		23		29
Counterparty collateral, net		(4)		(126)
Taum Sauk costs, net of insurance recoveries		(48)		(133)

Net cash provided by operating activities		908		501

Cash Flows From Investing Activities:
Capital expenditures		(846)		(798)
Nuclear fuel expenditures		(35)		(123)
Purchases of securities – nuclear decommissioning trust fund		(288)		(247)
Sales of securities – nuclear decommissioning trust fund		291		231
Purchases of emission allowances		(4)		(2)
Sales of emission allowances		-		2
Other		-		2

Net cash used in investing activities		(882)		(935)

Cash Flows From Financing Activities:
Dividends on common stock		(164)		(266)
Debt issuance costs		(47)		(9)
Dividends paid to noncontrolling interest holders		(16)		(21)
Short-term debt, net		(209)		(22)
Redemptions, repurchases, and maturities of long-term debt		(250)		(808)
Issuances:
Common stock		47		75
Long-term debt		772		1,335

Net cash provided by financing activities		133		284


Net change in cash and cash equivalents		159		(150)
Cash and cash equivalents at beginning of year		92		355

Cash and cash equivalents at end of period	$	251	$	205

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

UNION ELECTRIC COMPANY

STATEMENT OF INCOME

(Unaudited) (In millions)


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Operating Revenues:
Electric – excluding off-system	$	634	$	586	$	1,080	$	1,073
Electric – off-system		91		150		224		304
Gas		26		35		101		118
Other		1		-		2		-

Total operating revenues		752		771		1,407		1,495


Operating Expenses:
Fuel		163		104		298		251
Purchased power		28		37		61		90
Gas purchased for resale		12		18		60		73
Other operations and maintenance		220		238		436		455
Depreciation and amortization		90		82		176		163
Taxes other than income taxes		66		60		128		120

Total operating expenses		579		539		1,159		1,152

Operating Income		173		232		248		343

Other Income and Expenses:
Miscellaneous income		15		15		28		29
Miscellaneous expense		(2)		(2)		(4)		(4)

Total other income		13		13		24		25

Interest Charges		57		50		110		91

Income Before Income Taxes and Equity in Income of Unconsolidated Investment		129		195		162		277
Income Taxes		45		71		56		100

Income Before Equity in Income of Unconsolidated Investment		84		124		106		177
Equity in Income of Unconsolidated Investment, Net of Taxes		-		-		-		11

Net Income		84		124		106		188
Preferred Stock Dividends		2		2		3		3

Net Income Available to Common Stockholder	$	82	$	122	$	103	$	185

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)


	June 30, 2009		December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	30	$	-
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $8, respectively)		163		142
Unbilled revenue		168		111
Miscellaneous accounts and notes receivable		311		261
Accounts receivable – affiliates		79		32
Materials and supplies		345		339
Mark-to-market derivative assets		31		50
Other current assets		67		58

Total current assets		1,194		993

Property and Plant, Net		9,218		8,995
Investments and Other Assets:
Nuclear decommissioning trust fund		249		239
Intangible assets		41		48
Regulatory assets		908		897
Other assets		389		352

Total investments and other assets		1,587		1,536

TOTAL ASSETS	$	11,999	$	11,524


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	4	$	4
Short-term debt		460		251
Intercompany note payable – Ameren		-		92
Accounts and wages payable		190		360
Accounts payable – affiliates		104		151
Taxes accrued		136		20
Interest accrued		75		56
Other current liabilities		132		121

Total current liabilities		1,101		1,055

Long-term Debt, Net		4,022		3,673
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,433		1,372
Accumulated deferred investment tax credits		78		80
Regulatory liabilities		926		922
Asset retirement obligations		326		317
Pension and other postretirement benefits		522		494
Other deferred credits and liabilities		50		49

Total deferred credits and other liabilities		3,335		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		1,119		1,119
Preferred stock not subject to mandatory redemption		113		113
Retained earnings		1,798		1,794
Accumulated other comprehensive income		-		25

Total stockholders’ equity		3,541		3,562

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	11,999	$	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)


	Six Months Ended June 30,
	2009		2008
Cash Flows From Operating Activities:
Net income	$	106	$	188
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		(30)		(73)
Depreciation and amortization		176		163
Amortization of nuclear fuel		25		20
Amortization of debt issuance costs and premium/discounts		3		3
Deferred income taxes and investment tax credits, net		49		74
Other		(5)		(9)
Changes in assets and liabilities:
Receivables		(146)		66
Materials and supplies		(4)		(17)
Accounts and wages payable		(162)		(227)
Taxes accrued		116		(31)
Assets, other		17		53
Liabilities, other		26		26
Pension and other postretirement benefits		10		13
Taum Sauk costs, net of insurance recoveries		(48)		(133)

Net cash provided by operating activities		133		115

Cash Flows From Investing Activities:
Capital expenditures		(421)		(377)
Nuclear fuel expenditures		(35)		(123)
Proceeds from intercompany note receivable		-		6
Purchases of securities – nuclear decommissioning trust fund		(288)		(247)
Sales of securities – nuclear decommissioning trust fund		291		231
Other		-		1

Net cash used in investing activities		(453)		(509)

Cash Flows From Financing Activities:
Dividends on common stock		(99)		(105)
Dividends on preferred stock		(3)		(3)
Debt issuance costs		(14)		(5)
Short-term debt, net		209		(49)
Intercompany note payable – Ameren, net		(92)		50
Redemptions, repurchases, and maturities of long-term debt		-		(378)
Issuances of long-term debt		349		699

Net cash provided by financing activities		350		209


Net change in cash and cash equivalents		30		(185)
Cash and cash equivalents at beginning of year		-		185

Cash and cash equivalents at end of period	$	30	$	-

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 June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Operating Revenues:
Electric	$	163	$	169	$	328	$	349
Gas		33		38		131		148
Other		-		-		2		-

Total operating revenues		196		207		461		497


Operating Expenses:
Purchased power		94		108		200		231
Gas purchased for resale		16		24		89		104
Other operations and maintenance		55		48		98		98
Depreciation and amortization		17		17		34		34
Taxes other than income taxes		8		7		18		19

Total operating expenses		190		204		439		486


Operating Income		6		3		22		11

Other Income and Expenses:
Miscellaneous income		2		3		5		6
Miscellaneous expense		-		(2)		(1)		(2)

Total other income		2		1		4		4

Interest Charges		7		8		14		15

Income (Loss) Before Income Taxes		1		(4)		12		-
Income Taxes (Benefit)		-		(1)		4		-

Net Income (Loss)		1		(3)		8		-
Preferred Stock Dividends		-		-		1		1

Net Income (Loss) Available to Common Stockholder	$	1	$	(3)	$	7	$	(1)

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)


	June 30, 2009		December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	10	$	-
Accounts receivable – trade (less allowance for doubtful accounts of $6 and $6, respectively)		61		79
Unbilled revenue		51		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		38		70
Counterparty collateral asset		19		21
Current portion of regulatory assets		58		31
Other current assets		18		8

Total current assets		314		339

Property and Plant, Net		1,239		1,212
Investments and Other Assets:
Intercompany note receivable – Genco		-		45
Intercompany tax receivable – Genco		89		93
Regulatory assets		228		195
Other assets		31		33

Total investments and other assets		348		366

TOTAL ASSETS	$	1,901	$	1,917


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	-	$	62
Borrowings from money pool		-		44
Accounts and wages payable		60		48
Accounts payable – affiliates		50		49
Taxes accrued		5		7
Customer deposits		15		16
Mark-to-market derivative liabilities		21		17
Mark-to-market derivative liabilities – affiliates		37		14
Other current liabilities		45		51

Total current liabilities		233		308

Long-term Debt, Net		421		421
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		265		259
Accumulated deferred investment tax credits		8		9
Regulatory liabilities		238		234
Pension and other postretirement benefits		78		79
Other deferred credits and liabilities		122		78

Total deferred credits and other liabilities		711		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		191		191
Preferred stock not subject to mandatory redemption		50		50
Retained earnings		295		288

Total stockholders’ equity		536		529

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,901	$	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)


	Six Months Ended June 30,
	2009		2008
Cash Flows From Operating Activities:
Net income	$	8	$	-
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		34		34
Amortization of debt issuance costs and premium/discounts		1		1
Deferred income taxes and investment tax credits, net		(2)		(2)
Changes in assets and liabilities:
Receivables		45		20
Materials and supplies		32		18
Accounts and wages payable		8		12
Taxes accrued		(2)		(12)
Assets, other		4		29
Liabilities, other		(5)		7
Pension and other postretirement benefits		2		2

Net cash provided by operating activities		125		109

Cash Flows From Investing Activities:
Capital expenditures		(47)		(41)
Proceeds from intercompany note receivable – Genco		42		39

Net cash used in investing activities		(5)		(2)

Cash Flows From Financing Activities:
Dividends on preferred stock		(1)		(1)
Debt issuance costs		(3)		-
Short-term debt, net		(62)		(100)
Money pool borrowings, net		(44)		3
Redemptions, repurchases, and maturities of long-term debt		-		(35)

Net cash used in financing activities		(110)		(133)


Net change in cash and cash equivalents		10		(26)
Cash and cash equivalents at beginning of year		-		26

Cash and cash equivalents at end of period	$	10	$	-

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 June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Operating Revenues	$	218	$	196	$	443	$	429

Operating Expenses:
Fuel		69		49		145		137
Coal contract settlement		-		(60)		-		(60)
Other operations and maintenance		43		53		81		93
Depreciation and amortization		17		16		33		32
Taxes other than income taxes		5		5		10		11

Total operating expenses		134		63		269		213

Operating Income		84		133		174		216
Miscellaneous Income		-		1		-		1
Interest Charges		13		17		29		26

Income Before Income Taxes		71		117		145		191
Income Taxes		25		43		52		71

Net Income	$	46	$	74	$	93	$	120

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)


	June 30, 2009		December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	3	$	2
Accounts receivable – affiliates		103		88
Miscellaneous accounts and notes receivable		6		15
Materials and supplies		121		122
Other current assets		13		10

Total current assets		246		237

Property and Plant, Net		2,037		1,950
Intangible Assets		42		49
Other Assets		13		8

TOTAL ASSETS	$	2,338	$	2,244


LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Current portion of intercompany note payable – CIPS	$	45	$	42
Borrowings from money pool		114		80
Accounts and wages payable		65		82
Accounts payable – affiliates		70		58
Current portion of intercompany tax payable – CIPS		9		9
Taxes accrued		23		16
Other current liabilities		41		43

Total current liabilities		367		330

Long-term Debt, Net		774		774
Intercompany Note Payable – CIPS		-		45
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		156		136
Accumulated deferred investment tax credits		5		6
Intercompany tax payable – CIPS		89		93
Asset retirement obligations		51		49
Pension and other postretirement benefits		69		67
Other deferred credits and liabilities		38		49

Total deferred credits and other liabilities		408		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		334		241
Accumulated other comprehensive loss		(48)		(49)

Total stockholder’s equity		789		695

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	2,338	$	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)


	Six Months Ended June 30,
	2009		2008
Cash Flows From Operating Activities:
Net income	$	93	$	120
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		(8)		(29)
Coal contract settlement		-		(60)
Depreciation and amortization		41		45
Deferred income taxes and investment tax credits, net		16		18
Other		5		1
Changes in assets and liabilities:
Receivables		(6)		28
Materials and supplies		1		(16)
Accounts and wages payable		16		(24)
Taxes accrued		7		2
Assets, other		(3)		8
Liabilities, other		(14)		(2)
Pension and other postretirement benefits		2		2

Net cash provided by operating activities		150		92

Cash Flows From Investing Activities:
Capital expenditures		(135)		(117)
Purchases of emission allowances		(2)		(2)
Sales of emission allowances		-		1

Net cash used in investing activities		(137)		(118)

Cash Flows From Financing Activities:
Dividends on common stock		-		(84)
Debt issuance costs		(4)		(2)
Short-term debt, net		-		(100)
Money pool borrowings, net		34		(49)
Intercompany note payable – CIPS		(42)		(39)
Issuances of long-term debt		-		300

Net cash provided by (used in) financing activities		(12)		26


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 June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Operating Revenues:
Electric	$	178	$	163	$	348	$	357
Gas		33		69		157		220
Support services		18		-		34		-
Other		3		1		4		1

Total operating revenues		232		233		543		578


Operating Expenses:
Fuel		26		25		48		53
Purchased power		40		63		87		141
Gas purchased for resale		19		50		115		165
Other operations and maintenance		66		49		127		96
Goodwill impairment loss		-		-		462		-
Depreciation and amortization		19		22		36		43
Taxes other than income taxes		6		5		14		14

Total operating expenses		176		214		889		512


Operating Income (Loss)		56		19		(346)		66
Other Income and Expenses:
Miscellaneous income		-		1		-		1
Miscellaneous expense		(1)		(2)		(2)		(2)

Total other expenses		(1)		(1)		(2)		(1)
Interest Charges		17		13		31		28

Income (Loss) Before Income Taxes		38		5		(379)		37
Income Taxes		14		-		29		12

Net Income (Loss)		24		5		(408)		25
Less: Net Income Attributable to Noncontrolling Interests		-		1		-		1

Net Income (Loss) Attributable to CILCORP Inc.	$	24	$	4	$	(408)	$	24

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

CILCORP INC.

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions, except shares)


	June 30, 2009		December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	64	$	-
Accounts receivable – trade (less allowance for doubtful accounts of $10 and $3, respectively)		43		60
Unbilled revenue		25		65
Accounts and notes receivable – affiliates		64		59
Advances to money pool		1		2
Materials and supplies		100		131
Current portion of accumulated deferred income taxes, net		15		24
Counterparty collateral asset		22		16
Current portion of regulatory assets		39		24
Other current assets		18		4

Total current assets		391		385

Property and Plant, Net		1,748		1,710
Investments and Other Assets:
Goodwill		80		542
Intangible assets		34		35
Regulatory assets		182		171
Other assets		30		22

Total investments and other assets		326		770

TOTAL ASSETS	$	2,465	$	2,865


LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt	$	125	$	126
Short-term debt		-		286
Borrowings from money pool		-		98
Intercompany note payable – Ameren		556		152
Accounts and wages payable		59		117
Accounts payable – affiliates		75		84
Taxes accrued		3		4
Mark-to-market derivative liabilities		22		21
Mark-to-market derivative liabilities – affiliates		17		7
Other current liabilities		74		69

Total current liabilities		931		964

Long-term Debt, Net		535		536
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		212		212
Accumulated deferred investment tax credits		4		5
Regulatory liabilities		60		59
Pension and other postretirement benefits		230		216
Other deferred credits and liabilities		122		104

Total deferred credits and other liabilities		628		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		638		627
Retained earnings (deficit)		(308)		100
Accumulated other comprehensive income		22		23

Total CILCORP Inc. stockholder’s equity		352		750

Noncontrolling Interest		19		19

Total equity		371		769

TOTAL LIABILITIES AND EQUITY	$	2,465	$	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)


	Six Months Ended June 30,
	2009		2008
Cash Flows From Operating Activities:
Net income (loss)	$	(408)	$	25
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net mark-to-market gain on derivatives		(3)		(7)
Depreciation and amortization		35		43
Amortization of debt issuance costs and premium/discounts		1		-
Deferred income taxes and investment tax credits, net		6		14
Loss on goodwill impairment		462		-
Changes in assets and liabilities:
Receivables		50		10
Materials and supplies		31		9
Accounts and wages payable		(38)		43
Taxes accrued		(1)		-
Assets, other		(12)		(12)
Liabilities, other		9		9
Pension and postretirement benefits		11		(5)

Net cash provided by operating activities		143		129

Cash Flows From Investing Activities:
Capital expenditures		(96)		(140)
Money pool advances, net		1		-
Purchases of emission allowances		(1)		-
Other		-		(1)

Net cash used in investing activities		(96)		(141)

Cash Flows From Financing Activities:
Debt issuance costs		(14)		-
Dividends paid to noncontrolling interest holders		-		(1)
Short-term debt, net		(286)		30
Intercompany note payable – Ameren, net		404		13
Money pool borrowings, net		(98)		2
Redemptions, repurchases and maturities of long-term debt		-		(19)
Capital contribution from parent		11		-

Net cash provided by financing activities		17		25


Net change in cash and cash equivalents		64		13
Cash and cash equivalents at beginning of year		-		6

Cash and cash equivalents at end of period	$	64	$	19

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 June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Operating Revenues:
Electric	$	178	$	163	$	348	$	357
Gas		33		69		157		220
Support services		18		-		34		-
Other		3		1		4		1

Total operating revenues		232		233		543		578


Operating Expenses:
Fuel		24		23		46		50
Purchased power		40		63		87		141
Gas purchased for resale		19		50		115		165
Other operations and maintenance		66		49		129		97
Depreciation and amortization		18		21		34		41
Taxes other than income taxes		6		5		14		14

Total operating expenses		173		211		425		508

Operating Income		59		22		118		70
Other Income and Expenses:
Miscellaneous income		-		1		-		1
Miscellaneous expense		(2)		(1)		(3)		(1)

Total other expenses		(2)		-		(3)		-

Interest Charges		8		5		15		11

Income Before Income Taxes		49		17		100		59
Income Taxes		18		5		36		21

Net Income		31		12		64		38
Preferred Stock Dividends		-		1		-		1

Net Income Available to Common Stockholder	$	31	$	11	$	64	$	37

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)


	June 30, 2009		December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	64	$	-
Accounts receivable – trade (less allowance for doubtful accounts of $10 and $3, respectively)		43		60
Unbilled revenue		25		65
Accounts receivable – affiliates		60		51
Materials and supplies		100		131
Counterparty collateral asset		22		16
Current portion of regulatory assets		39		24
Other current assets		26		19

Total current assets		379		366

Property and Plant, Net		1,774		1,734
Investments and Other Assets:
Intangible assets		2		1
Regulatory assets		182		171
Other assets		22		22

Total investments and other assets		206		194

TOTAL ASSETS	$	2,359	$	2,294


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	-	$	236
Borrowings from money pool		-		98
Intercompany note payable – Ameren		346		-
Accounts and wages payable		58		117
Accounts payable – affiliates		67		83
Taxes accrued		3		8
Mark-to-market derivative liabilities		22		21
Mark-to-market derivative liabilities – affiliates		17		7
Other current liabilities		65		60

Total current liabilities		578		630

Long-term Debt, Net		279		279
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		179		171
Accumulated deferred investment tax credits		4		5
Regulatory liabilities		208		206
Pension and other postretirement benefits		230		216
Other deferred credits and liabilities		121		103

Total deferred credits and other liabilities		742		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		440		429
Preferred stock not subject to mandatory redemption		19		19
Retained earnings		304		240
Accumulated other comprehensive loss		(3)		(4)

Total stockholders’ equity		760		684

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,359	$	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)


	Six Months Ended June 30,
	2009		2008
Cash Flows From Operating Activities:
Net income	$	64	$	38
Adjustments to reconcile net income to net cash provided by operating activities:
Net mark-to-market gain on derivatives		(3)		(7)
Depreciation and amortization		35		41
Amortization of debt issuance costs and premium/discounts		1		-
Deferred income taxes and investment tax credits, net		5		14
Changes in assets and liabilities:
Receivables		46		13
Materials and supplies		31		9
Accounts and wages payable		(46)		42
Taxes accrued		(5)		(1)
Assets, other		(6)		(14)
Liabilities, other		9		6
Pension and postretirement benefits		14		(1)

Net cash provided by operating activities		145		140

Cash Flows From Investing Activities:
Capital expenditures		(96)		(140)
Purchases of emission allowances		(1)		-
Other		-		1

Net cash used in investing activities		(97)		(139)

Cash Flows From Financing Activities:
Dividends on preferred stock		-		(1)
Debt issuance costs		(7)		-
Short-term debt, net		(236)		30
Intercompany note payable – Ameren, net		346		-
Money pool borrowings, net		(98)		2
Redemptions, repurchases and maturities of long-term debt		-		(19)
Capital contribution from parent		11		-

Net cash provided by financing activities		16		12


Net change in cash and cash equivalents		64		13
Cash and cash equivalents at beginning of year		-		6

Cash and cash equivalents at end of period	$	64	$	19

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 June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Operating Revenues:
Electric	$	247	$	258	$	499	$	496
Gas		74		101		290		365
Other		4		1		8		2

Total operating revenues		325		360		797		863


Operating Expenses:
Purchased power		126		161		275		314
Gas purchased for resale		33		71		191		276
Other operations and maintenance		77		83		144		154
Depreciation and amortization		25		20		49		40
Amortization of regulatory assets		4		4		8		8
Taxes other than income taxes		13		13		34		36

Total operating expenses		278		352		701		828

Operating Income		47		8		96		35
Other Income and Expenses:
Miscellaneous income		1		3		2		6
Miscellaneous expense		-		(2)		(1)		(3)

Total other income		1		1		1		3

Interest Charges		26		26		52		50

Income (Loss) Before Income Taxes		22		(17)		45		(12)
Income Taxes (Benefit)		9		(7)		18		(5)

Net Income (Loss)		13		(10)		27		(7)
Preferred Stock Dividends		-		-		1		1

Net Income (Loss) Available to Common Stockholder	$	13	$	(10)	$	26	$	(8)

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

ILLINOIS POWER COMPANY

BALANCE SHEET

(Unaudited) (In millions)


	June 30, 2009		December 31, 2008
ASSETS
Current Assets:
Cash and cash equivalents	$	64	$	50
Accounts receivable – trade (less allowance for doubtful accounts of $11 and $12, respectively)		118		152
Unbilled revenue		74		133
Accounts receivable – affiliates		53		23
Advances to money pool		-		44
Materials and supplies		94		144
Counterparty collateral asset		32		35
Current portion of regulatory assets		90		57
Other current assets		27		21

Total current assets		552		659

Property and Plant, Net		2,356		2,329
Investments and Other Assets:
Goodwill		214		214
Regulatory assets		565		517
Other assets		57		47

Total investments and other assets		836		778

TOTAL ASSETS	$	3,744	$	3,766


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	-	$	250
Accounts and wages payable		72		94
Accounts payable – affiliates		136		105
Taxes accrued		4		8
Customer deposits		40		50
Mark-to-market derivative liabilities		43		36
Mark-to-market derivative liabilities – affiliates		47		20
Other current liabilities		81		85

Total current liabilities		423		648

Long-term Debt, Net		1,146		1,150
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		191		176
Regulatory liabilities		83		76
Pension and other postretirement benefits		297		314
Other deferred credits and liabilities		270		151

Total deferred credits and other liabilities		841		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		1,252		1,194
Preferred stock not subject to mandatory redemption		46		46
Retained earnings		32		7
Accumulated other comprehensive income		4		4

Total stockholders’ equity		1,334		1,251

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,744	$	3,766

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

ILLINOIS POWER COMPANY

STATEMENT OF CASH FLOWS

(Unaudited) (In millions)


	Six Months Ended June 30,
	2009		2008
Cash Flows From Operating Activities:
Net income (loss)	$	27	$	(7)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		53		43
Amortization of debt issuance costs and premium/discounts		2		4
Deferred income taxes		13		14
Other		(1)		-
Changes in assets and liabilities:
Receivables		65		24
Materials and supplies		50		20
Accounts and wages payable		22		41
Taxes accrued		(4)		(2)
Assets, other		9		(1)
Liabilities, other		22		40
Pension and other postretirement benefits		3		3

Net cash provided by operating activities		261		179

Cash Flows From Investing Activities:
Capital expenditures		(91)		(73)
Money pool advances, net		44		(5)
Other		-		(1)

Net cash used in investing activities		(47)		(79)

Cash Flows From Financing Activities:
Dividends on common stock		-		(30)
Dividends on preferred stock		(1)		(1)
Debt issuance costs		(7)		(2)
Redemptions, repurchases and maturities of long-term debt		(250)		(337)
Issuance of long-term debt		-		336
Capital contribution from parent		58		-
IP SPT maturities		-		(43)
Overfunding of TFNs		-		4

Net cash used in financing activities		(200)		(73)


Net change in cash and cash equivalents		14		27
Cash and cash equivalents at beginning of year		50		6

Cash and cash equivalents at end of period	$	64	$	33

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)

June 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 non-rate-regulated 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 non-rate-regulated electric generation business in Illinois and Missouri.

•

CILCO, or Central Illinois Light Company, also known as AmerenCILCO, is a subsidiary of CILCORP (a holding company). It operates a rate-regulated electric transmission and distribution business, a non-rate-regulated electric generation business (through its subsidiary, AERG) and a rate-regulated natural gas transmission and distribution business, 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 August 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 six months ended June 30, 2009 and 2008. The number of stock options, restricted stock shares, and performance share units outstanding was immaterial.

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

A summary of nonvested shares as of June 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
	Shares		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^(a)	741,738			15.52	-			-
Dividends	-			-	4,134			23.99
Forfeitures	(4,080	)		29.47	(3,645	)		48.30
Vested^(b)	(126,620	)		16.98	(82,277	)		45.15
Nonvested at June 30, 2009	1,287,015		$	29.91	131,895		$	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 $3 million and $7 million for the three months ended June 30, 2009 and 2008, respectively, and a related tax benefit of $1 million and $3 million for the three months ended June 30, 2009 and 2008, respectively. Ameren recorded compensation expense of $8 million and $14 million for each of the six-month periods ended June 30, 2009 and 2008, respectively, and a related tax benefit of $3 million and $5 million for the six-month periods ended June 30, 2009 and 2008, respectively. As of June 30, 2009, total compensation expense of $15 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 22 months.

Accounting Changes and Other Matters

SFAS No. 157, Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and expands required disclosures about fair value measurements. We adopted SFAS No. 157 as of January 1, 2008, for financial assets and liabilities and as of January 1, 2009, for nonfinancial assets and liabilities not already reported at fair value on a recurring basis. See Note 7 - Fair Value Measurements for additional information on our adoption of SFAS No. 157.

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51

In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards for minority interests, which have been recharacterized as noncontrolling interests. Under the provisions of SFAS No. 160, noncontrolling interests will 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 will be accounted for as equity transactions; net income attributable to the noncontrolling interest will 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, will be recorded at fair value, with any gain or loss recognized in earnings. We adopted SFAS No. 160 as of the beginning of 2009. SFAS No. 160 applies prospectively, except for the presentation and disclosure requirements, for which it applies retroactively. This standard is applicable to Ameren and CILCORP. See Noncontrolling Interest below for additional information.

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

In March 2008, the FASB issued SFAS No. 161, which requires enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 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. SFAS No. 161 was effective in the first quarter of 2009. The adoption

of SFAS No. 161 did not have a material impact on our results of operations, financial position, or liquidity, because it provided enhanced disclosure requirements only. See Note 6 - Derivative Financial Instruments for additional information on our adoption of SFAS No. 161.

FSP SFAS No. 157-4, 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 FSP SFAS No. 157-4, which was effective for us as of June 30, 2009. FSP SFAS No. 157-4 provides additional 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 FSP SFAS No. 157-4 did not have a material impact on our results of operations, financial position, or liquidity.

FSP SFAS No. 107-1 and APB Opinion No. 28-1, Interim Disclosures about Fair Value of Financial Instruments

In April 2009, the FASB issued FSP SFAS No. 107-1 and APB Opinion No. 28-1, which was effective for us as of June 30, 2009. It amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” and APB Opinion No. 28, “Interim Financial Reporting,” 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 FSP SFAS No. 107-1 and APB Opinion No. 28-1 did not have a material impact on our results of operations, financial position, or liquidity, because it provides enhanced disclosure requirements only. See Note 7 - Fair Value Measurements for our interim reporting disclosures.

FSP SFAS No. 115-2 and SFAS No. 124-2, Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB issued FSP SFAS No. 115-2 and SFAS No. 124-2, which establishes 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 FSP, 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. FSP SFAS No. 115-2 and SFAS No. 124-2 was effective for us as of June 30, 2009. The adoption of FSP SFAS No. 115-2 and SFAS No. 124-2 did not have a material impact on our results of operations, financial position, or liquidity.

SFAS No. 165, Subsequent Events

In May 2009, the FASB issued SFAS No. 165, effective for interim and annual reporting periods ending after June 15, 2009. SFAS No. 165 establishes 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. SFAS No. 165 was effective for us as of June 30, 2009. The adoption did not have a material impact on our results of operations, financial position, or liquidity.

SFAS No. 167, Amendments to FASB Interpretation No. 46(R)

In June 2009, the FASB issued SFAS No. 167, which significantly changes the consolidation model for VIEs. SFAS No. 167 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. Additionally, SFAS No. 167 changes the consideration of kick-out rights in determining if an entity is a VIE, which may cause certain additional entities to now be considered VIEs. Further, SFAS No. 167 requires an ongoing reconsideration of the primary beneficiary. It also amends the events that trigger a reassessment of whether an entity is a VIE. This standard is effective for us as of January 1, 2010. We are still determining the impact the adoption of SFAS No. 167 will have on our results of operations, financial position, and liquidity, if any.

SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of SFAS No. 162

In June 2009, the FASB issued SFAS No. 168 (the “Codification”), which will become 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 will supersede all non-SEC accounting and reporting standards. All other nongrandfathered, non-SEC accounting literature not included in the Codification will become nonauthoritative. The Codification was effective for us as of July 1, 2009. The adoption of the Codification will not impact our results of operations, financial position, or liquidity. The adoption of the Codification will change future referencing of authoritative accounting literature to conform to the Codification.

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 in the first quarter 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 June 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 June 30, 2009. Emission allowances consist of various individual emission allowance certificates and do not have expiration dates. Emission allowances are charged to fuel expense as they are used in operations.


SO2 and NOx in tons	SO2 ^(a)	NOx ^(b)	Book Value^(c)
Ameren^(d)	3,144,000	51,267	150	^(e)
UE	1,686,000	28,633	41
Genco	764,000	15,152	42
CILCORP	360,000	2,621	34	^(f)
CILCO (AERG)	360,000	2,621	2
EEI	334,000	4,861	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 $25 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 the 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 six months ended June 30, 2009 and 2008.


	Three Months					Six Months
	2009			2008		2009			2008
Ameren^(a)(b)	$	8		$	9	$	13		$	16
UE		(c	)		-		(c	)		(1	)
Genco		5			6		8			13
CILCORP^(b)		2			3		2			3
CILCO (AERG)		1			-		1			-

(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.

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 six months ended June 30, 2009 and 2008:


	Three Months				Six Months
	2009		2008		2009		2008
Ameren	$	42	$	38	$	84	$	87
UE		30		27		53		52
CIPS		3		3		8		9
CILCORP		2		2		6		7
CILCO		2		2		6		7
IP		7		6		17		19

Uncertain Tax Positions

The amount of unrecognized tax benefits as of June 30, 2009, was $106 million, $24 million, less than $1 million, $39 million, $27 million, $27 million and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. The total unrecognized tax benefits (detriments) that would impact the effective tax rate, if recognized, for each of the respective companies was as follows: Ameren - $10 million, UE - $1 million, CIPS - $- million, Genco - ($2 million), CILCORP - less than $1 million, CILCO - less than $1 million, and IP - $- million.

Ameren remains subject to U.S. federal income tax examination by the Internal Revenue Service for years 2005, 2006 and 2007. State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. 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 that are 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. Equity changes attributable to the noncontrolling interest at Ameren included net income of $3 million and $11 million and dividends paid to the noncontrolling interest holders of $8 million and $11 million for the three months ended June 30, 2009 and 2008, respectively. Equity changes attributable to the noncontrolling interest at Ameren included net income of $7 million and $22 million and dividends paid to the noncontrolling interest holders of $16 million and $21 million for the six months ended June 30, 2009, and 2008, respectively. CILCORP had no changes in equity attributable to the noncontrolling interest for the three and six months ended June 30, 2009. For the three and six months ended June 30, 2008, equity changes attributable to the noncontrolling interest at CILCORP included net income of $1 million and $1 million, respectively, and dividends paid to the noncontrolling interest holders of $1 million and $1 million, respectively.

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 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. UE cannot predict the outcome of the court appeals.

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 a 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 February 28, 2010.

UE’s filing includes a request for interim rate relief which, if approved, would place into effect approximately $37 million of the requested increase on October 1, 2009, subject to refund with interest based on the final outcome of the rate proceeding. The amount of this interim increase request reflects the increased revenue requirement associated with rate base additions made by UE between October 2008 and May 2009.

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, UE’s largest electric customer, to prospectively address the significant lost revenues UE can incur due to Noranda’s operational issues at its 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 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 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. 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 2009 Energy Efficiency Legislation

In July 2009, the Missouri governor signed a law that takes effect August 28, 2009, that, 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 as opposed to the current model of cost recovery.

Illinois

Pending Electric and Natural Gas Delivery Service Rate Cases

CIPS, CILCO and IP filed requests with the ICC in June 2009 to increase their annual revenues for electric delivery service by $181 million in the aggregate (CIPS - $51 million, CILCO - $28 million, and IP - $102 million). In supplemental testimony filed in July 2009, CIPS, CILCO, and IP revised their requests to an increase in annual revenues for electric delivery service of $176 million in the aggregate (CIPS - $50 million, CILCO - $28 million, and IP - $98 million). The electric rate increase requests are based on an 11.75% to 12.25% 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.

CIPS, CILCO and IP also filed requests with the ICC in June 2009 to increase their annual revenues for natural gas delivery service by $45 million in the aggregate (CIPS - $11 million, CILCO - $9 million, and IP - $25 million). In supplemental testimony filed in July 2009, CIPS, CILCO, and IP revised their requests to an increase in annual revenues for natural gas delivery service of $43 million in the aggregate (CIPS - $11 million, CILCO - $9 million, and

IP - $23 million). The natural gas rate increase requests are based on an 11.25% to 11.6% 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 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. 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 June 30, 2009, of $6 million, $1 million, less than $1 million, $1 million, $3 million, and $1 million, respectively (quarter ended June 30, 2008 - $11 million, $1 million, $1 million, $2 million, $5 million, and $2 million, respectively) and during the six months ended June 30, 2009, of $12 million, $2 million, $1 million, $2 million, $5 million, and $2 million, respectively (six months ended June 30, 2008 - $22 million, $3 million, $2 million, $4 million, $9 million, and $4 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.

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 $20 million of capital costs and an estimated $60 million of cumulative operations and maintenance expenses for the 2009 through 2013 timeframe in order to implement the recommendations. The Ameren Illinois Utilities requested recovery for 2009 and 2010 costs in the electric delivery service rate cases filed in June 2009, and they will seek recovery of the remainder of these costs in future rate cases.

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 beginning with 2008 and prospectively. During 2008, the Ameren Illinois Utilities under collected approximately $25 million (CIPS - $5 million, CILCO - $4 million, and IP - $16 million). The Ameren Illinois Utilities plan to file with the ICC in August 2009 electric and gas rate adjustment clause tariffs to recover bad debt expense not recovered in 2008 and to adjust rates to recover the differential thereafter. The ICC has up to 180 days from the date of filing to approve, or approve as modified, the filed tariffs. Upon ICC approval of the rate adjustment clause tariffs, 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.

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 is 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 current 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 June 30, 2009, UE had capitalized approximately $65 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. However, UE cannot at this time predict which option will ultimately be selected, whether any or all of its investment in this project will be realized or whether there will be a material impact on UE’s and Ameren’s results of operations. If all efforts are permanently abandoned with respect to the future construction of a new nuclear unit in Missouri, 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.

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. 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 rehearing request will have a material effect on their 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. These facilities, as described below, cumulatively provide $2.1 billion of credit through July 14, 2010, reducing to $1.8795 billion through June 30, 2011, and 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 as stated 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, commercial paper liquidity support 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 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 under (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 June 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
June 30, 2009:
Average daily borrowings outstanding during 2009	$	293		$	376		$	17		$	686
Outstanding short-term debt at period end		429			407			-			836
Weighted-average interest rate during 2009		1.14	%		1.14	%		1.04	%		1.14	%
Peak short-term borrowings during 2009^(b)	$	484		$	457		$	50		$	940
Peak interest rate during 2009		5.50	%		5.50	%		1.11	%		5.50	%


Supplemental Agreement ($150 million)							Ameren (Parent)			UE			Genco			Total
June 30, 2009:
Average daily borrowings outstanding during 2009							$	(c	)	$	(c	)	$	-		$	1
Outstanding short-term debt at period end								56			53			-			109
Weighted-average interest rate during 2009								5.50	%		5.50	%		-			5.50	%
Peak short-term borrowings during 2009^(b)							$	56		$	53		$	-		$	109
Peak interest rate during 2009								5.50	%		5.50	%		-			5.50	%

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

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

2006 $500 Million Credit Facility (Terminated)	CIPS			CILCORP (Parent)			CILCO (Parent)			IP			AERG			Total
June 30, 2009:
Average daily borrowings outstanding during 2009	$	5		$	49		$	-		$	-		$	96		$	150
Outstanding short-term debt at period end		-			-			-			-			-			-
Weighted-average interest rate during 2009		2.02	%		1.88	%		-			-			1.34	%		1.54	%
Peak short-term borrowings during 2009^(b)	$	62		$	50		$	-		$	-		$	151		$	263
Peak interest rate during 2009		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 simultaneous peak short-term borrowings under all facilities during the first six months of 2009 were $1.0 billion.

(c)	Amount less than $1 million.

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 June 30, 2009, were $344 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 2.07% and 2.10% during the three and six months ended June 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 2.00% and 1.98% during the three and six months ended June 30, 2009, respectively. 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 (as defined below) 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 June 30, 2009, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2009 Multiyear Credit Agreements, were 54%, 54% 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 June 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 54%, 45%, 46%, and 47%, 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 June 30, 2009 was 4.4 to 1. Failure to satisfy these capitalization 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 then 65% of consolidated total capitalization pursuant to a calculation defined in the term loan agreement. As of June 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 53%.

None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At June 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 June 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 six months ended June 30, 2009, was 0.2% and 0.2%, respectively (2008 - 2.8% and 3.5%, 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 June 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 six months ended June 30, 2009, was 1.1% and 1.1%, respectively (2008 - 3.1% and 3.8%, 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 six months ended June 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 0.8 million new shares of common stock valued at $19 million and 1.9 million new shares valued at $47 million in the three and six months ended June 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 will be used to provide such amounts, by way of a capital contribution, loan or otherwise to CILCORP, to permit CILCORP to repay its outstanding 8.70% senior notes due October 15, 2009.

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 $0.5 million and $1 million (2008 - $2 million and $3 million) for the three and six months ended June 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 outstanding 8.70% senior notes due 2009 ($123.755 million aggregate principal amount) and its 9.375% senior bonds due 2029 ($210.565 million aggregate principal amount). In April 2009, CILCORP terminated the tender offer and the consent solicitation related to the 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 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 June 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	2.1	$	279	³2.5	28.4	$	769
CIPS	³2.0	2.8		128	³1.5	1.7		47
CILCO	³2.0^(d)	8.6		215	³2.5	109.1		50	^(e)
IP	³2.0	2.7		939	³1.5	1.4		-

(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 $110 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 six months ended June 30, 2009, CILCO had earnings equivalent to at least 31% 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 June 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 June 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)	5.7	£60	%	50	%
CILCORP^(c)	³2.2		4.1	£67	%	40	%

(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 June 30, 2009, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were BB+, Ba2, 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 June 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 six months ended June 30, 2009 and 2008:


	Three Months						Six Months
	2009			2008			2009			2008
Ameren:^(a)
Miscellaneous income:
Interest and dividend income	$	7		$	13		$	15		$	25
Allowance for equity funds used during construction		8			5			14			11
Other		2			1			4			2
Total miscellaneous income	$	17		$	19		$	33		$	38
Miscellaneous expense:
Other	$	(7	)	$	(8	)	$	(11	)	$	(13	)
Total miscellaneous expense	$	(7	)	$	(8	)	$	(11	)	$	(13	)
UE:
Miscellaneous income:
Interest and dividend income	$	7		$	10		$	14		$	18
Allowance for equity funds used during construction		7			5			13			11
Other		1			-			1			-
Total miscellaneous income	$	15		$	15		$	28		$	29
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(4	)	$	(4	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(4	)	$	(4	)


	Three Months						Six Months
	2009			2008			2009			2008
CIPS:
Miscellaneous income:
Interest and dividend income	$	1		$	2		$	3		$	5
Other		1			1			2			1
Total miscellaneous income	$	2		$	3		$	5		$	6
Miscellaneous expense:
Other	$	-		$	(2	)	$	(1	)	$	(2	)
Total miscellaneous expense	$	-		$	(2	)	$	(1	)	$	(2	)
Genco:
Miscellaneous income:
Other	$	-		$	1		$	-		$	1
Total miscellaneous income	$	-		$	1		$	-		$	1
CILCORP:
Miscellaneous income:
Interest income	$	-		$	1		$	-		$	1
Total miscellaneous income	$	-		$	1		$	-		$	1
Miscellaneous expense:
Other		(1	)		(2	)		(2	)		(2	)
Total miscellaneous expense	$	(1	)	$	(2	)	$	(2	)	$	(2	)
CILCO:
Miscellaneous income:
Interest income	$	-		$	1		$	-		$	1
Total miscellaneous income	$	-		$	1		$	-		$	1
Miscellaneous expense:
Other		(2	)		(1	)		(3	)		(1	)
Total miscellaneous expense	$	(2	)	$	(1	)	$	(3	)	$	(1	)
IP:
Miscellaneous income:
Interest income	$	-		$	2		$	-		$	4
Allowance for equity funds used during construction		1			-			1			-
Other		-			1			1			2
Total miscellaneous income	$	1		$	3		$	2		$	6
Miscellaneous expense:
Other	$	-		$	(2	)	$	(1	)	$	(3	)
Total miscellaneous expense	$	-		$	(2	)	$	(1	)	$	(3	)

(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. Price fluctuations in natural gas, fuel, electricity, and emission allowances 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, emission allowances or purchased power 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 June 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)	89,119,000		(f	)	(f	)	(f	)
UE	49,242,000		(f	)	(f	)	(f	)
Genco	19,155,000		(f	)	(f	)	(f	)
CILCORP/CILCO	10,401,000		(f	)	(f	)	(f	)
Natural gas (in mmbtu)
Ameren^(e)	194,941,000		(f	)	6,278,000		118,342,000
UE	26,451,000		(f	)	(f	)	18,189,000
CIPS	33,563,000		(f	)	(f	)	19,186,000
Genco	1,665,000		(f	)	4,390,000		(f	)
CILCORP/CILCO	57,903,000		(f	)	868,000		29,372,000
IP	75,197,000		(f	)	(f	)	51,595,000
Heating oil (in gallons)
Ameren^(e)	(f	)	(f	)	186,018,000		42,588,000
UE	(f	)	(f	)	(f	)	42,588,000
Power (in megawatthours)
Ameren^(e)	84,887,000		5,961,000		31,006,000		13,339,000
UE	3,921,000		(f	)	232,000		3,795,000
CIPS	(f	)	(f	)	(f	)	12,813,000
CILCORP/CILCO	(f	)	(f	)	(f	)	6,600,000
IP	(f	)	(f	)	(f	)	19,413,000
SO₂ emission allowances (in tons)
Ameren	(f	)	(f	)	2,000		(f	)
Genco	(f	)	(f	)	2,000		(f	)

(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, 2012, and 2009 for natural gas, heating oil, power, and SO₂ emission allowances, respectively.

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

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

(f)	Not applicable.

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133), 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 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 under SFAS No. 133. We also consider whether gains and losses resulting from such derivatives qualify for deferral under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). 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.

Contracts that qualify for fair value hedge accounting 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. In addition, the underlying exposure being hedged in a fair value hedge relationship is similarly treated. The net effect to the statement of income in a fair value hedge relationship is equal to the change in fair value of the derivative instrument offset by the change in the value of the underlying.

Contracts that qualify for deferral under SFAS No. 71 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 under SFAS No. 133, or deferral accounting under SFAS No. 71. 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 June 30, 2009:


	Balance Sheet Location	Ameren^(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Derivative assets designated as hedging instruments under SFAS No. 133
Commodity contracts:
Power	MTM derivative assets	$	66		$	-		$	(b	)	$	(b	)	$	(b	)	$	(b	)
	Other assets		7			-			-			-			-			-
	Total assets	$	73		$	-		$	-		$	-		$	-		$	-
Derivative liabilities designated as hedging instruments under SFAS No. 133
Commodity contracts:
Power	MTM derivative liabilities	$	1		$	(b	)	$	-		$	(b	)	$	-		$	-
	Total liabilities	$	1		$	-		$	-		$	-		$	-		$	-
Derivative assets not designated as hedging instruments under SFAS No. 133
Commodity contracts:
Natural gas	MTM derivative assets	$	2		$	-		$	(b	)	$	(b	)	$	(b	)	$	(b	)
Heating oil	MTM derivative assets		28			3			(b	)		(b	)		(b	)		(b	)
	Other assets		57			16			-			-			-			-
Power	MTM derivative assets		181			28			(b	)		(b	)		(b	)		(b	)
	Other current assets		-			-			-			-			-			-
	Other assets		21			-			1			-			1			2
	Total assets	$	289		$	47		$	1		$	-		$	1		$	2
Derivative liabilities not designated as hedging instruments under SFAS No. 133
Commodity contracts:
Natural gas	MTM derivative liabilities	$	102		$	(b	)	$	18		$	(b	)	$	21		$	39
	Other current liabilities		-			16			-			-			-			-
	Other deferred credits and liabilities		34			5			8			-			6			15
Heating oil	MTM derivative liabilities		21			(b	)		-			(b	)		-			-
	Other deferred credits and liabilities		19			-			-			-			-			-
Power	MTM derivative liabilities		109			(b	)		3			(b	)		1			4
	MTM derivative liabilities – affiliates		(b	)		(b	)		37			(b	)		17			47
	Other current liabilities		-			7			-			-			-			-
	Other deferred credits and liabilities		5			-			88			-			45			133
SO₂ emission allowances	MTM derivative liabilities		1			-			-			(b	)		-			-
	Other current liabilities		-			-			-			1			-			-
	Total liabilities	$	291		$	28		$	154		$	1		$	90		$	238

(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 June 30, 2009:


	Ameren^(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Cumulative gains (losses) deferred in accumulated OCI:
Power forwards^(b)	$	69		$	-		$	-		$	-		$	-		$	-
Interest rate swaps^(c)(d)		(10	)		-			-			(10	)		-			-
Cumulative gains (losses) deferred in regulatory assets or liabilities:
Natural gas swaps and futures contracts^(e)		(128	)		(22	)		(27	)		-			(26	)		(53	)
Financial contracts^(f)		16			21			(126	)		-			(63	)		(182	)
Heating oil options and swaps^(g)		(5	)		(5	)		-			-			-			-

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

(b)	Represents the MTM value for the hedged portion of electricity price exposure through August 2011, including current gains of $55 million at Ameren as of June 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 that began in June 2002. The carrying value at June 30, 2009, was $2 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 that began in April 2008. The carrying value at June 30, 2009 was a loss of $12 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 October 2013 at UE and CIPS, through March 2013 at CILCO and through March 2014 at IP as of June 30, 2009. Current losses deferred as regulatory assets include $16 million, $19 million, $21 million, and $39 million at UE, CIPS, CILCO and IP, respectively, as of June 30, 2009.

(f)

Represents gains (losses) associated with financial contracts. The financial contracts are a partial hedge of power price exposure through December 2010 at UE and December 2012 at CIPS, CILCO, and IP. Current gains deferred as regulatory liabilities include $24 million at UE as of June 30, 2009. Current losses deferred as regulatory assets include $7 million, $39 million, $18 million, and $51 million at UE, CIPS, CILCO and IP, respectively, as of June 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 2012. Current gains deferred as regulatory liabilities include $2 million at UE as of June 30, 2009. Current losses deferred as regulatory assets include $11 million at UE as of June 30, 2009.

Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. In all other transactions, we are exposed to credit risk. 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 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 reviewed our individual counterparties and categorized 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 June 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)	$	639	$	14	$	48	$	177	$	31	$	206	$	18	$	82	$	1,215
UE		70		10		9		32		-		36		-		-		157
CIPS		-		-		-		1		-		-		-		-		1
Genco		-		3		1		3		-		-		4		-		11
CILCORP/CILCO		-		1		-		3		-		-		-		-		4
IP		-		-		-		3		-		-		1		-		4

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

The following table presents the amount of cash collateral held from counterparties, as of June 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 June 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 $39 million and $1 million held by Ameren and UE, respectively, as of June 30, 2009. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of June 30, 2009:


	Affiliates		Coal Producers		Electric Utilities		Financial Companies		Commodity Marketing Companies		Municipalities/ Cooperatives		Oil and Gas Companies		Retail Companies		Total
Ameren^(a)	$	617	$	1	$	19	$	130	$	15	$	157	$	16	$	81	$	1,036
UE		70		1		8		29		-		35		-		-		143
CIPS		-		-		-		-		-		-		-		-		-
Genco		-		-		1		-		-		-		3		-		4
CILCORP/CILCO		-		-		-		1		-		-		-		-		1
IP		-		-		-		-		-		-		1		-		1

(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 June 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 June 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)	$	693	$	116	$	386
UE		162		14		143
CIPS		57		26		28
Genco		50		-		45
CILCORP/CILCO		82		26		48
IP		135		48		55

(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 (loss) for the three months ended June 30, 2009, associated with derivative instruments designated as cash flow hedges:


Derivatives in SFAS No. 133 Cash Flow Hedging Relationship	Amount of Gain (Loss) Recognized in OCI on Derivative^(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 Derivative^(c)	Amount of Gain (Loss) Recognized in Income on Derivative^(c)
Ameren:^(d)
Power	$	1	Operating Revenues - Electric	$	(23	)	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 (loss) for the six months ended June 30, 2009, associated with derivative instruments designated as cash flow hedges:


Derivatives in SFAS No. 133 Cash Flow Hedging Relationship	Amount of Gain (Loss) Recognized in OCI on Derivative^(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 Derivative^(c)	Amount of Gain (Loss) Recognized in Income on Derivative^(c)
Ameren:^(d)
Power	$	47		Operating Revenues -Electric	$	(63	)	Operating Revenues - Electric	$	(16	)
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.

Fair Value Hedges

During the third quarter ended September 30, 2008, UE entered into foreign currency forward contracts to fix the amount of U.S. dollars UE would pay for future equipment deliveries denominated in euros. Subsequently, UE entered into an agreement with a supplier to terminate a purchase commitment related to those equipment deliveries. Therefore, the payments previously required under the commitment will not be incurred. As a result, all foreign currency forward contracts and fair value hedges were discontinued, resulting in less than a $1 million impact on earnings, during the second quarter ended June 30, 2009.

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments under SFAS No. 133 for the three months ended June 30, 2009:


	Derivatives Not Designated as Hedging Instruments under SFAS No. 133	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
Ameren^(a)	Natural gas (generation)	Operating Expenses - Fuel	$	1
	Natural gas (resale)	Operating Revenues - Gas		(2	)
	Heating oil	Operating Expenses - Fuel		15
	Power	Operating Revenues - Electric		(5	)
		Total	$	9
Genco	Heating oil	Operating Expenses - Fuel		9
CILCORP/CILCO	Natural gas (resale)	Operating Revenues - Gas	$	(2	)
	Heating oil	Operating Expenses - Fuel		3
		Total	$	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 under SFAS No. 133 for the six months ended June 30, 2009:


	Derivatives Not Designated as Hedging Instruments under SFAS No. 133	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
Ameren^(a)	Natural gas (generation)	Operating Expenses - Fuel	$	4
	Natural gas (resale)	Operating Revenues - Gas		-
	Heating oil	Operating Expenses - Fuel		39
	Power	Operating Revenues - Electric		29
		Total	$	72
UE	Natural gas (generation)	Operating Expenses - Fuel	$	4
	Heating oil	Operating Expenses - Fuel		25
	Power	Operating Revenues - Electric - excluding off-system		(2	)
	Power	Operating Revenues - Electric - off-system		1
		Total	$	28
Genco	Heating oil	Operating Expenses - Fuel	$	8
CILCORP/CILCO	Natural gas (resale)	Operating Revenues - Gas	$	-
	Heating oil	Operating Expenses - Fuel		3
		Total	$	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 deferral under SFAS No. 71 for the three months ended June 30, 2009:


	Derivatives Subject to Regulatory Deferral	Amount of Gain or (Loss) Recognized in Regulatory Assets or Regulatory Liabilities on Derivative
Ameren^(a)	Natural gas	$	74
	Heating oil		22
	Power		(22	)
	Total	$	74
UE	Natural gas	$	9
	Heating oil		22
	Power		(17	)
	Total	$	14
CIPS	Natural gas	$	14
	Power		3
	Total	$	17
CILCORP/CILCO	Natural gas	$	18
	Power		2
	Total	$	20
IP	Natural gas	$	33
	Power		9
	Total	$	42

(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 deferral under SFAS No. 71 for the six months ended June 30, 2009:


	Derivatives Subject to Regulatory Deferral	Amount of Gain or (Loss) Recognized in Regulatory Assets or Regulatory Liabilities on Derivative
Ameren^(a)	Natural gas	$	(10	)
	Heating oil		(5	)
	Power		16
	Total	$	1
UE	Natural gas	$	(6	)
	Heating oil		(5	)
	Power		21
	Total	$	10
CIPS	Natural gas	$	1
	Power		(70	)
	Total	$	(69	)
CILCORP/CILCO	Natural gas	$	(1	)
	Power		(34	)
	Total	$	(35	)
IP	Natural gas	$	(4	)
	Power		(97	)
	Total	$	(101	)

(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 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 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, under SFAS No. 71. 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 pre-tax 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

SFAS No. 157 provides a framework for measuring fair value for all assets and liabilities that are measured and reported at fair value. The Ameren Companies adopted SFAS No. 157 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 SFAS No. 157 for financial assets and liabilities at January 1, 2008, and for nonfinancial assets and liabilities at January 1, 2009, was not material. SFAS No. 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. 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. SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities primarily include exchange-traded derivatives and assets 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 SFAS No. 157. 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). SFAS No. 157 also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded $5 million in losses in the second quarter of 2009 related to valuation adjustments for counterparty default risk. At June 30, 2009, the counterparty default risk valuation adjustment related to net derivative (assets) liabilities totaled $(3) million, less than $1 million, $10 million, $7 million, and $25 million for Ameren, UE, CIPS, 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 June 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)		2		103		257		362
	Nuclear Decommissioning Trust Fund^(c)		189		56		3		248
UE	Derivative assets		-		8		39		47
	Nuclear Decommissioning Trust Fund^(c)		189		56		3		248
CIPS	Derivative assets^(b)		-		-		1		1
Genco	Derivative assets^(b)		-		-		-		-
CILCORP/CILCO	Derivative assets^(b)		-		-		1		1
IP	Derivative assets^(b)		-		-		2		2
Liabilities:
Ameren^(a)	Derivative liabilities^(b)	$	9	$	51	$	232	$	292
UE	Derivative liabilities^(b)		-		2		26		28
CIPS	Derivative liabilities^(b)		-		-		154		154
Genco	Derivative liabilities^(b)		-		-		1		1
CILCORP/CILCO	Derivative liabilities^(b)		-		-		90		90
IP	Derivative liabilities^(b)		-		-		238		238

(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


		Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
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 June 30, 2009:


					Realized and Unrealized Gains (Losses)								Total Realized			Purchases,								Change in Unrealized Gains (Losses)
		Beginning Balance at April 1, 2009			Included in Earnings^(a)		Included In OCI			Included in Regulatory Assets/ Liabilities			and Unrealized Gains (Losses)			Issuances, and Other Settlements, Net		Net Transfers Into (Out of) Level 3			Ending Balance at June 30, 2009			Related to Assets/ Liabilities Still Held at June 30, 2009
Other current assets	Ameren	$	2		$	-	$	-		$	-		$	-		$	-	$	-		$	2		$	-
Net derivative	Ameren	$	1		$	35	$	(24	)	$	34		$	45		$	22	$	(43	)	$	25		$	13
contracts	UE		(6	)		-		5			16			21			3		(5	)		13			7
	CIPS		(170	)		-		(10	)		(4	)		(14	)		31		-			(153	)		(4	)
	Genco		(2	)		-		-			-			-			1		-			(1	)		-
	CILCORP/CILCO		(108	)		5		(5	)		(5	)		(5	)		24		-			(89	)		1
	IP		(277	)		-		(16	)		5			(11	)		52		-			(236	)		5
Nuclear	Ameren	$	-		$	-	$	-		$	-		$	-		$	3	$	-		$	3		$	-
Decommissioning Trust Fund	UE		-			-		-			-			-			3		-			3			-

(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 six months ended June 30, 2009:


					Realized and Unrealized Gains (Losses)									Total Realized			Purchases,									Change in Unrealized Gains (Losses)
		Beginning Balance at January 1, 2009			Included in Earnings^(a)			Included In OCI			Included in Regulatory Assets/ Liabilities			and Unrealized Gains (Losses)			Issuances, and Other Settlements, Net			Net Transfers Into (Out of) Level 3			Ending Balance at June 30, 2009			Related to Assets/ Liabilities Still Held at June 30, 2009
Other current assets	Ameren	$	6		$	-		$	-		$	-		$	-		$	-		$	(4	)	$	2		$	-
Net derivative	Ameren	$	15		$	52		$	57		$	(52	)	$	57		$	7		$	(54	)	$	25		$	(32	)
contracts	UE		5			-			37			(3	)		34			(8	)		(18	)		13			(4	)
	CIPS		(84	)		-			(10	)		(108	)		(118	)		49			-			(153	)		(91	)
	Genco		(1	)		(1	)		-			-			(1	)		1			-			(1	)		-
	CILCORP/CILCO		(55	)		(19	)		(5	)		(47	)		(71	)		37			-			(89	)		(52	)
Nuclear	Ameren	$	2		$	-		$	-		$	-		$	-		$	1		$	-		$	3		$	-
Decommissioning Trust Fund	UE		2			-			-			-			-			1			-			3			-

(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 June 30, 2008:


				Realized and Unrealized Gains (Losses)								Total Realized		Purchases,								Change in Unrealized Gains (Losses)
		Beginning Balance at April 1, 2008		Included in Earnings			Included In OCI			Included in Regulatory Assets/ Liabilities		and Unrealized Gains (Losses)		Issuances, and Other Settlements, Net			Net Transfers Into (Out of) Level 3			Ending Balance at June 30, 2008		Related to Assets/ Liabilities Still Held at June 30, 2008
Net derivative	Ameren	$	59	$	87		$	(25	)	$	109	$	171	$	(29	)	$	1		$	202	$	122
contracts	UE		15		8			3			12		23		2			(a	)		40		18
	CIPS		58		-			-			56		56		(2	)		-			112		56
	Genco		1		4			(a	)		-		4		(1	)		-			4		4
	CILCORP/CILCO		40		(1	)		-			42		41		(4	)		-			77		42
	IP		102		-			-			97		97		(4	)		-			195		101
Nuclear	Ameren	$	2	$	-		$	-		$	-	$	-	$	(1	)	$	-		$	1	$	-
Decommissioning Trust Fund	UE		2		-			-			-		-		(1	)		-			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 six months ended June 30, 2008:


				Realized and Unrealized Gains (Losses)								Total Realized		Purchases,								Change in Unrealized Gains (Losses)
		Beginning Balance at January 1, 2008		Included in Earnings			Included In OCI			Included in Regulatory Assets/ Liabilities		and Unrealized Gains (Losses)		Issuances, and Other Settlements, Net			Net Transfers Into (Out of) Level 3			Ending Balance at June 30, 2008		Related to Assets/ Liabilities Still Held at June 30, 2008
Net derivative	Ameren	$	19	$	93		$	(59	)	$	178	$	212	$	(19	)	$	(10	)	$	202	$	75
contracts	UE		3		10			10			19		39		(3	)		1			40		14
	CIPS		38		-			-			75		75		(1	)		-			112		66
	Genco		1		4			(a	)		-		4		(1	)		-			4		4
	CILCORP/CILCO		21		(1	)		(a	)		62		61		(5	)		-			77		54
	IP		55		-			-			140		140		(a	)		-			195		132
Nuclear	Ameren	$	5	$	-		$	-		$	-	$	-	$	(4	)	$	-		$	1	$	-
Decommissioning Trust Fund	UE		5		-			-			-		-		(4	)		-			1		-

(a)	Less than $1 million.

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 June 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 impairment charge recorded related to CILCORP’s goodwill. 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 June 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)	In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” 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 preferred stock at June 30, 2009:


	Carrying Amount		Fair Value
Ameren:^(a)
Long-term debt and capital lease obligations (including current portion)	$	7,450	$	7,363
Preferred stock		195		121
UE:
Long-term debt and capital lease obligations (including current portion)	$	4,026	$	3,950
Preferred stock		113		75
CIPS:
Long-term debt (including current portion)	$	421	$	411
Preferred stock		50		25
Genco:
Long-term debt (including current portion)	$	774	$	710
CILCORP:
Long-term debt (including current portion)	$	660	$	664
Preferred stock		19		13
CILCO:
Long-term debt (including current portion)	$	279	$	292
Preferred stock		19		13
IP:
Long-term debt (including current portion)	$	1,146	$	1,181
Preferred stock		46		29

(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

As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over four years as part of a comprehensive program providing approximately $1 billion of funding for rate relief to certain Illinois electric customers, including customers of the Ameren Illinois Utilities. At June 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 June 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 six months ended June 30, 2009, Genco incurred charges to earnings of $3 million and $5 million, respectively, for customer rate relief contributions and program funding reimbursements to the Ameren Illinois Utilities (CIPS - $1 million and $2 million, CILCO - less than $1 million and $1 million, IP - $1 million and $2 million, respectively), and AERG incurred charges to earnings of $1 million and $2 million, respectively (CIPS - less than $1 million and $1 million, CILCO - less than $1 million for both periods, 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 six months ended June 30, 2009 and 2008:


	Three Months		Six Months
	2009	2008	2009	2008
Genco sales to Marketing Company^(a)	3,494	3,529	6,958	7,941
AERG sales to Marketing Company^(a)	1,591	1,610	2,975	3,313
Marketing Company sales to CIPS^(b)	372	472	818	1,094
Marketing Company sales to CILCO^(b)	153	223	361	480
Marketing Company sales to IP^(b)	506	698	1,127	1,502

(a)	Genco and Marketing Company, and AERG and Marketing Company have power supply agreements 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 June 30, 2009, and December 31, 2008, there were no collateral postings 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 posting 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 June 30, 2009, there were no collateral postings 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 Agreement

In 2008, Genco and CIPS signed an agreement requiring Genco to fund the construction costs of upgrades to CIPS’ transmission system. At June 30, 2009, CIPS had recorded $2 million in Other Deferred Credits and Liabilities and Genco had recorded $2 million in Accounts Receivable - Affiliates. 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 $4 million) for the three and six months ended June 30, 2009, respectively.

CILCORP (parent company) had outstanding borrowings from Ameren of $210 million and $152 million at June 30, 2009, and December 31, 2008, respectively. The separate unilateral borrowing agreement between CILCORP and Ameren, entered into in March 2009, was repaid during the second quarter with no borrowings outstanding at June 30, 2009. The average interest rate on all of the Ameren borrowings was 3.6% and 2.6% for the three and six months ended June 30, 2009, respectively (2008 - 3.1% and 3.8%, respectively). CILCORP recorded interest expense of $1 million and $2 million for these borrowings for the three and six months ended June 30, 2009, respectively (2008 - less than $1 million for the three and six months periods).

CILCO (AERG) had outstanding borrowings from Ameren of $346 million at June 30, 2009. The separate unilateral borrowing agreement between CILCO (AERG) and Ameren, entered into in March 2009, was repaid during the second quarter with no borrowings outstanding at June 30, 2009. The average interest rate on all of the Ameren borrowings was 4.4% and 4.3% for the three and six months ended June 30, 2009, respectively. CILCO (AERG) recorded interest expense of $2 million and $2 million, respectively for these borrowings for the three and six months ended June 30, 2009.

UE had no outstanding borrowings directly from Ameren at June 30, 2009, and had outstanding borrowings directly from Ameren of $92 million at December 31, 2008. During the second quarter, UE did not have any borrowings from Ameren. The average interest rate on UE’s borrowings from Ameren was 1.4% for the six months ended June 30, 2009 (2008 - 3.8%). UE recorded interest expense of less than $1 million for these borrowings for the six months ended June 30, 2009 (2008 - less than $1 million for the six-month period).

The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the three and six months ended June 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													Six Months
Agreement		UE			CIPS			Genco			CILCORP^(a)	IP			UE			CIPS			Genco			CILCORP^(a)	IP
Operating Revenues:
Genco and AERG power supply	2009	$	(b	)	$	(b	)	$	218		$105	$	(b	)	$	(b	)	$	(b	)	$	440		$198	$	(b	)
agreements with Marketing Company	2008		(b	)		(b	)		199		70		(b	)		(b	)		(b	)		425		153		(b	)

Ancillary services and capacity	2009		(e	)		(b	)		(b	)	(b)		(b	)		1			(b	)		(b	)	(b)		(b	)
agreements with CIPS, CILCO and IP^(c)	2008		3			(b	)		(b	)	(b)		(b	)		6			(b	)		(b	)	(b)		(b	)

Genco gas sales to Medina Valley	2009		(b	)		(b	)		(e	)	(b)		(b	)		(b	)		(b	)		1		(b)		(b	)
	2008		(b	)		(b	)		-		(b)		(b	)		(b	)		(b	)		-		(b)		(b	)

CILCO support services^(h)	2009		(b	)		(b	)		(b	)	18		(b	)		(b	)		(b	)		(b	)	34		(b	)
	2008		(b	)		(b	)		(b	)	(b)		(b	)		(b	)		(b	)		(b	)	(b)		(b	)

Genco gas sales to distribution	2009		(b	)		(b	)		1		(b)		(b	)		(b	)		(b	)		1		(b)		(b	)
companies	2008		(b	)		(b	)		5		(b)		(b	)		(b	)		(b	)		5		(b)		(b	)
Total Operating Revenues	2009	$	(e	)	$	(b	)	$	219		$123	$	(b	)	$	1		$	(b	)	$	442		$232	$	(b	)
	2008		3			(b	)		204		70		(b	)		6			(b	)		430		153		(b	)

Purchased Power:
CIPS, CILCO and IP agreements with	2009	$	(b	)	$	37		$	(b	)	$16	$	52		$	(b	)	$	78		$	(b	)	$36	$	111
Marketing Company^(d)	2008		(b	)		31			(b	)	15		46			(b	)		72			(b	)	32		99

Ancillary services and capacity	2009		(b	)		(e	)		(b	)	(e)		(e	)		(b	)		(e	)		(b	)	(e)		(e	)
agreements with UE^(c)	2008		(b	)		1			(b	)	(e)		2			(b	)		2			(b	)	1		3

Ancillary services agreement with	2009		(b	)		-			(b	)	-		-			(b	)		(e	)		(b	)	(e)		(e	)
Marketing Company	2008		(b	)		1			(b	)	1		1			(b	)		3			(b	)	2		4

Executory tolling agreement with	2009		(b	)		(b	)		(b	)	(f)		(b	)		(b	)		(b	)		(b	)	(f)		(b	)
Medina Valley	2008		(b	)		(b	)		(b	)	9		(b	)		(b	)		(b	)		(b	)	22		(b	)
Total Purchased Power	2009	$	(b	)	$	37		$	(b	)	$16	$	52		$	(b	)	$	78		$	(b	)	$36	$	111
	2008		(b	)		33			(b	)	25		49			(b	)		77			(b	)	57		106


		Three Months													Six Months
Agreement		UE			CIPS			Genco			CILCORP^(a)	IP			UE			CIPS			Genco			CILCORP^(a)	IP

Gas purchases for resale
Gas purchases from Genco	2009	$	-		$	-		$	(b	)	$1	$	(e	)	$	-		$	-		$	(b	)	$1	$	(e	)
	2008		-			-			(b	)	5		-			-			-			(b	)	5		-
Operating Revenues and Purchased Power:
Insurance recoveries	2009	$	-		$	(b	)	$	-		$-	$	(b	)	$	-		$	(b	)	$	-		$-	$	(b	)
	2008		-			(b	)		(e	)	(1)		(b	)		(e	)		(b	)		(6	)	(1)		(b	)

Other Operations and Maintenance:
Ameren Services support services	2009	$	33		$	8		$	8		$9	$	12		$	65		$	15		$	14		$19	$	24
agreement	2008		36			15			7		15		22			71			28			14		28		42

CILCO support services	2009		(b	)		6			(b	)	(b)		8			(b	)		11			(b	)	(b)		15
	2008		(b	)		(b	)		(b	)	(b)		(b	)		(b	)		(b	)		(b	)	(b)		(b	)

AFS support services agreement	2009		2			(e	)		1		(e)		(e	)		4			1			2		1		1
	2008		1			1			(e	)	1		1			3			1			1		1		1

Insurance premiums^(g)	2009		(e	)		(b	)		(e	)	(e)		(b	)		1			(b	)		1		(e)		(b	)
	2008		2			(b	)		1		1		(b	)		5			(b	)		2		2		(b	)

Total Other Operations and	2009	$	35		$	14		$	9		$9	$	20		$	70		$	27		$	17		$20	$	40
Maintenance Expenses	2008		39			16			8		17		23			79			29			17		31		43
Interest Charges:
Interest expense (income) from money	2009	$	-		$	(e	)	$	(e	)	$(e)	$	(e	)	$	-		$	(e	)	$	1		$1	$	(e	)
pool borrowings (advances)	2008		-			(e	)		(e	)	(e)		(e	)		-			(e	)		(e	)	(e)		(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 June 30, 2009 (CIPS - $2 million, and IP - $2 million) and during the six months ended June 30, 2009 (CIPS - $3 million and IP - $5 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 these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 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 June 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			118	^(b)
	$	12,519	^(c)	$	118
Property damage:
Nuclear Electric Insurance Ltd.	$	2,750	^(d)	$	22
Replacement power:
Nuclear Electric Insurance Ltd.	$	490	^(e)	$	9
Energy Risk Assurance Company	$	64	^(f)	$	-

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

(b)

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

(c)

Limit of liability for each incident under Price-Anderson. 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.

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

(e)	Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. Weekly indemnity of $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 weeks thereafter.

(f)

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

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

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

If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or if coverage is unavailable, UE is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and UE’s results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. We have also entered into various long-term commitments for the purchase of electric capacity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

Our commitments for the procurement of coal have materially changed from amounts previously disclosed as of December 31, 2008. The following table presents our total estimated coal purchase commitments at June 30, 2009:


	2009		2010		2011		2012		2013		Thereafter
Ameren^(a)	$	344	$	967	$	802	$	562	$	178	$	635
UE		177		530		435		242		120		564
Genco		64		186		132		110		6		-
CILCORP/CILCO		27		104		105		94		47		71

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

Our commitments for the procurement of natural gas have materially changed from amounts previously disclosed as of December 31, 2008. The following table presents our total estimated natural gas purchase commitments at June 30, 2009:


	2009		2010		2011		2012		2013		Thereafter
Ameren^(a)	$	280	$	492	$	406	$	254	$	152	$	282
UE		45		77		59		45		35		31
CIPS		53		85		69		56		44		32
Genco		8		8		8		5		3		8
CILCORP/CILCO		58		120		117		71		47		190
IP		109		197		152		75		25		21

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

Our commitments for the procurement of nuclear fuel have materially changed from amounts previously disclosed as of December 31, 2008. The following table presents our total estimated nuclear fuel procurement commitments at June 30, 2009:


	2009		2010		2011		2012		2013		Thereafter
Ameren	$	35	$	60	$	18	$	56	$	58	$	431
UE		35		60		18		56		58		431

Our commitments for the purchase of electric capacity have materially changed from amounts previously disclosed as of December 31, 2008. The following table presents our total estimated electric capacity commitments at June 30, 2009:


	2009		2010		2011		2012		2013		Thereafter
Ameren	$	10	$	22	$	22	$	22	$	22	$	230
UE		10		22		22		22		22		230

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 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 contract. See Note 2 - Rate and Regulatory Matters for further information.

Ameren Illinois Utilities’ Purchased Power Agreements

The IPA procured capacity through a RFP process on behalf of the Ameren Illinois Utilities 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. As a result, the Ameren Illinois Utilities’ commitments for the purchase of electric capacity as of June 30, 2009, was $27 million, $26 million, $26 million and $1 million for 2009, 2010, 2011, and 2012, respectively.

Additionally, the IPA procured financial energy swaps through a RFP process on behalf of the Ameren Illinois Utilities 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. As a result, the Ameren Illinois Utilities’ commitments for the purchase of financial energy swaps as of June 30, 2009 was $112 million, $183 million, and $56 million for 2009, 2010, and 2011, respectively.

The IPA procured renewable energy credits through a RFP process on behalf of the Ameren Illinois Utilities which resulted in the Ameren Illinois Utilities contracting to purchase 720,000 credits at an average price of approximately $16 per credit, for the period June 1, 2009 through May 31, 2010. As a result, the Ameren Illinois Utilities’ commitments for the purchase of renewable energy credits as of June 30, 2009 were $6 million and $5 million for 2009 and 2010, respectively.

Illinois Electric Settlement Agreement

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


	Ameren		CIPS		CILCO (Illinois Regulated)		IP		Genco		CILCO (AERG)
2009^(a)	$	14.4	$	2.1	$	1.0	$	2.8	$	5.9	$	2.6
2010^(a)		1.9		0.3		0.1		0.4		0.8		0.3
Total	$	16.3	$	2.4	$	1.1	$	3.2	$	6.7	$	2.9

(a)	Estimated.

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 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 early 2010 and a final version in 2011.

The state of Missouri has adopted state 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_x emissions 30% and SO₂ emissions 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 state rules to implement the federal Clean Air Mercury Rule. However, those state 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 90%, NO_x emissions 50%, and SO₂ emissions 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, 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 submitted a request for a variance from the MPS to the Illinois Pollution Control Board. In preparing this request, Genco, CILCO (AERG) and EEI worked with the Illinois EPA and agreed to control SO₂ and NO_x emissions to lower levels between 2010 and 2020 in order to make the variance proposal “environmentally neutral.” In January 2009, the Illinois Pollution Control Board denied the variance request on procedural grounds. Genco, CILCO (AERG) and EEI filed a motion for reconsideration in February 2009. With the Illinois EPA’s concurrence, they then sought to amend the MPS within a pending rulemaking pertaining to technical amendments of the underlying mercury regulations. In April 2009, the Illinois Pollution Control Board approved the revisions to the MPS within that rulemaking. 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 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. Non-rate-regulated Generation has 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 June 30, 2009.

UE, Genco, CILCO 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, 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. Both sets of allowances for the years 2009 through 2014 were issued by the Missouri Department of Natural Resources in December 2007. Allocations for UE’s Missouri generating facilities 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. Both sets of allowances for the years 2009 through 2011 were issued by the Illinois EPA in April 2008. Allocations for UE’s, Genco’s, AERG’s, and EEI’s Illinois generating facilities 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

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. 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 and 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. Leaders in the U.S. Senate have indicated they are developing climate change legislation that they hope to bring before the full Senate in the fall 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 to 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 were enacted into law in its current form, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of the region’s reliance on electricity generated by coal-fired power plants. Natural gas emits about half the amount of CO₂ that coal emits 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 warming may also be subject to the activities 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. These 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.

With regard to greenhouse gas regulation under existing law, 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 Clean Air Act. This decision was a result of a Bush Administration ruling denying a waiver request by the state of California to implement such regulations. The Supreme Court sent the case back to the EPA to conduct a rulemaking process to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” In April 2009, the EPA issued a proposed determination finding that the combination of six greenhouse gases 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 by the combustion of fossil fuels by electric generating units. The comment period on this rulemaking is now closed. It is anticipated that the endangerment finding could enable states to regulate greenhouse gas emissions from automobiles. It could also set in motion the process of establishing emission limitations for power plants and other industrial sources of greenhouse gasses. This endangerment finding is expected to be final by the end of 2009. However, specific regulations governing power plants and other sources would be developed in subsequent rulemakings and may be preempted by federal legislative actions.

The EPA also proposed regulations in April 2009 that would require businesses, including fossil-fuel fired electric generators, to monitor and report their greenhouse gas emissions beginning January 2010. It is anticipated that these proposed regulations, if adopted, would supplement the existing emission monitoring and reporting requirements that are applicable to our facilities.

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 warming 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 regulation of greenhouse gas emissions will eventually be implemented. 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 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 for existing power plants to use the best available technology to protect aquatic species against environmental benefits in enforcing 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 for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of June 30, 2009, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 15, CILCO 4, and IP 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 June 30, 2009, estimated obligations were: CIPS - $17 million to $28 million, CILCO - $1 million, IP - $97 million to $161 million. CIPS, CILCO and IP have liabilities of $17 million, $1 million, and $97 million, respectively, recorded to represent estimated minimum obligations, as no other amount within the range was a better estimate.

CIPS is also responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of June 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 June 30, 2009, IP recorded a liability of $1 million to represent its best estimate of the obligation for these sites.

In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one 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 June 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, most 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.

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 are largely completed, and the results along with recommendations for appropriate remediation activities will be submitted to the EPA later this year. Following this submission, the EPA will ultimately select a remedy alternative and begin negotiations with various PRPs to implement it. Over the last several years, numerous other parties have joined the PRP group and presumably will participate in the funding of any required remediation. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection. As of June 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 July 2008, the EPA issued an administrative order to UE pertaining to a former coal tar distillery operated by Koppers Company or its predecessor and successor companies. UE is the current owner of the site but did not conduct any of the manufacturing operations involving coal tar or its 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 June 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 December 2004, AERG submitted a comprehensive conceptual 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 June 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 and 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) or

wastes. The EPA is considering regulating CCBs under the hazardous waste regulations, which could impact future disposal and handling costs at our facilities. Ameren received and responded to an information collection request from the EPA in March 2009. The EPA sent the information collection request to numerous electric generators in the country. The EPA is considering requiring as part of its proposed regulations that coal-fired power plants engage in the mandatory closure of surface impoundments used for the management of CCB. It is anticipated that some form of additional regulation concerning the integrity of ash ponds and the handling and disposal of CCB or waste may be proposed by the fourth quarter 2009. Ameren’s CCB impoundments were not identified in EPA’s recent listing of 44 high hazard potential impoundments containing CCBs. 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 settled with FERC and the State of Missouri all issues associated with the December 2005 Taum Sauk incident. In December 2008, the Department of the Army, Corps of Engineers filed a lawsuit regarding the Taum Sauk breach. The suit, which was filed in the U.S. District Court in Cape Girardeau, Missouri, claimed that Clearwater Lake in southeastern Missouri was damaged by sediment from the Taum Sauk breach. In April 2009, in response to the Corps of Engineers’ motion, the court dismissed the lawsuit without prejudice to the Corps of Engineers’ right to refile the lawsuit. UE cannot predict whether the lawsuit will be refiled.

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 $220 million. As of June 30, 2009, UE had paid $201 million, including costs resulting from the FERC-approved stipulation and consent agreement. UE accrued a $2 million liability while expensing $35 million for items not covered by insurance and recorded a $168 million receivable due from insurance companies under liability coverage. As of June 30, 2009, UE has received $95 million from insurance companies, which reduced the insurance receivable balance subject to liability coverage to $73 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 through early 2010. The estimated cost to rebuild the upper reservoir is in the range of $480 million. As of June 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 June 30, 2009, UE has received $208 million from insurance companies, which reduced the property insurance receivable balance as of June 30, 2009, to $212 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 $480 million cost of the design approved by FERC and being used by Ameren. Ameren disagrees with the position of these insurers and intends to defend its position. 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 $480 million. We are unable to predict the timing or outcome of this litigation, or its possible effect on UE’s results of operations, financial position or liquidity. Despite this litigation, discussions to settle claims under the property policy are ongoing with these insurance carriers and other insurance carriers not parties to the litigation.

Until the insurance review is completed and the litigation is 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. At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the facility, and the cost of replacement power (up to $8 million annually), will be recovered through insurance. Any amounts not recovered through insurance 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 June 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 June 30, 2009:


Specifically Named as Defendant
Ameren	UE	CIPS	Genco	CILCO	IP	Total^(a)
2	32	32	-	14	41	75

(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 June 30, 2009, seven 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 June 30, 2009, Ameren, UE, CIPS, CILCO and IP had liabilities of $14 million, $5 million, $3 million, $1 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 June 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 is not expected to have its permanent storage facility for spent fuel available before 2020. UE has sufficient installed storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.

Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. It is assumed that the Callaway nuclear plant site will be decommissioned based on the immediate dismantlement method and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are charged to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 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. The 2008 study included the minor tritium contamination discovered on the Callaway nuclear plant site, which did not result in a significant increase in the decommissioning cost estimate. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear

decommissioning trust fund for UE’s Callaway nuclear plant is reported as Nuclear Decommissioning Trust Fund in Ameren’s Consolidated Balance Sheet and UE’s Balance Sheet. This amount is legally restricted. It may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to a regulatory asset or regulatory liability, as appropriate.

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 six months ended June 30, 2009 and 2008, is shown below for the Ameren Companies:


	Three Months						Six Months
	2009			2008			2009			2008
Ameren:^(a)
Net income	$	168		$	217		$	313		$	366
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $9, $(27), $53 and $(63), respectively		17			(48	)		98			(111	)
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $17, $(3), $43 and $(6), respectively		(31	)		5			(77	)		11
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, $3, $7 and $1, respectively		(5	)		(4	)		(5	)		(2	)
Total comprehensive income, net of taxes		149			170			300			264
Less: Net income attributable to noncontrolling interests, net of taxes		3			11			7			22
Total comprehensive income attributable to Ameren Corporation, net of taxes	$	146		$	159		$	293		$	242
UE:
Net income	$	84		$	124		$	106		$	188
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $(4), $11 and $(11), respectively		-			(6	)		17			(17	)
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $1, $8 and $1, respectively		-			(2	)		(13	)		(1	)
Reclassification adjustment due to implementation of FAC, net of taxes of $-, $-, $18 and $-, respectively		-			-			(29	)		-
Total comprehensive income, net of taxes	$	84		$	116		$	81		$	170
CIPS:
Net income (loss)	$	1		$	(3	)	$	8		$	-
Total comprehensive income (loss), net of taxes	$	1		$	(3	)	$	8		$	-
Genco:
Net income	$	46		$	74		$	93		$	120
Unrealized net gain on derivative hedging instruments, net of taxes of $-, $4, $- and $-, respectively		-			6			-			-
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $4, $- and $4, respectively		-			(5	)		-			(5	)
Adjustment to pension and benefit obligation, net of taxes (benefit) of $-, $-, $- and $(2), respectively		-			-			1			3
Total comprehensive income, net of taxes	$	46		$	75		$	94		$	118
CILCORP:
Net income (loss)	$	24		$	5		$	(408	)	$	25
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 $1, $2, $1 and $1, respectively		(1	)		3			(1	)		3
Total comprehensive income (loss), net of taxes	$	23		$	8		$	(409	)	$	27
Less: Net income attributable to noncontrolling interests, net of taxes		-			1			-			1
Total comprehensive income (loss) attributable to CILCORP Inc., net of taxes	$	23		$	7		$	(409	)	$	26
CILCO:
Net income	$	31		$	12		$	64		$	38
Adjustment to pension and benefit obligation, net of taxes of $1, $2, $1 and $2, respectively		1			4			1			4
Total comprehensive income, net of taxes	$	32		$	16		$	65		$	42
IP:
Net income (loss)	$	13		$	(10	)	$	27		$	(7	)
Total comprehensive income (loss), net of taxes	$	13		$	(10	)	$	27		$	(7	)

(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 June 30, 2009, and our pension funding policy, Ameren expects to make annual contributions of $90 million to $250 million in each of the next five years. These amounts are estimates. They 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 a contribution to its pension plan of $24 million in the second quarter of 2009. A pension contribution was not made in the first half of 2008. In July 2009, Ameren made a $23 million contribution to its pension plan. Additionally, Ameren made contributions to its postretirement benefit plans during the second quarter 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 six months ended June 30, 2009 and 2008:


	Pension Benefits^(a)												Postretirement Benefits^(a)
	Three Months						Six Months						Three Months						Six Months
	2009			2008			2009			2008			2009			2008			2009			2008
Service cost	$	17		$	14		$	34		$	29		$	5		$	4		$	10		$	9
Interest cost		46			46			93			93			16			16			33			35
Expected return on plan assets		(50	)		(53	)		(102	)		(106	)		(14	)		(15	)		(27	)		(29	)
Amortization of:
Transition obligation		-			-			-			-			1			1			1			1
Prior service cost (benefit)		2			3			4			6			(2	)		(2	)		(4	)		(4	)
Actuarial loss		5			-			12			1			1			-			4			4
Net periodic benefit cost	$	20		$	10		$	41		$	23		$	7		$	4		$	17		$	16

(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 six months ended June 30, 2009 and 2008:


	Pension Costs										Postretirement Costs
	Three Months					Six Months					Three Months					Six Months
	2009		2008			2009		2008			2009		2008			2009		2008
Ameren^(a)	$	20	$	10		$	41	$	23		$	7	$	4		$	17	$	16
UE		12		10			25		19			3		-			7		6
CIPS		1		1			4		3			-		1			1		2
Genco		2		2			3		3			1		-			1		1
CILCORP		2		(2	)		4		(4	)		1		(1	)		2		(2	)
CILCO		4		-			8		2			2		-			4		2
IP		-		(3	)		1		(2	)		3		4			6		7

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

NOTE 13 - SEGMENT INFORMATION

Ameren has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s 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 Non-rate-regulated Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, and Marketing Company. The category called Other primarily includes Ameren parent company activities.

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

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

Ameren


Three Months	Missouri Regulated		Illinois Regulated			Non-rate-regulated Generation		Other			Intersegment Eliminations			Consolidated
2009:
External revenues	$	745	$	618		$	315	$	6		$	-		$	1,684
Intersegment revenues		7		6			106		6			(125	)		-
Net income (loss) attributable to Ameren Corporation^(a)		82		15			75		(7	)		-			165
2008:
External revenues	$	760	$	717		$	314	$	(1	)	$	-		$	1,790
Intersegment revenues		11		12			96		4			(123	)		-
Net income (loss) attributable to Ameren Corporation^(a)		122		(14	)		98		-			-			206

Six Months
2009:
External revenues	$	1,393	$	1,546		$	651	$	10		$	-		$	3,600
Intersegment revenues		14		14			222		10			(260	)		-
Net income (loss) attributable to Ameren Corporation^(a)		103		40			168		(5	)		-			306
2008:
External revenues	$	1,475	$	1,763		$	632	$	1		$	-		$	3,871
Intersegment revenues		20		23			228		8			(279	)		-
Net income (loss) attributable to Ameren Corporation^(a)		174		2			176		(8	)		-			344
As of June 30, 2009:
Total assets	$	11,999	$	7,069		$	4,985	$	1,385		$	(2,248	)	$	23,190
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	$	752	$	-	$	752
Net income^(b)		82		-		82
2008:
Revenues	$	771	$	-	$	771
Net income^(b)		122		-		122

Six Months
2009:
Revenues	$	1,407	$	-	$	1,407
Net income^(b)		103		-		103
2008:
Revenues	$	1,495	$	-	$	1,495
Net income^(b)		174		11		185
As of June 30, 2009:
Total assets	$	11,999	$	-	$	11,999
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			Non-rate-regulated Generation			CILCORP Other		Intersegment Eliminations			Consolidated CILCORP
2009:
External revenues	$	128		$	104		$	-	$	-		$	232
Intersegment revenues		-			-			-		-			-
Net income^(b)		1			23			-		-			24
2008:
External revenues	$	162		$	71		$	-	$	-		$	233
Intersegment revenues		2			(1	)		-		(1	)		-
Net income(loss)^(b)		(1	)		5			-		-			4

Six Months
2009:
External revenues	$	347		$	196		$	-	$	-		$	543
Intersegment revenues		-			-			-		-			-
Goodwill impairment^(a)		(117	)		(345	)		-		-			(462	)
Net loss^(b)		(109	)		(299	)		-		-			(408	)
2008:
External revenues	$	428		$	150		$	-	$	-		$	578
Intersegment revenues		2			-			-		(2	)		-
Net income^(b)		11			13			-		-			24
As of June 30, 2009:
Total assets	$	1,324		$	1,342		$	2	$	(203	)	$	2,465
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			Non-rate-regulated Generation			CILCO Other		Intersegment Eliminations			Consolidated CILCO
2009:
External revenues	$	128		$	104		$	-	$	-		$	232
Intersegment revenues		-			-			-		-			-
Net income^(a)		1			30			-		-			31
2008:
External revenues	$	162		$	71		$	-	$	-		$	233
Intersegment revenues		2			(1	)		-		(1	)		-
Net income (loss)^(a)		(1	)		12			-		-			11

Six Months
2009:
External revenues	$	347		$	196		$	-	$	-		$	543
Intersegment revenues		-			-			-		-			-
Net income^(a)		8			56			-		-			64
2008:
External revenues	$	428		$	150		$	-	$	-		$	578
Intersegment revenues		2			-			-		(2	)		-
Net income^(a)		11			26			-		-			37
As of June 30, 2009:
Total assets	$	1,251		$	1,108		$	-	$	-		$	2,359
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 Non-rate-regulated 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 twenty-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.

As a result of the interim impairment test as of March 31, 2009, CILCORP’s Illinois Regulated reporting unit and CILCORP’s Non-rate-regulated Generation reporting unit both failed step one 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 Non-rate-regulated 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 Non-rate-regulated Generation goodwill was impaired as of March 31, 2009. Based on the results of step two, CILCORP recorded a noncash impairment charge of $462 million, which represented all of the goodwill assigned to CILCORP’s Non-rate-regulated 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 recorded at 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 Non-rate-regulated 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 Non-rate-regulated 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 second 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 June 30, 2009:

Ameren


	Missouri Regulated		Illinois Regulated			Non-rate-regulated Generation			Total^(a)
Balance at December 31, 2008	$	-	$	411		$	420		$	831
Impairment loss recorded in first quarter		-		-			-			-
Balance at June 30, 2009	$	-	$	411		$	420		$	831
(a) Includes amounts for Ameren registrants and nonregistrant subsidiaries. CILCORP
	Missouri Regulated		Illinois Regulated			Non-rate-regulated Generation			Total
Balance at December 31, 2008	$	-	$	197		$	345		$	542
Impairment loss recorded in first quarter		-		(117	)		(345	)		(462	)
Balance at June 30, 2009	$	-	$	80		$	-		$	80
IP
	Missouri Regulated		Illinois Regulated			Non-rate-regulated Generation			Total
Balance at December 31, 2008	$	-	$	214		$	-		$	214
Impairment loss recorded in first quarter		-		-			-			-
Balance at June 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 second quarter and first half of 2009 were lower compared with its earnings in the second quarter and first half of 2008 by $41 million and $38 million, respectively. Earnings in the second quarter and first half of 2009 were unfavorably impacted by higher net fuel costs, unfavorable unrealized MTM activity on derivatives, the absence in 2009 of a lump-sum payment from a coal supplier received last year as a result of the premature closure of a mine and termination of a contract, and other items. Reducing the impact of these factors in the second quarter and first half of 2009 were new utility service rates in Illinois, effective October 1, 2008, and in Missouri, effective March 1, 2009, as well as lower plant operations and maintenance expenses and warmer weather.

Ameren’s rate-regulated businesses are currently earning well below their allowed rates of return largely as a result of regulatory lag associated with investments in utility infrastructure, as well as higher operating and financing costs and lower customer demand. Last fall, Ameren identified cost control measures in its rate-regulated businesses designed to reduce 2008 and 2009 capital and operating expenditures, as compared to prior plans, and took action to reduce such costs by $350 million to $400 million. Through recent planning efforts, Ameren has identified further possible opportunities to reduce planned capital expenditures and operations and maintenance expenses across its organization. Ameren is evaluating these opportunities, which it believes will lessen the impact of expected future energy cost increases on its customers while strengthening the financial profiles of the rate-regulated utilities. However, costs will not be reduced to a level that would prevent the Ameren Companies from providing safe and reliable service to their customers. In addition to identifying further possible opportunities to control costs, UE, CIPS, CILCO and IP have recently filed rate increase requests totaling over $600 million. The rate requests reflect the need to recover the significant investments made in utility infrastructure to improve reliability, increases in operating costs, higher financing costs and, in Missouri, rising net fuel costs.

At Ameren’s Non-rate-regulated Generation segment, forward sales in prior years of expected generation is protecting its 2009 earnings from a significant decrease in market prices for power. Further, Non-rate-regulated Generation has hedged a substantial portion of its 2010 and 2011 forecasted generation. However, recent prices for electricity for 2010 and 2011 are lower than the prices being realized in 2009, or that have been locked-in through 2010 and 2011 forward sales. These lower power prices are linked to weak economic conditions, which are reducing the demand for power and other energy commodities. We believe that when the economy recovers, these prices will also rise.

The Non-rate-regulated Generation segment instituted cost control measures last fall to reduce 2008 and 2009 capital and operating expenditures, as compared to prior plans, and took action to reduce such costs by approximately $400 million to $450 million. The Non-rate-regulated Generation segment has now analyzed further its plans for 2010 through 2013 and implemented significant additional planned spending reductions. Approximately $1 billion of capital expenditure reductions have been made from Non-rate-regulated Generation’s previous 2010 to 2013 estimates. These reductions are expected to be achieved by eliminating almost all capital expenditures other than mandatory environmental and maintenance-type projects. While the Non-rate-regulated Generation segment does not expect to realize the efficiencies that may have otherwise resulted from these expenditures, it does not believe such expenditures are cost-justified in the current power market and credit environment. However, as a result of eliminating these capital expenditures, reduced scheduled outage time is expected to more than offset increased unplanned outages. This should improve the net availability of Non-rate-regulated Generation’s core baseload power plants. Non-rate-regulated Generation’s small noncore generating facilities are not currently expected to be sold as was previously being explored. Alternative operating modes for these small plants are being considered to improve their profitability. It is the expectation that actions being taken to address costs in the Non-rate-regulated Generation segment will result in 2010 nonfuel operations and maintenance expenses that are 5% to 10% lower than 2008 levels.

Ameren has identified approximately $2 billion of opportunities to reduce Ameren consolidated planned capital expenditures for 2010 through 2013, as compared to earlier plans. This amount includes approximately $1 billion of planned capital expenditure reductions in the Non-rate-regulated Generation segment for this period, as discussed above. In Ameren’s rate-regulated businesses, approximately $1 billion of potential reductions have been identified. Which projects may be eliminated or deferred is currently being evaluated. Ameren is also reviewing planned operations and maintenance expenditures across the organization, but especially in the Non-rate-regulated Generation business and business support functions. Ameren’s objective is to significantly lower 2010 nonfuel operations and maintenance costs, relative to the 2008 level, in its Non-rate-regulated Generation segment. Planned and potential cost-containment actions include reduced scheduled Non-rate-regulated Generation power plant outages, wage and workforce reductions, and other cost reductions in business support functions.

General

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

•

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

•

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

•

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

•

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

•

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

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

RESULTS OF OPERATIONS

Earnings Summary

Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also

affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. Non-rate-regulated Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil 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 businesses, purchased power cost recovery mechanisms for our Illinois electric delivery businesses and a FAC for our Missouri electric utility business. See Note 2—Rate and Regulatory Matters to our financial statements 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, 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 decreased to $165 million, or 77 cents per share, in the second quarter of 2009, from $206 million, or 98 cents per share, in the second quarter of 2008. Net income attributable to Ameren Corporation in the second quarter of 2009 increased in the Illinois Regulated segment by $29 million from the prior-year period, while net income attributable to Ameren Corporation in the Missouri Regulated and Non-rate-regulated Generation segments decreased by $40 million and $23 million, respectively, from the same period in 2008.

Net income attributable to Ameren Corporation decreased to $306 million, or $1.43 per share, in the first six months of 2009 from $344 million, or $1.64 per share, in the first six months of 2008. Net income attributable to Ameren Corporation increased in the Illinois Regulated segment by $38 million in the first six months of 2009 compared to the prior-year period, while net income attributable to Ameren Corporation in the Missouri Regulated and Non-rate-regulated Generation segments decreased by $71 million and $8 million, respectively, from the same period in 2008.

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

•

lower electric and gas margins at our rate-regulated businesses, primarily as a result of higher net fuel costs at UE, excluding favorable impacts of rate increases noted below (20 cents per share and 37 cents per share, respectively);

•

unfavorable net unrealized MTM activity on derivatives (19 cents per share and 10 cents per share, respectively);

•

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 and 18 cents per share, respectively);

•

higher financing costs (5 cents per share and 9 cents per share, respectively);

•

increased depreciation and amortization expense (5 cents per share and 6 cents per share, respectively);

•

reduced sales to Noranda due to a severe storm-related outage (3 cents per share and 6 cents per share, respectively);

•

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 4 cents per share, respectively); and

•

increased distribution system reliability expenditures (2 cents per share and 3 cents per share, respectively).

Earnings were favorably impacted in the second quarter and first six 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 26 cents per share, respectively);

•

higher electric rates, effective March 1, 2009, in the Missouri Regulated segment pursuant to a MoPSC rate order (12 cents per share and 15 cents per share, respectively);

•

decreased plant operations and maintenance expense (10 cents per share and 12 cents per share, respectively);

•

favorable weather conditions (estimated at 7 cents per share and 4 cents per share, respectively);

•

higher electric margins in the Non-rate-regulated Generation segment (5 cents per share and 8 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 (2 cents per share and 3 cents per share, respectively).

In addition to the above items affecting both periods, earnings were unfavorably impacted in the first six months of 2009, as compared with the first six months of 2008, by the implementation of redesigned gas delivery service rates at the Ameren Illinois Utilities, which impacts quarterly earnings comparison but is not expected to have a material impact on annual margins (4 cents per share).

The cents per share information presented above is based on average shares outstanding in the second quarter and first six months of 2008.

Because it is a holding company, net income attributable to Ameren Corporation and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren’s principal subsidiaries to net income attributable to Ameren Corporation for the three and six months ended June 30, 2009 and 2008:


	Three Months						Six Months
	2009			2008			2009			2008
Net income (loss):
UE	$	82		$	122		$	103		$	185	^(a)
CIPS		1			(3	)		7			(1	)
Genco		46			74			93			120
CILCORP		24			4			(408	)^(b)		24
IP		13			(10	)		26			(8	)
Other^(c)		(1	)		19			485	^(b)		24
Net income attributable to Ameren Corporation	$	165		$	206		$	306		$	344

(a)	Includes earnings from a non-rate-regulated 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 to our financial statements under Part I, Item 1, of this report for additional information.

(c)	Includes earnings from EEI, other non-rate-regulated operations, as well as corporate general and administrative expenses, and intercompany eliminations. Includes a 40% interest in EEI prior to 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 six months ended June 30, 2009 and 2008:


	Missouri Regulated			Illinois Regulated			Non-rate- regulated Generation			Other / Intersegment Eliminations			Total
Three Months 2009:
Electric margin	$	534		$	223		$	259		$	(7	)	$	1,009
Gas margin		14			72			-			-			86
Other revenues		1			-			-			(1	)		-
Other operations and maintenance		(220	)		(153	)		(84	)		6			(451	)
Depreciation and amortization		(90	)		(54	)		(31	)		(7	)		(182	)
Taxes other than income taxes		(66	)		(25	)		(7	)		1			(97	)
Other income and (expenses)		13			2			-			(5	)		10
Interest expense		(57	)		(40	)		(23	)		(4	)		(124	)
Income taxes		(45	)		(8	)		(39	)		9			(83	)
Net income (loss)		84			17			75			(8	)		168
Noncontrolling interest and preferred dividends		(2	)		(2	)		-			1			(3	)
Net income (loss) attributable to Ameren Corporation		82			15			75			(7	)		165
Three Months 2008:
Electric margin	$	595		$	188		$	322		$	(4	)	$	1,101
Gas margin		17			63			-			(2	)		78
Other operations and maintenance		(238	)		(160	)		(92	)		14			(476	)
Depreciation and amortization		(82	)		(55	)		(27	)		(7	)		(171	)
Taxes other than income taxes		(60	)		(24	)		(6	)		1			(89	)
Other income and (expenses)		13			3			2			(7	)		11
Interest expense		(50	)		(37	)		(29	)		(2	)		(118	)
Income taxes		(71	)		9			(64	)		7			(119	)
Net income (loss)		124			(13	)		106			-			217
Noncontrolling interest and preferred dividends		(2	)		(1	)		(8	)		-			(11	)
Net income (loss) attributable to Ameren Corporation		122			(14	)		98			-			206
Six Months 2009:
Electric margin	$	945		$	416		$	546		$	(10	)	$	1,897
Gas margin		41			183			-			-			224
Other revenues		2			4			-			(6	)		-
Other operations and maintenance		(436	)		(289	)		(162	)		15			(872	)
Depreciation and amortization		(176	)		(107	)		(59	)		(14	)		(356	)


	Missouri Regulated			Illinois Regulated			Non-rate- regulated Generation			Other / Intersegment Eliminations			Total
Taxes other than income taxes		(128	)		(64	)		(14	)		(1	)		(207	)
Other income and (expenses)		24			3			-			(5	)		22
Interest expense		(110	)		(81	)		(48	)		(3	)		(242	)
Income taxes		(56	)		(22	)		(93	)		18			(153	)
Net income (loss)		106			43			170			(6	)		313
Noncontrolling interest and preferred dividends		(3	)		(3	)		(2	)		1			(7	)
Net income (loss) attributable to Ameren Corporation		103			40			168			(5	)		306
Six Months 2008:
Electric margin	$	1,036		$	366		$	596		$	(17	)	$	1,981
Gas margin		45			188			-			(2	)		231
Other operations and maintenance		(455	)		(307	)		(171	)		28			(905	)
Depreciation and amortization		(163	)		(110	)		(54	)		(13	)		(340	)
Taxes other than income taxes		(120	)		(67	)		(14	)		(1	)		(202	)
Other income and (expenses)		25			7			1			(8	)		25
Interest expense		(91	)		(72	)		(50	)		(5	)		(218	)
Income taxes		(100	)		-			(116	)		10			(206	)
Net income (loss)		177			5			192			(8	)		366
Noncontrolling interest and preferred dividends		(3	)		(3	)		(16	)		-			(22	)
Net income (loss) attributable to Ameren Corporation		174			2			176			(8	)		344

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins for the three and six months ended June 30, 2009, compared with the same periods in 2008. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined as gas revenues less gas purchased for resale. We consider electric, interchange, and gas margins useful measures to analyze the change in profitability of our electric and gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.


Three Months	Ameren^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Electric revenue change:
Effect of weather (estimate)	$	20		$	17		$	2		$	-		$	-		$	-		$	1
Regulated rates:
Changes in base rates		69			42			5			-			-			-			22
Noranda sales		(14	)		(14	)		-			-			-			-			-
Illinois pass-through power costs		(46	)		-			(6	)		-			(16	)		(16	)		(24	)
Non-rate-regulated Generation sales price changes		30			-			-			39			17			17			-
Off-system revenues		(59	)		(59	)		-			-			-			-			-
Illinois electric settlement agreement, net of reimbursement		3			-			-			2			2			2			-
Net MTM gains		5			(7	)		-			-			-			-			-
Generation output and other		(40	)		10			(7	)		(19	)		12			12			(10	)
Total electric revenue change	$	(32	)	$	(11	)	$	(6	)	$	22		$	15		$	15		$	(11	)
Fuel and purchased power change:
Fuel:
Generation and other	$	(59	)	$	(7	)	$	-		$	(61	)	$	3		$	3		$	-
Reduced net MTM gains		(75	)		(52	)		-			(15	)		(3	)		(3	)		-
Price		(13	)		-			-			(4	)		(1	)		(1	)		-
Purchased power		41			9			8			-			7			7			11
Illinois pass-through power costs		46			-			6			-			16			16			24
Total fuel and purchased power change	$	(60	)	$	(50	)	$	14		$	(80	)	$	22		$	22		$	35
Net change in electric margin	$	(92	)	$	(61	)	$	8		$	(58	)	$	37		$	37		$	24
Gas margin change:
Effect of weather (estimate)	$	(1	)	$	-		$	-		$	-		$	-		$	-		$	(1	)
Gas rate increases		12			-			3			-			(1	)		(1	)		10
Illinois seasonal rate redesign		5			-			1			-			1			1			3
Other		(8	)		(3	)		(1	)		-			(5	)		(5	)		(1	)
Net change in gas margin	$	8		$	(3	)	$	3		$	-		$	(5	)	$	(5	)	$	11


Six Months	Ameren^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Electric revenue change:
Effect of weather (estimate)	$	8		$	6		$	1		$	-		$	-		$	-		$	1
Regulated rates:
Changes in base rates		105			53			10			-			(1	)		(1	)		43
Noranda sales		(27	)		(27	)		-			-			-			-			-
Illinois pass-through power costs		(98	)		-			(26	)		-			(33	)		(33	)		(39	)
Non-rate-regulated Generation sales price changes		36			-			-			57			24			24			-
Off-system revenues		(80	)		(80	)		-			-			-			-			-
Illinois electric settlement agreement, net of reimbursement		8			-			1			4			3			3			1
Net MTM gains		28			(9	)		-			-			-			-			-
Generation output and other		(86	)		(16	)		(7	)		(47	)		(2	)		(2	)		(3	)
Total electric revenue change	$	(106	)	$	(73	)	$	(21	)	$	14		$	(9	)	$	(9	)	$	3
Fuel and purchased power change:
Fuel:
Generation and other	$	(27	)	$	(13	)	$	-		$	(37	)	$	10		$	9		$	-
Reduced net MTM gains		(67	)		(34	)		-			(21	)		(4	)		(4	)		-
Price		(25	)		-			-			(10	)		(1	)		(1	)		-
Purchased power		43			29			5			-			21			21			-
Illinois pass-through power costs		98			-			26			-			33			33			39
Total fuel and purchased power change	$	22		$	(18	)	$	31		$	(68	)	$	59		$	58		$	39
Net change in electric margin	$	(84	)	$	(91	)	$	10		$	(54	)	$	50		$	49		$	42
Gas margin change:
Effect of weather (estimate)	$	(5	)	$	-		$	(1	)	$	-		$	(1	)	$	(1	)	$	(3	)
Gas rate increases		25			-			6			-			(5	)		(5	)		24
Illinois seasonal rate redesign		(12	)		-			(3	)		-			(3	)		(3	)		(6	)
Other		(15	)		(4	)		(4	)		-			(4	)		(4	)		(5	)
Net change in gas margin	$	(7	)	$	(4	)	$	(2	)	$	-		$	(13	)	$	(13	)	$	10

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

Ameren

Ameren’s electric margin decreased by $92 million, or 8%, and $84 million, or 4%, for the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008. The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

UE’s net fuel expense (defined in the FAC as fuel and purchased power expense, excluding MTM activity, net of off-system sales) increased $47 million and $66 million for the three and six months ended June 30, 2009, respectively, which included a $10 million FAC under-recovery and a $2 million FAC over-recovery for the three and six months ended June 30, 2009. This increase was primarily due to a decrease in off-system sales revenues of $59 million and $80 million, respectively.

•

A $59 million and $85 million reduction in net MTM gains at UE on energy and fuel-related transactions for the three and six months ended June 30, 2009, respectively. The impact of these reduced gains was mitigated as UE reversed and deferred as regulatory assets previously recorded net MTM losses on energy and fuel-related transactions of $42 million in the first quarter 2009 when they became probable of recovery because of the FAC. See Note - 6 Derivative Financial Instruments to our financial statements under Part I, Item I, of this report, for additional information.

•

A $22 million and $31 million reduction in net MTM gains at the Non-rate-regulated Generation segment on fuel-related transactions for the three and six months ended June 30, 2009, respectively. These unrealized gains 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.

•

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. The settlement agreement compensated Genco, in total, for higher fuel costs it incurred throughout 2008 and is incurring throughout 2009. Because the entire settlement was recorded in the second quarter of 2008 earnings, Ameren’s earnings in the second quarter and first six months of 2009 were comparatively lower than they otherwise would have been.

•

Excluding the impact of the 2008 coal mine settlement, Non-rate-regulated Generation segment fuel prices increased by 9% and 6% for the three and six months ended June 30, 2009, respectively.

•

Reduced sales by UE to Noranda because of a severe storm-related outage, which lowered electric revenues by $14 million and $27 million for the three and six months ended June 30, 2009, respectively. See Outlook for further information on the Noranda plant outage.

•

Excluding UE’s reduced sales to Noranda, weather-normalized end-use retail sales volumes decreased 3% and 4% for three and six months ended June 30, 2009, respectively, which decreased margin by $3 million and $16 million, respectively, because of the economic slowdown.

•

Decreased power plant utilization because of lower demand and system transmission congestion. Ameren’s baseload coal-fired generating plants’ equivalent availability and capacity factors were 84% and 71%, respectively, in 2009 compared with 84% and 76%, respectively, in 2008.

•

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

The following items had a favorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

The effect of rate increases. The UE electric rate increase, effective March 1, 2009, increased electric margin by $42 million and $53 million for the three and six months ended June 30, 2009, respectively. The Ameren Illinois Utilities’ net electric rate increase, effective October 1, 2008, increased electric margin by $27 million and $52 million for the three and six months ended June 30, 2009, respectively.

•

The repricing of wholesale and retail electric power supply agreements and financial swaps settling at higher margins at Non-rate-regulated Generation.

•

Increased net MTM gains at the Non-rate-regulated Generation segment on energy transactions of $12 million and $37 million for the three and six months ended June 30, 2009, respectively, primarily related to nonqualifying hedges of changes in market prices for electricity.

•

An $8 million and $10 million increase in UE’s wholesale sales margin for the three and six months ended June 30, 2009, respectively, because of additional customers and higher-priced sales contracts.

•

Increased electric margin of $4 million and $9 million for the three and six months ended June 30, 2009, respectively, related to the recovery of power supply costs incurred by the Ameren Illinois Utilities, including an increase in the Supply Cost Adjustment (SCA) factors as approved in the 2008 ICC electric rate order.

•

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $3 million and $8 million for the three and six months ended June 30, 2009, respectively.

•

Favorable weather conditions, as evidenced by a 25% increase in cooling degree-days for both the three and six months ended June 30, 2009, respectively, which increased electric margin by an estimated $20 million and $8 million, respectively.

Ameren’s gas margin increased by $8 million, or 10%, in the second quarter of 2009 compared with the year-ago period. Ameren’s gas margin decreased by $7 million, or 3%, for the six months ended June 30, 2009, compared with the same period in 2008. Natural gas revenues decreased 30% and 19% for the three and six months ended June 30, 2009, respectively, primarily because of lower natural gas costs included in the PGA at UE, CIPS, CILCO and IP compared to the year-ago periods. The following items had an unfavorable impact on gas margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

The implementation of redesigned seasonal gas delivery service rates at the Ameren Illinois Utilities, effective October 1, 2008, which decreased gas margin by $12 million for the six months ended June 30, 2009. In the second quarter of 2009, gas margin increased by $5 million as a result of the rate redesign. These redesigned delivery service rates have an impact on quarterly earnings comparisons but are not expected to materially impact annual margin.

•

Unfavorable weather conditions, as evidenced by a 7% reduction in heating degree-days, which decreased gas margin by an estimated $5 million for the six months ended June 30, 2009.

•

A 13% decrease in weather-normalized sales volumes driven by the economic slowdown, which decreased gas margin by $15 million for the six months ended June 30, 2009.

The following items had a favorable impact on gas margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

The Ameren Illinois Utilities’ net gas delivery service rate increase, effective October 1, 2008, which increased gas margin by $12 million and $25 million for the three and six months ended June 30, 2009, respectively.

•

Increased transportation revenues, which increased gas margin by $1 million for the six months ended June 30, 2009.

Missouri Regulated (UE)

UE’s electric margin decreased by $61 million, or 10% and, $91 million, or 9%, for the three and six months ended June 30, 2009, respectively, compared with the same period in 2008. The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

Net fuel expense (as defined in UE’s FAC) increased $47 million and $66 million for the three and six months ended June 30, 2009, respectively, which included a $10 million FAC under-recovery and a $2 million FAC over-recovery for the three and six months ended June 30, 2009, respectively. This increase was primarily due to a decrease in off-system sales revenues of $59 million and $80 million, respectively.

•

A $59 million and $85 million reduction in net MTM gains on energy and fuel-related transactions for the three and six months ended June 30, 2009, respectively. These reduced gains were partially offset as UE reversed and deferred as regulatory assets previously recorded net MTM losses on energy and fuel-related transactions of $42 million in the first quarter 2009 when they became probable of recovery because of the FAC. See Note 6—Derivative Financial Instruments to our financial statements under Part I, Item I, of this report, for additional information.

•

Reduced sales to Noranda due to a severe storm-related outage, which lowered electric revenues by $14 million and $27 million for the three and six months ended June 30, 2009, respectively. See Outlook for further information on the Noranda plant outage.

•

Excluding the reduced sales to Noranda, weather-normalized end-use retail sales volumes decreased 3% for the three and six months ended June 30, 2009, respectively, which decreased margin by $5 million and $13 million, respectively, because of the economic slowdown.

•

The following items had a favorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

The electric rate increase, effective March 1, 2009, which increased electric margin by $42 million and $53 million for the three and six months ended June 30, 2009, respectively.

•

An $8 million and $10 million increase in wholesale sales margin for the three and six months ended June 30, 2009, respectively, because of additional customers and higher-priced sales contracts.

•

Favorable weather conditions, as evidenced by a 34% increase in cooling degree-days for both the three and six months ended June 30, 2009, respectively, which increased electric margin by an estimated $17 million and $6 million, respectively.

UE’s gas margin decreased by $3 million, or 18%, and, $4 million, or 9%, for the three and six months ended June 30, 2009, respectively, compared with the same period in 2008, primarily because of a 6% and 9% decrease in weather-normalized sales volumes, respectively.

Illinois Regulated

Illinois Regulated’s electric margin increased by $35 million, or 19%, and $50 million, or 14%, for the three and six months ended June 30, 2009, respectively, compared with the same period in 2008. Illinois Regulated’s gas margin increased by $9 million, or 14%, in the second quarter 2009, compared with the year-ago period. Illinois Regulated’s gas margin decreased by $5 million, or 3%, for the six months ended June 30, 2009, compared with the year-ago period.

CIPS

CIPS’ electric margin increased by $8 million, or 13%, and $10 million, or 9%, for the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008. The following items had a favorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

The electric delivery service rate increase, effective October 1, 2008, which increased electric margin by $5 million and $10 million for the three and six months ended June 30, 2009, respectively.

•

Increased electric margin of $1 million and $2 million for the three and six months ended June 30, 2009, respectively, related to the recovery of power supply costs incurred, including an increase in the SCA factors as approved in the 2008 ICC electric rate order.

•

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $1 million for the six months ended June 30, 2009.

The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

A $2 million and $4 million reduction in net transmission margin in the three and six months ended June 30, 2009, respectively, primarily related to reduced transmission service rates that were based on lower transmission costs in the prior-year periods.

•

A 2% decrease in weather-normalized sales volumes driven by the economic slowdown, which decreased electric margin by $1 million for the six months ended June 30, 2009.

CIPS’ gas margin increased by $3 million, or 21%, in the second quarter 2009 compared with the year-ago period. CIPS’ gas margin decreased by $2 million, or 5%, for the six months ended June 30, 2009, compared with the year-ago period. The following items had an unfavorable impact on gas margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

The implementation of redesigned seasonal gas delivery service rates, effective October 1, 2008, which decreased gas margin by $3 million for the six months ended June 30, 2009. In the second quarter of 2009, gas margin increased $1 million as a result of the rate redesign. The redesigned delivery service rates have an impact on quarterly earnings comparisons, but are not expected to materially impact annual margin.

•

A 9% decrease in weather-normalized sales volumes driven by the economic slowdown, which decreased gas margin by $3 million for the six months ended June 30, 2009.

•

Unfavorable weather conditions, as evidenced by a 9% decrease in heating degree-days, which decreased gas margin by an estimated $1 million for the six months ended June 30, 2009.

These unfavorable variances were reduced by the gas delivery service rate increase, effective October 1, 2008, which increased gas margin by $3 million and $6 million for the three and six months ended June 30, 2009, respectively.

CILCO (Illinois Regulated)

The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for the three and six months ended June 30, 2009, as compared with the same period in 2008:


	Three Months		Six Months
CILCO (Illinois Regulated)	$	3	$	(2	)
CILCO (AERG)		34		51
Total change in electric margin	$	37	$	49

CILCO’s (Illinois Regulated) electric margin increased by $3 million, or 11%, in the second quarter of 2009 compared with the year-ago period. CILCO’s (Illinois Regulated) electric margin decreased by $2 million, or 2%, for the six months ended June 30, 2009, compared with the year-ago period. The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

A 12% decrease in weather-normalized sales volumes driven by the economic slowdown, which decreased electric margin by $1 million for the six months ended June 30, 2009. The decreased sales were primarily in the lower margin industrial customer sector.

•

A $1 million reduction in transmission margin in the six months ended June 30, 2009, primarily related to reduced transmission service rates that were based on lower transmission costs in the prior-year period.

•

The electric delivery service rate decrease, effective October 1, 2008, which decreased electric margin by $1 million for the six months ended June 30, 2009.

These unfavorable variances were reduced by an increase of $1 million and $2 million for the three and six months ended June 30, 2009, respectively, related to the recovery of power supply costs incurred, including an increase in the SCA factors as approved in the 2008 ICC electric rate order.

See Non-rate-regulated Generation below for an explanation of CILCO’s (AERG) change in electric margin for the three and six months ended June 30, 2009, as compared with the same period in 2008.

CILCO’s (Illinois Regulated) gas margin decreased by $5 million, or 26%, and $13 million, or 24%, for the three and six months ended June 30, 2009, respectively, compared with the same period in 2008. The following items had an unfavorable impact on gas margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

The implementation of redesigned seasonal gas delivery service rates, effective October 1, 2008, which decreased gas margin by $3 million for the six months ended June 30, 2009. In the second quarter 2009, gas margin increased $1 million as a result of the rate redesign. These 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 decrease, effective October 1, 2008, which decreased gas margin by $1 million and $5 million for the three and six months ended June 30, 2009, respectively.

•

A 19% decrease in weather-normalized sales volumes driven by the economic slowdown, which decreased gas margin by $3 million for the six months ended June 30, 2009.

•

Unfavorable weather conditions, as evidenced by a 7% reduction in heating degree-days, which decreased gas margin by an estimated $1 million for the six months ended June 30, 2009.

IP’s electric margin increased by $24 million, or 25%, and $42 million, or 23%, for the three and six months ended June 30, 2009, respectively, compared with the same period in 2008. The following items had a favorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

The electric delivery service rate increase, effective October 1, 2008, which increased electric margin by $22 million and $43 million for the three and six months ended June 30, 2009, respectively.

•

Increased electric margin of $2 million and $5 million for the three and six months ended June 30, 2009, respectively, related to the recovery of power supply costs incurred, including an increase in the SCA factors as approved in the 2008 ICC electric rate order.

•

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $1 million for the six months ended June 30, 2009.

The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

A $4 million reduction in transmission margin in the six months ended June 30, 2009, primarily related to ongoing MISO settlements and reduced transmission service rates that were based on lower transmission costs in the prior-year period.

•

A 5% decrease in weather-normalized sales volumes driven by the economic slowdown, which decreased electric margin by $1 million for the six months ended June 30, 2009. The decreased sales were primarily in the lower margin industrial customer sector.

IP’s gas margin increased by $11 million, or 37%, and $10 million, or 11%, for the three and six months ended June 30, 2009, respectively, compared with the same period in 2008. The increase was primarily due to the gas delivery service rate increase, effective October 1, 2008, which increased gas margin by $10 million and $24 million for the three and six months ended June 30, 2009, respectively.

The following items had an unfavorable impact on gas margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

The implementation of redesigned seasonal gas delivery service rates, effective October 1, 2008, which decreased gas margin by $6 million for the six months ended June 30, 2009. In the second quarter 2009, gas margin increased $3 million as a result of the rate redesign. These redesigned delivery service rates have an impact on quarterly earnings comparisons but are not expected to materially impact annual margin.

•

An 11% decrease in weather-normalized sales volumes driven by the economic slowdown, which decreased gas margin by $7 million for the six months ended June 30, 2009.

•

Unfavorable weather conditions, as evidenced by a 6% decrease in heating degree-days, which decreased gas margin by an estimated $3 million for the six months ended June 30, 2009.

Non-rate-regulated Generation

Non-rate-regulated Generation’s electric margin decreased by $63 million, or 20%, and $50 million, or 8%, for the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008.

Genco

Genco’s electric margin decreased by $58 million, or 28%, and $54 million, or 15%, for the three and six months ended June 30, 2009, respectively, compared with the same period in 2008. The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

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. The settlement agreement compensated Genco, in total, for higher fuel costs it incurred throughout 2008 and is incurring throughout 2009. Because the entire settlement was recorded in the second quarter of 2008 earnings, Genco’s earnings in the second quarter and first six months of 2009 were comparatively lower than they otherwise would have been.

•

Excluding the 2008 coal mine settlement, fuel prices increased by 7% and 5% for the three and six months ended June 30, 2009, respectively.

•

Decreased power plant utilization. Genco’s baseload coal-fired generating plants’ equivalent availability factor was 87% in 2009 compared with 80% in 2008. However, the average capacity factor was 62% in 2009 compared with 71% in 2008, primarily due to lower prices resulting in fewer opportunities for economic sales and transmission congestion limiting the period when power could be sold.

•

Reduced net MTM gains on fuel-related transactions of $15 million and $21 million for the three and six months ended June 30, 2009, respectively. These unrealized gains 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.

•

Lower affiliated replacement power insurance recoveries of $6 million for the six months ended June 30, 2009.

The following items had a favorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

Increased revenues allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company. Revenues from the Genco PSA increased

due to financial swaps settling at higher margins and new higher-priced wholesale and retail electric power supply agreements, partially offset by lower reimbursable expenses in accordance with the Genco PSA.

•

Lower emission allowance costs of $2 million and $5 million for the three and six months ended June 30, 2009, respectively due to lower prices and reduced generation.

•

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $2 million and $4 million for the three and six months ended June 30, 2009, respectively.

CILCO (AERG)

AERG’s electric margin increased by $34 million, or 71%, and $51 million, or 51%, for the three and six months ended June 30, 2009, respectively, compared with the same period in 2008. The following items had a favorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

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

•

A $2 million and $3 million decrease in oil consumption for the three and six months ended June 30, 2009, respectively, resulting from fewer plant start-ups and lower prices in 2009.

•

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $1 million and $2 million for the three and six months ended June 30, 2009, respectively.

The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

Decreased power plant availability due, in part, to a planned plant outage. AERG’s baseload coal-fired generating plants’ equivalent availability and average capacity factors were 68% and 62%, respectively, in 2009, compared with 77% and 70%, respectively, in 2008.

•

A $3 million and $4 million reduction in net MTM gains on fuel-related transactions for the three and six months ended June 30, 2009, respectively. These unrealized gains 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.

Other Non-rate-regulated Generation

Electric margin from Ameren’s other Non-rate-regulated Generation operations, primarily from EEI and Marketing Company, decreased by $39 million, or 58%, and $47 million, or 33%, for the three and six months ended June 30, 2009, respectively. The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2009, as compared to the year-ago periods, unless otherwise noted:

•

The impact of the economic slowdown, which lowered power demand and sales prices, decreased revenues by $44 million and $73 million for the three and six months ended June 30, 2009, respectively. The average sales price for power decreased by 33% and 28% for the three and six months ended June 30, 2009, respectively.

•

Fuel prices at EEI increased by 27% and 22% for the three and six months ended June 30, 2009, respectively, due to an 88% increase in transportation costs.

•

Decreased power plant availability due to plant outages. EEI’s baseload coal-fired generating plant’s equivalent availability and average capacity factors were 82% and 78%, respectively, in 2009, compared with 87% and 86%, respectively, in 2008.

•

Reduced net MTM gains on fuel-related transactions of $6 million and $9 million for the three and six months ended June 30, 2009, respectively. These unrealized gains 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.

These unfavorable variances were partially offset by net MTM gains on energy transactions of $13 million and $38 million for the three and six months ended June 30, 2009, respectively. These unrealized gains primarily related to nonqualifying hedges of changes in market prices for electricity.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren

Three months - Other operations and maintenance expenses decreased $25 million in the second quarter of 2009, compared with the second quarter of 2008, primarily because of reductions in plant maintenance costs of $35 million, lower injuries and damages expenses of $10 million, reduced bad debt expense of $6 million, and favorable unrealized net MTM adjustments, as compared to unfavorable adjustments in the prior year period, resulting from the market value of investments used to support

Ameren’s deferred compensation plans. Reducing the benefit of these items were increased storm repair expenditures of $10 million in the second quarter of 2009 compared with the same period in 2008. In the second quarter of 2009, a $5 million penalty 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.

Six months - Other operations and maintenance expenses decreased $33 million in the first six months of 2009, compared with the first six months of 2008, primarily because of reductions in plant maintenance costs of $45 million, lower injuries and damages expenses of $12 million, reduced bad debt expense of $12 million, and favorable unrealized net MTM adjustments, as compared to unfavorable adjustments in the prior year period, resulting from the market value of investments used to support Ameren’s deferred compensation plans. Reducing the benefit of these items were increased storm repair expenditures of $15 million and higher labor costs. Additionally, the penalty incurred for the termination of the heavy forgings contract, the termination of the rail line extension project, and the absence of the MoPSC accounting order in the current-year period, as described above, increased other operations and maintenance expenses.

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 six months ended June 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

UE’s other operations and maintenance expenses decreased $18 million and $19 million in the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008, primarily because of reduced plant maintenance costs, lower employee benefit costs and bad debt expense, and favorable unrealized net MTM adjustments, as compared to unfavorable adjustments in the prior year periods, resulting from the market value of investments used to support Ameren’s deferred compensation plans. Reducing the benefit of these items were the penalty incurred for the termination of the heavy forgings contract, higher labor costs, and the absence of an 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 six months of 2009 resulting from ice storms at the beginning of the year.

Illinois Regulated

Other operations and maintenance expenses decreased $7 million and $18 million in the Illinois Regulated segment in the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008.

CIPS

Three months - Other operations and maintenance expenses increased $7 million in the second quarter of 2009, compared with the second quarter of 2008, primarily because of increased storm repair expenditures.

Six months - Other operations and maintenance expenses were comparable in the first six months of 2009 with the first six months of 2008 as increased storm repair expenditures were mitigated by a reduction in bad debt expense.

CILCO (Illinois Regulated)

Three and six months - Other operations and maintenance expenses increased $19 million and $35 million in the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008, primarily because of higher labor and employee benefit costs. These increases were primarily a result of work performed on behalf of CIPS and CILCO 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 on its statement of income, which increased $18 million and $34 million in the three and six months ended June 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 support services.

Three and six months - IP’s other operations and maintenance expenses decreased $6 million and $10 million in the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008, primarily because of reductions in bad debt expense and distribution system reliability expenditures.

Non-rate-regulated Generation

Other operations and maintenance expenses decreased $8 million and $9 million in the Non-rate-regulated Generation segment in the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008.

Genco

Three and six months - Other operations and maintenance expenses decreased $10 million and $12 million in the second quarter and first six months of 2009, respectively, compared with the same periods in 2008, primarily because of lower plant maintenance costs. Expenses recognized for termination of the rail line extension project, as noted above, mitigated these benefits.

CILCO (AERG), CILCORP (parent company only), and EEI

Three and six months - Other operations and maintenance expenses were comparable in the three and six months ended June 30, 2009 with the same periods in 2008 at CILCO (AERG), CILCORP (parent company only), and EEI.

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 to our financial statements under Part I, Item 1, of this report for additional information.

Depreciation and Amortization

Ameren

Ameren’s depreciation and amortization expenses increased $11 million and $16 million in the three and six months ended June 30, 2009, 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 six months ended June 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

Depreciation and amortization expenses increased $8 million and $13 million in the three and six months ended June 30, 2009, compared with the same periods in 2008, primarily because of capital additions.

Illinois Regulated

Depreciation and amortization expenses were comparable in the Illinois Regulated segment in the second quarter of 2009 with the same period in 2008. Depreciation and amortization expenses decreased $3 million in the six months ended June 30, 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 $6 million and $12 million and an increase at IP of $5 million and $9 million in the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008. Depreciation and amortization expenses at CIPS were comparable between periods.

Non-rate-regulated Generation

Depreciation and amortization expenses increased $4 million and $5 million in the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008, in the Non-rate-regulated Generation segment primarily because of capital additions at CILCO (AERG). Depreciation and amortization expenses were comparable at Genco, CILCORP (parent company only), and EEI between periods.

Taxes Other Than Income Taxes

Ameren

Three months - Ameren’s taxes other than income taxes increased $8 million in the second quarter of 2009, compared with the second quarter of 2008, primarily because of higher property taxes and gross receipts taxes.

Six months - Ameren’s taxes other than income taxes at Ameren increased $5 million in the first six months of 2009, compared with the first six months of 2008, primarily because of higher property taxes.

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 six months ended June 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

Taxes other than income taxes increased $6 million and $8 million at UE in the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008, primarily because of higher property taxes and gross receipts taxes.

Illinois Regulated

Taxes other than income taxes were comparable in the Illinois Regulated segment in the second quarter of 2009 with the same period in 2008. Taxes other than income taxes decreased $3 million in the first six months of 2009, compared with the same period in 2008, primarily because of lower gross receipts taxes at IP. Taxes other than income taxes at CIPS and CILCO (Illinois Regulated) were comparable between periods.

Non-rate-regulated Generation

Taxes other than income taxes were comparable in the three and six months ended June 30, 2009, with the same periods in 2008, in the Non-rate-regulated Generation segment and for Genco, CILCO (AERG), CILCORP (parent company only) and EEI.

Other Income and Expenses

Ameren

Other income and expenses were comparable in the three and six months ended June 30, 2009, with the same periods in 2008.

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 six months ended June 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

Other income and expenses were comparable in the three and six months ended June 30, 2009, with the same periods in 2008, as increases in allowance for funds used during construction were mitigated by reduced interest income.

Illinois Regulated

Other income and expenses were comparable in the second quarter of 2009 with the same period in 2008. Other income and expenses decreased $4 million in the six months ended June 30, 2009, compared with the same period in 2008, primarily because of lower interest income at IP. Other income taxes and expenses at CIPS and CILCO (Illinois Regulated) were comparable between periods.

Non-rate-regulated Generation

Other income and expenses in the Non-rate-regulated Generation segment and at Genco, CILCO (AERG), CILCORP (parent company only) and EEI were comparable in the three and six months ended June 30, 2009, with the same periods in 2008.

Interest

Ameren

Ameren’s interest expense increased $6 million and $24 million in the three and six months ended June 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 six months ended June 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

Interest expense increased $7 million and $19 million in the three and six months ended June 30, 2009, respectively, compared with the same periods in 2008. Interest expense increased primarily because of the issuance of senior secured notes of $350 million, $450 million and $250 million in March 2009, June 2008 and April 2008, respectively, with the $350 million issuance carrying a higher interest rate due to the tightening of credit markets towards the end of 2008. Additionally, interest expense increased in the first half 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 prior-year periods mitigated the impact of the above items.

Illinois Regulated

Interest expense was comparable in the Illinois Regulated segment in the second quarter of 2009 with the same period in 2008. Interest expense increased $9 million in the Illinois Regulated segment in the first six months of 2009, compared with the same period in 2008.

CIPS

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

CILCO (Illinois Regulated)

Three and six months - Interest expense increased $3 million and $4 million in the second quarter and first six months of 2009, compared with the same periods in 2008, primarily because of the issuance of senior secured notes of $150 million in December 2008, at a higher-than-historical interest rate due to the tightening of credit markets towards the end of 2008, which replaced lower-rate short-term debt.

Three months - Interest expense was comparable in the first six months of 2009 with the first six months of 2008.

Six months - Interest expense was comparable in the first six months of 2009 with the first six months of 2008. Increased interest expense associated with the issuance of senior secured notes of $400 million and $337 million in October 2008 and April 2008, respectively, 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.

Non-rate-regulated Generation

Interest expense decreased $6 million in the second quarter of 2009, compared with the same period in 2008. Interest expense was comparable in the Non-rate-regulated Generation segment in the first six months of 2009 with the same period in 2008.

Genco

Three months - Interest expense decreased $4 million in the second quarter of 2009, compared with the same period in 2008, primarily because of reduced interest expense associated with uncertain tax positions.

Six months - Interest expense increased $3 million in the six months ended June 30, 2009, compared with the same period in 2008, primarily because of the issuance of $300 million of senior unsecured notes in April 2008, reduced by lower short-term borrowings.

CILCO (AERG), CILCORP (parent company only), and EEI

Three and six months - Interest expense was comparable in the three and six months ended June 30, 2009 with the same periods in 2008 at CILCO (AERG), CILCORP (parent company only), and EEI.

Income Taxes

Ameren

Three and six months - Ameren’s effective tax rate in the second quarter and first six months of 2009 was lower than the effective tax rate for the same periods 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 six months ended June 30, 2009, compared with the same periods in 2008, were as follows:

Missouri Regulated (UE)

Three and six months - The effective tax rate for the second quarter and first six months of 2009 was lower than the effective tax rate for the same periods in 2008, primarily because of higher favorable net amortization of property-related regulatory assets and liabilities, along with the impact of investment tax credit amortization and permanent items, on lower pretax book income in the 2009 periods compared with the year-ago periods.

Illinois Regulated

The effective tax rate for the second quarter of 2009 was lower than the effective tax rate for the same period in 2008, while the effective tax rate for the first six months of 2009 was higher than the effective rate for the same period in 2008, because of items detailed below.

CIPS

Three months - The effective tax rate for the second quarter of 2009 was lower than the effective tax rate for the same period in 2008, primarily because of the impact of net amortization of property-related regulatory assets and liabilities, investment tax credit amortization, and permanent items on pretax book income in the second quarter of 2009 as compared to a pretax book loss in the year-ago period.

Six months - The effective tax rate for the first six months of 2009 was higher than the effective tax rate for the same period in 2008, 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 in the first six months of 2009 compared with the prior year period.

CILCO (Illinois Regulated)

Three months - The effective tax rate for the second quarter of 2009 was lower than the effective tax rate for the

same period in 2008, primarily because of the impact of permanent items, net amortization of property-related regulatory assets and liabilities, and amortization of investment tax credit on pretax book income during the 2009 period as compared to a pretax book loss in the year-ago period.

Six months - The effective tax rate for the first six months of 2009 was lower than the effective tax rate for the same period in 2008, primarily because of the increased impact of net amortization of property-related regulatory assets and liabilities, investment tax credit amortization, and permanent items on lower pretax book income in the 2009 period compared with the year-ago period.

Three and six months - The effective tax rate for the second quarter and first six months of 2009 was lower than the effective tax rate for the same periods in 2008, 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 periods as compared to a pretax book loss in the same periods in 2008.

Non-rate-regulated Generation

The effective tax rate for the second quarter and first six months of 2009 was lower than the effective tax rate for the same periods in 2008 in the Non-rate-regulated Generation segment, because of items detailed below.

Genco

CILCO (AERG)

Three months - The effective tax rate for the second quarter of 2009 was higher than the effective tax rate for the same period in 2008, primarily because of changes to reserves for uncertain tax positions, offset by the increased impact of production activity deductions when compared to the year-ago period.

Six months - The effective tax rate was comparable between periods.

CILCORP (parent company only)

Three months - The effective tax rate for the second quarter of 2009 was higher than the effective tax rate for the same period in 2008, primarily because of the effect of permanent items on higher consolidated pretax book income in the second quarter of 2009 as compared with the year-ago period.

Six months - The effective tax rate for the first six months of 2009 was lower than the effective tax rate for the same period in 2008, primarily because of the effect of the goodwill impairment loss of $462 million, which was a permanent item, on a pretax book loss. The amount of the goodwill impairment loss that was assigned to CILCORP’s Illinois Regulated and Non-rate-regulated Generation business segments was $117 million and $345 million, respectively. As a result of the impairment loss, the effective tax rates for the first six months of 2009 for CILCORP’s Illinois Regulated and Non-rate-regulated Generation business segments were also lower than the effective tax rates in the same period in 2008.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO (Illinois Regulated) and IP) continue to be the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows for Ameren, UE, CIPS, CILCO (Illinois Regulated) and IP. For operating cash flows, Genco and AERG rely on power sales to Marketing Company, which sold power through the September 2006 Illinois power procurement auction, financial contracts that were part of the Illinois electric settlement agreement, 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 June 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 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. Consequently, 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.

The global capital and credit markets experienced extreme volatility and disruption in 2008, and continue to experience volatility and disruption in 2009. See Outlook for a discussion of the implications of this volatility and disruption for the Ameren Companies and our plans to address these issues.

The following table presents net cash provided by (used in) operating, investing and financing activities for the six months ended June 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)	$	908	$	501	$	407	$	(882	)	$	(935	)	$	53		$	133		$	284		$	(151	)
UE		133		115		18		(453	)		(509	)		56			350			209			141
CIPS		125		109		16		(5	)		(2	)		(3	)		(110	)		(133	)		23
Genco		150		92		58		(137	)		(118	)		(19	)		(12	)		26			(38	)
CILCORP		143		129		14		(96	)		(141	)		45			17			25			(8	)
CILCO		145		140		5		(97	)		(139	)		42			16			12			4
IP		261		179		82		(47	)		(79	)		32			(200	)		(73	)		(127	)

(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 six months of 2009 compared with the first six months of 2008. The increase was primarily due to a $122 million net reduction in collateral posted with suppliers, a decrease in income tax payments, net of refunds, of $107 million, and an $85 million decrease in cash payments related to the December 2005 Taum Sauk incident, net of insurance recoveries. Other factors contributing to the increase in operating cash flow during the first six months of 2009, compared with the same period in 2008, included an $82 million decrease in natural gas inventories because of lower prices, an increase in electric costs over-recovered from Illinois customers under cost recovery mechanisms, and a $20 million increase in customer advances for construction. Reducing the increase in cash flow from operations during the first six months of 2009, compared with the same period in 2008, were lower margins as discussed in Results of Operations, a $16 million increase in interest payments, an increase in annual incentive compensation payments, and a $9 million increase in cash payments for major storm restoration costs. The price of natural gas declined significantly during 2009 compared to an increase during 2008. This price change between the two periods was the principal cause of the net working capital decrease associated with accounts and wages payable. Additionally, Ameren made a $24 million contribution to its pension plan during the first six months of 2009. A similar payment was not made during the first six months of 2008.

UE’s cash from operating activities increased in the first six months of 2009 compared with the first six months of 2008. The increase was primarily due to a $123 million decrease in income tax payments, net of refunds, and an $85 million decrease in cash payments related to the December 2005 Taum Sauk incident, net of insurance recoveries. Other factors contributing to the increase in operating cash flow during the first six months of 2009, compared with the same period in 2008, included a $9 million decrease in natural gas inventories because of lower prices, an increase in gas costs over-recovered from customers under the PGA, and a $6 million net reduction in collateral posted with suppliers. Reducing the increase in cash flow from operations during the first six months of 2009, compared to the same period in 2008, was the collection in 2008 of an $85 million affiliate receivable, lower margins as discussed in Results of Operations, an $11 million increase in interest payments, an $8 million increase in major storm restoration costs, and a $10 million pension plan contribution.

CIPS’ cash from operating activities increased in the first six months of 2009 compared with the first six months of 2008. The increase was primarily a result of more cash collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Other factors contributing to the increase in operating cash flow during the second quarter of 2009, compared with the same period in 2008, included a $13 million decrease in natural gas inventories because of lower prices, an increase in electric costs over-recovered from Illinois customers under cost recovery mechanisms, and higher electric margins as discussed in Results of Operations. Reducing the increase in

cash flow from operations during the first six months of 2009, compared to the same period in 2008, were a $6 million net increase in collateral posted with suppliers and a $6 million increase in income tax payments, net of refunds.

Genco’s cash from operating activities increased in the first six months of 2009 compared with the first six months of 2008. Factors contributing to the increase included less cash used for fuel purchases as coal inventory was reduced and a $6 million reduction in funding required by the Illinois electric settlement agreement. Other increases in cash flow from operations were due to the timing of cash receipts from Marketing Company. Reducing the increase in cash flow from operations during the first six months of 2009, compared to the same period in 2008, were lower margins as discussed in Results of Operations, an $18 million increase in income tax payments, net of refunds, and a $7 million increase in interest payments.

CILCORP’s and CILCO’s cash from operating activities increased in the first six months of 2009 compared with the first six months of 2008. Factors contributing to the increase included more cash collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007, a $29 million decrease in natural gas inventories because of lower prices, an increase in electric and gas costs over-recovered from Illinois customers under cost recovery mechanisms, higher electric margins as discussed in Results of Operations, and a $7 million decrease in interest payments for CILCORP and a $4 million decrease for CILCO. Reducing the increase in cash flow from operations during the first six months of 2009 compared to the same period in 2008 were a $31 million increase in income tax payments, net of refunds, for CILCORP and a $34 million increase for CILCO, a $13 million net increase in collateral posted with suppliers, more cash used for the purchase of coal as inventory levels increased at AERG, and an increase in annual incentive compensation payments. On January 1, 2009, approximately 570 Ameren Services employees who provide support services to the Ameren Illinois Utilities were transferred to CILCO. As CILCO employees, they provide services to CIPS and IP as well as to CILCO. The timing of related-party payments for services provided to CIPS and IP resulted in an $8 million temporary reduction of operating cash flow.

IP’s cash from operating activities increased in the first six months of 2009 compared with the first six months of 2008. The increase was primarily a result of more cash collected in 2009 from receivables, because of colder weather in the fourth quarter of 2008, compared with 2007. Other factors contributing to the increase in operating cash flow during the second quarter of 2009, compared with the same period in 2008, included a $31 million decrease in natural gas inventories because of lower prices, an increase in electric and gas costs over-recovered from Illinois customers under cost recovery mechanisms, and higher electric and natural gas margins as discussed in Results of Operations. Reducing the increase in cash flow from operations during the first six months of 2009, compared to the same period in 2008, were a $37 million net increase in collateral posted with suppliers, a $16 million increase in interest payments, and a $9 million increase in income tax payments, net of refunds.

Cash Flows from Investing Activities

Ameren’s cash used for investing activities decreased during the first six months of 2009 compared with the first six months of 2008. The decrease was primarily driven by an $88 million decrease in nuclear fuel expenditures. Partially offsetting this decrease was an increase in net cash used for capital expenditures as a result of increased storm restoration expenditures.

UE’s cash used in investing activities decreased during the second quarter of 2009, compared with the same period in 2008, principally because of an $88 million decrease in nuclear fuel expenditures. Partially offsetting this decrease was a $44 million increase in capital expenditures primarily as a result of increased storm restoration expenditures.

CIPS’ cash used in investing activities during the first six months of 2009 increased compared with the same period in 2008. The $6 million increase in capital expenditures was the result of increased storm restoration expenditures during the 2009 period.

Genco’s cash used in investing activities increased in the first six months of 2009 compared with the same period in 2008, principally because of an $18 million increase in capital expenditures primarily associated with a power plant scrubber project.

CILCORP’s and CILCO’s cash used in investing activities decreased in the first six months of 2009, compared with the same period in 2008, primarily as a result of a $44 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 six months of 2009, compared with the same period in 2008, principally as a result of a $49 million increase in net money pool advances. Capital expenditures also increased by $18 million in the first six months of 2009 from the year-ago period.

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 expenditure reductions have been made from Non-rate-regulated Generation’s previous estimates for this period.

In our rate-regulated businesses, approximately $1 billion of potential reductions have been identified. Which projects may be eliminated or deferred is currently being evaluated.

The following table estimates the capital expenditures that will be incurred by the Ameren Companies from 2009 through 2013, including construction expenditures, capitalized interest for our Non-rate-regulated 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 our Non-rate-regulated 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 to our financial statements under Part I, Item 1, of this report for a discussion of future environmental capital expenditure estimates.

We continually review our 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 six months of 2009 compared with the first six months of 2008. During the first quarter of 2009, UE issued $350 million of senior secured notes and used the proceeds to reduce net short-term borrowings. During the second quarter of 2009, Ameren issued $425 million of senior unsecured notes and used the proceeds to repay borrowings under its $300 million term loan agreement and will use the remainder of the proceeds, by way of a capital contribution, loan or otherwise to CILCORP to permit CILCORP to repay its outstanding senior notes due October 15, 2009. Additionally, during the first six months of 2009, Ameren paid $40 million in banking fees associated with the 2009 Multiyear Credit Agreements and the 2009 Illinois Credit Agreement. Comparatively, during the first six months of 2008, Ameren’s subsidiaries issued $1,335 million of senior secured debt and used the proceeds to repurchase, redeem, and fund maturities of $808 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. Also benefiting cash flow from financing activities for the six months ended June 30, 2009, compared with the year-ago period, was a $102 million decrease in dividends paid on Ameren common stock resulting from the reduction of the quarterly dividend rate.

UE’s net cash provided by financing activities increased in the first six months of 2009, compared with the same period of the prior year. During the six months ended June 30, 2009, UE issued $350 million of senior secured notes and used the proceeds to reduce short-term debt. Comparatively, during the six months ended June 30, 2008, UE used $699 million in proceeds from the issuance of senior secured notes to reduce short-term debt, redeem outstanding auction rate environmental improvement revenue refunding bonds, and fund the current maturity of first mortgage bonds. Partially offsetting cash provided by financing activities, UE reduced its borrowings under an intercompany borrowing arrangement with Ameren during the six months ended June 30, 2009, compared with borrowings from Ameren during the six months ended June 30, 2008, and had a $9 million increase in debt issuance costs as a result of the banking fees associated with the multiyear credit agreements.

CIPS’ net cash used in financing activities decreased during the six months ended June 30, 2009, compared with the first six 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 had a $3 million increase in debt issuance costs as a result of the banking fees associated with the multiyear credit agreements.

Genco had a net use of cash from financing activities during the six months ended June 30, 2009, compared with a net source of cash during the six months ended June 30, 2008. During the 2009 period, Genco had a net $34 million increase in money pool borrowings that were used to fund working capital needs and to fund the current maturity of its intercompany note with CIPS. Debt issuance costs increased as a result of the banking fees associated with the multiyear credit agreements. Additionally, during the first six months of 2009, Genco had no long-term debt issuances and paid no common stock dividends. Comparatively, during the first six months of 2008, Genco issued $300 million of senior unsecured notes, repaid a net $100 million of short-term debt borrowings and paid $84 million of common stock dividends.

CILCORP’s cash provided by financing activities decreased during the six months ended June 30, 2009, compared with the same period in 2008. During the 2009 period, CILCORP had increased intercompany borrowings that were used to reduce their short-term debt and outstanding money pool borrowings, compared with the 2008 period. An $11 million capital contribution received from Ameren in 2009 resulted in a positive impact on cash flows for the first six months of 2009. Additionally, CILCORP’s debt issuance costs increased $14 million during the six months ended June 30, 2009, compared with the same period in 2008, as a result of banking fees associated with the 2009 Multiyear Credit Agreement and the 2009 Illinois Credit Agreement.

CILCO’s cash provided by financing activities increased during the first six months of 2009 compared with the year-ago period. This change was primarily the result of increased intercompany borrowings with Ameren during the first six months of 2009. Comparatively, the 2008 period contained no such borrowings. CILCO also received an $11 million capital contribution from CILCORP during the 2009 period that positively impacted CILCO’s cash flows. Partially offsetting the increase was a $266 million increase in short term debt repayments, a $100 million increase in net money pool repayments, and a $7 million increase in debt issuance costs as a result of banking fees associated with the multiyear credit agreements.

IP’s net cash used in financing activities increased during the first six months of 2009 compared with the year-ago period. During 2009, IP used existing cash to fund the current maturity of its 7.50% mortgage bonds and to pay $6 million for banking fees associated with the 2009 Illinois Credit Agreement. Partially offsetting the increase was a $58 million capital contribution from Ameren during the first six months of 2009. Comparatively, during the six months ended June 30, 2008, IP’s net cash used in financing activities was the result of the issuance of $337 million of senior secured notes that were issued 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; fund current debt maturities; and fund common stock dividends.

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 to our financial statements under Part I, Item 1, of this report for additional information on credit facilities, short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements.

The following table presents the various committed bank credit facilities of Ameren and the Ameren Companies, and their availability, as of June 30, 2009:


Credit Facility	Expiration	Amount Committed		Amount Available
Ameren, UE and, Genco:
2009 multiyear revolving^(a)(b)	July 2011	$	1,300	$	344	^(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 Sublimit 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 June 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 June 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 June 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 to our financial statements 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 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 June 30, 2009, Ameren (on a consolidated basis), UE, CIPS, Genco, CILCORP (on a consolidated basis), CILCO, and IP had $251 million, $30 million, $10 million, $3 million, $64 million, $64 million, and $64 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.

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 agreements or other short-term borrowing arrangements.

Long-term Debt and Equity

The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt (net of any issuance discounts and including any redemption premiums) for the six months ended June 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 to our financial statements under Part I, Item 1, of this report.


	Month Issued, Redeemed, Repurchased or Matured	Six 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 secured 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:
DRPlus and 401(k)	Various	$	47	$	75
Total common stock issuances		$	47	$	75
Total Ameren long-term debt and common stock issuances		$	819	$	1,410
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		-		39
7.50% Series mortgage bond due 2009	June		250		-
Total Ameren long-term debt redemptions, repurchases and maturities		$	250	$	808

The following table presents information with respect to the Form S-3 shelf registration statements filed and effective for certain Ameren Companies as of June 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 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 0.8 million new shares of common stock valued at $19 million and 1.9 million new shares valued at $47 million in the three and six months ended June 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 June 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.

Dividends

Ameren paid to its stockholders common stock dividends totaling $164 million, or 77 cents per share, during the first six months of 2009 (2008 - $266 million or $1.27 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 June 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 six months ended June 30, 2009 and 2008.


	Six Months
	2009		2008
UE	$	99	$	105
Genco		-		84
IP		-		30
Nonregistrants		65		47
Dividends paid by Ameren	$	164	$	266

Contractual Obligations

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

Subsequent to December 31, 2008, obligations related to the procurement of coal, natural gas, nuclear fuel, electric capacity, and heavy forgings materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $6,339 million, $3,345 million, $339 million, $538 million, $1,051 million, $1,051 million and $579 million, respectively. Total other obligations, including the amount of unrecognized tax benefits, at June 30, 2009, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $670 million, $346 million, $24 million, $39 million, $61 million, $61 million and $127 million, respectively.

As a result of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and $28 million from AERG. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the quarter ended June 30, 2009, of $6 million, $1 million, less than $1 million, $1 million, $3 million, and $1 million, respectively (quarter ended June 30, 2008 - $11 million, $1 million, $1 million, $2 million, $5 million, and $2 million, respectively) and during the six months ended June 30, 2009, of $12 million, $2 million, $1 million, $2 million, $5 million, and $2 million, respectively (six months ended June 30, 2008 - $22 million, $3 million, $2 million, $4 million, $9 million, and $4 million, respectively) under the terms of the Illinois electric settlement agreement. At June 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 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	Ba1	BBB	-	BBB	-
Secured debt	Baa2	BBB	+	BBB	+
Senior unsecured debt	Ba1	BBB	-	BBB
Genco:
Issuer/corporate credit rating	-	BBB	-	BBB	+
Senior unsecured debt	Baa3	BBB	-	BBB	+
CILCORP:
Issuer/corporate credit rating	-	BBB	-	BBB	-
Senior unsecured debt	Ba2	BB	+	BBB	-
CILCO:
Issuer/corporate credit rating	Ba1	BBB	-	BBB
Secured debt	Baa2	BBB	+	A	-
IP:
Issuer/corporate credit rating	Ba1	BBB	-	BBB	-
Secured debt	Baa2	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 reflects Moody’s view that Ameren’s announcement to reduce its common stock dividend by 39% is 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 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 reflects 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.

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.

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 June 30, 2009, were $123 million, $15 million, $26 million, $26 million, $26 million, and $48 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively. The amount of collateral external counterparties posted with Ameren was $15 million at June 30, 2009. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3” from S&P or Moody’s, respectively) at June 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 $386 million, $142 million, $28 million, $46 million, $48 million, $48 million, and $55 million, respectively.

In addition, changes in commodity prices could trigger additional collateral postings and prepayments. If market prices were 15% higher than June 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 $133 million, $56 million, $- million, $- million, $6 million, $6 million, and $- million, respectively. If market prices were 15% lower than June 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 $418 million, $191 million, $28 million, $- million, $92 million, $92 million, and $76 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.

Economy and Capital and Credit Markets

The global capital and credit markets experienced extreme volatility and disruption in 2008 and the first half of 2009, and we expect those conditions to continue throughout the rest of 2009 and potentially longer. Several factors have driven this situation, including the U.S. and global economic recession and the weakened condition of major financial institutions. These conditions have led governments around the world to establish policies and programs that are designed to strengthen the global financial system, to enhance liquidity, and to restore investor confidence. We believe that these events have several implications for the capital and credit markets, the economy and our industry as a whole, including Ameren. They include the following:

•

Access to Capital Markets and Cost of Capital - The extreme disruption in the capital markets has 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 at commercially acceptable, but higher, rates as evidenced by Ameren’s, CILCO’s, IP’s, and UE’s sale of debt securities in late 2008 and the first half of 2009. Ameren expects access to the capital markets for its non-rate-regulated subsidiaries to be more difficult and costly. Ameren currently plans to issue up to approximately $250 million of debt at our rate-regulated utilities, and up to approximately $500 million at our non-rate-regulated generation subsidiaries during the remainder of 2009.

•

Credit Facilities - At 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, reducing to $1.8795 billion through June 30, 2011, and with $1.0795 billion through July 14, 2011. The facilities include 24 international, national and regional lenders with no single lender providing more than $146 million of the aggregate commitments. 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.

•

Economic Conditions - Limited access to capital and credit and higher cost of capital for businesses and consumers are expected to reduce spending and investment, result in job losses, and pressure economic growth. The current weak economic conditions will likely result in continued weaker power and commodity markets, greater risk of defaults by our counterparties, weaker customer sales growth or sales contraction, particularly with respect to industrial sales, higher bad debt expense, higher financing costs, and possible impairment of goodwill and long-lived assets, among other things. Due to a significant decline in Ameren’s market capitalization, the continuing decline in market prices for electricity, and a decrease in observable industry market multiples, CILCORP’s Illinois Regulated and CILCORP’s Non-rate-regulated 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 Non-rate-regulated Generation reporting unit, and IP’s Illinois Regulated reporting unit exceeded their carrying value by a nominal amount 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 second quarter of 2009, and therefore, no interim impairment test was performed. We are unable to predict the ultimate impact of the economic recession on our results of operations, financial position, or liquidity.

•

Investment Returns - The disruption in the capital markets, coupled with weak global economic conditions, has adversely affected financial markets. As a result, we 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 June 30, 2009, and reflecting Ameren’s pension funding policy, Ameren expects to make annual contributions of $90 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.

•

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 Non-rate-regulated 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 our planned operations and maintenance expenditures across our organization, but especially in our Non-rate-regulated Generation business and business support functions. We are managing power plant outages and labor costs, among other things. Our objective is to significantly lower 2010 nonfuel operations and maintenance costs, relative to the 2008 level, in our Non-rate-regulated Generation business. 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.

•

Liquidity - At June 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 $1.4 billion, which was approximately $230 million higher than the same time last year. We expect our available liquidity to remain at acceptable levels through the end of 2009 as we strategically access the capital markets and execute expenditure control initiatives. However, we are unable to predict whether significant changes in economic conditions, further disruption in the capital and credit markets, or other unforeseen events could materially impact our expectation.

Although we believe that the uncertainty in the capital and credit markets will persist throughout 2009 and potentially longer, we do believe that actions taken by the U.S. government and governments around the world will ultimately help ease the extreme volatility and disruption of these markets. In addition, we believe we will continue to have access to the capital markets on terms commercially acceptable to us. As discussed above, additional financings are expected through 2009, subject to market conditions. Also, in February 2009, Ameren’s board of directors made the decision to reduce the common stock dividend. Specifically, this dividend reduction would be 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. 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 through the end of 2009, at a minimum. However, there can be no assurance that significant changes in economic conditions, further disruptions in the capital and credit markets, or other unforeseen events will not materially impact our ability to execute our expected operating, capital or financing plans.

Current Capital Expenditure Plans

•

Between 2009 and 2018, Ameren expects that certain Ameren Companies will be required to invest between

$4.0 billion and $5.0 billion 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 Non-rate-regulated Generation operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased environmental costs for generators.

•

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

•

UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. 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 efficiency programs is to reduce electric usage by 540 megawatts by 2025, which is the equivalent of a medium-sized coal-fired power plant.

•

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.

•

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.

•

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.

•

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.

•

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

Revenues

•

The earnings of UE, CIPS, CILCO and IP are largely determined by the regulation of their rates by state agencies. 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.

•

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.

•

In July 2009, a new law became effective in Illinois that allows electric and gas utilities to recover through a rate adjustment the difference between its actual bad debt expense and the bad debt expense included in the utility’s rates. The legislation provides utilities the ability to adjust their rates annually through a rate adjustment mechanism beginning with 2008 and prospectively. During 2008, the Ameren

100

Illinois Utilities under collected approximately $25 million (CIPS - $5 million, CILCO - $4 million, and IP - $16 million). The Ameren Illinois Utilities plan to file with the ICC in August 2009 electric and gas rate adjustment clause tariffs to recover bad debt expense not recovered in 2008 and to adjust rates to recover the differential thereafter. The ICC has up to 180 days from the date of filing to approve of the rate adjustment clause tariffs, or approve as modified, the filed tariff. Upon ICC approval, 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) to customer assistance programs.

•

CIPS, CILCO, and IP filed requests with the ICC in June 2009 to increase their annual revenues for electric and natural gas delivery services. In supplemental testimony filed with the ICC in July 2009, CIPS, CILCO, and IP requested to increase their annual revenues for electric delivery service by $176 million in the aggregate (CIPS - $50 million, CILCO - $28 million, and IP - $98 million). The electric rate increase requests are based on an 11.75% to 12.25% 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. Also in supplemental testimony filed with the ICC in July 2009, CIPS, CILCO, and IP requested to increase their annual revenues for natural gas delivery service by $43 million in the aggregate (CIPS - $11 million, CILCO - $9 million, and IP - $23 million). The natural gas rate increase requests are based on an 11.25% to 11.6% 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 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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The ICC issued a consolidated order in September 2008 approving a net increase in annual revenues for electric delivery service of $123 million in the aggregate (CIPS - $22 million increase, CILCO - $3 million decrease and IP - $104 million increase) and a net increase in annual revenues for natural gas delivery service of $38 million in the aggregate (CIPS - $7 million increase, CILCO - $9 million decrease, and IP - $40 million increase). These rate changes were effective on October 1, 2008. Because of the Ameren Illinois Utilities’ pledge to keep the overall residential electric bill increase resulting from these rate changes during the first year to less than 10% for each utility, IP will not recover approximately $10 million in revenue in the first year the electric delivery service rates are in effect. Beginning in November 2009, IP’s residential electric delivery service rates will be adjusted to recover the full increase. In addition, the ICC changed the depreciable lives used in calculating depreciation expense for the Ameren Illinois Utilities’ electric and natural gas rates. As a result, annual depreciation expense for the Ameren Illinois Utilities will be reduced for financial reporting purposes by a net $13 million in the aggregate (CIPS - $4 million reduction, CILCO - $26 million reduction, and IP - $17 million increase).

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In the ICC consolidated electric and natural gas rate order issued in September 2008, the ICC order approved an increase in the percentage of costs to be recovered through fixed non-volumetric residential and commercial natural gas customer charges to 80% from 53%. This increase will impact 2009 quarterly results of operations and cash flows but is not expected to have any impact on annual margins. The ICC also approved an increase in the SCA factors for the Ameren Illinois Utilities. The SCA is a charge applied only to the bills of customers who take their power supply from the Ameren Illinois Utilities. The change in the SCA factors is expected to result in increased electric revenues of $9.5 million per year in the aggregate (CIPS - $2.6 million, CILCO - $1.6 million, and IP - $5.3 million) covering the increased cost of administering the Ameren Illinois Utilities’ power supply responsibilities.

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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 is 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 February 28, 2010. UE’s filing includes a request for interim rate relief which, if approved, would place into effect approximately $37 million of the requested increase on October 1, 2009, subject to refund with interest based on the final outcome of the rate proceeding. The amount of this interim increase request reflects the increased revenue requirement associated with the rate base additions made by UE between October 2008 and May 2009. The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months, and a decision by the MoPSC in such proceeding is required by 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 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 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.

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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 an August 4, 2009 press release, Noranda stated that its smelter plant operated above 55% of its capacity throughout the second quarter of 2009. In a presentation provided to the MoPSC in July 2009, Noranda management indicated full restart timing will depend on market conditions, among other things. 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 $10 million and $20 million lower during the second quarter and first six 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 Noranda’s operational issues at its smelter plant, 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 provides approximately $1 billion over a four-year period that began in 2007 to fund rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Funding for the settlement is coming from electric generators in Illinois and certain Illinois electric utilities. The Ameren Illinois Utilities, Genco, and AERG agreed to fund an aggregate of $150 million, of which the following contributions remained to be made at June 30, 2009:


	Ameren		CIPS		CILCO (Illinois Regulated)		IP		Genco		CILCO (AERG)
2009^(a)	$	14.4	$	2.1	$	1.0	$	2.8	$	5.9	$	2.6
2010^(a)		1.9		0.3		0.1		0.4		0.8		0.3
Total	$	16.3	$	2.4	$	1.1	$	3.2	$	6.7	$	2.9

(a)	Estimated.

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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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In addition, the Illinois electric settlement agreement would allow the Ameren Illinois Utilities to lease or invest in generation facilities, subject to ICC approval.

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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 second quarter and during the first six months of 2009 compared with the same periods in 2008, and are expected to remain lower compared to 2008 for the remainder of the year.

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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 Non-rate-regulated Generation segment expects to generate 28 million megawatthours of power from its coal-fired plants in 2009 (Genco - 14 million, AERG - 7 million, EEI - 7 million) based on expected power prices in 2009. Should power prices rise more than expected in 2009, the Non-rate-regulated Generation segment has the capacity and availability to sell more generation.

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With few scheduled outages in 2010 and 2011, the Non-rate-regulated Generation segment expects to have available generation of 35 million megawatthours in each year. However, the Non-rate-regulated 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 Non-rate-regulated Generation segment is to optimize generation output in a low risk manner to minimize volatility of earnings and cash flow, while seeking to capitalize on its low-cost generation fleet to provide solid, sustainable returns. To accomplish this strategy, the Non-rate-regulated Generation segment has established hedge targets for near-term years. Through a mix of physical and financial sales contracts, Marketing Company targets to hedge Non-rate-regulated Generation’s expected output by 80% to 90% for the following year, 50% to 70% for two years out, and 30% to 50% for three years out. As of August 6, 2009, Marketing Company had sold 100% of Non-rate-regulated Generation’s expected 2009 generation, at an average price of $54 per megawatthour. For 2010, Marketing Company has hedged approximately 23 million megawatthours of Non-rate-regulated Generation’s forecasted generation sales at an average price of $48 per megawatthour. For 2011, Marketing Company has hedged approximately 15 million megawatthours of Non-rate-regulated Generation’s forecasted generation sales at an average price of $51 per megawatthour. Additionally, Marketing Company has entered into capacity-only sales contracts for 2010 and 2011 resulting in expected capacity-only revenues related to these contracts of $60 million in 2010 and $45 million in 2011.

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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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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.

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In July 2009, the weather conditions in the Midwest market and in Ameren’s electric utility companies’ service territories were unseasonably mild. Cooling degree-days in Ameren’s service territories during July 2009 were 30% lower than normal July weather conditions. This mild weather will have an unfavorable impact on the Ameren Companies’ results of operations.

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 June 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 during the second half of 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 June 30, 2009, Non-rate-regulated Generation’s baseload hedged fuel costs, which include coal, transportation, diesel fuel surcharges, and other charges, were increasing from an average cost of approximately $20.50 per megawatthour in 2009 to approximately $23.50 per megawatthour in 2010 and $26 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 through early 2010. The estimated cost to rebuild the upper reservoir is in the range of $480 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. We are unable to predict the timing or outcome of this litigation, or its possible effect on UE’s results of operations, financial position or liquidity. Despite this litigation, discussions to settle claims under the property policy are ongoing with these insurance carriers and other insurance carriers not parties to the litigation. Until the insurance review is completed and the litigation is 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. At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the facility, and the cost of replacement power (up to $8 million annually), will be recovered through insurance. Any amounts not recovered through insurance could result in charges to earnings, which could be material. See Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further discussion of Taum Sauk matters.

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UE’s Callaway nuclear plant had a 28-day scheduled refueling and maintenance outage during the fourth quarter of 2008. UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in the spring of 2010. During a scheduled outage, which occurs every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, versus non-outage years.

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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. The Ameren Companies do not expect the decision to have a material impact on their results of operations, financial position or liquidity.

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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.

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In July 2009, Non-rate-regulated Generation announced staff reductions. Non-rate-regulated Generation estimates approximately $2 million of severance and related costs will be incurred during 2009 related to displaced employees. The majority of the 42 eliminated positions will be effective in early September, with a smaller group expected to be effective in March 2010. Ameren’s Non-rate-regulated Generation segment continues to evaluate opportunities to further reduce cost as are the other Ameren segments.

Other

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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.

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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.

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Ameren and Genco are currently considering strategic alternatives for some of Genco’s smaller non-rate-regulated generating units.

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UE and the Ameren Illinois Utilities have applied for three grants under DOE’s Smart Grid Investment Program. The grants would partially offset, as much as a half of the estimated capital costs of $230 million, ($140 million for UE and $90 million for the Ameren Illinois Utilities), to install smart grid technology on portions of the companies’ electric distribution systems. The filing of those applications does not mean a decision has been made to construct those assets. If UE and/or the Ameren Illinois Utilities are awarded grants, they will seek authority for rate recovery from customers for any portion of the construction costs not provided for under the grants. UE and the Ameren Illinois Utilities are expected to be notified by the DOE in the fourth quarter of 2009 if they have been awarded grants.

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 to our financial statements under Part I, Item 1, of this report.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

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

Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Form 10-K. See Item 7A under Part II of the Form 10-K for a more detailed discussion of our market risks.

Interest Rate Risk

We are exposed to market risk through changes in interest rates. The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable-rate debt outstanding at June 30, 2009:


	Interest Expense			Net Income^(a)
Ameren^(b)	$	12		$	(8	)
UE		7			(4	)
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. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction. See Note 6—Derivative Financial Instruments to our financial statements under Part I, Item 1, of this report for information on the potential loss on counterparty exposure as of June 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 June 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 weakening economic environment on customer collections. These companies 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 June 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 less than $1 million, net of collateral (2008 - $2 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 $5 million at June 30, 2009 (2008 - $62 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 provides $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, at the end of each month, the Ameren Illinois Utilities will bill the participating generators for their proportionate share of that month’s rate relief and assistance, which is due in 30 days, or drawn from the funds provided by the generators’ escrow. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for additional information.

Equity Price Risk

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

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.

The following table shows how Ameren’s cumulative earnings might decrease if power prices were to decrease by 1% on unhedged economic generation for the remainder of 2009 through 2012:


	Net Income^(a)
Ameren^(b)	$	(16	)
UE		(7	)
Genco		(5	)
CILCO (AERG)		(2	)
EEI		(5	)

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

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

Ameren also uses its portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. Due to our physical presence in the market, we are able to identify and pursue opportunities, which can generate additional returns through portfolio management and trading activities. All of this activity is

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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 was 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 to our financial statements 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 deals or market conditions. The strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions.

Transportation costs for coal and natural gas can be a significant portion of fuel costs. 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 through 2013, as of June 30, 2009. The projected required supply of these commodities could be significantly impacted by changes in our assumptions for such matters as customer demand of our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.


	2009		2010		2011 - 2013
Ameren:
Coal	100	%	89	%	27	%
Coal transportation	100		99		60
Nuclear fuel	100		100		86
Natural gas for generation	70		8		-
Natural gas for distribution^(a)	69		34		13
Purchased power for Illinois Regulated^(b)	100		82		35
UE:
Coal	100	%	91	%	26	%
Coal transportation	100		100		62
Nuclear fuel	100		100		86
Natural gas for generation	50		6		-
Natural gas for distribution^(a)	72		35		17
CIPS:
Natural gas for distribution^(a)	69	%	30	%	13	%
Purchased power^(b)	100		82		35
Genco:
Coal	100	%	89	%	26	%
Coal transportation	100		97		37
Natural gas for generation	100		-		-
CILCORP/CILCO:
Coal (AERG)	100	%	84	%	35	%
Coal transportation (AERG)	100		100		79
Natural gas for distribution^(a)	73		34		12
Purchased power^(b)	100		82		35

107


	2009		2010		2011 - 2013
IP:
Natural gas for distribution^(a)	66	%	34	%	12	%
Purchased power^(b)	100		82		35
EEI:
Coal	100	%	90	%	26	%
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 to our financial statements 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.

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)	$	24	$	(15	)	$	8	$	(5	)
UE		14		(8	)		5		(3	)
Genco		5		(3	)		1		(1	)
CILCORP		3		(2	)		1		(c	)
CILCO (AERG)		3		(2	)		1		(c	)
EEI		3		(2	)		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 $10 million annually for 2009 (UE - $5 million, Genco - $2 million, AERG - $1 million and EEI - $2 million). As of June 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 90% of the 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 to our financial statements under Part I, Item 1, of this report for further information regarding the long-term commitments for the procurement of coal, natural gas and nuclear fuel.

Fair Value of Contracts

Most of our commodity contracts qualify for treatment as 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 three and six months ended June 30, 2009. We use various methods to determine the fair value of our contracts. In accordance with SFAS No. 157 hierarchy levels, our sources used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). All of these contracts have maturities of less than five years. See Note 7 - Fair Value Measurements to our financial statements under Part I, Item 1, of this report for further information regarding the methods used to determine the fair value of these contracts.

108


	Ameren^(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Three Months Ended June 30, 2009
Fair value of contracts at beginning of period, net	$	6		$	7		$	(170	)	$	(2	)	$	(110	)	$	(277	)
Contracts realized or otherwise settled during the period		15			(3	)		16			1			20			30
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		51			17			(1	)		1			1			3
Other changes in fair value		(2	)		(2	)		2			(1	)		-			8
Fair value of contracts outstanding at the end of period, net	$	70		$	19		$	(153	)	$	(1	)	$	(89	)	$	(236	)
Six Months Ended June 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		12			(17	)		30			1			34			57
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		57			24			(2	)		-			-			(7	)
Other changes in fair value		(19	)		(4	)		(97	)		(1	)		(64	)		(152	)
Fair value of contracts outstanding at the end of period, net	$	70		$	19		$	(153	)	$	(1	)	$	(89	)	$	(236	)

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

The following table presents maturities of derivative contracts as of June 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	$	(7	)	$	-		$	-		$	-	$	(7	)
Level 2^(a)		52			-			-			-		52
Level 3^(b)		(1	)		22			4			-		25
Total	$	44		$	22		$	4		$	-	$	70
UE:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2^(a)		6			-			-			-		6
Level 3^(b)		2			8			3			-		13
Total	$	8		$	8		$	3		$	-	$	19
CIPS:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2^(a)		-			-			-			-		-
Level 3^(b)		(59	)		(81	)		(13	)		-		(153	)
Total	$	(59	)	$	(81	)	$	(13	)	$	-	$	(153	)
Genco:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2^(a)		-			-			-			-		-
Level 3^(b)		(1	)		-			-			-		(1	)
Total	$	(1	)	$	-		$	-		$	-	$	(1	)
CILCORP/CILCO:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2^(a)		-			-			-			-		-
Level 3^(b)		(40	)		(44	)		(5	)		-		(89	)
Total	$	(40	)	$	(44	)	$	(5	)	$	-	$	(89	)
IP:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2^(a)		-			-			-			-		-
Level 3^(b)		(91	)		(124	)		(21	)		-		(236	)
Total	$	(91	)	$	(124	)	$	(21	)	$	-	$	(236	)

(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.

109

ITEM 4 and ITEM 4T. CONTROLS AND PROCEDURES.

(a)	Evaluation of Disclosure Controls and Procedures

As of June 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, Note 8 - Related Party Transactions and Note 9 - Commitments and Contingencies to our financial statements under Part I, Item 1 of this report.

ITEM 1A.

RISK FACTORS.

There have been no material changes to the risk factors disclosed in Item 1A. Risk Factors in the Form 10-K.

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
April 1 - April 30, 2009	-	$	-	-	-
May 1 - May 31, 2009	-		-	-	-
June 1 - June 30, 2009	3,330		24.09	-	-
Total	3,330	$	24.09	-	-

(a)

Included in June were 3,330 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 for a director compensation award. Ameren does not have any publicly announced equity securities repurchase plans or programs.

None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the April 1 to June 30, 2009 period.

110

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Ameren

At Ameren’s annual meeting of shareholders held on April 28, 2009, the following matters were presented to the meeting for a vote and the results of such voting are as follows:

Item (1)

Election of 13 directors (comprising Ameren’s full Board of Directors) to serve until the next annual meeting of shareholders in 2010.


Name	For	Withheld	Broker Non-Votes^(a)
Stephen F. Brauer	172,349,273	6,703,643	-
Susan S. Elliott	172,018,055	7,034,861	-
Ellen M. Fitzsimmons	172,084,430	6,968,486	-
Walter J. Galvin	167,759,094	11,293,822	-
Gayle P.W. Jackson	172,360,492	6,692,424	-
James C. Johnson	172,245,090	6,807,826	-
Charles W. Mueller	171,779,004	7,273,912	-
Douglas R. Oberhelman	167,719,157	11,333,759	-
Gary L. Rainwater	171,213,261	7,839,655	-
Harvey Saligman	171,380,731	7,672,185	-
Patrick T. Stokes	171,903,927	7,148,989	-
Thomas R. Voss	172,192,821	6,860,095	-
Jack D. Woodard	172,340,237	6,712,679	-

(a)	Broker shares included in the quorum but not voting on the item.

Item (2)

Ameren proposal regarding ratification of the appointment of PricewaterhouseCoopers LLP as Ameren’s independent registered public accounting firm for the fiscal year ending December 31, 2009.


For	Against	Abstain	Broker Non-Votes^(a)
175,471,904	2,277,050	1,303,962	-

(a)	Broker shares included in the quorum but not voting on the item.

Item (3)

Shareholder proposal relating to releases from UE’s Callaway nuclear plant.


For	Against	Abstain	Broker Non-Votes^(a)
14,215,494	115,270,277	14,977,585	34,589,559

(a)	Broker shares included in the quorum but not voting on the item.

At UE’s annual meeting of shareholders held on April 28, 2009, the following individuals (comprising UE’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2010: Warner L. Baxter, Daniel F. Cole, Adam C. Heflin, Martin J. Lyons, Richard J. Mark and Steven R. Sullivan. Each individual received 102,123,834 votes for election and no withheld votes or broker non-votes.

CIPS

At CIPS’ annual meeting of shareholders held on April 28, 2009, the following individuals (comprising CIPS’ full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2010: Scott A. Cisel, Daniel F. Cole, Martin J. Lyons and Steven R. Sullivan. Each individual received 25,452,373 votes for election and no withheld votes or broker non-votes.

CILCO

At CILCO’s annual meeting of shareholders held on April 28, 2009, the following individuals (comprising CILCO’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2010: Scott A. Cisel, Daniel F. Cole, Martin J. Lyons and Steven R. Sullivan. Each individual received 13,563,871 votes for election and no withheld votes or broker non-votes.

111

At IP’s annual meeting of shareholders held on April 28, 2009, the following individuals (comprising IP’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2010: Scott A. Cisel, Daniel F. Cole, Martin J. Lyons and Steven R. Sullivan. Each individual received 23,662,924 votes for election and no withheld votes or broker non-votes.

GENCO and CILCORP

The information called for by this item is omitted in reliance on General Instruction H(1)(a) and (b) of Form 10-Q.

112

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:
Instruments Defining Rights of Securities Holders, Including Indentures
4.1	Ameren CIPS	Supplemental Indenture dated June 15, 2009 to Indenture of Mortgage or Deed of Trust dated October 1, 1941, from CIPS to U.S. Bank National Association and Richard Prokosch, as successor trustees, for the 2009 Illinois Credit Agreement series bonds
4.2	Ameren CILCO	Supplemental Indenture dated June 15, 2009 to Indenture of Mortgage and Deed of Trust between Illinois Power Company (predecessor in interest to CILCO) and Deutsche Bank Trust Company Americas’ (formerly known as Bankers Trust Company), as trustee, dated as of April 1, 1933, for the 2009 Illinois Credit Agreement series bonds
4.3	Ameren IP	Supplemental Indenture dated June 15, 2009 to General Mortgage Indenture and Deed of Trust dated as of November 1, 1992 between IP and The Bank of New York Mellon Trust Company, N.A., as successor trustee, for the 2009 Illinois Credit Agreement series bonds
4.4	Ameren	Ameren Company Order dated May 15, 2009 establishing the 8.875% Senior Notes due 2014 (including the global note)	May 15, 2009 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756
Material Contracts
10.1	Ameren Companies	*Revised Schedule I to Second Amended and Restated Ameren Corporation Change of Control Severance Plan
10.2	Ameren CIPS CILCO IP	Credit Agreement dated as of June 30, 2009, among Ameren, CIPS, CILCO, IP and JPMorgan Chase Bank, N.A., as agent (2009 Illinois Credit Agreement)
10.3	Ameren UE Genco	Amendment Agreement dated as of June 30, 2009, among Ameren, UE, Genco and JPMorgan Chase Bank, N.A., as administrative agent, in respect of the Amended and Restated Credit Agreement dated as of July 14, 2006, among Ameren, UE, Genco and JPMorgan Chase Bank, N.A., as agent
10.4	Ameren UE Genco	Supplemental Credit Agreement dated as of June 30, 2009, among Ameren, UE, Genco and JPMorgan Chase Bank, N.A., as agent
Statement re: Computation of Ratios
12.1	Ameren	Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges

113


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
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
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

114


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
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 June 30, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statement of Income for the three and six months ended June 30, 2009 and 2008, (ii) the Consolidated Balance Sheet at June 30, 2009, and December 31, 2008, (iii) the Consolidated Statement of Cash Flows for the six months ended June 30, 2009 and 2008, and (iv) the Combined Notes to the financial Statements for the six months ended June 30, 2009, tagged as blocks of text. These Exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.

115

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)

116

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: August 10, 2009

117