Edgar Filing: AMEREN CORP

ameren10q06302008.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(X) Quarterly report pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

for the Quarterly Period Ended June 30, 2008

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

of the Securities Exchange Act of 1934

for the transition period from ____ to ____.

Commission File Number	Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number	IRS Employer Identification No.

1-14756	Ameren Corporation	43-1723446
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

1-2967	Union Electric Company	43-0559760
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

1-3672	Central Illinois Public Service Company	37-0211380
	(Illinois Corporation)
	607 East Adams Street
	Springfield, Illinois 62739
	(888) 789-2477

333-56594	Ameren Energy Generating Company	37-1395586
	(Illinois Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222

2-95569	CILCORP Inc.	37-1169387
	(Illinois Corporation)
	300 Liberty Street
	Peoria, Illinois 61602
	(309) 677-5271

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

1-3004	Illinois Power Company	37-0344645
	(Illinois Corporation)
	370 South Main Street
	Decatur, Illinois 62523
	(217) 424-6600

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes (X) No ( )

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

	Large Accelerated Filer	Accelerated Filer	Non-Accelerated Filer	Smaller Reporting Company
Ameren Corporation	(X)	( )	( )	( )
Union Electric Company	( )	( )	(X)	( )
Central Illinois Public Service Company	( )	( )	(X)	( )
Ameren Energy Generating Company	( )	( )	(X)	( )
CILCORP Inc.	( )	( )	(X)	( )
Central Illinois Light Company	( )	( )	(X)	( )
Illinois Power Company	( )	( )	(X)	( )

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

Ameren Corporation	Yes	( )	No	(X)
Union Electric Company	Yes	( )	No	(X)
Central Illinois Public Service Company	Yes	( )	No	(X)
Ameren Energy Generating Company	Yes	( )	No	(X)
CILCORP Inc.	Yes	( )	No	(X)
Central Illinois Light Company	Yes	( )	No	(X)
Illinois Power Company	Yes	( )	No	(X)

The number of shares outstanding of each registrant’s classes of common stock as of July 31, 2008, was as follows:

Ameren Corporation	Common stock, $.01 par value per share – 210,208,319

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

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations............................................................................................................	60
Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................................................................................................................................................	85
Item 4 and
Item 4T. Controls and Procedures...............................................................................................................................................................................................................................	90

PART II Other Information

Item 1. Legal Proceedings...........................................................................................................................................................................................................................................	90
Item 1A. Risk Factors......................................................................................................................................................................................................................................................	91
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.................................................................................................................................................................	91
Item 4. Submission of Matters to a Vote of Security Holders...............................................................................................................................................................................	91
Item 6. Exhibits..............................................................................................................................................................................................................................................................	93

Signatures.........................................................................................................................................................................................................................................................................	96

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

GLOSSARY OF TERMS AND ABBREVIATIONS

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

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

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

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

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

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

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

ARO – Asset retirement obligations.

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

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

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

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

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

CIPSCO – CIPSCO Inc., the former parent of CIPS.

CO2 – Carbon dioxide.

COLA – Combined construction and operating license application.

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

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

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

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

Dynegy – Dynegy Inc.

EEI – Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary that operates non-rate-regulated electric generation facilities and FERC-regulated transmission facilities in Illinois. Prior to February 29, 2008, EEI was 40% owned by UE and 40% owned by Development Company. On February 29, 2008, UE’s 40% ownership interest and Development Company’s 40% ownership interest were transferred to Resources Company. The remaining 20% is owned by Kentucky Utilities Company.

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

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

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

FASB – Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.

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

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

Fitch – Fitch Ratings, a credit rating agency.

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

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

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

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

Gigawatthour – One thousand megawatthours.

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

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

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

Illinois electric settlement agreement – A comprehensive settlement of issues in Illinois arising out of the end of ten

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

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

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

IP – Illinois Power Company, an Ameren Corporation subsidiary. IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenIP.

IP LLC – Illinois Power Securitization Limited Liability Company, which is a special-purpose Delaware limited-liability company.

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

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

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

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

Medina Valley – AmerenEnergy Medina Valley Cogen L.L.C., a Resources Company subsidiary, which owns a 40-megawatt gas-fired electric generation plant.

Megawatthour – One thousand kilowatthours.

MGP – Manufactured gas plant.

MISO – Midwest Independent Transmission System Operator, Inc.

MISO Day Two Energy Market – A market that uses market-based pricing, incorporating transmission congestion and line losses, to compensate market participants for power.

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

Money pool – Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools maintained for rate-regulated and non-rate-regulated business are referred to as the utility money pool and the non-state-regulated subsidiary money pool, respectively.

Moody’s – Moody’s Investors Service Inc., a credit rating agency.

MoPSC – Missouri Public Service Commission, a state agency that regulates Missouri utility businesses, including the rate-regulated operations of UE.

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

NOx – Nitrogen oxide.

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

NYMEX – New York Mercantile Exchange.

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

Off-system revenues – Revenues from nonnative load sales.

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

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

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

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

RFP – Request for proposal.

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

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

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

SO2 – Sulfur dioxide.

TFN – Transitional Funding Trust Notes issued by IP SPT as allowed under the Illinois Customer Choice Law. IP must designate a portion of cash received from customer billings to pay the TFNs. The proceeds received by IP are remitted to IP SPT. The proceeds are restricted for the sole purpose of making payments of principal and interest on, and paying other fees and expenses related to, the TFNs. Since the application of FIN 46R, IP does not consolidate IP SPT. Therefore, the obligation to IP SPT appears on IP’s balance sheet.

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

FORWARD-LOOKING STATEMENTS

Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:

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

·	uncertainty as to the effect of implementation of the Illinois electric settlement agreement on Ameren, the Ameren Illinois Utilities, Genco and AERG, including implementation of a new power procurement process in Illinois that began in 2008;

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

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

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

the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at both the state and federal levels, and the implementation of deregulation, such as occurred when the electric rate freeze and power supply contracts expired in Illinois at the end of 2006;

·	the effects of participation in the MISO;

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

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

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

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

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

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

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

·	weather conditions and other natural phenomena;

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

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

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

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

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

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

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

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

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

·	legal and administrative proceedings; and

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

Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to update or revise publicly any forward-looking statements to reflect new information or future events.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Operating Revenues:
Electric	$	1,545		$	1,519		$	3,012		$	2,982
Gas		243			209			855			770
Total operating revenues		1,788			1,728			3,867			3,752

Operating Expenses:
Fuel		200			263			502			526
Coal contract settlement		(60	)		-			(60	)		-
Purchased power		306			314			593			687
Gas purchased for resale		165			133			624			554
Other operations and maintenance		469			420			891			809
Depreciation and amortization		178			176			354			359
Taxes other than income taxes		89			96			202			198
Total operating expenses		1,347			1,402			3,106			3,133
Operating Income		441			326			761			619
Other Income and Expenses:
Miscellaneous income		21			20			42			34
Miscellaneous expense		(8	)		(8	)		(13	)		(13	)
Total other income		13			12			29			21
Interest Charges		118			108			218			206
Income Before Income Taxes, Minority Interest
and Preferred Dividends of Subsidiaries		336			230			572			434
Income Taxes		119			78			206			149
Income Before Minority Interest and Preferred
Dividends of Subsidiaries		217			152			366			285
Minority Interest and Preferred Dividends of Subsidiaries		11			9			22			19
Net Income	$	206		$	143		$	344		$	266

Earnings per Common Share – Basic and Diluted	$	0.98		$	0.69		$	1.64		$	1.29
Dividends per Common Share	$	0.635		$	0.635		$	1.270		$	1.270
Average Common Shares Outstanding		209.5			207.1			209.1			206.9

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,			December 31,
	2008			2007
ASSETS
Current Assets:
Cash and cash equivalents	$	205		$	355
Accounts receivable – trade (less allowance for doubtful
accounts of $26 and $22, respectively)		529			570
Unbilled revenue		389			359
Miscellaneous accounts and notes receivable		376			280
Materials and supplies		719			735
Mark-to-market derivative assets		273			35
Other current assets		275			146
Total current assets		2,766			2,480
Property and Plant, Net		15,566			15,069
Investments and Other Assets:
Nuclear decommissioning trust fund		284			307
Goodwill		831			831
Intangible assets		177			198
Regulatory assets		1,081			1,158
Other assets		940			685
Total investments and other assets		3,313			3,179
TOTAL ASSETS	$	21,645		$	20,728

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	285		$	221
Short-term debt		1,450			1,472
Accounts and wages payable		527			687
Taxes accrued		111			84
Mark-to-market derivative liabilities		236			24
Other current liabilities		469			414
Total current liabilities		3,078			2,902
Long-term Debt, Net		6,146			5,691
Preferred Stock of Subsidiary Subject to Mandatory Redemption		16			16
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,104			2,046
Accumulated deferred investment tax credits		104			109
Regulatory liabilities		1,437			1,240
Asset retirement obligations		576			562
Accrued pension and other postretirement benefits		758			839
Other deferred credits and liabilities		390			354
Total deferred credits and other liabilities		5,369			5,150
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption		195			195
Minority Interest in Consolidated Subsidiaries		24			22
Commitments and Contingencies (Notes 2, 8, 9 and 10)
Stockholders' Equity:
Common stock, $.01 par value, 400.0 shares authorized –
shares outstanding of 210.1 and 208.3, respectively		2			2
Other paid-in capital, principally premium on common stock		4,693			4,604
Retained earnings		2,188			2,110
Accumulated other comprehensive income (loss)		(66	)		36
Total stockholders’ equity		6,817			6,752
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	21,645		$	20,728

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,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	344		$	266
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sales of emission allowances		(2	)		(2	)
Mark-to-market gain on derivatives		(94	)		(1	)
Coal contract settlement		(60	)		-
Depreciation and amortization		364			357
Amortization of nuclear fuel		20			15
Amortization of debt issuance costs and premium/discounts		8			10
Deferred income taxes and investment tax credits, net		107			(8	)
Minority interest		16			13
Other		4			7
Changes in assets and liabilities:
Receivables		15			(131	)
Materials and supplies		16			35
Accounts and wages payable		(64	)		(62	)
Taxes accrued, net		(58	)		59
Assets, other		32			29
Liabilities, other		65			19
Pension and other postretirement benefit obligations		15			50
Counterparty collateral asset		(205	)		(97	)
Counterparty collateral liability		79			-
Taum Sauk insurance receivable, net		(107	)		(16	)
Net cash provided by operating activities		495			543
Cash Flows From Investing Activities:
Capital expenditures		(798	)		(715	)
Nuclear fuel expenditures		(123	)		(24	)
Purchases of securities – nuclear decommissioning trust fund		(247	)		(75	)
Sales of securities – nuclear decommissioning trust fund		231			65
Purchases of emission allowances		(2	)		(9	)
Sales of emission allowances		2			3
Other		2			1
Net cash used in investing activities		(935	)		(754	)
Cash Flows From Financing Activities:
Dividends on common stock		(266	)		(263	)
Capital issuance costs		(9	)		(3	)
Short-term debt, net		(22	)		1,007
Dividends paid to minority interest holder		(15	)		(10	)
Redemptions, repurchases, and maturities of long-term debt		(808	)		(443	)
Issuances:
Common stock		75			48
Long-term debt		1,335			425
Net cash provided by financing activities		290			761
Net change in cash and cash equivalents		(150	)		550
Cash and cash equivalents at beginning of year		355			137
Cash and cash equivalents at end of period	$	205		$	687

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

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Operating Revenues:
Electric - excluding off-system	$	589		$	579		$	1,079		$	1,030
Electric - off-system		147			89			298			211
Gas		35			29			118			105
Other		-			-			-			1
Total operating revenues		771			697			1,495			1,347
Operating Expenses:
Fuel		104			143			251			268
Purchased power		37			29			90			69
Gas purchased for resale		18			15			73			64
Other operations and maintenance		238			222			455			446
Depreciation and amortization		82			84			163			171
Taxes other than income taxes		60			60			120			117
Total operating expenses		539			553			1,152			1,135
Operating Income		232			144			343			212
Other Income and Expenses:
Miscellaneous income		15			12			29			20
Miscellaneous expense		(2	)		(6	)		(4	)		(8	)
Total other income		13			6			25			12
Interest Charges		50			51			91			97
Income Before Income Taxes and Equity
in Income of Unconsolidated Investment		195			99			277			127
Income Taxes		71			30			100			39
Income Before Equity in Income
of Unconsolidated Investment		124			69			177			88
Equity in Income of Unconsolidated Investment,
Net of Taxes		-			12			11			26
Net Income		124			81			188			114
Preferred Stock Dividends		2			2			3			3
Net Income Available to Common Stockholder	$	122		$	79		$	185		$	111

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

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

	June 30,			December 31,
	2008			2007
ASSETS
Current Assets:
Cash and cash equivalents	$	-		$	185
Accounts receivable – trade (less allowance for doubtful
accounts of $7 and $6, respectively)		176			191
Unbilled revenue		165			118
Miscellaneous accounts and notes receivable		268			213
Advances to money pool		-			15
Accounts receivable – affiliates		28			90
Materials and supplies		318			301
Mark-to-market derivative assets		106			7
Other current assets		75			43
Total current assets		1,136			1,163
Property and Plant, Net		8,477			8,189
Investments and Other Assets:
Nuclear decommissioning trust fund		284			307
Intercompany note receivable – affiliate		30			-
Intangible assets		52			56
Regulatory assets		677			697
Other assets		393			491
Total investments and other assets		1,436			1,551
TOTAL ASSETS	$	11,049		$	10,903

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	4		$	152
Short-term debt		33			82
Intercompany note payable – Ameren		50			-
Accounts and wages payable		143			315
Accounts payable – affiliates		85			212
Taxes accrued		78			78
Accrued interest		56			47
Taum Sauk pumped-storage hydroelectric facility liability		35			103
Mark-to-market derivative liabilities		101			1
Other current liabilities		58			58
Total current liabilities		643			1,048
Long-term Debt, Net		3,677			3,208
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,347			1,273
Accumulated deferred investment tax credits		82			85
Regulatory liabilities		907			865
Asset retirement obligations		489			476
Accrued pension and other postretirement benefits		237			297
Other deferred credits and liabilities		45			50
Total deferred credits and other liabilities		3,107			3,046
Commitments and Contingencies (Notes 2, 8, 9 and 10)
Stockholders' Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding		511			511
Preferred stock not subject to mandatory redemption		113			113
Other paid-in capital, principally premium on common stock		1,119			1,119
Retained earnings		1,894			1,855
Accumulated other comprehensive income (loss)		(15	)		3
Total stockholders' equity		3,622			3,601
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	11,049		$	10,903

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

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

	Six Months Ended
	June 30,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	188		$	114
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sales of emission allowances		(1	)		-
Mark-to-market gain on derivatives		(73	)		-
Depreciation and amortization		163			171
Amortization of nuclear fuel		20			15
Amortization of debt issuance costs and premium/discounts		3			3
Deferred income taxes and investment tax credits, net		74			15
Other		(9	)		-
Changes in assets and liabilities:
Receivables		66			(110	)
Materials and supplies		(17	)		(31	)
Accounts and wages payable		(253	)		(129	)
Taxes accrued, net		(31	)		74
Assets, other		53			55
Liabilities, other		26			(31	)
Pension and other postretirement benefit obligations		13			15
Taum Sauk insurance receivable, net		(107	)		(16	)
Net cash provided by operating activities		115			145
Cash Flows From Investing Activities:
Capital expenditures		(377	)		(355	)
Nuclear fuel expenditures		(123	)		(24	)
Changes in money pool advances		-			6
Proceeds from intercompany note receivable		6			-
Purchases of securities – nuclear decommissioning trust fund		(247	)		(75	)
Sales of securities – nuclear decommissioning trust fund		231			65
Sales of emission allowances		1			2
Net cash used in investing activities		(509	)		(381	)
Cash Flows From Financing Activities:
Dividends on common stock		(105	)		(127	)
Dividends on preferred stock		(3	)		(3	)
Capital issuance costs		(5	)		(3	)
Short-term debt, net		(49	)		192
Intercompany note payable – Ameren, net		50			(40	)
Redemptions, repurchases, and maturities of long-term debt		(378	)		-
Issuances of long-term debt		699			425
Net cash provided by financing activities		209			444
Net change in cash and cash equivalents		(185	)		208
Cash and cash equivalents at beginning of year		185			1
Cash and cash equivalents at end of period	$	-		$	209

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Operating Revenues:
Electric	$	169		$	193		$	349		$	404
Gas		38			36			148			137
Other		-			-			-			2
Total operating revenues		207			229			497			543
Operating Expenses:
Purchased power		108			127			231			275
Gas purchased for resale		24			21			104			95
Other operations and maintenance		48			41			98			84
Depreciation and amortization		17			16			34			33
Taxes other than income taxes		7			9			19			18
Total operating expenses		204			214			486			505
Operating Income		3			15			11			38
Other Income and Expenses:
Miscellaneous income		3			5			6			8
Miscellaneous expense		(2	)		(1	)		(2	)		(1	)
Total other income		1			4			4			7
Interest Charges		8			10			15			18
Income (Loss) Before Income Taxes		(4	)		9			-			27
Income Taxes (Benefit)		(1	)		4			-			10
Net Income (Loss)		(3	)		5			-			17
Preferred Stock Dividends		-			-			1			1
Net Income (Loss) Available to Common Stockholder	$	(3	)	$	5		$	(1	)	$	16

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

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

	June 30,		December 31,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	26
Accounts receivable – trade (less allowance for doubtful
accounts of $6 and $5, respectively)		69		62
Unbilled revenue		49		66
Miscellaneous accounts and notes receivable		19		19
Accounts receivable – affiliates		4		9
Current portion of intercompany note receivable – Genco		42		39
Current portion of intercompany tax receivable – Genco		9		9
Materials and supplies		48		66
Mark-to-market derivative assets with affiliate		38		1
Other current assets		19		15
Total current assets		297		312
Property and Plant, Net		1,184		1,174
Investments and Other Assets:
Intercompany note receivable – Genco		45		87
Intercompany tax receivable – Genco		100		105
Regulatory assets		83		113
Other assets		79		69
Total investments and other assets		307		374
TOTAL ASSETS	$	1,788	$	1,860

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	15	$	15
Short-term debt		25		125
Accounts and wages payable		59		44
Accounts payable – affiliates		19		19
Borrowings from money pool		3		-
Taxes accrued		4		8
Customer deposits		16		16
Regulatory liabilities		21		2
Other current liabilities		37		29
Total current liabilities		199		258
Long-term Debt, Net		421		456
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net		266		269
Regulatory liabilities		320		265
Accrued pension and other postretirement benefits		38		67
Other deferred credits and liabilities		28		28
Total deferred credits and other liabilities		652		629
Commitments and Contingencies (Notes 2, 8, and 9)
Stockholders' Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding		-		-
Other paid-in capital		191		191
Preferred stock not subject to mandatory redemption		50		50
Retained earnings		275		276
Total stockholders' equity		516		517
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,788	$	1,860

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

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

	Six Months Ended
	June 30,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	-		$	17
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		34			33
Amortization of debt issuance costs and premium/discounts		1			1
Deferred income taxes and investment tax credits, net		(2	)		(10	)
Changes in assets and liabilities:
Receivables		20			11
Materials and supplies		18			20
Accounts and wages payable		12			(30	)
Taxes accrued, net		(12	)		(3	)
Assets, other		29			6
Liabilities, other		7			(4	)
Pension and other postretirement benefit obligations		2			3
Net cash provided by operating activities		109			44
Cash Flows From Investing Activities:
Capital expenditures		(41	)		(39	)
Proceeds from intercompany note receivable – Genco		39			37
Changes in money pool advances		-			1
Net cash used in investing activities		(2	)		(1	)
Cash Flows From Financing Activities:
Dividends on preferred stock		(1	)		(1	)
Short-term debt, net		(100	)		100
Changes in money pool borrowings		3			-
Redemptions, repurchases, and maturities of long-term debt		(35	)		-
Net cash provided by (used in) financing activities		(133	)		99
Net change in cash and cash equivalents		(26	)		142
Cash and cash equivalents at beginning of year		26			6
Cash and cash equivalents at end of period	$	-		$	148

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

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007

Operating Revenues	$	194		$	186	$	425		$	429
Operating Expenses:
Fuel		49			74		137			155
Coal contract settlement		(60	)		-		(60	)		-
Purchased power		-			-		-			21
Other operations and maintenance		53			49		93			83
Depreciation and amortization		16			18		32			36
Taxes other than income taxes		5			4		11			10
Total operating expenses		63			145		213			305
Operating Income		131			41		212			124
Miscellaneous Income		3			1		5			1
Interest Charges		17			14		26			28
Income Before Income Taxes		117			28		191			97
Income Taxes		43			11		71			37
Net Income	$	74		$	17	$	120		$	60

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

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

	June 30,			December 31,
	2008			2007
ASSETS
Current Assets:
Cash and cash equivalents	$	2		$	2
Accounts receivable – affiliates		96			93
Miscellaneous accounts and notes receivable		66			12
Materials and supplies		109			93
Other current assets		11			4
Total current assets		284			204
Property and Plant, Net		1,753			1,683
Intangible Assets		52			63
Other Assets		8			18
TOTAL ASSETS	$	2,097		$	1,968

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Short-term debt	$	-		$	100
Current portion of intercompany note payable – CIPS		42			39
Borrowings from money pool		5			54
Accounts and wages payable		43			61
Accounts payable – affiliates		48			57
Current portion of intercompany tax payable – CIPS		9			9
Taxes accrued		17			15
Accrued interest		12			5
Deferred taxes - current		15			7
Other current liabilities		12			18
Total current liabilities		203			365
Long-term Debt, Net		774			474
Intercompany Note Payable – CIPS		45			87
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		168			161
Accumulated deferred investment tax credits		6			7
Intercompany tax payable – CIPS		100			105
Asset retirement obligations		48			47
Accrued pension and other postretirement benefits		33			32
Other deferred credits and liabilities		37			42
Total deferred credits and other liabilities		392			394
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholder's Equity:
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding		-			-
Other paid-in capital		503			503
Retained earnings		204			167
Accumulated other comprehensive loss		(24	)		(22	)
Total stockholder's equity		683			648
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	2,097		$	1,968

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

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

	Six Months Ended
	June 30,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	120		$	60
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sales of emission allowances		(1	)		(1	)
Mark-to-market gain on derivatives		(29	)		(1	)
Coal contract settlement		(60	)		-
Depreciation and amortization		45			52
Deferred income taxes and investment tax credits, net		18			8
Other		1			1
Changes in assets and liabilities:
Receivables		28			10
Materials and supplies		(16	)		(1	)
Accounts and wages payable		(24	)		13
Taxes accrued, net		3			(2	)
Assets, other		7			(25	)
Liabilities, other		(2	)		(2	)
Pension and other postretirement obligations		2			3
Net cash provided by operating activities		92			115
Cash Flows From Investing Activities:
Capital expenditures		(117	)		(77	)
Purchases of emission allowances		(2	)		(5	)
Sales of emission allowances		1			1
Net cash used in investing activities		(118	)		(81	)
Cash Flows From Financing Activities:
Dividends on common stock		(84	)		(113	)
Debt issuance costs		(2	)		-
Short-term debt, net		(100	)		-
Changes in money pool borrowings		(49	)		116
Intercompany note payable – CIPS		(39	)		(37	)
Issuances of long-term debt		300			-
Net cash provided by (used in) financing activities		26			(34	)
Net change in cash and cash equivalents		-			-
Cash and cash equivalents at beginning of year		2			1
Cash and cash equivalents at end of period	$	2		$	1

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,
	2008			2007			2008			2007
Operating Revenues:
Electric	$	162		$	165		$	356		$	345
Gas		69			60			220			195
Other		1			1			1			1
Total operating revenues		232			226			577			541
Operating Expenses:
Fuel		25			14			53			37
Purchased power		62			64			140			140
Gas purchased for resale		50			42			165			145
Other operations and maintenance		48			43			93			83
Depreciation and amortization		23			21			46			42
Taxes other than income taxes		5			6			14			14
Total operating expenses		213			190			511			461
Operating Income		19			36			66			80

Other Income and Expenses:
Miscellaneous income		1			-			1			2
Miscellaneous expense		(2	)		(2	)		(2	)		(3	)
Total other expenses		(1	)		(2	)		(1	)		(1	)
Interest Charges		13			15			28			29
Income Before Income Taxes		5			19			37			50
Income Taxes		-			6			12			16
Income Before Preferred Dividends of Subsidiaries		5			13			25			34
Preferred Dividends of Subsidiaries		1			1			1			1
Net Income	$	4		$	12		$	24		$	33

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,		December 31,
	2008		2007

ASSETS
Current Assets:
Cash and cash equivalents	$	19	$	6
Accounts receivable – trade (less allowance for doubtful
accounts of $3 and $2, respectively)		54		52
Unbilled revenue		39		54
Accounts receivable – affiliates		57		47
Advances to money pool		2		2
Note receivable – affiliates		1		-
Materials and supplies		101		110
Mark-to-market derivative assets		10		1
Mark-to-market derivative assets with affiliate		24		1
Income tax receivable		19		16
Other current assets		27		22
Total current assets		353		311
Property and Plant, Net		1,562		1,494
Investments and Other Assets:
Goodwill		542		542
Intangible assets		37		41
Regulatory assets		24		32
Other assets		59		39
Total investments and other assets		662		654
TOTAL ASSETS	$	2,577	$	2,459

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Short-term debt	$	550	$	520
Borrowings from money pool, net		2		-
Intercompany note payable – Ameren		15		2
Accounts and wages payable		66		75
Accounts payable – affiliates		54		34
Taxes accrued		3		3
Other current liabilities		69		54
Total current liabilities		759		688
Long-term Debt, Net		515		537
Preferred Stock of Subsidiary Subject to Mandatory Redemption		16		16
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		197		193
Accumulated deferred investment tax credits		5		6
Regulatory liabilities		147		92
Accrued pension and other postretirement benefits		111		127
Other deferred credits and liabilities		67		66
Total deferred credits and other liabilities		527		484
Preferred Stock of Subsidiary Not Subject to Mandatory Redemption		19		19
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholder's Equity:
Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding		-		-
Other paid-in capital		627		627
Retained earnings		82		58
Accumulated other comprehensive income		32		30
Total stockholder's equity		741		715
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	2,577	$	2,459

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

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


	Six Months Ended
	June 30,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	24		$	33
Adjustments to reconcile net income to net cash
provided by operating activities:
Mark-to-market gain on derivatives		(7	)		-
Depreciation and amortization		46			38
Amortization of debt issuance costs and premium/discounts		-			1
Deferred income taxes and investment tax credits		14			(3	)
Changes in assets and liabilities:
Receivables		10			(13	)
Materials and supplies		9			14
Accounts and wages payable		43			3
Taxes accrued, net		(10	)		(3	)
Assets, other		(2	)		(2	)
Liabilities, other		9			(7	)
Pension and postretirement benefit obligations		(8	)		1
Net cash provided by operating activities		128			62
Cash Flows From Investing Activities:
Capital expenditures		(140	)		(127	)
Changes in money pool advances		-			42
Other		(1	)		-
Net cash used in investing activities		(141	)		(85	)
Cash Flows From Financing Activities:
Short-term debt, net		30			250
Changes in money pool borrowings		2			-
Intercompany note payable – Ameren, net		13			(73	)
Redemptions, repurchases, and maturities of long-term debt		(19	)		(50	)
Net cash provided by financing activities		26			127

Net change in cash and cash equivalents		13			104
Cash and cash equivalents at beginning of year		6			4
Cash and cash equivalents at end of period	$	19		$	108

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,
	2008			2007			2008			2007
Operating Revenues:
Electric	$	162		$	165		$	356		$	345
Gas		69			60			220			195
Other		1			1			1			1
Total operating revenues		232			226			577			541

Operating Expenses:
Fuel		23			12			50			34
Purchased power		62			64			140			140
Gas purchased for resale		50			42			165			145
Other operations and maintenance		49			46			97			87
Depreciation and amortization		21			18			41			36
Taxes other than income taxes		5			5			14			13
Total operating expenses		210			187			507			455
Operating Income		22			39			70			86
Other Income and Expenses:
Miscellaneous income		1			1			1			2
Miscellaneous expense		(1	)		(2	)		(1	)		(3	)
Total other expenses		-			(1	)		-			(1	)
Interest Charges		5			5			11			11
Income Before Income Taxes		17			33			59			74
Income Taxes		5			12			21			26
Net Income		12			21			38			48
Preferred Stock Dividends		1			1			1			1
Net Income Available To Common Shareholders	$	11		$	20		$	37		$	47

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,		December 31
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	19	$	6
Accounts receivable – trade (less allowance for doubtful
accounts of $3 and $2, respectively)		54		52
Unbilled revenue		39		54
Accounts receivable – affiliates		53		45
Materials and supplies		101		110
Mark-to-market derivative assets		10		1
Mark-to-market derivative assets with affiliate		24		1
Income tax receivable		17		8
Other current assets		25		17
Total current assets		342		294
Property and Plant, Net		1,562		1,492
Investments and Other Assets:
Intangible assets		1		1
Regulatory assets		24		32
Other assets		62		43
Total investments and other assets		87		76
TOTAL ASSETS	$	1,991	$	1,862

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Short-term debt	$	375	$	345
Borrowings from money pool		2		-
Accounts and wages payable		66		75
Accounts payable – affiliates		54		34
Taxes accrued		2		3
Other current liabilities		60		45
Total current liabilities		559		502
Long-term Debt, Net		129		148
Preferred Stock Subject to Mandatory Redemption		16		16
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		168		155
Accumulated deferred investment tax credits		5		6
Regulatory liabilities		273		220
Accrued pension and other postretirement benefits		111		127
Other deferred credits and liabilities		67		66
Total deferred credits and other liabilities		624		574
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholders' Equity:
Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding		-		-
Preferred stock not subject to mandatory redemption		19		19
Other paid-in capital		429		429
Retained earnings		209		172
Accumulated other comprehensive income		6		2
Total stockholders' equity		663		622
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,991	$	1,862

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

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

	Six Months Ended
	June 30,
	2008			2007
Cash Flows From Operating Activities:
Net income	$	37		$	48
Adjustments to reconcile net income to net cash
provided by operating activities:
Mark-to-market gain on derivatives		(7	)		-
Depreciation and amortization		41			37
Amortization of debt issuance costs and premium/discounts		-			1
Deferred income taxes and investment tax credits, net		14			(3	)
Changes in assets and liabilities:
Receivables		13			(11	)
Materials and supplies		9			14
Accounts and wages payable		42			16
Taxes accrued, net		(11	)		(3	)
Assets, other		(4	)		(7	)
Liabilities, other		6			(4	)
Pension and postretirement benefit obligations		(1	)		1
Net cash provided by operating activities		139			89
Cash Flows From Investing Activities:
Capital expenditures		(140	)		(127	)
Changes in money pool advances		-			42
Other		1			-
Net cash used in investing activities		(139	)		(85	)
Cash Flows From Financing Activities:
Dividends on preferred stock		-			(1	)
Short-term debt, net		30			125
Changes in money pool borrowings		2			-
Redemptions, repurchases, and maturities of long-term debt		(19	)		(50	)
Capital contribution from parent		-			14
Net cash provided by financing activities		13			88
Net change in cash and cash equivalents		13			92
Cash and cash equivalents at beginning of year		6			3
Cash and cash equivalents at end of period	$	19		$	95

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

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008			2007		2008			2007
Operating Revenues:
Electric	$	258		$	280	$	496		$	552
Gas		101			85		365			326
Other		1			-		2			2
Total operating revenues		360			365		863			880

Operating Expenses:
Purchased power		161			178		314			363
Gas purchased for resale		71			56		276			241
Other operations and maintenance		77			58		143			112
Depreciation and amortization		26			24		51			50
Amortization of regulatory assets		4			4		8			8
Taxes other than income taxes		13			16		36			37
Total operating expenses		352			336		828			811

Operating Income		8			29		35			69

Other Income and Expenses:
Miscellaneous income		3			3		6			5
Miscellaneous expense		(2	)		-		(3	)		(1	)
Total other income		1			3		3			4

Interest Charges		26			20		50			36
Income (Loss) Before Income Taxes		(17	)		12		(12	)		37
Income Taxes (Benefit)		(7	)		5		(5	)		15
Net Income (Loss)		(10	)		7		(7	)		22
Preferred Stock Dividends		-			-		1			1
Net Income (Loss) Available to Common Stockholder	$	(10	)	$	7	$	(8	)	$	21

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

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

	June 30,		December 31,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	33	$	6
Accounts receivable - trade (less allowance for doubtful
accounts of $11 and $9, respectively)		140		137
Unbilled revenue		93		118
Accounts receivable – affiliates		15		17
Advances to money pool		5		-
Materials and supplies		114		134
Mark-to-market derivative assets		30		2
Mark-to-market derivative assets with affiliate		45		-
Other current assets		43		36
Total current assets		518		450
Property and Plant, Net		2,250		2,220
Investments and Other Assets:
Investment in IP SPT		11		10
Goodwill		214		214
Regulatory assets		296		316
Other assets		155		109
Total investments and other assets		676		649
TOTAL ASSETS	$	3,444	$	3,319

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	251	$	-
Current maturities of long-term debt payable to IP SPT		15		54
Short-term debt		175		175
Accounts and wages payable		117		85
Accounts payable – affiliates		44		36
Taxes accrued		5		7
Customer deposits		38		40
Other current liabilities		98		40
Total current liabilities		743		437
Long-term Debt, Net		759		1,014
Long-term Debt to IP SPT		-		2
Deferred Credits and Other Liabilities:
Regulatory liabilities		241		129
Accrued pension and other postretirement benefits		185		189
Accumulated deferred income taxes		148		148
Other deferred credits and liabilities		99		92
Total deferred credits and other liabilities		673		558
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholders’ Equity:
Common stock, no par value, 100.0 shares authorized – 23.0 shares outstanding		-		-
Other paid-in-capital		1,194		1,194
Preferred stock not subject to mandatory redemption		46		46
Retained earnings		25		64
Accumulated other comprehensive income		4		4
Total stockholders’ equity		1,269		1,308
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,444	$	3,319

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

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

	Six Months Ended
	June 30,
	2008			2007
Cash Flows From Operating Activities:
Net income (loss)	$	(7	)	$	22
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		54			42
Amortization of debt issuance costs and premium/discounts		4			4
Deferred income taxes		14			6
Changes in assets and liabilities:
Receivables		24			1
Materials and supplies		20			29
Accounts and wages payable		41			(38	)
Taxes accrued, net		(16	)		(2	)
Assets, other		13			(7	)
Liabilities, other		40			4
Pension and other postretirement benefit obligations		(8	)		12
Net cash provided by operating activities		179			73

Cash Flows From Investing Activities:
Capital expenditures		(73	)		(92	)
Changes in money pool advances		(5	)		-
Other		(1	)		(1	)
Net cash used in investing activities		(79	)		(93	)

Cash Flows From Financing Activities:
Dividends on common stock		(30	)		-
Dividends on preferred stock		(1	)		(1	)
Capital issuance costs		(2	)		-
Short-term debt, net		-			250
Changes in money pool borrowings, net		-			(43	)
Redemptions, repurchases and maturities of long-term debt		(337	)		-
Issuance of long-term debt		336			-
IP SPT maturities		(43	)		(43	)
Overfunding of TFNs		4			-
Net cash provided by (used in) financing activities		(73	)		163
Net change in cash and cash equivalents		27			143
Cash and cash equivalents at beginning of year		6			-
Cash and cash equivalents at end of period	$	33		$	143

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

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY (Consolidated)

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

AMEREN ENERGY GENERATING COMPANY (Consolidated)

CILCORP INC. (Consolidated)

CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)

ILLINOIS POWER COMPANY (Consolidated)

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

June 30, 2008

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

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

·	UE, or Union Electric Company, also known as AmerenUE, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.

·	CIPS, or Central Illinois Public Service Company, also known as AmerenCIPS, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

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

CILCO, or Central Illinois Light Company, also known as AmerenCILCO, is a subsidiary of CILCORP (a holding company). It operates a rate-regulated electric transmission and distribution business, a non-rate-regulated electric generation business (through its subsidiary, AERG) and a rate-regulated natural gas transmission and distribution business in Illinois.

·	IP, or Illinois Power Company, also known as AmerenIP, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

Ameren has various other subsidiaries responsible for the short- and long-term marketing of power, procurement of fuel, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI, which until February 29, 2008, was held 40% by UE and 40% by Development Company. Ameren consolidates EEI for financial reporting purposes, while UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren. See Note 8 – Related Party Transactions for additional information.

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

	Three Months				Six Months
	2008		2007		2008		2007
Operating revenues	$	137	$	109	$	247	$	206
Operating income		68		51		132		105
Net income		42		32		82		66

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

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. All UE, CIPS, CILCORP, CILCO and IP financial information as of and for the three months and six months ended June 30, 2007, included in this quarterly report reflects the correction of an error. During the third quarter of 2007, we identified and corrected a misallocation of first quarter 2007 purchased power expense among Ameren subsidiaries. The error resulted in an understatement of UE purchased power expense of approximately $7 million and an overstatement of

CIPS, CILCORP, CILCO and IP purchased power expense of approximately $2 million, $1 million, $1 million, and $4 million, respectively, during the three months and six months ended June 30, 2007. The error resulted in an overstatement of UE net income of $5 million, and an understatement of CIPS, CILCORP, CILCO and IP net income of approximately $1 million, $1 million, $1 million, and $3 million, respectively, during the three months and six months ended June 30, 2007. The error did not have a significant impact on previously reported subsidiary balance sheets or statements of cash flows, and the error had no impact on Ameren’s previously reported consolidated financial position, results of operations or cash flows.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months and six months ended June 30, 2008 and 2007. The number of stock options, restricted stock shares, and performance share units outstanding was immaterial.

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

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

	Performance Share Units					Restricted Shares
	Shares			Weighted-average Fair Value Per Unit		Shares			Weighted-average Fair Value Per Share
Nonvested at January 1, 2008		669,403		$	57.88		316,768		$	46.23
Granted(a)		495,847			47.57		-			-
Dividends		-			-		5,974			42.83
Forfeitures		-			-		(2,163	)		48.19
Vested(b)		(40,575	)		53.48		(114,286	)		44.05
Nonvested at June 30, 2008		1,124,675		$	53.50		206,293		$	47.46

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

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

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

Ameren recorded compensation expense of $7 million and $4 million for the quarters ended June 30, 2008 and 2007, respectively, and a related tax benefit of $3 million and $2 million for the quarters ended June 30, 2008 and 2007, respectively. Ameren recorded compensation expense of $14 million and $9 million for each of the six-month periods ended June 30, 2008 and 2007, respectively, and a related tax benefit of $5 million and $4 million for the six-month periods ended June 30, 2008 and 2007, respectively. As of June 30, 2008, total compensation cost of $28 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 23 months.

Accounting Changes and Other Matters

SFAS No. 157, Fair Value Measurements

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

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

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

Goodwill and Intangible Assets

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

Intangible Assets. We evaluate intangible assets for impairment whenever events or circumstances indicate that their carrying amount might be impaired. See also Note 9 – Commitments and Contingencies. Ameren’s, UE’s, Genco’s, CILCORP’s and CILCO’s intangible assets consisted of the following:

	Ameren(a)	UE	Genco	CILCORP(b)	CILCO
June 30, 2008
Emission allowances(c)	$ 177	$ 52	$ 52	$ 37	$ 1

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

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

(c)	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.

The following table presents the net book value of emission allowances consumed or (sold) for Ameren, UE, Genco, CILCORP and CILCO during the three months and six months ended June 30, 2008 and 2007.

	Three Months					Six Months
	2008		2007			2008			2007
Ameren(a)	$	9	$	13		$	16		$	20
UE		-		3			(1	)		-
Genco		6		8			13			15
CILCORP(b)		3		1			3			3
CILCO		-		(1	)		-			-

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

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

Excise Taxes

Excise taxes imposed on us are reflected on Missouri electric, Missouri gas, and Illinois gas customer bills. They are recorded gross in Operating Revenues and Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued. The following table presents excise taxes recorded in Operating Revenues and Taxes Other than Income Taxes for the three months and six months ended June 30, 2008 and 2007:

	Three Months				Six Months
	2008		2007		2008		2007
Ameren	$	38	$	40	$	87	$	82
UE		27		28		52		50
CIPS		3		3		9		8
CILCORP		2		3		7		7
CILCO		2		3		7		7
IP		6		6		19		17

Coal Contract Settlement

In June 2008, Genco entered into an agreement with a coal mine owner, which provided Genco a lump-sum payment of $60 million in July 2008 due to the coal supplier’s premature closing of a mine and the early termination of a coal supply contract. The settlement agreement compensates Genco, in total, for higher fuel costs it expects to incur in 2008 and 2009 as a result of the mine closure and contract termination.

Uncertain Tax Positions

The amount of unrecognized tax benefits as of June 30, 2008, was $104 million, $18 million, less than $1 million, $36 million, $19 million, $19 million and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. The total unrecognized tax benefits (detriments), that would impact the effective tax rate, if recognized, for each of the respective companies was as follows: Ameren - $23 million, UE - $3 million, CIPS - none, Genco - ($1 million), CILCORP - less than $1 million, CILCO - less than $1 million, and

IP - none.

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

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

Asset Retirement Obligations

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

NOTE 2 – RATE AND REGULATORY MATTERS

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

Missouri

Electric

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

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

January 2007 Ice Storm Cost Recovery

UE submitted a filing to the MoPSC in November 2007 requesting that operations and maintenance expenses UE incurred as a result of a severe ice storm in January 2007 be deferred as a regulatory asset and, if approved, be amortized over five years beginning with the effective date of electric rates approved in UE’s next rate proceeding. UE incurred

$25 million of operations and maintenance expenses in the first quarter of 2007 as a result of the January storm. On April 30, 2008, the MoPSC issued an accounting order that gave UE the ability to seek direct recovery of, and record as a regulatory asset, all or a portion of these storm costs. The appropriate amount to be amortized and the start date of the amortization will be decided in UE’s rate case filed in April 2008. UE recorded a regulatory asset of $13 million in the second quarter of 2008, representing the minimum amount of its storm costs that it expects to recover as a result of this order.

Illinois

Electric and Natural Gas Delivery Service Rate Cases

CIPS, CILCO and IP filed requests with the ICC in November 2007 to adjust their annual revenues for electric and natural gas delivery services. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million and IP - $139 million). CIPS, CILCO and IP requested to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - $15 million increase, CILCO - $4 million decrease and IP - $56 million increase). These rate change requests were based on an 11% return on equity.

In their rate case filings, the Ameren Illinois Utilities are seeking approval of a mechanism that would permit a more timely recovery of investments in existing electric distribution plant. Because general rate adjustment proceedings require up to 11 months in Illinois, this mechanism would allow current revenues to better match current costs. In addition, the Ameren Illinois Utilities are seeking approval of a revenue decoupling rate adjustment mechanism as a part of their natural gas delivery service rate change requests. This mechanism would separate each utility’s fixed cost recovery from the volume of gas it sells by providing a periodic true-up of revenues. The periodic true-up would result in adjustments to a utility’s ICC-approved tariffs based on increases or decreases in demand for natural gas.

In May 2008, the ICC staff filed rebuttal testimony recommending a net increase in revenues for electric delivery service for the Ameren Illinois Utilities of $76 million in the aggregate (CIPS - $9 million increase, CILCO - $11 million decrease, and IP - $78 million increase) and a net increase in revenues for natural gas delivery service of $11 million in the aggregate (CIPS - $3 million increase, CILCO - $15 million decrease, and IP - $23 million increase). Other parties also made recommendations through rebuttal testimony in the rate cases.

The Ameren Illinois Utilities revised their revenue requests for electric and natural gas delivery services to accept certain positions proposed by the ICC staff and intervenors, including the ICC staff’s recommended return on equity of approximately 10.7%. In a brief filed with the ICC in July 2008, CIPS, CILCO and IP revised their requests to an increase in annual revenues for electric delivery service of $156 million in the aggregate (CIPS - $26 million, CILCO - $3 million, and IP - $127 million) and an increase in annual revenues for natural gas delivery service of $51 million in the aggregate (CIPS - $10 million increase, CILCO - $7 million decrease, and IP - $48 million increase). The electric and natural gas rate change requests were based on a capital structure composed of 50% to 53% equity, an aggregate rate base for the Ameren Illinois Utilities of $2 billion and $0.9 billion for electric and natural gas, respectively, and a test year ended December 31, 2006, with certain prospective updates. The Ameren Illinois Utilities pledged in 2007 to keep the overall residential electric bill increase to less than 10% for each utility in the next rate filings. Accordingly, the requested rate increase for IP residential customers would be capped at the 10% increase level in the first year of the increase, even if the final authorized rate increase exceeds that amount. This rate increase limit could result in approximately $24 million of IP’s requested electric rate increase not being phased in until October 2009.

The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes take place over a period of up to 11 months, and decisions by the ICC in such proceedings are required by the end of September 2008. The Ameren Illinois Utilities cannot predict the level of any delivery service rate change the ICC may approve, when any rate change may go into effect, whether any rate adjustment mechanism will be approved, or whether any rate increase that may eventually be approved will be sufficient for the Ameren Illinois Utilities to recover their costs and earn a reasonable return on their investments when the increase goes into effect.

Illinois Electric Settlement Agreement

In 2007, an agreement was reached among key stakeholders in Illinois to avoid rate rollback and freeze legislation and legislation that would impose a tax on electric generation and to address the increase in electric rates and the future power procurement process in Illinois. The terms of the agreement include a comprehensive rate relief and customer assistance program. The Illinois electric settlement agreement provides approximately $1 billion of funding for rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Pursuant to the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and 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. See Note 9 – Commitments and Contingencies for information on the remaining contributions to be made as of June 30, 2008.

The Ameren Illinois Utilities, Genco and CILCO (AERG) recognize in their financial statements the costs of their respective rate relief contributions and program funding in a manner corresponding with the timing of the funding. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, during the quarter ended June 30, 2008, of $11 million, $1 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.

Other electric generators and utilities in Illinois agreed to contribute $851 million to the comprehensive rate relief and customer assistance program. Contributions by the other electric generators (the Generators) and utilities to the comprehensive program are subject to funding agreements. Under these agreements, at the end of each month, the Ameren Illinois Utilities send a bill, due in 30 days, to the Generators and utilities for their proportionate share of that month’s rate relief and assistance. If any escrow funds have been provided by the Generators, these funds will be drawn prior to seeking reimbursement from the Generators. At June 30, 2008, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $19 million, $7 million, $3 million and $9 million, respectively.

Redesigned Rates

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

Federal

Regional Transmission Organization

agreement. The service agreement’s primary function was to ensure that the MoPSC continued to set the transmission component of UE’s rates to serve its bundled retail load. In June 2008, a stipulation and agreement among UE, the MoPSC staff, MISO and other parties to the proceeding was filed with the MoPSC, which provides for UE’s continued, conditional MISO participation through April 30, 2012. The stipulation and agreement provides UE the right to seek permission from the MoPSC for early withdrawal from MISO if UE determines that sufficient progress toward mitigating some of the continuing uncertainties respecting its MISO participation is not being made. The MoPSC has not acted on the stipulation and agreement.

UE Power Purchase Agreement with Entergy Arkansas, Inc.

In July 2007, as a consequence of a series of orders issued by FERC addressing a complaint filed by the Louisiana Public Service Commission (LPSC) against Entergy Arkansas, Inc. (Entergy) and certain of its affiliates, which alleged unjust and unreasonable cost allocations, Entergy commenced billing UE for additional charges under a 165-megawatt power purchase agreement. Additional charges are expected to continue during the remainder of the term of the power purchase agreement, which expires effective August 25, 2009. Although UE was not a party to the FERC proceedings that gave rise to these additional charges, UE has intervened in related FERC proceedings and filed a complaint with the FERC against Entergy and Entergy Services, Inc. in April 2008 to challenge the additional charges. UE is unable to predict whether FERC will grant any relief.

Additionally, LPSC appealed FERC’s orders regarding LPSC’s complaint against Entergy to the U.S. Court of Appeals for the District of Columbia. In April 2008, the court issued a decision ordering further FERC proceedings regarding the LPSC complaint. The court’s decision ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. FERC’s decision on remand of the retroactive impact of these issues could have a financial impact on UE. UE is unable to predict how FERC will respond to the court’s decision. UE estimates that it could incur an additional one-time expense of up to $30 million if FERC orders retroactive application for the years 2001 to 2005. UE plans to participate in any proceeding that FERC initiates to address the court’s decision.

Nuclear Combined Construction and Operating License Application

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

Pumped-storage Hydroelectric Facility Relicensing

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

NOTE 3 – SHORT-TERM BORROWINGS AND LIQUIDITY

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

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

$1.15 Billion Credit Facility	Ameren (Parent)			UE			Genco			Total
June 30, 2008:
Average daily borrowings outstanding during 2008	$	511		$	243		$	82		$	836
Outstanding short-term debt at period end		400			33	(a)		-			433	(a)
Weighted-average interest rate during 2008		3.84	%		3.40	%		3.97	%		3.73	%
Peak short-term borrowings during 2008	$	675		$	493		$	150		$	983
Peak interest rate during 2008		7.25	%		5.65	%		5.53	%		7.25	%

(a)	Includes issuances under a commercial paper program of $33 million at UE supported by this facility as of June 30, 2008, all of which is held by an affiliate.

2007 $500 Million Credit Facility	CIPS			CILCORP (Parent)			CILCO (Parent)			IP			AERG			Total
June 30, 2008:
Average daily borrowings outstanding during 2008	$	-		$	125		$	56		$	153		$	91		$	425
Outstanding short-term debt at period end		-			125			-			175			100			400
Weighted-average interest rate during 2008		-			4.81	%		4.41	%		4.54	%		4.20	%		4.53	%
Peak short-term borrowings during 2008	$	-		$	125		$	75		$	200		$	105		$	490
Peak interest rate during 2008		-			6.66	%		6.47	%		6.15	%		6.22	%		6.66	%
2006 $500 Million Credit Facility
June 30, 2008:
Average daily borrowings outstanding during 2008	$	71		$	50		$	11		$	3		$	187		$	322
Outstanding short-term debt at period end		25			50			75			-			200			350
Weighted-average interest rate during 2008		4.64	%		4.79	%		4.79	%		6.50	%		4.30	%		4.49	%
Peak short-term borrowings during 2008	$	135		$	50		$	75		$	100		$	200		$	465
Peak interest rate during 2008		6.31	%		7.01	%		5.98	%		6.50	%		7.01	%		7.01	%

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

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

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

Borrowings under the $300 million term loan agreement will bear interest, at the election of Ameren, at (1) a Eurodollar rate plus a margin, which margin is subject to a floor of 0.90% per annum and a cap of 1.50% per annum, or (2) a rate equal to the higher of the prime rate or the federal funds effective rate plus 0.50% per year. Ameren used the proceeds borrowed under the term loan agreement to reduce amounts borrowed under the $1.15 billion credit facility, which thereby made additional amounts available for borrowing under that credit facility. The average interest rate for borrowing under the $300 million term loan agreement was 3.68% from its inception through June 30, 2008.

The obligations of Ameren under the term loan agreement are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under, the term loan agreement.

Indebtedness Provisions and Other Covenants

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

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

Under the 2007 $500 million and 2006 $500 million credit facilities, each of CIPS, CILCO and IP had been required to reserve future bonding capacity under their respective mortgage indentures (that is, they agreed to forego the issuance of additional mortgage bonds otherwise permitted under the terms of each mortgage indenture). On March 26, 2008, CIPS, CILCO and IP and other parties to the credit facilities entered into amendments to the credit facilities, which eliminated this requirement.

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

The $1.15 billion credit facility and both the 2007 $500 million credit facility and the 2006 $500 million credit facility limit the total indebtedness of each borrower to 65% of total consolidated capitalization pursuant to a calculation set forth in the facilities. As of June 30, 2008, the ratios of total indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the $1.15 billion credit facility, were 55%, 49% and 51%, for Ameren, UE and Genco, respectively. The ratios for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the provisions of the 2007 $500 million credit facility and 2006 $500 million credit facility, were 49%, 58%, 44%, 49% and 43%, respectively. The ratio of consolidated indebtedness to consolidated total capitalization for Ameren calculated in accordance with the provisions of the $300 million term loan agreement was 53%.

None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At June 30, 2008, management believes that the Ameren Companies were in compliance with their credit facility 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. CIPS, CILCO and IP 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. Although UE and Ameren Services are parties to the utility money pool agreement, they are not currently borrowing or lending under the agreement. The average interest rate for borrowing under the utility money pool for the three months and six months ended June 30, 2008, was 2.8% and 3.5%, respectively (2007 – 5.6% and 5.8%, 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 Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool. At June 30, 2008, $708 million was available through the non-state-regulated subsidiary money pool, excluding additional funds available through excess cash balances. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months and six months ended June 30, 2008, was 3.1% and 3.8%, respectively (2007 – 5.1% and 4.9%).

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

NOTE 4 – LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to an effective SEC Form S-3 registration statement, and under our 401(k) plan, pursuant to an effective SEC Form S-8 registration statement, Ameren issued a total of 0.7 million new shares of common stock valued at $29 million and 1.7 million new shares valued at

$75 million in the three months and six months ended June 30, 2008, respectively.

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

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

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

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

CIPS

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

Genco

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

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

CILCORP

In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $2 million and $3 million (2007 - $2 million and $3 million) for the three months and six months ended June 30, 2008, respectively, and was included as a reduction to interest expense in the consolidated statements of income of Ameren and CILCORP. See Note 4 – Credit Facilities and Liquidity in the Form 10-K regarding CILCORP’s pledge of the common stock of CILCO as security for its obligations under the 2007 $500 million credit facility and the 2006 $500 million credit facility.

CILCO

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

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

In conjunction with Ameren’s acquisition of IP, IP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $2 million and $5 million (2007 - $3 million and $6 million) for the three months and six months ended June 30, 2008, respectively, and was included as a reduction to interest expense in the consolidated statements of income of Ameren and IP.

In April 2008, IP issued and sold, with registration rights in a private placement, $337 million of 6.25% senior secured notes due April 1, 2018, with interest payable semiannually on April 1 and October 1 of each year, beginning in October 2008. IP received net proceeds of $334 million, which were

used to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds during May and June 2008 as discussed below. In connection with IP’s April 2008 issuance of $337 million of senior secured notes, IP agreed, for so long as these senior secured notes are outstanding, that it will not, prior to maturity, cause a first mortgage bond release date to occur. The mortgage bond release date is the date at which the security provided by the pledge under IP’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness.

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

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

Indenture Provisions and Other Covenants

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

UE’s, CIPS’, CILCO’s and IP’s indentures and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable based on the 12 months ended June 30, 2008, at an assumed interest and dividend rate of 7%.

	Required Interest Coverage Ratio(a)	Actual Interest Coverage Ratio	Bonds Issuable(b)	Required Dividend Coverage Ratio(c)	Actual Dividend Coverage Ratio	Preferred Stock Issuable
UE	≥ 2.0	4.0	$ 2,757	≥ 2.5	62.5	$ 2,038
CIPS	≥ 2.0	1.1	38	≥ 1.5	0.9	-
CILCO	≥ 2.0(d)	12.9	331	≥ 2.5	33.1	321(e)
IP	≥ 2.0	2.3	792	≥ 1.5	0.9	-

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

(b)

Amount of bonds issuable based on either meeting required coverage ratios or unfunded property additions, whichever is more restrictive. In addition to these tests, UE, CIPS, CILCO and IP have the ability to issue bonds based upon retired bond capacity of $162 million, $38 million, $194 million and $664 million, respectively, which are included in the amounts above. No earnings coverage test is required for these bonds.

(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 months and six months ended June 30, 2008, CILCO had earnings equivalent to at least 41% of the principal amount of all mortgage bonds outstanding.

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

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

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

	Required Interest Coverage Ratio	Actual Interest Coverage Ratio	Required Debt-to- Capital Ratio	Actual Debt-to- Capital Ratio
Genco (a)	≥1.75(b)	8.9	≤60%	50%
CILCORP(c)	≥2.2	3.1	≤67%	26%

(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 requires an interest coverage ratio of 2.5 for the most recently ended four fiscal quarters.

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

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

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

Off-Balance-Sheet Arrangements

At June 30, 2008, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

NOTE 5 – OTHER INCOME AND EXPENSES

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

	Three Months						Six Months
	2008			2007			2008			2007
Ameren:(a)
Miscellaneous income:
Interest and dividend income	$	13		$	14		$	25		$	25
Allowance for equity funds used during construction		5			-			11			-
Other		3			6			6			9
Total miscellaneous income	$	21		$	20		$	42		$	34
Miscellaneous expense:
Other	$	(8	)	$	(8	)	$	(13	)	$	(13	)
Total miscellaneous expense	$	(8	)	$	(8	)	$	(13	)	$	(13	)
UE:
Miscellaneous income:
Interest and dividend income	$	10		$	8		$	18		$	15
Allowance for equity funds used during construction		5			-			11			-
Other		-			4			-			5
Total miscellaneous income	$	15		$	12		$	29		$	20
Miscellaneous expense:
Other	$	(2	)	$	(6	)	$	(4	)	$	(8	)
Total miscellaneous expense	$	(2	)	$	(6	)	$	(4	)	$	(8	)
CIPS:
Miscellaneous income:
Interest and dividend income	$	2		$	4		$	5		$	8
Other		1			1			1			-
Total miscellaneous income	$	3		$	5		$	6		$	8

	Three Months						Six Months
	2008			2007			2008			2007
Miscellaneous expense:
Other	$	(2	)	$	(1	)	$	(2	)	$	(1	)
Total miscellaneous expense	$	(2	)	$	(1	)	$	(2	)	$	(1	)
Genco:
Miscellaneous income:
Other	$	3		$	1		$	5		$	1
Total miscellaneous income	$	3		$	1		$	5		$	1
CILCORP:
Miscellaneous income:
Interest income	$	1		$	-		$	1		$	2
Total miscellaneous income	$	1		$	-		$	1		$	2
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(2	)	$	(3	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(2	)	$	(3	)
CILCO:
Miscellaneous income:
Interest income	$	1		$	1		$	1		$	2
Total miscellaneous income	$	1		$	1		$	1		$	2
Miscellaneous expense:
Other	$	(1	)	$	(2	)	$	(1	)	$	(3	)
Total miscellaneous expense	$	(1	)	$	(2	)	$	(1	)	$	(3	)
IP:
Miscellaneous income:
Interest income	$	2		$	2		$	4		$	3
Other		1			1			2			2
Total miscellaneous income	$	3		$	3		$	6		$	5
Miscellaneous expense:
Other	$	(2	)	$	-		$	(3	)	$	(1	)
Total miscellaneous expense	$	(2	)	$	-		$	(3	)	$	(1	)

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

NOTE 6 – DERIVATIVE FINANCIAL INSTRUMENTS

The following table presents the pretax net gain (loss) for the three months and six months ended June 30, 2008 and 2007, of power hedges included in Operating Revenues – Electric. This pretax net gain (loss) represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI due to transactions being delivered or settled:

	Three Months						Six Months
Gains (Losses)	2008			2007			2008			2007
Ameren	$	(22	)	$	8		$	(30	)	$	13
UE		(3	)		(4	)		(5	)		(2	)

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

	Three Months				Six Months
Gains (Losses)	2008		2007		2008		2007
SO2 options and swaps:
Ameren	$	1	$	2	$	-	$	6
UE		-		1		-		5
Genco		-		1		-		1
Coal options:
Ameren		-		1		-		2
UE		-		1		-		2

	Three Months						Six Months
Gains (Losses)	2008			2007			2008		2007
Heating oil options:
Ameren		90			1			109		3
UE		50			-			60		-
Genco		24			-			29		-
CILCORP/CILCO		6			-			7		-
Nonhedge power swaps and forwards:
Ameren		(6	)		(5	)		-		(4	)
UE		(1	)		(4	)		2		(4	)
Gas forwards and swaps:
Ameren		7			2			2		2
UE		4			2			3		2
FTRs:
Ameren		9			-			14		-
UE		10			-			12		-

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

	Ameren(a)			UE			CIPS		Genco			CILCORP/ CILCO		IP
Derivative instruments carrying value:
Current assets	$	273		$	106		$	38	$	5		$	34	$	75
Other assets		128			8			74		-			44		121
Current liabilities		236			101			-		1			1		1
Other deferred credits and liabilities		42			2			-		-			-		-
Gains (losses) deferred in accumulated OCI:
Power forwards(b)		(143	)		(33	)		-		-			-		-
Interest rate swaps(c)(d)		(11	)		-			-		(11	)		-		-
Gas swaps and futures contracts(e)		3			-			-		-			-		-
Coal options		8			9			-		-			-		-
Gains deferred in regulatory assets or liabilities:
Gas swaps and futures contracts(e)		164			18			30		-			38		78
Financial contracts(f)		-			-			81		-			40		117

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

(b)	Represents the mark-to-market value for the hedged portion of electricity price exposure for periods of up to three years, including losses of $116 million over the next 12 months.

(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, 2008, was $2 million.

(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 cumulative 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, 2008 was a loss of $13 million.

(e)	Represents gains associated with natural gas swaps and futures contracts. The swaps and futures contracts are a partial hedge of our natural gas requirements through October 2011.

(f)	Current amounts deferred as regulatory liabilities include $21 million at CIPS, $10 million at CILCO, and $30 million at IP that were recorded in other current liabilities at June 30, 2008.

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

NOTE 7 – FAIR VALUE MEASUREMENTS

SFAS No. 157 provides a framework for measuring fair value for all assets and liabilities that are measured and reported at fair value. This standard was effective and adopted by the Ameren Companies as of January 1, 2008, for financial assets and liabilities. The impact of this adoption of SFAS No. 157 was not material. SFAS No. 157 will be effective, in the first quarter of 2009, for all nonfinancial assets and liabilities that are measured and reported on a fair value basis. The impact of adoption of SFAS No. 157 for nonfinancial assets and liabilities is not expected to be material. SFAS No. 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income and cost approaches.

Based on these approaches, we use certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

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

Level 2: Observable market-based inputs or unobservable inputs that are corroborated by 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. Derivative instruments classified as Level 2 are valued using corroborated observable inputs including those from pricing services or prices from similar instruments that trade in liquid markets.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued based on internally-developed models and assumptions or methodologies using significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets where pricing is largely unobservable, including the financial contracts entered into between the Ameren Illinois Utilities and Marketing Company as part of the Illinois electric settlement agreement. We value Level 3 instruments using pricing models with inputs, which are often unobservable in the market, and certain internal assumptions.

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

We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g. collateral). SFAS No. 157 also requires that the fair value measurement of liabilities should reflect the nonperformance risk of the entity, where 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.

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, 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)	Derivative assets(b)	$ 3	$ 90	$ 308	$ 401
	Nuclear Decommissioning
	Trust Fund(c)	208	84	1	293
UE	Derivative assets	-	66	48	114
	Nuclear Decommissioning
	Trust Fund(c)	208	84	1	293
CIPS	Derivative assets(b)	-	-	112	112
Genco	Derivative assets(b)	-	-	5	5
CILCORP/CILCO	Derivative assets(b)	(d)	-	78	78
IP	Derivative assets(b)	-	-	196	196
Liabilities:
Ameren(a)	Derivative liabilities(b)	$ 1	$ 171	$ 106	$ 278
UE	Derivative liabilities(b)	-	95	8	103
CIPS	Derivative liabilities(b)	-	-	(d)	(d)
Genco	Derivative liabilities(b)	(d)	-	1	1

Quoted Prices in

Active Markets for Identified Assets

(Level 1)

Significant Other Observable Inputs

(Level 2)

Significant Other

Unobservable Inputs

(Level 3)

Total

CILCORP/CILCO	Derivative liabilities(b)	-	-	1	1
IP	Derivative liabilities(b)	-	-	1	1

(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 ($9) million of receivables, payables, and accrued income, net.

(d)	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 three months ended June 30, 2008:

																						Change in
												Total										Unrealized
				Realized and Unrealized Gains (Losses)								Realized		Purchases,								Gains (Losses)
		Beginning								Included in		and		Issuances,			Net			Ending		Related to
		Balance at								Regulatory		Unrealized		and Other			Transfers In			Balance at		Assets/Liabilities
		April 1,		Included in			Included			Assets/		Gains		Settlements,			and/or (Out)			June 30,		Still Held at
		2008		Earnings(a)			In OCI			Liabilities		(Losses)		Net			of Level 3			2008		June 30, 2008
Net Derivative	Ameren	$	59	$	87		$	(25	)	$	109	$	171	$	(29	)	$	1		$	202	$	122
Contracts	UE		15		8			3			12		23		2		(b		)		40		18
	CIPS		58		-			-			56		56		(2	)		-			112		56
	Genco		1		4		(b		)		-		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	UE		2		-			-			-		-		(1	)		-			1		-
Trust Fund

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

(b)	Less than $1 million.

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

																						Change in
												Total										Unrealized
				Realized and Unrealized Gains (Losses)								Realized		Purchases,								Gains (Losses)
		Beginning								Included in		and		Issuances,			Net			Ending		Related to
		Balance at								Regulatory		Unrealized		and Other			Transfers In			Balance at		Assets/Liabilities
		January 1,		Included in			Included			Assets/		Gains		Settlements,			and/or (Out)			June 30,		Still Held at
		2008		Earnings(a)			In OCI			Liabilities		(Losses)		Net			of Level 3			2008		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		(b		)		-		4		(1	)		-			4		4
	CILCORP/CILCO		21		(1	)	(b		)		62		61		(5	)		-			77		54
	IP		55		-			-			140		140	(b		)		-			195		132
Nuclear	Ameren	$	5	$	-		$	-		$	-	$	-	$	(4	)	$	-		$	1	$	-
Decommissioning	UE		5		-			-			-		-		(4	)		-			1		-
Trust Fund

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

(b)	Less than $1 million.

Transfers in and/or out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Any reclassifications are reported as transfers in/out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur.

NOTE 8 – RELATED PARTY TRANSACTIONS

The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 12 – Related Party Transactions under Part II, Item 8 of the Form 10-K.

Illinois Electric Settlement Agreement

As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make contributions of $150 million 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, 2008, CIPS, CILCO and IP had receivable balances from Genco for reimbursement of customer rate relief of $1 million, $1 million and $2 million, respectively. Also at June 30, 2008, CIPS, CILCO and IP had receivable balances from AERG for reimbursement of customer rate relief of $1 million, less than $1 million, and $1 million, respectively. In addition, as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company to lock-in energy prices for a portion of their around-the-clock power requirements from 2008 to 2012 at relevant market prices. These financial contracts became effective on August 28, 2007. See Note 6 – Derivative Financial Instruments for additional information on the financial contracts and Note 2 – Rate and Regulatory Matters for additional information on the Illinois electric settlement agreement.

Electric Power Supply and Resource Sharing Agreements

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

	Three Months		Six Months
	2008	2007	2008	2007
Genco sales to Marketing Company	3,529	3,838	7,941	7,957
AERG sales to Marketing Company	1,610	1,154	3,313	2,642
Marketing Company sales to CIPS	472	562	1,094	1,181
Marketing Company sales to CILCO	223	285	480	573
Marketing Company sales to IP	698	874	1,502	1,700

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

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

One-third of the Ameren Illinois Utilities’ supply contracts that served the load needs of their fixed-price residential and small commercial customers, and all of the supply contracts that served large commercial and industrial customers, expired on May 31, 2008. To replace a portion of these expired supply contracts, the Ameren Illinois Utilities used RFP processes in early 2008, pursuant to the Illinois electric settlement agreement, to contract for the necessary power and energy requirements for the period from June 1, 2008 through May 31, 2009. Marketing Company was one of the winning suppliers in the Ameren

Illinois Utilities’ energy and capacity RFPs. Marketing Company entered into financial instruments that fixed the price that the Ameren Illinois Utilities will pay for approximately two million megawatthours at approximately $60 per megawatthour. Marketing Company contracted to supply a portion of the Ameren Illinois Utilities’ capacity for approximately $6 million. In addition, UE contracted to supply a portion of the Ameren Illinois Utilities’ capacity for approximately $1 million.

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

Collateral Postings

Under the terms of the power supply agreements between Marketing Company and the Ameren Illinois Utilities, which were entered into as part of the September 2006 Illinois power procurement auction, collateral is required to be posted by Marketing Company under certain market conditions to protect the Ameren Illinois Utilities in the event of nonperformance by Marketing Company. The collateral postings are unilateral, meaning that Marketing Company as the supplier is the only counterparty required to post collateral. When Marketing Company is required to post collateral, the funds are placed in separate escrow accounts for the benefit of the Ameren Illinois Utilities, and these funds are restricted from use as working capital by any of the Ameren Companies while held in escrow. The escrow accounts are reflected in other assets in Ameren’s consolidated balance sheet and changes in the escrow accounts are presented in operating activities in Ameren’s consolidated statement of cash flows.

The following table presents the amount of cash collateral related to the 2006 auction power supply agreements that was posted for affiliates by Marketing Company as of June 30, 2008 and December 31, 2007:

	June 30, 2008(a)		December 31, 2007
CIPS	$	49	$	1
CILCO		24	(b		)
IP		74		1
Total	$	147	$	2

(a)	As of July 23, 2008, the collateral was returned due to changes in power prices, and as a result the cash is no longer restricted as collateral.

(b)	Amount is less than $1 million.

In addition, under the terms of the 2008 Illinois power procurement RFP, collateral is required to be posted by Marketing Company and the Ameren Illinois Utilities under certain market conditions. Unlike the collateral described above for the 2006 auction power supply agreements, the cash collateral on the financial instruments, which were entered into by Marketing Company and the Ameren Illinois Utilities as part of the RFP process, is not held in escrow. The funds are held directly by the party calling the collateral. Collateral postings are bilateral, meaning that either counterparty may be required to post collateral at any given time. As of June 30, 2008, Marketing Company had cash collateral postings as follows with the Ameren Illinois Utilities: CIPS - $3 million, CILCO - $2 million and IP - $5 million. These bilateral collateral postings were eliminated in consolidation on Ameren’s financial statements.

Intercompany Transfers

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

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

Money Pools

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

Intercompany Borrowings

Genco’s subordinated note payable to CIPS associated with the transfer in 2000 of CIPS’ electric generating assets and related liabilities to Genco matures on May 1, 2010. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $2 million (2007 - $2 million) and $4 million (2007 - $5 million) for the three months and six months ended June 30, 2008 and 2007, respectively.

CILCORP had outstanding borrowings directly from Ameren of $15 million at June 30, 2008. CILCORP did not have borrowings from Ameren at June 30, 2007. The average interest rate on these borrowings was 3.1% and

3.8% for the three months and six months ended June 30, 2008, respectively (2007 - 5.0% and 4.8%, respectively). CILCORP recorded interest expense of less than $1 million (2007 - none) and less than $1 million (2007 - less than $1 million) for these borrowings for the three months and six months ended June 30, 2008, respectively.

UE had outstanding borrowings directly from Ameren of $50 million and $37 million at June 30, 2008 and June 30, 2007, respectively. The average interest rate on these borrowings was 3.1% and 3.8% for the three months and six months ended June 30, 2008, respectively (2007 - 5.0% and 4.8%, respectively). UE recorded interest expense of less than $1 million (2007 - $2 million) and less than $1 million (2007 - $3 million) for these borrowings for the three months and six months ended June 30, 2008, respectively.

UE had an intercompany note receivable of $30 million from Ameren Development Company at June 30, 2008. This note was transferred to Ameren Development Company from Union Electric Development Corporation as a result of the intercompany transfers discussed above. The average interest rate on these borrowings was 5.1% and 5.2%, respectively, for the three months and six months ended June 30, 2008. UE recorded interest revenue of $1 million for these borrowings for both the three months and six months ended June 30, 2008.

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

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

Operating Revenues:
Genco and AERG power supply agreements with	2008	$	(b)	$	(b)	$	199	$	70	$	(b)	$	(b)	$	(b)	$	425	$	153	$	(b)
Marketing Company	2007	(b)		(b)			182		62	(b)		(b)		(b)			393		134	(b)
Ancillary service agreement with CIPS,	2008		3	(b)		(b)		(b)		(b)			6	(b)		(b)		(b)		(b)
CILCO and IP	2007		4	(b)		(b)		(b)		(b)			8	(b)		(b)		(b)		(b)
UE and Genco gas transportation	2008	(c)		(b)		(b)		(b)		(b)		(c)		(b)		(b)		(b)		(b)
agreement	2007	(c)		(b)		(b)		(b)		(b)		(c)		(b)		(b)		(b)		(b)
Total Operating	2008	$	3	$	(b)	$	199	$	70	$	(b)	$	6	$	(b)	$	425	$	153	$	(b)
Revenues	2007		4	(b)			182		62	(b)			8	(b)			393		134	(b)
Fuel and Purchased Power:
CIPS, CILCO and IP agreements with Marketing ompany (2006 auction and
energy and capacity	2008	$	(b)	$	31	$	(b)	$	15	$	46	$	(b)	$	72	$	(b)	$	32	$	99
agreements)	2007	(b)			36	(b)			19		57	(b)			78	(b)			38		112
Ancillary service	2008	(b)			1	(b)		(c)			2	(b)			2	(b)			1		3
agreement with UE	2007	(b)			2	(b)		(c)			2	(b)			3	(b)			1		4
Ancillary service agreement with	2008	(b)			2	(b)			1		3	(b)			4	(b)			2		6
Marketing Company	2007	(b)			1	(b)		(c)			1	(b)			2	(b)			1		2
Executory tolling agreement with	2008	(b)		(b)		(b)			9	(b)		(b)		(b)		(b)			22	(b)
Medina Valley	2007	(b)		(b)		(b)			8	(b)		(b)		(b)		(b)			20	(b)
UE and Genco gas transportation	2008	(b)		(b)		(c)		(b)		(b)		(b)		(b)		(c)		(b)		(b)
agreement	2007	(b)		(b)		(c)		(b)		(b)		(b)		(b)		(c)		(b)		(b)
Total Fuel and
Purchased	2008	$	(b)	$	34	$	(c)	$	25	$	51	$	(b)	$	78	$	(c)	$	57	$	108
Power	2007	(b)			39	(c)			27		60	(b)			83	(c)			60		118
Other Operating Expense:
Ameren Services support services	2008	$	38	$	15	$	8	$	15	$	23	$	74	$	29	$	15	$	29	$	44
agreement	2007		35		13		6		13		20		74		27		13		28		42
Ameren Energy, Inc. support services	2008	(e)		(e)		(e)		(e)		(e)		(e)		(e)		(e)		(e)		(e)
agreement	2007		2	(b)		(c)		(b)		(b)			5	(b)		(c)		(b)		(b)
AFS support services	2008		1		1	(c)			1		1		3		1		1		1		1
agreement	2007		1		1	(c)		(c)			1		3		1		1		1		1
Insurance	2008		3	(b)			1		1	(b)			5	(b)			2		2	(b)
premiums(d)	2007		5	(b)			1		1	(b)			9	(b)			2		1	(b)
Total Other Operating	2008	$	42	$	16	$	8	$	17	$	24	$	82	$	30	$	18	$	32	$	45
Expenses	2007		43		14		7		14		21		91		28		16		30		43

Three Months

Six Months

Agreement

CIPS

Genco

CILCORP(a)

CIPS

Genco

CILCORP(a)

Interest expense on commercial paper	2008		$	(c)		$	(b)			$	(b)			$	(b)			$	(b)			$	1			$	(b)			$	(b)			$	(b)			$	(b)
held by affiliate(f)	2007			1		(b)				(b)				(b)				(b)					2			(b)				(b)				(b)				(b)

Interest expense (income) from money

2008

(c)

pool borrowings (advances)

2007

(c)

(a)	Amounts represent CILCORP and CILCO activity.

(b)	Not applicable.
(c)	Amount less than $1 million.
(d)	Represents insurance expenses on affiliate policies for replacement power, property damage and terrorism coverage.
(e)	Ameren Energy, Inc. was eliminated December 31, 2007 through an internal reorganization.
(f)	See Note 3 - Short-term Borrowings and Liquidity for more information.

NOTE 9 – COMMITMENTS AND CONTINGENCIES

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

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

Callaway Nuclear Plant

The following table presents insurance coverage at UE’s Callaway nuclear plant at June 30, 2008. The property coverage and the nuclear liability coverage must be renewed on October 1 and January 1, respectively, of each year

Type and Source of Coverage	Maximum Coverages	Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$ 300(a)	$ -
Pool participation	10,461	101(b)
	$ 10,761(c)	$ 101
Property damage:
Nuclear Electric Insurance Ltd.	$ 2,750(d)	$ 24
Replacement power:
Nuclear Electric Insurance Ltd.	$ 490(e)	$ 9
Energy Risk Assurance Company	$ 64(f)	$ -

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

(b)

Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This is subject to retrospective assessment with respect to a covered loss in excess of $300 million from an incident at any licensed U.S. commercial reactor, payable at $15 million per year.

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

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

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

(f)

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

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. 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. In addition, we have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 13 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

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

	2008		2009		2010		2011		2012		Thereafter
Ameren(a)	$	276	$	360	$	206	$	77	$	-	$	-
UE		162		246		153		77		-		-
Genco		53		63		24		-		-		-
CILCORP/CILCO		26		18		11		-		-		-

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

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

	2008		2009		2010		2011		2012		Thereafter
Ameren	$	40	$	68	$	74	$	52	$	67	$	232
UE		40		68		74		52		67		232

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

	2008		2009		2010		2011		2012		Thereafter
Ameren	$	-	$	14	$	44	$	-	$	44	$	-
UE		-		14		44		-		44		-

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

	Ameren		CIPS		CILCO (Illinois Regulated)		IP		Genco		CILCO (AERG)
2008(a)	$	21.6	$	3.3	$	1.5	$	4.5	$	8.5	$	3.8
2009(a)		25.2		3.5		1.8		4.7		10.5		4.7
2010(a)		2.0		0.3		0.1		0.4		0.8		0.4
Total	$	48.8	$	7.1	$	3.4	$	9.6	$	19.8	$	8.9

(a) Estimated.

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

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric

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

Clean Air Act

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

In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method used to remove electric generating units from the list of sources subject to the maximum available control technology requirements under the Clean Air Act. The EPA and a group representing the electric utility industry filed petitions for rehearing; however, the court denied those petitions in May 2008. Parties have until August 18, 2008, to file petitions for review with the U.S. Supreme Court.

On July 11, 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 matters. The EPA has 45 days from the date of the court’s decision to file a petition for rehearing. After this step the remaining court appeal is to file a petition for review with the U.S. Supreme Court.

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

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

We do not believe the recent court decisions that vacated the federal Clean Air Interstate Rule and the federal Clean Air Mercury Rule will nullify the Illinois mercury emission regulations. Under the regulations, which incorporate an agreement which was reached in 2006 among Genco, CILCO (AERG), EEI and the Illinois EPA, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NOx and SO2 controls. In 2009, Genco, AERG and EEI expect to begin putting into service equipment designed to reduce mercury emissions. These rules, when fully implemented, are expected to reduce mercury emissions 90%, NOx emissions 50%, and SO2 emissions 70% by 2015 in Illinois.

Illinois and Missouri must also develop attainment plans to meet the existing federal eight-hour ozone ambient standard, the federal fine particulate ambient standard, and the Clean Air Visibility rule. Both states have filed ozone attainment plans for the St. Louis area. Illinois and Missouri are finalizing their attainment plans for fine particulate matter for submission to the EPA. The Illinois and Missouri plans for the Clean Air Visibility rule were submitted in December 2007. The EPA finalized regulations in March 2008 that will lower the ambient standard for ozone. It is expected that areas will be designated as nonattainment in 2009 and that state implementation plans will need to be submitted in 2013 unless Illinois and Missouri seek extensions of various requirement dates. Additional emission reductions may be required as a result of the future state implementation plans. At this time, we are unable to determine the impact such state actions would

have on our results of operations, financial position, or liquidity.

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

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

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

Emission Allowances

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

The following table presents the SO2 and NOx emission allowances held and the related SO2 and NOx emission allowance book values that were carried as intangible assets as of June 30, 2008.

	SO2 (a)	NOx (b)	Book Value(c)
Ameren	3.129	32,635	$ 177(d)
UE	1.716	11,919	52
Genco	0.735	10,522	52
CILCORP	0.346	1,312	37
CILCO (AERG)	0.346	1,312	1
EEI	0.332	8,882	9

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

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

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

(d)	Includes value assigned to EEI allowances as a result of purchase accounting of $26 million.

UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. Environmental regulations, the timing of the installation of pollution control equipment, and the level of operations will have a significant impact on the amount of allowances actually required for ongoing operations.

The federal Clean Air Interstate Rule required a reduction in SO2 emissions by increasing the ratio of Acid Rain Program allowances surrendered for each ton of SO2 emitted. As discussed above, in July 2008 the U.S. Court of Appeals for the District of Columbia vacated the federal Clean Air Interstate Rule. At this time, it is uncertain what legal actions the EPA may make in response to this decision, such as requesting a rehearing or filing an appeal. If the Clean Air Interstate Rule is ultimately vacated, then SO2 allowances will only be used for the Acid Rain program with the value of one SO2 allowance for each ton emitted. Additionally, the annual NOx trading program under the federal Clean Air Interstate Rule will no longer be required; however, we expect the existing NOx Budget Trading Program to continue. We have evaluated the impact of the court’s decision on the recoverability of the carrying amounts of our emission allowances and have concluded that our emission allowances have not been impaired as a result of the ruling.

Global Climate

Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. In June 2008, the U.S. Senate

considered legislation proposed by Senators Lieberman, Warner, and Boxer that would set up a “cap and trade” program for greenhouse gas emissions. That legislation was not approved by the U.S. Senate and further action on climate change legislation is not expected in the U.S. Senate this year. In the U.S. House of Representatives, the Energy and Commerce Committee is working on a cap and trade form of climate change legislation, and individual members of Congress have proposed cap and trade legislation. However, it is uncertain whether such legislation will be taken up this year.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Clean Water Act

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

New Source Review

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

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. We are currently in discussions with the EPA and the state of Illinois regarding resolution of these matters, but we are unable to predict the outcome of these discussions.

In March 2008, Ameren received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to UE’s Labadie, Meramec, Rush Island, and Sioux facilities. All of these facilities are coal-fired power plants. The information request required UE to provide responses to specific EPA questions regarding certain projects and maintenance activities to determine compliance with state and federal regulatory requirements. UE is complying with this information request, but we are unable to predict the outcome of this matter.

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

Remediation

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

for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of June 30, 2008, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 14, CILCO four, and IP 25. All of these sites are in various stages of investigation, evaluation and remediation. Under its current schedule, Ameren anticipates that remediation at these sites should be completed by 2015. The ICC permits each company to recover remediation and litigation costs associated with its former MGP sites from its Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred, and costs are subject to annual reconciliation review by the ICC. As of June 30, 2008, estimated obligations were: CIPS - $20 million to $32 million, CILCO - $5 million to $6 million, and IP - $77 million to $145 million. CIPS, CILCO and IP also recorded liabilities of $20 million, $5 million and $77 million, respectively, 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 landfill in Coffeen, Illinois. As of June 30, 2008, CIPS estimated its obligation at $0.5 million to $6 million. CIPS recorded a liability of $0.5 million to represent its estimated minimum obligation for this site as no other amount within the range was a better estimate. IP is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of June 30, 2008, IP recorded a liability of $1 million to represent its best estimate of the obligation for these sites.

In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. UE does not currently have in effect in Missouri a rate rider mechanism that permits remediation costs associated with MGP sites to be recovered from utility customers. UE does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs. As of June 30, 2008, UE estimated its obligation at $5 million to $7 million. UE recorded a liability of $5 million to represent its estimated minimum obligation for its MGP sites as no other amount within the range was a better estimate. UE also is responsible for four electric sites in Missouri that have corporate cleanup liability, most as a result of federal agency mandates. As of June 30, 2008, UE estimated its obligation at $3 million to $16 million. UE recorded a liability of $3 million to represent its estimated minimum obligation for these sites as no other amount within the range was a better estimate.

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

Sauget Area 2 investigation activities under the oversight of the EPA are largely completed, and the results will be submitted to the EPA by the third quarter of 2008. 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.

In March 2008, the EPA issued an administrative order to CIPS requesting that it participate in a portion of an environmental cleanup of a site within Sauget Area 2 previously occupied by Clayton Chemical Company. CIPS was formerly a customer of Clayton Chemical Company that, before its dissolution, was a recycler of waste solvents and oil. Other former customers of Clayton Chemical Company were issued similar orders by the EPA.

In December 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $1 million at June 30, 2008, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort, which involves treating and discharging recycle-system water in order to address these groundwater and surface water issues.

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

Polychlorinated Biphenyls Information Request

Polychlorinated biphenyls (PCBs) are a blend of chemical compounds that were historically used in a variety

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

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

Pumped-storage Hydroelectric Facility Breach

UE has settled all state and federal issues associated with the December 2005 Taum Sauk incident. In addition, UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and has begun rebuilding the facility. The estimated cost to rebuild the upper reservoir is in the range of $450 million. UE expects the Taum Sauk plant to be out of service through early 2010.

In December 2006, 10 business owners filed a lawsuit regarding the Taum Sauk breach. The suit, which was filed in the Missouri Circuit Court of Reynolds County and remains pending, contains allegations of negligence, violations of the Missouri Clean Water Act, and various other statutory and common law claims and seeks damages relating to business losses, lost profit, and unspecified punitive damages.

At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. UE expects that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the reservoir, will range from $200 million to $220 million. As of June 30, 2008, UE had paid $165 million and accrued a $35 million liability, including costs resulting from the FERC-approved stipulation and consent agreement, while expensing $32 million and recording a $168 million receivable due from insurance companies. As of June 30, 2008, UE had received $119 million from insurance companies, which reduced the insurance receivable balance to $49 million. As of June 30, 2008, UE had a $188 million receivable due from insurance companies related to the rebuilding of the facility. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.

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

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

Mechanics’ Liens

Approximately 20 mechanics’ liens were filed by various subcontractors who provided labor or material for a 2007 maintenance outage at the Duck Creek facility of CILCO subsidiary, AERG. The total lien claim amount was $26 million plus interest at June 30, 2008. In November 2007, the primary subcontractor on the project filed a complaint for foreclosure of its mechanic’s lien of $19 million plus interest against AERG in the Circuit Court of Fulton County, Illinois. Since that time, various second tier subcontractors of the primary subcontractor have filed for foreclosure of their mechanics’ lien claims against AERG in the Circuit Court of Fulton County, Illinois in addition to filing their claim against the primary subcontractor. Many of these claims are based on additional work outside of the contract scope, which was not approved by AERG. AERG believes it has paid the general contractor the amount due in full (less a contract-allowed holdback of $4 million), and since this arose out of a contract dispute between the general contractor and the primary subcontractor, AERG is currently considering its potential remedies against the general contractor. Beginning in February 2008, AERG has filed its answers to the claims in the foreclosure lawsuits denying the validity of the liens. At this time, we are unable to predict the impact of these liens and lawsuit on CILCO’s or AERG’s future results of operations, financial position, or liquidity.

Asbestos-related Litigation

Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case is significant; as many as 161 parties are named in some pending cases and as few as six in others. However, in the cases that were pending as of June 30, 2008, the average number of parties was 69.

The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a Dynegy subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS and CILCO have contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages, which, if awarded at trial, typically would be shared among various defendants.

From April 1, 2008, through June 30, 2008, nine additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois. Four lawsuits were dismissed. The following table presents the status as of June 30, 2008, of the asbestos-related lawsuits that have been filed against the Ameren Companies:

		Specifically Named as Defendant
	Total(a)	Ameren	UE	CIPS	Genco	CILCO	IP
Filed	366	33	202	152	2	50	181
Settled	126	-	67	56	-	19	64
Dismissed	164	29	108	59	2	17	79
Pending	76	4	27	37	-	14	38

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

As of June 30, 2008, 10 asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

IP has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms. 90% of cash expenditures in excess of the amount included in base electric rates are recovered by IP from a trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy. At June 30, 2008, the trust fund balance was $23 million, including accumulated interest.

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

The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.

NOTE 10 – CALLAWAY NUCLEAR PLANT

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or 1/10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available before 2020. UE has sufficient installed storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.

Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. It is assumed that the Callaway nuclear plant site will be decommissioned based on the immediate dismantlement method and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are charged to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2007, 2006 and 2005. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway

nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest study was filed in 2005. Minor tritium contamination was discovered on the Callaway nuclear plant site in the summer of 2006. Existing facts and regulatory requirements indicate that this discovery will not cause any significant increase in a decommissioning cost estimate when the next study is conducted and filed on September 1, 2008. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for UE’s Callaway nuclear plant is reported in Nuclear Decommissioning Trust Fund in Ameren’s and UE’s Consolidated Balance Sheets. This amount is legally restricted. It may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to a regulatory asset or regulatory liability, as appropriate.

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

NOTE 11 – OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income as reported on the statements of income and all other changes in common stockholders’ equity, except those resulting from transactions with common shareholders. A reconciliation of net income to comprehensive income for the three months and six months ended June 30, 2008 and 2007, is shown below for the Ameren Companies:

	Three Months						Six Months
	2008			2007			2008			2007
Ameren:(a)
Net income	$	206		$	143		$	344		$	266
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(27), $12, $(63) and $(3), respectively		(48	)		23			(111	)		(5	)
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $(3), $2, $(6) and $9, respectively		5			(2	)		11			(15	)
Adjustment to pension and benefit obligation, net of taxes (benefit) of $3, $(1), $1 and $(2), respectively		(4	)		(2	)		(2	)		-
Total comprehensive income, net of taxes	$	159		$	162		$	242		$	246
UE:
Net income	$	124		$	81		$	188		$	114
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(4), $2, $(11) and $(1), respectively		(6	)		4			(17	)		(1	)
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $1, $(1), $1 and $1, respectively		(2	)		1			(1	)		(2	)
Total comprehensive income, net of taxes	$	116		$	86		$	170		$	111
CIPS:
Net income (loss)	$	(3	)	$	5		$	-		$	17
Unrealized net (loss) on derivative hedging instruments, net of taxes of $-, $-, $- and $-, respectively		-			(1	)		-			-
Total comprehensive income (loss), net of taxes	$	(3	)	$	4		$	-		$	17
Genco:
Net income	$	74		$	17		$	120		$	60
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $4, $-, $- and $(1), respectively		6			-			-			(2	)
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $4, $-, $4 and $-, respectively		(5	)		-			(5	)		-
Adjustment to pension and benefit obligation, net of taxes (benefit) of $-, $(2), $(2) and $(2), respectively		-			(3	)		3			(2	)
Total comprehensive income, net of taxes	$	75		$	14		$	118		$	56
CILCORP:
Net income	$	4		$	12		$	24		$	33
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $(2), $- and $-, respectively		-			(2	)		-			1
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $-, $(1), $1 and $1, respectively		-			1			(1	)		(2	)

	Three Months						Six Months
	2008			2007			2008			2007
Adjustment to pension and benefit obligation, net of taxes of $2, $1, $1 and $-, respectively		3			(1	)		3			-
Total comprehensive income, net of taxes	$	7		$	10		$	26		$	32
CILCO:
Net income	$	12		$	21		$	38		$	48
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $(2), $- and $-, respectively		-			(2	)		-			1
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $-, $-, $- and $1, respectively		-			-			-			(3	)
Adjustment to pension and benefit obligation, net of taxes of $2, $-, $2 and $-, respectively		4			-			4			-
Total comprehensive income, net of taxes	$	16		$	19		$	42		$	46
IP:
Net income (loss)	$	(10	)	$	7		$	(7	)	$	22
Total comprehensive income (loss), net of taxes	$	(10	)	$	7		$	(7	)	$	22

(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 federal funding requirements. In May 2007, the MoPSC issued an electric rate order for UE that allows UE to recover, through customer rates, pension expense incurred under GAAP. Ameren expects to fund its pension plans at a level equal to the pension expense. Based on Ameren's assumptions at December 31, 2007, and reflecting this pension funding policy, Ameren expects annual contributions of $50 million to $75 million in each of the next five years. These amounts are estimates and may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association trusts to match the annual postretirement expense.

Ameren made a contribution to its postretirement benefit plan of $22 million in the second quarter of 2008 and $26 million in the second quarter of the prior year.

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

	Pension Benefits(a)												Postretirement Benefits(a)
	Three Months						Six Months						Three Months						Six Months
	2008			2007			2008			2007			2008			2007			2008			2007
Service cost	$	14		$	15		$	29		$	31		$	4		$	4		$	9		$	10
Interest cost		46			45			93			90			16			17			35			36
Expected return on plan assets		(53	)		(51	)		(106	)		(103	)		(15	)		(13	)		(29	)		(26	)
Amortization of:
Transition obligation		-			-			-			-			1			1			1			1
Prior service cost (benefit)		3			3			6			6			(2	)		(2	)		(4	)		(4	)
Actuarial loss		-			5			1			11			-			5			4			12
Net periodic benefit cost	$	10		$	17		$	23		$	35		$	4		$	12		$	16		$	29

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

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

	Pension Costs										Postretirement Costs
	Three Months					Six Months					Three Months						Six Months
	2008			2007		2008			2007		2008			2007			2008			2007
Ameren(a)	$	10		$	17	$	23		$	35	$	4		$	12		$	16		$	29
UE		10			10		19			20		-			6			6			15
CIPS		1			2		3			4		1			1			2			3
Genco		2			1		3			2		-			1			1			2
CILCORP		(2	)		-		(4	)		-		(1	)		(1	)		(2	)		(2	)
CILCO		-			2		2			5		-			2			2			5
IP		(3	)		1		(2	)		3		4			3			7			6

(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 and other non-rate regulated activities, which are included in Other. UE’s interest in EEI was transferred to Resources Company on February 29, 2008. The Illinois Regulated segment for Ameren consists of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO, and IP, as described in Note 1 – Summary of Significant Accounting Policies. The Non-rate-regulated Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, and Marketing Company. The category called Other primarily includes Ameren parent company activities and the leasing activities of CILCORP, AERG, Resources Company, and CIPSCO Investment Company.

CIPSCO Investment Company was eliminated on March 31, 2008, through an internal reorganization.

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

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

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

Three Months	Missouri Regulated		Illinois Regulated			Non-rate- regulated Generation		Other			Intersegment Eliminations			Consolidated
2008:
External revenues	$	760	$	717		$	312	$	(1	)	$	-		$	1,788
Intersegment revenues		11		12			95		4			(122	)		-
Net income (loss)(a)		122		(14	)		98		-			-			206
2007:
External revenues	$	686	$	750		$	290	$	2		$	-		$	1,728
Intersegment revenues		11		6			124		10			(151	)		-
Net income(a)		67		20			56		-			-			143
Six Months
2008:
External revenues	$	1,475	$	1,763		$	628	$	1		$	-		$	3,867
Intersegment revenues		20		23			227		8			(278	)		-
Net income (loss)(a)		174		2			176		(8	)		-			344
2007:
External revenues	$	1,324	$	1,809		$	608	$	11		$	-		$	3,752
Intersegment revenues		23		13			257		20			(313	)		-
Net income(a)		85		53			126		2			-			266
As of June 30, 2008:
Total assets	$	11,049	$	6,465		$	4,544	$	1,218		$	(1,631	)	$	21,645
As of December 31, 2007:
Total assets	$	10,852	$	6,385		$	4,027	$	965		$	(1,501	)	$	20,728

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

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

Three Months	Missouri Regulated		Other (a)		Consolidated UE
2008:
Revenues	$	771	$	-	$	771
Net income(b)		122		-		122
2007:
Revenues	$	697	$	-	$	697
Net income(b)		67		12		79

Six Months	Missouri Regulated			Other (a)		Consolidated UE
2008:
Revenues	$	1,495	$	-	$	1,495
Net income(b)		174		11		185
2007:
Revenues	$	1,347	$	-	$	1,347
Net income(b)		85		26		111
As of June 30, 2008:
Total assets	$	11,049	$	-	$	11,049
As of December 31, 2007:
Total assets	$	10,852	$	51	$	10,903

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

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

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

Three Months	Illinois Regulated			Non-rate- regulated Generation			CILCORP Other		Intersegment Eliminations			Consolidated CILCORP
2008:
External revenues	$	162		$	70		$	-	$	-		$	232
Intersegment revenues		2			(1	)		-		(1	)		-
Net income (loss)(a)		(1	)		5			-		-			4
2007:
External revenues	$	164		$	62		$	-	$	-		$	226
Intersegment revenues		-			1			-		(1	)		-
Net income(a)		6			6			-		-			12

Six Months
2008:
External revenues	$	428	$	149	$	-	$	-		$	577
Intersegment revenues		2		-		-		(2	)		-
Net income(a)		11		13		-		-			24
2007:
External revenues	$	403	$	138	$	-	$	-		$	541
Intersegment revenues		-		2		-		(2	)		-
Net income(a)		14		19		-		-			33
As of June 30, 2008:
Total assets(b)	$	1,235	$	1,530	$	2	$	(190	)	$	2,577
As of December 31, 2007:
Total assets(b)	$	1,202	$	1,455	$	1	$	(199	)	$	2,459

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

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

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

Three Months	Illinois Regulated			Non-rate- regulated Generation			CILCO Other		Intersegment Eliminations			Consolidated CILCO
2008:
External revenues	$	162		$	70		$	-	$	-		$	232
Intersegment revenues		2			(1	)		-		(1	)		-
Net income (loss)(a)		(1	)		12			-		-			11
2007:
External revenues	$	164		$	62		$	-	$	-		$	226
Intersegment revenues		-			1			-		(1	)		-
Net income(a)		6			14			-		-			20

Six Months	Illinois Regulated		Non-rate- regulated Generation		CILCO Other		Intersegment Eliminations			Consolidated CILCO
2008:
External revenues	$	428	$	149	$	-	$	-		$	577
Intersegment revenues		2		-		-		(2	)		-
Net income(a)		11		26		-		-			37
2007:
External revenues	$	403	$	138	$	-	$	-		$	541
Intersegment revenues		-		2		-		(2	)		-
Net income(a)		14		33		-		-			47
As of June 30, 2008:
Total assets	$	1,045	$	946	$	-	$	(1	)	$	1,990
As of December 31, 2007:
Total assets	$	1,012	$	859	$	-	$	(9	)	$	1,862

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

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

OVERVIEW

Ameren Executive Summary

Ameren’s earnings in the second quarter and first half of 2008 exceeded its earnings in the 2007 comparable periods principally because of the net impact of the following items:

Net unrealized mark-to-market gains from nonqualifying hedges increased Ameren’s net income in the second quarter and first six months of 2008 by $48 million and $58 million, respectively, as compared to gains of $5 million and $1 million in the second quarter and first six months of 2007, respectively.

A lump-sum payment from a coal supplier for expected higher fuel costs for our Non-rate-regulated Generation segment in 2009 as a result of the premature closure of a mine in late 2007 and the resulting termination of a contract increased Ameren’s second quarter and first half of 2008 net income by $16 million.

·	The estimated minimum amount of storm costs that UE expects to recover, as a result of an accounting order issued by the MoPSC, which was recorded as a regulatory asset, increased Ameren’s net income in the second quarter and first six months of 2008 by $8 million.

·	Severe ice storms reduced Ameren’s net income in the first half of 2007 by $18 million as compared to minor storm expenditures in the first half of 2008.

·	A FERC order that resettled costs among market participants, retroactive to 2005, reduced Ameren’s net income in the first six months of 2007 by $10 million.

The net costs associated with the Illinois electric settlement agreement reduced Ameren’s net income by $8 million and $14 million in the second quarter and first half of 2008, respectively, while the reversal of a 2006 charge related to funding commitments for the Illinois Customer Elect electric rate increase phase-in plan benefited net income in the first six months of 2007 by $10 million.

Excluding these items, Ameren’s earnings in the second quarter of 2008 were comparable with the same period in 2007. Higher electric and gas margins and the benefit of not having a Callaway nuclear plant refueling and maintenance outage in the second quarter of 2008, as occurred in the second quarter of 2007, were largely offset by the following factors: higher fuel prices, increased spending on utility distribution system reliability, coal-fired plant operations and maintenance and other operating expenses, and the earnings impact of milder weather.

Excluding the items discussed above, Ameren’s earnings in the first half of 2008 were below its earnings in the same period in 2007 principally because of higher fuel prices, increased spending on utility distribution system reliability and coal-fired plant operations and maintenance, higher other operating expenses and the impact of electric rate redesign in Illinois. In late 2007, the ICC authorized redesigned electric rates to reduce seasonal fluctuations for residential customers who use electricity to heat their homes. The effect of these redesigned rates will shift some revenues from winter to summer months with no impact on full-year earnings. The earnings impact of these unfavorable items was reduced by, among other things, higher electric and gas margins and the lack of a Callaway nuclear plant refueling and maintenance outage in the second quarter of 2008.

A great deal of activity took place in Ameren’s business in the first half of 2008 from an operational and regulatory perspective. Ameren’s coal procurement and management strategies allowed the coal plants to run at full available capacity despite meaningful delays in coal deliveries at some of the plants due to significant flooding in the Midwest. Additionally, Ameren successfully negotiated the coal contract settlement with a coal

supplier over higher fuel costs Ameren expects to incur in 2008 and 2009.

Increasing costs for the fuel to run Ameren’s business are indicative of the rising cost environment that the entire industry is facing. Ameren is experiencing significant cost increases across the board during a period when substantial investments in infrastructure for improved reliability and cleaner air are needed. Ameren has proactively taken actions to manage these cost increases, especially as they relate to fuel costs. However, Ameren’s hedging activities and other proactive cost control activities cannot entirely eliminate the rising costs, which are impacting all aspects of the business. These cost pressures, coupled with significant investments in utility infrastructure, have required Ameren to seek rate increases for both the Illinois Regulated and Missouri Regulated business segments. The current ICC-requested electric and natural gas delivery service annual revenue increase for the Ameren Illinois Utilities is approximately $207 million, in the aggregate, and the ICC staff has recommended an increase of approximately $87 million, in the aggregate. UE has requested the MoPSC for an annual electric revenue increase of approximately $251 million. These cases are progressing, and final decisions are expected by the end of September 2008 for the Illinois rate cases and by March 2009 for the Missouri rate case. Achieving constructive outcomes in these cases is critical to UE’s, CIPS’, CILCO’s and IP’s ability to continue to invest in their infrastructure in order to meet customers’ expectations for safe and reliable service.

In July 2008, UE filed a COLA with the NRC for a potential new nuclear plant unit at its existing Callaway nuclear plant site. Ameren has not made a decision to build a second nuclear power plant at this time; however, seeking NRC approval and a license will preserve the nuclear generation option for the future. It will also position UE to seek nuclear-specific federal loan guarantees and production tax credits, made possible by the Energy Policy Act of 2005. It is estimated that the NRC review may require up to 42 months for completion.

On July 11, 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Interstate Rule and earlier this year this court had vacated the federal Clean Air Mercury Rule. Ameren is currently evaluating the impact that these court decisions will have on its environmental compliance strategy. Included in the evaluation will be a review of other relevant environmental regulations. It is unclear how this matter will be resolved at this time. Ameren expects this uncertainty to persist until the matter of further court appeals has been exhausted or expired. It is also possible that the U.S. Congress may take legislation action in response to these court decisions.

General

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

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

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

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

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

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

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

RESULTS OF OPERATIONS

Earnings Summary

Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren’s revenues are

subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. Non-rate-regulated Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We do not currently have a fuel and purchased power cost recovery mechanism in Missouri for our electric utility business. We do have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses and purchased power cost recovery mechanisms for our Illinois electric delivery businesses. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, for a discussion of pending rate cases and the Illinois electric settlement agreement. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Ameren’s net income increased to $206 million, or 98 cents per share, in the second quarter of 2008 from $143 million, or 69 cents per share, in the second quarter of 2007. Net income in the second quarter of 2008 increased in the Missouri Regulated and Non-rate-regulated Generation segments by $55 million and $42 million, respectively, from the prior-year period, while net income in the Illinois Regulated segment declined by $34 million from the same period in 2007.

Ameren’s net income increased to $344 million, or $1.64 per share, in the first six months of 2008 from $266 million, or $1.29 per share, in the first six months of 2007. Net income increased in the Missouri Regulated and Non-rate-regulated Generation segments by $89 million and $50 million, respectively, in the first six months of 2008 compared to the prior-year period, while net income in the Illinois Regulated segment decreased by $51 million from the same period in 2007.

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

·	increased margins on interchange sales in the Missouri Regulated segment;

·	increased plant availability and higher realized electric margins in the Non-rate-regulated Generation segment;

·	net mark-to-market gains on energy and fuel-related transactions (21 cents per share and 28 cents per share, respectively);

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

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

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

·	higher electric rates, lower depreciation expense and decreased income tax expense in the Missouri Regulated segment pursuant to the MoPSC electric rate order for UE issued in May 2007 (2 cents per share and 8 cents per share, respectively).

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

·	higher fuel and related transportation prices (8 cents per share and 17 cents per share, respectively);

·	increased distribution system reliability expenditures (8 cents per share and 14 cents per share, respectively);

·	higher plant operations and maintenance expense (6 cents per share and 8 cents per share, respectively);

·	unfavorable weather conditions (estimated at 3 cents per share for the second quarter only);

·	electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities electric customers under the Illinois electric settlement agreement (4 cents per share and 7 cents per share, respectively);

·	higher labor and employee benefit costs (5 cents per share and 6 cents per share, respectively);

·	higher financing costs (3 cents per share and 3 cents per share, respectively);

·	higher bad debt expenses (2 cents per share and 3 cents per share, respectively); and

·	the implementation of new seasonal delivery service tariffs at the Ameren Illinois Utilities, which will impact quarterly earnings comparisons in 2008 but are not expected to have any impact on annual margins (1 cent per share and 6 cents per share, respectively).

In addition to the above items affecting both periods, earnings were favorably impacted in the first six months of 2008 as compared with the first six months of 2007 by the absence of costs in 2008 that were incurred in January 2007 associated with electric outages caused by a severe ice storm (9 cents per share) and as a result of a March 2007 FERC order that resettled costs among market participants retroactive to 2005 (5 cents per share). Reducing the effect of these items was the absence in 2008 of the reversal, recorded in 2007, of the Illinois Customer Elect electric rate increase phase-in plan accrual (5 cents per share).

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

Because it is a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren’s principal subsidiaries to Ameren’s consolidated net income for the three months and six months ended June 30, 2008 and 2007:

	Three Months					Six Months
	2008			2007		2008			2007
Net income (loss):
UE(a)	$	122		$	79	$	185		$	111
CIPS		(3	)		5		(1	)		16
Genco		74			17		120			60
CILCORP		4			12		24			33
IP		(10	)		7		(8	)		21
Other(b)		19			23		24			25
Ameren net income	$	206		$	143	$	344		$	266

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

(b)

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

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

	Missouri Regulated			Illinois Regulated			Non-rate- regulated Generation			Other / Intersegment Eliminations			Total
Three Months 2008:
Electric margin	$	595		$	188		$	320		$	(4	)	$	1,099
Gas margin		17			63			-			(2	)		78
Other operations and maintenance		(238	)		(154	)		(90	)		13			(469	)
Depreciation and amortization		(82	)		(61	)		(29	)		(6	)		(178	)
Taxes other than income taxes		(60	)		(24	)		(6	)		1			(89	)
Other income and (expenses)		13			3			4			(7	)		13
Interest expense		(50	)		(37	)		(29	)		(2	)		(118	)
Income taxes		(71	)		9			(64	)		7			(119	)
Minority interest and preferred dividends		(2	)		(1	)		(8	)		-			(11	)
Net income (loss)	$	122		$	(14	)	$	98		$	-		$	206
Three Months 2007:
Electric margin	$	494		$	207		$	251		$	(10	)	$	942
Gas margin		14			63			-			(1	)		76
Other operations and maintenance		(223	)		(124	)		(89	)		16			(420	)
Depreciation and amortization		(84	)		(58	)		(30	)		(4	)		(176	)
Taxes other than income taxes		(60	)		(30	)		(6	)		-			(96	)
Other income and (expenses)		7			7			1			(3	)		12
Interest expense		(49	)		(33	)		(28	)		2			(108	)
Income taxes		(30	)		(11	)		(37	)		-			(78	)
Minority interest and preferred dividends		(2	)		(1	)		(6	)		-			(9	)
Net income	$	67		$	20		$	56		$	-		$	143
Six Months 2008:
Electric margin	$	1,036		$	366		$	592		$	(17	)	$	1,977
Gas margin		45			189			-			(3	)		231
Other operations and maintenance		(455	)		(297	)		(168	)		29			(891	)
Depreciation and amortization		(163	)		(121	)		(57	)		(13	)		(354	)
Taxes other than income taxes		(120	)		(67	)		(14	)		(1	)		(202	)
Other income and (expenses)		25			7			5			(8	)		29

Six Months 2008:	Missouri Regulated			Illinois Regulated			Non-rate- regulated Generation			Other / Intersegment Eliminations			Total
Interest expense		(91	)		(72	)		(50	)		(5	)		(218	)
Income taxes		(100	)		-			(116	)		10			(206	)
Minority interest and preferred dividends		(3	)		(3	)		(16	)		-			(22	)
Net income (loss)	$	174		$	2		$	176		$	(8	)	$	344
Six Months 2007:
Electric margin	$	902		$	386		$	501		$	(20	)	$	1,769
Gas margin		41			178			-			(3	)		216
Other revenues		1			2			-			(3	)		-
Other operations and maintenance		(446	)		(245	)		(157	)		39			(809	)
Depreciation and amortization		(171	)		(118	)		(57	)		(13	)		(359	)
Taxes other than income taxes		(117	)		(66	)		(14	)		(1	)		(198	)
Other income and (expenses)		16			10			2			(7	)		21
Interest expense		(97	)		(62	)		(53	)		6			(206	)
Income taxes		(41	)		(29	)		(83	)		4			(149	)
Minority interest and preferred dividends		(3	)		(3	)		(13	)		-			(19	)
Net income	$	85		$	53		$	126		$	2		$	266

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins for the three months and six months ended June 30, 2008, compared with the same periods in 2007. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined as gas revenues less gas purchased for resale. We consider electric, interchange and gas margins useful measures to analyze the change in profitability of our electric and gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Three Months	Ameren(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Electric revenue change:
Effect of weather (estimate)	$	(28	)	$	(6	)	$	(8	)	$	-		$	(4	)	$	(4	)	$	(10	)
UE electric rate increase		7			7			-			-			-			-			-
Interchange revenues, excluding estimated weather impact of $13 million		42			42			-			-			-			-			-
Illinois electric settlement agreement - net of reimbursement		(8	)		-			(1	)		(5	)		(3	)		(3	)		(2	)
Illinois rate redesign		8			-			4			-			1			1			3
Net mark-to-market gains (losses) on energy contracts		(19	)		14			-			-			-			-			-
Growth, Illinois customer switching, and other		24			11			(19	)		13			3			3			(13	)
Total electric revenue change	$	26		$	68		$	(24	)	$	8		$	(3	)	$	(3	)	$	(22	)
Fuel and purchased power change:
Fuel:
Generation and other	$	17		$	12		$	-		$	16		$	(14	)	$	(14	)	$	-
Emission allowance sales (costs)		3			3			-			1			(1	)		(1	)		-
Net mark-to-market gains on fuel contracts		88			48			-			23			7			7			-
Price		(45	)		(24	)		-			(15	)		(3	)		(3	)		-
Coal contract settlement		60			-			-			60			-			-			-
Purchased power		18			(8	)		23			-			3			3			20
Illinois rate redesign		(10	)		-			(4	)		-			(1	)		(1	)		(3	)
Total fuel and purchased power change	$	131		$	31		$	19		$	85		$	(9	)	$	(9	)	$	17
Net change in electric margins	$	157		$	99		$	(5	)	$	93		$	(12	)	$	(12	)	$	(5	)
Net change in gas margins	$	2		$	3		$	(1	)	$	-		$	1		$	1		$	1
Six Months
Electric revenue change:
Effect of weather (estimate)	$	(24	)	$	(5	)	$	(7	)	$	-		$	(3	)	$	(3	)	$	(9	)
UE electric rate increase		16			16			-			-			-			-			-
Interchange revenues, excluding estimated weather impact of $10 million		74			74			-			-			-			-			-
Illinois electric settlement agreement – net of reimbursement		(19	)		-			(3	)		(9	)		(6	)		(6	)		(4	)

Six Months	Ameren(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
FERC-ordered MISO resettlements – March 2007		(13	)		-			-			(8	)		(4	)		(4	)		-
Illinois rate redesign		(30	)		-			(10	)		-			(5	)		(5	)		(15	)
Net mark-to-market gains (losses) on energy contracts		(7	)		18			-			-			-			-			-
Growth, Illinois customer switching, and other		33			33			(35	)		13			29			29			(28	)
Total electric revenue change	$	30		$	136		$	(55	)	$	(4	)	$	11		$	11		$	(56	)
Fuel and purchased power change:
Fuel:
Generation and other	$	(2	)	$	4		$	-		$	12		$	(19	)	$	(19	)	$	-
Emission allowance sales		3			1			-			2			-			-			-
Net mark-to-market gains on fuel contracts		99			54			-			28			8			8			-
Price		(76	)		(42	)		-			(24	)		(5	)		(5	)		-
Coal contract settlement		60			-			-			60			-			-			-
Purchased power		51			(34	)		36			21			(5	)		(5	)		32
Illinois rate redesign		11			-			4			-			2			2			5
FERC-ordered MISO resettlements – March 2007		32			13			4			-			3			3			12
Total fuel and purchased power change	$	178		$	(4	)	$	44		$	99		$	(16	)	$	(16	)	$	49
Net change in electric margins	$	208		$	132		$	(11	)	$	95		$	(5	)	$	(5	)	$	(7	)
Net change in gas margins	$	15		$	4		$	2		$	-		$	5		$	5		$	4

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

Ameren

Ameren’s electric margin increased by $157 million, or 17%, and $208 million, or 12%, for the three months and six months ended June 30, 2008, respectively, compared with the same periods in 2007. The following items had a favorable impact on electric margin for the three and six months ended June 30, 2008, as compared to the year-ago periods, unless otherwise noted:

Net mark-to-market gains on energy and fuel-related transactions of $69 million and $92 million for the three and six months ended June 30, 2008, 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 for the period 2008 through 2012.

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

An increase in margin on interchange sales of $29 million and $50 million for the three and six months ended June 30, 2008, respectively, due to a 15% increase in average sales prices in both the second quarter and first six months of 2008 and increased hydroelectric generation due to improved water levels.

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

·	Increased baseload coal-fired plant availability. These generating plants’ net capacity and equivalent availability factors were approximately 76% and 84%, respectively, in 2008 compared with 75% and 82%, respectively, in 2007.

·	Reduced net MISO purchased power costs of $19 million for the six months ended June 30, 2008, due to the absence of the March 2007 FERC order that resettled costs in 2007 among market participants retroactive to 2005.

·	UE’s electric rate increase that went into effect June 4, 2007, which increased electric margin by an estimated $7 million and $16 million for the three and six months ended June 30, 2008, respectively.

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

·	A 16% and 13% increase in fuel prices for the second quarter and the first six months of 2008, respectively.
·	The Illinois electric settlement agreement, which reduced electric margin by $8 million and $19 million for the three and six months ended June 30, 2008, respectively.

Implementation of new seasonal delivery service tariffs at the Ameren Illinois Utilities, effective January 2, 2008, decreased electric margin by $19 million for the six months ended June 30, 2008. These new seasonal delivery service tariffs will impact quarterly earnings comparisons but are not expected to have any impact on annual margins.

·	Unfavorable weather conditions, as evidenced by a 26% and 29% reduction in cooling degree-days for the second

quarter and six months ended June 30, 2008, decreased electric margin by an estimated $12 million and $9 million for the three and six months ended June 30, 2008, respectively.

Ameren’s gas margin was comparable for the second quarter of 2008 and increased by $15 million, or 7%, for the six months ended June 30, 2008, compared with the same periods in 2007. The following items had a favorable impact on gas margin for the six months ended June 30, 2008, as compared to the year-ago period:

·	Favorable weather conditions, as evidenced by a 12% increase in heating degree-days, increased margin an estimated $7 million.

·	UE’s gas rate increase that went into effect April 1, 2007, increased margin by $3 million for the six months ended June 30, 2008.

Missouri Regulated

UE’s electric margin increased $99 million, or 20%, and $132 million, or 15%, for the three months and six months ended June 30, 2008, respectively, compared with the same periods in 2007. The following items had a favorable impact on electric margin for the three and six months ended June 30, 2008, as compared to the year-ago periods, unless otherwise noted:

Net mark-to-market gains on energy and fuel-related transactions of $62 million and $72 million for the three and six months ended June 30, 2008, 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 for the period 2008 through 2012.

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

·	UE’s electric rate increase that went into effect June 4, 2007, which increased electric margin by an estimated $7 million and $16 million for the three and six months ended June 30, 2008, respectively.

·	Reduced MISO purchased power costs of $13 million for the six months ended June 30, 2008 due to the absence of the March 2007 FERC order.

The following items had an unfavorable impact on electric margin for the three months and six months ended June 30, 2008, as compared to the year-ago periods:

·	A 12% and 14% increase in fuel prices for the second quarter and the first six months of 2008, respectively.

·	Other MISO purchased power costs, excluding the effect of the March 2007 FERC order, increased $8 million and $9 million for the three and six months ended June 30, 2008, respectively.

·	Unfavorable weather conditions, as evidenced by a 30% reduction in cooling degree-days, decreased electric margin by an estimated $4 million and $3 million for the three and six months ended June 30, 2008, respectively.

UE’s gas margin increased by $3 million, or 21%, and $4 million, or 10%, for the three and six months ended June 30, 2008, respectively, compared to the same periods in 2007 due to a gas rate increase that went into effect April 1, 2007, favorable weather as evidenced by an 12% increase in heating degree-days, and growth.

Illinois Regulated

Illinois Regulated’s electric margin decreased by $19 million, or 9%, and $20 million, or 5%, for the three months and six months ended June 30, 2008, respectively, compared with the same periods in 2007. Illinois Regulated’s gas margin was unchanged for the three months ended June 30, 2008, compared with the same period in 2007. Illinois Regulated’s gas margin increased by $11 million, or 6%, for the six months ended June 30, 2008, compared with the same period in 2007.

CIPS

CIPS’ electric margin decreased by $5 million, or 8%, and $11 million, or 9%, for the three months and six months ended June 30, 2008, respectively, compared with the same periods in 2007. The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	The implementation of new seasonal delivery service tariffs decreased electric margin by $6 million for the six months ended June 30, 2008. These new seasonal delivery service tariffs will impact quarterly earnings comparisons but are not expected to have any impact on annual margins.

·	The Illinois electric settlement agreement, which reduced electric margin by $1 million and $3 million for the three and six months ended June 30, 2008, respectively.

·	Unfavorable weather conditions, as evidenced by a 30% reduction in cooling degree-days, decreased electric

margin by an estimated $2 million for both the three and six months ended June 30, 2008, respectively.

The unfavorable variances for the six months ended June 30, 2008, were partially offset by reduced MISO purchased power costs of $4 million due to the absence of the March 2007 FERC order.

CIPS’ gas margin was comparable for the three months ended June 30, 2008, with the same period in 2007. CIPS’ gas margin increased by $2 million, or 5%, for the six months ended June 30, 2008, compared with the same period in 2007 primarily because of favorable weather conditions as evidenced by an 11% increase in year-to-date heating degree-days.

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 months and six months ended June 30, 2008, as compared with the same periods in 2007:

	Three Months			Six Months
CILCO (Illinois Regulated)	$	(9	)	$	(2	)
CILCO (AERG)		(3	)		(3	)
Total change in electric margin	$	(12	)	$	(5	)

CILCO’s (Illinois Regulated) electric margin decreased by $9 million, or 22%, and $2 million, or 2%, for the three and six months ended June 30, 2008, respectively.

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

·	Reductions in delivery service margins during the second quarter of 2008 due to the lack of favorable MISO resettlements experienced during the comparable period last year.

·	The implementation of new seasonal delivery service tariffs decreased electric margin by $3 million for the six months ended June 30, 2008. These new seasonal delivery service tariffs will impact quarterly earnings comparisons but are not expected to have any impact on annual margins.

·	The Illinois electric settlement agreement, which reduced electric margin by $1 million and $2 million for the three and six months ended June 30, 2008, respectively.

·	Unfavorable weather conditions, as evidenced by a 26% reduction in cooling degree-days, decreased electric margin by an estimated $1 million for both the three and six months ended June 30, 2008, respectively.

The unfavorable variances for the six months ended June 30, 2008, were partially offset by reduced MISO purchased power costs of $3 million due to the absence of the March 2007 FERC order.

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

CILCO’s (Illinois Regulated) gas margin was comparable for the three months ended June 30, 2008, to the year-ago period. CILCO’s (Illinois Regulated) gas margin increased by $5 million, or 10%, for the six months ended June 30, 2008, compared with the same period in 2007 because of favorable weather conditions as evidenced by a 10% increase in year-to-date heating degree-days and increased growth.

IP’s electric margin decreased by $5 million, or 5%, and $7 million, or 4%, for the three months and six months ended June 30, 2008, respectively, compared with the same periods in 2007. The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	The implementation of new seasonal delivery service tariffs decreased electric margin by $10 million for the six months ended June 30, 2008. These new seasonal delivery service tariffs will impact quarterly earnings comparisons but are not expected to have any impact on annual margins.

·	The Illinois electric settlement agreement, which reduced electric margin by $2 million and $4 million for the three and six months ended June 30, 2008, respectively.

·	Unfavorable weather conditions, as evidenced by a 27% and 29% reduction in cooling degree-days in the second quarter and first six months of 2008, respectively, decreased electric margin by an estimated $3 million for both the three and six months ended June 30, 2008.

The unfavorable variances for the six months ended June 30, 2008, were partially offset by reduced MISO purchased power costs of $12 million due to the absence of the March 2007 FERC order.

IP’s gas margin was comparable for the three months ended June 30, 2008, with the same period in 2007. IP’s gas margin increased by $4 million, or 5%, for the six months ended June 30, 2008, compared with the same period in 2007, primarily because of favorable weather conditions as evidenced by a 14% increase in heating degree-days.

Non-rate-regulated Generation

Non-rate-regulated Generation’s electric margin increased by $69 million, or 27%, and $91 million, or 18%, for the three and six months ended June 30, 2008, respectively, compared with the same periods in 2007.

Genco

Genco’s electric margin increased by $93 million, or 83%, and $95 million, or 38%, for the three months and six months ended June 30, 2008, respectively, compared with the same periods in 2007 due in part to lower fuel expense as a result of Genco’s June 2008 agreement with a coal mine owner to receive a lump-sum payment of $60 million for the early termination of a contract. Genco is incurring incremental fuel costs in 2008 and 2009 to replace coal from an Illinois mine that was closed prematurely at the end of 2007.

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

Net mark-to-market gains on fuel related transactions of $23 million and $28 million for the three and six months ended June 30, 2008, 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 for the period 2008 through 2012.

An increase in average sales price per megawatthour allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company. Marketing Company’s average revenue per megawatthour sold under the Genco PSA increased 9% and 3% for the three and six months ended June 30, 2008, respectively, compared with the same periods in 2007 due to re-pricing of wholesale and retail electric power supply agreements and higher spot market prices. Genco’s allocated revenues increased 11% and 8% for the three and six months ended June 30, 2008, respectively, compared with the same periods in 2007 due primarily to an increase in reimbursable expenses in accordance with the Genco PSA.

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

·	An 18% and 14% increase in fuel prices for the second quarter and the first six months of 2008, respectively.

·	Reduced MISO-related revenues of $8 million for the six months ended June 30, 2008, due to the absence of the March 2007 FERC order.

·	The Illinois electric settlement agreement, which reduced electric margin by $5 million and $9 million for the three and six months ended June 30, 2008, respectively.

CILCO (AERG)

For both the three and six months ended June 30, 2008, AERG’s electric margin declined $3 million compared with the same periods in 2007. The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	A 24% and 15% increase in coal prices for the second quarter and the six months ended June 30, 2008, respectively, due to a greater percentage of non-Powder River Basin coal burned this year. In addition, oil consumed during plant startups increased.

A 10% and an 18% decrease in average sales price per megawatthour allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company for the three and six months ended June 30, 2008, respectively, due primarily to a reduction in reimbursable expenses in accordance with the AERG PSA.

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

·	The Illinois electric settlement agreement, which reduced electric margin by $2 million and $4 million for the three and six months ended June 30, 2008, respectively.

The following items had a favorable impact on electric margin for the three and six months ended June 30, 2008, as compared to the year-ago periods:

Increased baseload coal-fired plant availability due to the lack of an extended plant outage this year. AERG’s generating plants’ average capacity and equivalent availability factors for the six months ended June 30, 2008 were 70% and 77%, respectively, in 2008 compared with 55% and 60%, respectively, in 2007.

Net mark-to-market gains on fuel-related transactions of $7 million and $8 million for the three and six months ended June 30, 2008, 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 for the period 2008 through 2012.

EEI

EEI’s electric margin increased by $14 million, or 20%, and $25 million, or 18%, for the three and six months ended June 30, 2008, respectively, compared with the same periods

in 2007. The following items had a favorable impact on electric margin for the three and six months ended June 30, 2008, as compared to the year-ago periods, unless otherwise noted:

·	A 14% increase in the average sales price for power during the six months ended June 30, 2008.

Net mark-to-market gains on fuel-related transactions of $8 million for both the three and six months ended June 30, 2008, 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 for the period 2008 through 2012.

The following items had an unfavorable impact on electric margin for the three and six months ended June 30, 2008, as compared to the year-ago periods:

·	A 10% increase in fuel prices for the second quarter and the six months ended June 30, 2008.

·	Decreased baseload coal-fired plant availability. The generating plants’ average capacity and equivalent availability factors for the three and six months ended June 30, 2008 were 86% and 87%, respectively, in 2008 compared with 90% and 91%, respectively, in 2007.

Marketing Company

An increase in market prices during the second quarter of 2008 resulted in nonaffiliated mark-to-market losses on energy transactions of $33 million and $24 million for the three and six months ended June 30, 2008, respectively.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren

Three months - Other operations and maintenance expenses increased $49 million in the second quarter of 2008 compared with the second quarter of 2007, primarily because of higher distribution system reliability expenditures of $18 million, increased plant maintenance expenditures of $14 million at coal-fired plants due to outages, higher injuries and damages expenses of $9 million, and increased information technology and labor costs. Additionally, bad debt expense increased $6 million, primarily at the Ameren Illinois Utilities, because of increased rates in Illinois. Reducing the effect of these unfavorable items was the absence of a Callaway refueling and maintenance outage this spring. Maintenance and labor costs associated with the refueling and maintenance outage in the second quarter of 2007 were $35 million. Additionally, an accounting order issued by the MoPSC in April 2008, resulted in UE reversing previously- recorded expenses of $13 million, related to 2007 storms, as a regulatory asset.

Six months - Other operations and maintenance expenses increased $82 million in the first six months of 2008 compared with the first six months of 2007, primarily because of higher distribution system reliability expenditures of $28 million, increased plant maintenance expenditures of $22 million at coal-fired plants due to outages, higher injuries and damages expenses of $10 million, and increased information technology and labor costs. Bad debt expense also increased $10 million, primarily at the Ameren Illinois Utilities, as discussed above. Additionally, in the first quarter of 2007, a $15 million accrual established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan was reversed due to the termination of the plan, with no similar item in 2008. This plan was replaced with the Illinois electric settlement agreement in August 2007. Reducing the unfavorable effect of these items was the decreased impact of ice storms in the first quarter of 2008, as compared with the same period in 2007. In January 2007, UE and CIPS experienced a severe ice storm in their service territories resulting in system repair expenditures of $28 million, as compared with $10 million in expenditures for minor storms in the first quarter of 2008, primarily in CIPS’ service territory. Additionally, the absence of a Callaway refueling and maintenance outage in the first six months of the current year and the effect of the MoPSC storm accounting order received in the second quarter of 2008, as discussed above, resulted in decreased operations and maintenance expenses compared to the prior-year period.

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

Missouri Regulated

Three and six months - UE’s other operations and maintenance expenses increased $16 million and $9 million in the second quarter and first six months of 2008, respectively, as compared with the same periods in 2007, primarily because of increased distribution system reliability expenditures, higher labor and employee benefit costs, and increased plant maintenance expenditures at coal-fired plants and higher injuries and damages expenses. Partially offsetting these items were the absence of a Callaway refueling and maintenance outage this spring and the effect of the MoPSC storm accounting order, as discussed above. Decreased storm repair expenditures of $4 million in 2008, as compared with $25 million in 2007, additionally impacted the year-to-date periods.

Illinois Regulated

Other operations and maintenance expenses increased $30 million and $52 million in the Illinois Regulated segment in the three months and six months ended June 30, 2008, compared with the same periods in 2007.

CIPS

Three months - Other operations and maintenance expenses increased $7 million in the second quarter of 2008 compared with the same period in 2007 primarily because of higher distribution system reliability expenditures.

Six months - Other operations and maintenance expenses increased $14 million in the first six months of 2008 compared with the same period in 2007. The increase was partially because of the reversal in the first quarter of 2007 of an accrual of $4 million established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan, with no similar item in 2008. Additionally, storm repair expenditures in the first six months of 2008 exceeded the cost of storm repairs in the first six months of 2007 by $2 million and other distribution system reliability expenditures exceeded those in the prior-year period.

CILCO (Illinois Regulated)

Three and six months - Other operations and maintenance expenses increased $4 million and $6 million in the second quarter and first six months of 2008, respectively, as compared with the same periods in 2007, primarily because of higher distribution system reliability expenditures. Additionally, in the first quarter of 2007, CILCO (Illinois Regulated) reversed a $3 million accrual established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions, with no similar item in the first quarter of 2008, resulting in increased other operations and maintenance expenses in the first six months of 2008 compared with the same period in 2007.

Three and six months - Other operations and maintenance expenses increased $19 million and $31 million in the second quarter and first six months of 2008, respectively, as compared with the same periods in 2007, primarily because of higher distribution system reliability expenditures and increased bad debt expense. Additionally, in the first quarter of 2007, IP reversed an $8 million accrual established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions, with no similar item in the first quarter of 2008, resulting in increased other operations and maintenance expenses in the first six months of 2008 compared with the same period in 2007.

Non-rate-regulated Generation

Other operations and maintenance expenses were comparable in the second quarter of 2008 with the second quarter of 2007 in the Non-rate-regulated Generation segment. Other operations and maintenance expenses increased $11 million in the six months ended June 30, 2008, compared with the same period in 2007.

Genco

Three and six months - Other operations and maintenance expenses increased $4 million and $10 million at Genco in the second quarter and first six months of 2008, respectively, as compared with the same periods in 2007, primarily because of higher plant maintenance costs due to scheduled outages.

CILCO (AERG)

Three and six months - Other operations and maintenance expenses were comparable in the second quarter of 2008 with the second quarter of 2007 at CILCO (AERG). Other operations and maintenance expenses increased $4 million in the six months ended June 30, 2008, compared with the same period in 2007, primarily because of higher plant maintenance costs due to scheduled outages.

CILCORP (Parent Company Only)

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

EEI

Three and six months - Other operations and maintenance expenses decreased $3 million in both the second quarter and first six months of 2008, as compared with the same periods in 2007, primarily because of reduced plant maintenance costs.

Depreciation and Amortization

Ameren

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

Six months - Ameren’s depreciation and amortization expenses decreased $5 million in the six months ended June 30, 2008, compared with the same period in 2007, primarily because of changes in the useful lives of UE’s plants as discussed below. Increased capital additions over the past year reduced the benefit of this item.

Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and six months ended June 30, 2008, compared with the same periods in 2007 were as follows:

Missouri Regulated

Three and six months - Depreciation and amortization expenses decreased $2 million and $8 million in the three months and six months ended June 30, 2008, respectively, compared with the same periods in 2007, primarily because of the extension of UE’s nuclear and coal-fired plants’ useful lives for purposes of calculating depreciation expense in conjunction with a MoPSC electric rate order effective June 2007. Reducing the benefit of this item was an increase in capital additions over the past year.

Illinois Regulated

Depreciation and amortization expenses increased $3 million in both the three months and six months ended June 30, 2008, compared with the same periods in 2007 in the Illinois Regulated segment, primarily because of capital additions at CIPS, CILCO (Illinois Regulated) and IP.

Non-rate-regulated Generation

Depreciation and amortization expenses were comparable in the second quarter and first six months of 2008 with the same periods in 2007 in the Non-rate-regulated Generation segment and for CILCORP (Parent Company Only) and EEI. Depreciation and amortization expenses decreased $2 million and $4 million at Genco in the second quarter and first six months of 2008, respectively, compared with the same periods in 2007 as a result of a depreciation study completed in September 2007. Depreciation and amortization expenses increased $2 million and $4 million at CILCO (AERG) in the second quarter and first six months of 2008, respectively, compared with the same periods in 2007 because of capital additions over the past year.

Taxes Other Than Income Taxes

Ameren

Three and six months – Ameren’s taxes other than income taxes decreased $7 million in the second quarter of 2008 compared with the second quarter of 2007 primarily because of invested capital electricity distribution tax credits related to payments made in a previous year in the Illinois Regulated segment. Ameren’s taxes other than income taxes increased $4 million in the first six months of 2008 compared with the same period in 2007 primarily because of higher gross receipts taxes, partially reduced by the invested capital electricity distribution tax credits noted above.

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

Missouri Regulated

Three and six months - Taxes other than income taxes were comparable in the second quarter of 2008 with the second quarter of 2007. Taxes other than income taxes increased $3 million in the first six months of 2008 compared with the same period in 2007, primarily because of higher gross receipts taxes.

Illinois Regulated

Taxes other than income taxes decreased $6 million in the second quarter of 2008 compared with the second quarter of 2007 in the Illinois Regulated segment, primarily because of invested capital electricity distribution tax credits as discussed above. Taxes other than income taxes were comparable in the first six months of 2008 with the same period in 2007 at Illinois Regulated, CIPS and IP. The favorable impact of the invested capital electricity distribution tax credits at IP was offset by higher excise taxes in the six-month period. Taxes other than income taxes were comparable in both current-year periods with the same prior-year periods at CILCO (Illinois Regulated).

Non-rate-regulated Generation

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

Other Income and Expenses

Ameren

Three and six months - Miscellaneous income was comparable in the second quarter of 2008 with the second quarter of 2007. Miscellaneous income increased $8 million in the first six months of 2008 compared with the same period in 2007, primarily because of an increase in allowance for funds used during construction at UE. Miscellaneous expense was comparable between periods.

Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the

Ameren Companies for the three months and six months ended June 30, 2008, compared with the same periods in 2007 were as follows:

Missouri Regulated

Three and six months - Miscellaneous income increased $3 million and $9 million in the three months and six months ended June 30, 2008, respectively, compared with the same periods in 2007, primarily because of an increase in allowance for funds used during construction and increased interest income. The increase in allowance for funds used during construction resulted from higher rates and increased construction-in-progress balances. Miscellaneous expense decreased $4 million in both the second quarter and first six months of 2008, as compared with the same periods in 2007, primarily because of expenses recorded in the prior year related to UE’s electric rate case.

Illinois Regulated

Other income and expenses decreased in the second quarter and first six months of 2008 in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated) and IP, as compared with the same periods in 2007, primarily because of increased miscellaneous expense resulting from contributions made for energy efficiency and customer assistance programs as part of the Illinois electric settlement agreement.

Non-rate-regulated Generation

Miscellaneous income increased $3 million and $5 million in the Non-rate-regulated Generation segment and $2 million and $4 million at Genco in the three months and six months ended June 30, 2008, respectively, compared with the same periods in 2007, primarily because of gas sales at Genco. Miscellaneous expense was comparable between periods.

Other income and expenses were comparable in the three months and six months ended June 30, 2008, with the same periods in 2007, at CILCORP (Parent Company Only), CILCO (AERG) and EEI.

Interest

Ameren

Three and six months - Interest expense increased $10 million and $12 million in the three months and six months ended June 30, 2008, respectively, compared with the same periods in 2007. Long-term debt issuances, net of maturities and redemptions, and the cost of refinancing auction-rate environmental improvement and pollution control revenue refunding bonds resulted in increased interest expense in the 2008 periods - see Insured Auction-Rate Tax-exempt Bonds under Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk of this report for additional information. These increases were mitigated in the six-month period by the reversal of $12 million of interest reserves for uncertain tax positions resulting from a federal tax settlement in the first quarter of 2008.

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

Missouri Regulated

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

Six months - Interest expense decreased $6 million primarily because of the reversal of $8 million of interest reserves resulting from the federal tax settlement noted above. Reducing the benefit of these items was increased interest expense resulting from the issuance of $250 million senior secured notes and $450 million senior secured notes in April 2008 and June 2007, respectively. Additionally, the cost of refinancing auction-rate environmental improvement revenue refunding bonds resulted in higher interest expense.

Illinois Regulated

Interest expense increased $4 million and $10 million in the Illinois Regulated segment and $6 million and $14 million at IP in the second quarter and first six months of 2008, respectively, as compared with the same periods in the prior year. The increases were primarily because of the issuance of $250 million of senior secured notes at IP in November 2007, and the cost of refinancing auction-rate pollution control revenue refunding bonds, including the issuance of $337 million of senior secured notes in April 2008.

Interest expense decreased $2 million at CIPS in the second quarter of 2008 compared with the second quarter of 2007, primarily because of reduced short-term borrowings. Interest expense decreased $3 million at CIPS in the first six months of 2008, as compared with the same period in 2007, primarily because of the reversal of $2 million of interest reserves resulting from the federal tax settlement noted above. Interest expense at CILCO (Illinois Regulated) was comparable between periods.

Non-rate-regulated Generation

Three months - Interest expense was comparable between periods in the Non-rate-regulated Generation segment. Interest expense increased $3 million at Genco primarily because of the issuance of $300 million of senior unsecured notes in April 2008.

Six months - Interest expense decreased $3 million in the Non-rate-regulated Generation segment and $2 million at Genco primarily because of the reversal of $2 million of interest reserves resulting from the federal tax settlement noted above. Reduced intercompany borrowings offset increased interest expense resulting from the issuance of the senior unsecured notes as discussed above.

Interest expense was comparable in the three months and six months ended June 30, 2008, with the same periods in 2007 at CILCORP (Parent Company Only), CILCO (AERG) and EEI.

Income Taxes

Ameren

Three and six months - Ameren’s effective tax rate increased in both the second quarter and first six months of 2008, as compared with the same periods in the prior year, due to variations discussed below at the Ameren Companies.

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

Missouri Regulated

Three and six months - The effective tax rate increased in both the second quarter and first six months of 2008, as compared with the same periods in the prior year, primarily because of lower favorable net amortization of property-related regulatory assets and liabilities, along with decreased production activity deductions, in the 2008 periods compared with the year-ago periods.

Illinois Regulated

The effective tax rate increased in the second quarter of 2008 compared with the same period in 2007, but decreased in the six months ended June 30, 2008 compared with the same period in 2007 in the Illinois Regulated segment because of items detailed below.

CIPS

Three months – The effective tax rate decreased in the second quarter of 2008 compared with the same period in 2007, primarily because of the impact on a current-year pretax book loss of the amortization of investment tax credit, net amortization of property-related regulatory assets and liabilities, and permanent items compared with the impact on pretax book income in the second quarter of 2007.

Six months – The effective tax rate decreased in the first six months of 2008 compared with the same period in 2007, primarily because of lower pretax book income in the current-year period as compared with the same period last year.

CILCO (Illinois Regulated)

Three months – The effective tax rate increased in the second quarter of 2008 compared with the same period in 2007, primarily because of the impact of permanent items, net amortization of property-related regulatory assets and liabilities, and amortization of investment tax credit on a pretax book loss in the second quarter of 2008 as compared with pretax book income in the second quarter of 2007.

Six months – The effective tax rate increased in the first six months of 2008 compared with the same period in 2007, primarily because of lower estimated tax credits and lower favorable net amortization of property-related regulatory asset and liabilities in the current-year period compared to the same period in 2007.

Three months – The effective tax rate was comparable between periods.

Six months – The effective tax rate increased in the first six months of 2008 compared with the same period in 2007, primarily because of lower estimated tax credits and increased expenses related to lobbying activities.

Non-rate-regulated Generation

The effective tax rate decreased in the second quarter of 2008 in the Non-rate-regulated Generation segment, as compared with the second quarter of 2007, because of items detailed below. The effective tax rate was comparable between the six months ended June 30, 2008, and the same period in 2007.

Genco

Three and six months – The effective tax rate decreased in both the second quarter and first six months of 2008, as compared with the same periods in the prior year, primarily

because of changes to the reserve for uncertain tax positions, partially offset by the decreased impact of production activity deductions and investment tax credit amortization on higher pretax book income in the 2008 periods compared with the same periods in 2007.

CILCO (AERG)

Three months – The effective tax rate decreased in the second quarter of 2008 compared with the same period in 2007, primarily because of changes to the reserve for uncertain tax positions, along with the increased impact of production activity deductions on lower pretax book income in the second quarter of 2008 compared with the same period in 2007.

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

CILCORP (Parent Company only)

Three and six months – The effective tax rate decreased in both the second quarter and first six months of 2008 compared with the same year-ago periods, primarily due to the effect of permanent items on lower consolidated pretax book income in the current year periods as compared to the same periods in 2007.

EEI

Three months – The effective tax rate was comparable between periods.

Six months – The effective tax rate increased in the first six months of 2008 compared with the same period in 2007, due to the lower impact of production activity deductions on higher pretax book income in the 2008 period as compared with the same period in 2007.

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, and financial contracts that were part of the Illinois electric settlement agreement. Marketing Company is also selling power through other primarily market-based contracts with wholesale and retail customers. In addition to cash flows from operating activities, the Ameren Companies use available cash, credit facilities, money pool or other short-term borrowings from affiliates or commercial paper to support normal operations and other temporary capital requirements. The use of operating cash flows and short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at June 30, 2008, for Ameren, CILCORP, CILCO, and IP. 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 will incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Expenditures not funded with operating cash flows are expected to be funded primarily with debt. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a discussion of the Illinois electric settlement agreement, which among other things, will change the process for power procurement in Illinois in the future and will affect future cash flows of the Ameren Companies, except UE. The settlement resulted in customer refunds and credits during the first six months of 2008, and it will result in further credits to customers through 2010. The Ameren Illinois Utilities will receive reimbursement for most of these refunds and credits from Illinois power generators, including Genco and AERG.

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

	Net Cash Provided By Operating Activities							Net Cash Used In Investing Activities									Net Cash Provided By (Used In) Financing Activities
	2008		2007		Variance			2008			2007			Variance			2008			2007			Variance
Ameren (a)	$	495	$	543	$	(48	)	$	(935	)	$	(754	)	$	(181	)	$	290		$	761		$	(471	)
UE		115		145		(30	)		(509	)		(381	)		(128	)		209			444			(235	)
CIPS		109		44		65			(2	)		(1	)		(1	)		(133	)		99			(232	)
Genco		92		115		(23	)		(118	)		(81	)		(37	)		26			(34	)		60
CILCORP		128		62		66			(141	)		(85	)		(56	)		26			127			(101	)
CILCO		139		89		50			(139	)		(85	)		(54	)		13			88			(75	)
IP		179		73		106			(79	)		(93	)		14			(73	)		163			(236	)

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

Cash Flows from Operating Activities

Ameren’s cash from operating activities decreased in the first six months of 2008, as compared with the first six months of 2007 because of several factors. Payments, net of insurance recoveries, related to the December 2005 Taum Sauk incident were $91 million higher in the first six months of 2008 compared with the first six months of 2007. Other factors that reduced cash flows from operations included increased past-due accounts receivable, increased under-recovery of the PGA, increased collateral postings, and a smaller reduction in gas inventories during the first six months of 2008 compared to the same period in the prior year. Gas inventory quantities were comparable, but prices were higher in the first six months of 2008 compared with the same period in 2007. Benefiting cash flows from operations in the first six months of 2008 compared to the prior-year period was a decrease in income taxes paid, net of refunds. Cash flow from operations was also positively affected in the first six months of 2008 by the Illinois electric settlement agreement, as reimbursements from generators exceeded credits provided to customers by $19 million, and by a decrease in MISO receivables.

At UE, cash from operating activities decreased in the first six months of 2008, compared with the first six months of 2007. The decrease was primarily caused by decreases in accounts payable to Ameren Services and MISO compared to the prior year, a $91 million increase in payments, net of insurance recoveries, related to the December 2005 Taum Sauk incident, and increased income tax payments. Positive effects on operating cash flows included an increase in electric margins and lack of a Callaway nuclear plant refueling and maintenance outage in the current-year period, as discussed in Results of Operations, and a decrease in receivables. The receivable fluctuations were principally caused by changes in MISO and affiliate receivables.

At CIPS, cash from operating activities increased in the first six months of 2008, compared with the first six months of 2007, primarily because of a $16 million decrease in income tax payments (net of refunds) and changes in working capital that occurred in the ordinary course of business. In addition, favorable net changes in collateral postings and the Illinois electric settlement agreement had a positive effect on cash from operations in the first six months of 2008. Generator reimbursements under the Illinois electric settlement agreement exceeded credits provided to customers by $7 million. Working capital changes that benefited cash from operations included favorable changes in affiliate accounts payable and in MISO payables compared to the prior year. The Illinois rate redesign reduced cash flows and net income in the first six months of 2008. Partially offsetting these increases in cash from operations were increased past-due accounts receivable, a decrease in electric margins and an increase in other operations and maintenance expenses.

Genco’s cash from operating activities decreased in the first six months of 2008 compared to the 2007 period, primarily because of working capital changes in the ordinary course of business and an increase in cash paid for fuel inventory. Partially offsetting these decreases in cash from operations was a decrease in income tax payments (net of refunds).

Cash from operating activities increased for CILCORP and CILCO in the six months ended June 30, 2008, compared with the same period in 2007. The Illinois electric settlement agreement had a positive effect on cash from operations in the first six months of 2008 as generator reimbursements exceeded credits provided to customers by $4 million. Other increases in cash flow from operations were primarily due to fluctuations in working capital in the normal course of business, including decreases in affiliate accounts receivable and increases in accounts payable. Partially offsetting these increases in cash from operations were the Illinois rate redesign, which reduced cash flows and net income in the first six months of 2008, and an increase in under-recovery of the PGA.

IP’s cash from operating activities increased in the six months ended June 30, 2008, compared with the same period in 2007, primarily due to working capital changes in the ordinary course of business, including a reduction in affiliate receivables and an increase in affiliate and MISO payables. In addition, net changes in collateral postings were favorable, storm costs were lower in the current period compared to the same period last year, and the Illinois electric settlement agreement had a positive effect on cash from operations in the first six months of 2008 as generator reimbursements exceeded credits provided to customers by $8 million. Partially offsetting the aforementioned increases in cash from operations were increased past-due accounts receivable, increased under-recovery of the PGA and a smaller reduction in gas inventories in the current year than in the prior year. Gas inventory quantities were comparable, but prices were higher in the first six months of 2008 compared with the same period in 2007. In addition, the Illinois rate redesign reduced cash flows and net income in the first six months of 2008.

Cash Flows from Investing Activities

Ameren used more cash for investing activities in the first six months of 2008 than in the first six months of 2007. Net cash used for capital expenditures increased in 2008 as a result of power plant scrubber projects and upgrades at various power plants. Additionally, increased purchases and higher prices resulted in a $99 million increase in nuclear fuel expenditures.

UE’s cash used in investing activities increased during the six months ended June 30, 2008, compared to the same period in 2007, principally because of a $99 million increase in nuclear fuel expenditures resulting from increased purchases for future refueling outages and higher prices. Capital expenditures increased $22 million. This increase was a result

of increased spending related to a power plant scrubber project, reliability improvements of the transmission and distribution system, and various plant upgrades.

CIPS’ cash used in investing activities during the first six months of 2008 was comparable to the same period in 2007. During both periods, cash used for capital expenditures, primarily for reliability improvements of the transmission and distribution system, was offset by similar amounts of proceeds received from an intercompany note.

Genco’s cash used in investing activities increased in the first six months of 2008 compared with the same period in 2007. Capital expenditures increased $40 million, principally due to a power plant scrubber project. This increase was slightly offset by a $3 million decrease in emission allowance purchases.

CILCORP’s and CILCO’s cash used in investing activities increased in the six months ended June 30, 2008, compared with the same period in 2007. Cash used in investing activities increased as a result of a $13 million increase in capital expenditures, primarily due to a power plant scrubber project and plant upgrades at AERG. The receipt of a $42 million net repayment of prior-year money pool advances reduced cash flows used in investing activities in the 2008 period compared to 2007.

IP’s cash used in investing activities decreased in the first six months of 2008 compared to the same period in 2007. Capital expenditures decreased by $19 million in the first six months of 2008 from the year-ago period primarily because of a reduction in storm-related capital expenditures. Net money pool advances increased by $5 million in the first six months of 2008 compared with the prior-year period.

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

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

Cash Flows from Financing Activities

During the six months ended June 30, 2008, Ameren issued $1,335 million of senior debt. The proceeds were used to repurchase, redeem, and fund $808 million of long-term debt, reduce short-term borrowings, and fund capital expenditures and other working capital needs at UE, CIPS, Genco, CILCO, and IP. The refinancing activity that occurred during the first six months of 2008 resulted in a decrease in cash provided by financing activities compared with the year-ago period. The first six months of 2007 included net borrowings of

$1,007 million of short-term debt that were used to fund maturities of long-term debt, fund working capital needs at Ameren subsidiaries and build liquidity during a period of legislative uncertainty. Also benefiting the six months ended June 30, 2008, compared with the year-ago period was a $27 million increase in proceeds from the issuance of common stock resulting from increased sales through Ameren’s 401(k) plan and DRPlus.

UE’s net cash provided by financing activities decreased in the first six months of 2008, compared with the same period of the prior year. 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 that had adjusted to higher rates as a result of the collapse of the auction-rate securities market, and fund the current maturity of UE’s 6.75% first mortgage bonds. Comparably, during the six months ended June 30, 2007, UE issued $425 million in senior secured notes and received $192 million net proceeds from short-term borrowings to fund working capital requirements. A net increase in borrowings under an intercompany borrowing arrangement with Ameren also benefited the six months ended June 30, 2008, compared with the year-ago period.

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

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

CILCORP’s and CILCO’s cash provided by financing activities decreased during the six months ended June 30, 2008 compared to the 2007 period.

This decrease is primarily the result of CILCORP’s and CILCO’s reduced short-term borrowings during the six months ended June 30, 2008, compared with the 2007 period. Partially offsetting this were reduced redemptions and maturities of long-term debt in 2008. During the 2008 period, $19 million of auction-rate environmental improvement revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market were redeemed at CILCORP and CILCO, compared with the maturity of $50 million of CILCO’s 7.50% bonds during the 2007 period. Also benefiting the six months ended June 30, 2008, were net borrowings of a $13 million direct loan from Ameren at CILCORP compared with $73 million net repayments during the 2007 period. Net money pool borrowings totaled $2 million for CILCORP and CILCO in the first six months of 2007; there were no net borrowings in the first six months of 2008. A $14 million capital contribution received by CILCO in the second quarter of 2007 from CILCORP resulted in a positive impact on cash flows at CILCO.

IP had a net use of cash from financing activities in the first six months of 2008, compared with a net source of cash for the same period in 2007. During the first six months of 2008, IP issued $337 million of senior secured notes and used the proceeds to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market. Additionally, during the 2008 period, IP funded $30 million of dividends. Comparatively, in the first six months of 2007, IP paid no dividends and had $250 million of net borrowings under the 2007 credit facility. These borrowings were used to repay $43 million of outstanding money pool borrowings, fund $43 million of long-term debt maturities and build liquidity during a period of legislative uncertainty.

Short-term Borrowings and Liquidity

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

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

Credit Facility	Expiration	Amount Committed	Amount Available
Ameren, UE and Genco:
Multiyear revolving(a)	July 2010	1,150	708(e)
CIPS, CILCORP, CILCO, IP and AERG:
2007 Multiyear revolving(b)(c)	January 2010	500	100
2006 Multiyear revolving(b)(d)	January 2010	500	150

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

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

(c)

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

(d)

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

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

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

A further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents. At June 30, 2008, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP had $205 million, less than $1 million, less than $1 million, $2 million, $19 million, $19 million, and $33 million, respectively, of cash and cash equivalents.

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

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

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

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

Long-term Debt and Equity

The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt (net of any issuance discounts and including any redemption premiums) for the six months ended June 30, 2008 and 2007, for the Ameren Companies. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 4 – Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.

	Month Issued, Redeemed,	Six Months
	Repurchased or Matured	2008		2007
Issuances
Long-term debt
UE:
6.00% Senior secured notes due 2018	April	$	250	$	-
6.40% Senior secured notes due 2017	June		-		425
6.70% Senior secured notes due 2019	June		449		-
Genco:
7.00% Senior unsecured notes due 2018	April		300		-
IP:
6.25% Senior secured notes due 2018	April		336		-
Total Ameren long-term debt issuances		$	1,335	$	425
Common stock
Ameren:
DRPlus and 401(k)	Various	$	75	$	48
Total common stock issuances		$	75	$	48
Total Ameren long-term debt and common stock issuances		$	1,410	$	473
Redemptions, Repurchases and Maturities
Long-term debt
Ameren:
2002 5.70% notes due 2007	February	$	-	$	100
Senior notes due 2007	May		-		250
UE:
2000 Series B environmental improvement bonds due 2035	April		63		-
2000 Series A environmental improvement bonds due 2035	May		64		-
2000 Series C environmental improvement bonds due 2035	May		60		-
1991 Series environmental improvement bonds due 2020	May		43		-
6.75% Series first mortgage bonds due 2008	May		148		-
CIPS:
2004 Series pollution control bonds due 2025	April		35		-
CILCO:
7.50% First mortgage bonds due 2007	January		-		50
Series 2004 pollution control bonds due 2039	April		19		-
IP:
Series 2001 Non-AMT bonds due 2028	May		112		-
Series 2001 AMT bonds due 2017	May		75		-
1997 Series A pollution control bonds due 2032	May		70		-
1997 Series B pollution control bonds due 2032	May		45		-
1997 Series C pollution control bonds due 2032	June		35		-
Note payable to IP SPT:
5.65% Series due 2008	Various		39		43
Total Ameren long-term debt redemptions, repurchases and maturities		$	808	$	443

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

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

(a)

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

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

Ameren is also currently selling newly issued shares of its common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan (including a subsidiary plan that is now merged into the Ameren 401(k) plan), Ameren issued a total of 0.7 million new shares of common stock valued at $29 million and 1.7 million new shares valued at $75 million in the three months and six months ended June 30, 2008, respectively.

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

Indebtedness Provisions and Other Covenants

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

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

We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets or make our access to the capital markets uncertain or limited. Such events would increase our cost of capital and adversely affect our ability to access the capital markets.

Dividends

Ameren paid to its shareholders common stock dividends totaling $266 million, or $1.27 per share, during the first six months of 2008 (2007 - $263 million or $1.27 per share).

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

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

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

	Six Months
	2008		2007
UE	$	105	$	127
Genco		84		113
IP		30		-
Nonregistrants		47		23
Dividends paid by Ameren	$	266	$	263

Contractual Obligations

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

Subsequent to December 31, 2007, obligations related to the procurement of nuclear fuel, coal and heavy forgings materially changed at Ameren, UE, Genco, CILCORP and CILCO to $1,554 million, $1,273 million, $140 million, $55 million and $55 million, respectively. Total other obligations, including the amount of unrecognized tax benefits, at June 30, 2008, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $6,120 million, $1,946 million, $470 million, $245 million, $1,458 million, $1,458 million and $1,766 million, respectively.

As a result of the Illinois electric settlement agreement reached in July 2007 and reflected in legislation enacted on August 28, 2007, 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, 2008, of $11 million, $1 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, 2008, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $19 million, $7 million, $3 million and $9 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	Baa2	BBB-	BBB+
Senior unsecured debt	Baa2	BB+	BBB+
Commercial paper	P-2	A-3	F2
UE:
Issuer/corporate credit rating	Baa2	BBB-	A-
Secured debt	Baa1	BBB	A+
Commercial paper	P-2	A-3	F2
CIPS:
Issuer/corporate credit rating	Ba1	BB	BB+
Secured debt	Baa3	BBB	BBB
Senior unsecured debt	Ba1	BBB-	BBB-
Genco:
Issuer/corporate credit rating	-	BBB-	BBB+
Senior unsecured debt	Baa2	BBB-	BBB+
CILCORP:
Issuer/corporate credit rating	-	BB	BB+
Senior unsecured debt	Ba2	BB	BB+
CILCO:
Issuer/corporate credit rating	Ba1	BB	BB+
Secured debt	Baa2	BBB	BBB
IP:
Issuer/corporate credit rating	Ba1	BB	BB+
Secured debt	Baa3	BBB-	BBB

On February 12, 2008, Moody’s affirmed the ratings of Ameren and Genco but changed their rating outlook to negative from stable. Moody’s placed the long-term credit ratings of UE under review for possible downgrade and affirmed UE’s commercial paper rating. In addition, Moody’s affirmed the ratings of CIPS, CILCORP, CILCO and IP and maintained a positive rating outlook on these four companies. According to Moody’s, the review of UE’s ratings was prompted by declining cash flow coverage metrics, increased operating costs, higher capital expenditures for environmental compliance and transmission and distribution system investment, and significant regulatory lag in the recovery of these costs. Moody’s stated that the negative outlook on the credit rating of Genco reflected Genco’s “position as a predominantly coal generating company that is likely to be seriously affected by more stringent environmental regulations, including a potential cap or tax on carbon emissions.” The negative outlook on the ratings of Ameren reflects the factors that impacted its subsidiaries, UE and Genco, according to Moody’s.

On May 21, 2008, Moody's lowered the credit ratings of UE to Baa1 for its senior secured debt and to Baa2 for its unsecured debt and issuer credit and indicated a stable

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

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

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made with external parties at June 30, 2008, were $110 million, $10 million, $5 million, $14 million, $14 million, and $7 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively, resulting from our reduced issuer and senior unsecured debt ratings. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at June 30, 2008, could have resulted in Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to $227 million, $22 million, $34 million, $17 million, $43 million, $43 million, and $58 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization. See Quantitative and Qualitative Disclosures about Market Risk – Interest Rate Risk under Part I, Item 3, for information on credit rating changes with respect to insured tax-exempt auction-rate bonds.

OUTLOOK

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

Revenues

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

The Ameren Illinois Utilities filed delivery service rate cases with the ICC in November 2007 due to inadequate recovery of costs and low returns on equity of less than 5% experienced in 2007 and less than 4% expected in 2008. The ICC staff recommended in their rebuttal testimony filed in May 2008 a net increase in revenues for electric delivery service for the Ameren Illinois Utilities of $76 million in the aggregate (CIPS - $9 million increase, CILCO - $11 million decrease, and IP - $78 million increase) and a net increase in revenues for natural gas delivery service of $11 million in the aggregate (CIPS - $3 million increase, CILCO - $15 million decrease, and IP - $23 million increase). Other parties also made recommendations through rebuttal testimony in the rate cases. The Ameren Illinois Utilities revised their revenue requests for electric and natural gas delivery services to accept certain positions proposed by the ICC staff and intervenors, including the ICC staff’s recommended return on equity of 10.7%. In a brief filed with the ICC in July 2008, CIPS, CILCO and IP revised their requests to an increase in annual revenues for electric delivery service of $156 million in the aggregate (CIPS - $26 million increase, CILCO - $3 million increase, and IP - $127 million increase) and a net increase in annual revenues for natural gas delivery service of $51 million in the aggregate (CIPS - $10 million increase, CILCO -

$7 million decrease, and IP - $48 million increase). The Ameren Illinois Utilities’ electric and natural gas rate change requests were based on a capital structure composed of 50% to 53% equity, an aggregate rate base for the Ameren Illinois Utilities of $2 billion and $0.9 billion for electric and natural gas, respectively, and a test year ended December 31, 2006, with certain prospective updates. The ICC has until the end of September 2008 to render a decision in these rate cases.

·	UE filed an electric rate case with the MoPSC in April 2008 in order to recover rising costs and to earn a reasonable return on its investments. UE’s return on equity was 9% in 2007 and is expected to decrease to

7% in 2008. UE requested to increase its annual electric revenues by $251 million. The electric rate increase is based on a 10.9% return on equity, a capital structure composed of 51% common equity, a rate base of $5.9 billion and a test year ended March 31, 2008, with updates for known and measurable changes through September 30, 2008. The MoPSC has until March 2009 to render a decision in this rate case.

In current and future rate cases, UE, CIPS, CILCO and IP will also seek cost recovery mechanisms from their state regulators to reduce regulatory lag. In their pending electric and natural gas delivery service rate cases, the Ameren Illinois Utilities are requesting ICC approval to implement rate adjustment mechanisms for electric infrastructure investments and the decoupling of natural gas revenues from sales volumes. The ICC staff in their direct testimony filed in March 2008 opposed the Ameren Illinois Utilities’ requests to implement a rate adjustment mechanism for electric infrastructure investments. The ICC staff offered limited support for the Ameren Illinois Utilities’ request to implement a rate adjustment mechanism for the decoupling of natural gas revenues from sales volumes. In its pending electric rate case, UE is requesting the MoPSC to approve implementation of a fuel and purchased power cost recovery mechanism.

Average residential electric rates for CIPS, CILCO and IP increased significantly following the expiration of a rate freeze at the end of 2006. Electric rates rose because of the increased cost of power purchased on behalf of the Ameren Illinois Utilities’ customers and an increase in electric delivery service rates. Due to the magnitude of these increases, the Illinois electric settlement agreement reached in 2007 provides approximately $1 billion over a four-year period that began in 2007 to fund rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Funding for the settlement is coming from electric generators in Illinois and certain Illinois electric utilities. Pursuant to the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to fund an aggregate of $150 million, of which the following contributions remain to be made as of June 30, 2008:

	Ameren	CIPS	CILCO (Illinois Regulated)	IP	Genco	CILCO (AERG)
2008(a)	$ 21.6	$ 3.3	$ 1.5	$ 4.5	$ 8.5	$ 3.8
2009(a)	25.2	3.5	1.8	4.7	10.5	4.7
2010(a)	2.0	0.3	0.1	0.4	0.8	0.4
Total	$ 48.8	$ 7.1	$ 3.4	$ 9.6	$ 19.8	$ 8.9

(a) Estimated.

To fund these contributions, the Ameren Illinois Utilities, Genco and AERG may need to increase their respective borrowings.

·	As part of the Illinois electric settlement agreement, the reverse auction used for power procurement in Illinois was discontinued. It will be replaced with a new power procurement process to be led by the IPA, beginning in 2009. The impact of the new procurement process in Illinois is uncertain.

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

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

The availability and performance of UE’s, Genco’s, AERG’s and EEI’s electric generation fleet can materially impact their revenues. Genco and AERG are seeking to raise the equivalent availability and capacity factors of their power plants over the long-term through greater investments and a process improvement program. The Non-rate-regulated Generation segment expects to generate 32 million megawatthours of baseload power in 2008 (Genco – 17 million, AERG – 7 million, EEI – 8 million), 31 million megawatthours in 2009 (Genco – 16 million, AERG - 7 million, EEI - 8 million) and 33 million megawatthours in 2010 (Genco - 18 million, AERG - 7 million, EEI - 8 million).

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

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

As of June 30, 2008, Ameren sold approximately 95% of its expected 2008 system-wide generation; approximately 5 million megawatthours of Ameren's system-wide expected generation for the remainder of 2008 remained unhedged. As of June 30, 2008, Marketing Company sold approximately 80% of Non-rate-regulated Generation's expected 2009 generation; approximately 6 million megawatthours of Non-rate-regulated Generation's expected generation for 2009 remained unhedged.

Since July 1, 2008, power prices have fallen sharply. Several factors appeared to be driving this volatility, including the recent court decision that vacated the Clean Air Interstate Rule, falling natural gas and crude prices and the economy, among other things. Deep declines in power prices, should they persist, can have meaningful impacts on Ameren, UE, Genco and AERG's financial results for 2008 and beyond. We cannot predict future power prices with certainty as market conditions are unpredictable. We believe that power prices will see modest increases from current levels during the remainder of the summer cooling and tropical storm seasons and over the next few years.

The future development of ancillary services and capacity markets in MISO could increase the electric margins of UE, Genco, AERG and EEI. Ancillary services are services necessary to support the transmission of energy from generation resources to loads while maintaining reliable operation of the transmission provider’s system. In February 2008, FERC conditionally accepted the ancillary services market tariff proposed by MISO. We expect Non-rate-regulated Generation’s ancillary services market revenues to increase to $15 million in 2008 from $5 million realized in 2007. Ancillary services market revenues are allocated to Genco and AERG in accordance with their power supply agreements with Marketing Company.

We expect MISO will begin development of a capacity market once its ancillary services market is in place. A capacity market allows participants to purchase or sell capacity products that meet reliability requirements. MISO is currently in the process of developing a centralized regional wholesale ancillary services market, which is expected to begin during 2008. We expect capacity and energy prices to strengthen from current levels because of improving market liquidity and decreasing reserve margins in MISO. Non-rate-regulated Generation’s capacity revenues are expected to increase to approximately $40 million in 2008 from $25 million in 2007. EEI receives payment for 100% of its capacity sales under its power supply agreement with Marketing Company. Capacity revenues are allocated to Genco and AERG based on their generation in accordance with their power supply agreements with Marketing Company.

We expect continued economic growth in our service territory and market area to benefit energy demand in 2008 and beyond, but higher energy prices and challenging economic conditions could result in reduced demand from customers, especially in Illinois. Future energy efficiency programs developed by UE, CIPS, CILCO and IP and others could also result in reduced demand for our electric generation and our electric and gas transmission and distribution services.

Fuel and Purchased Power

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

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

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

Other Costs

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. In January 2008, the Circuit Court of Reynolds County, Missouri, approved UE’s November 2007 settlement agreement with the state of Missouri resolving the state’s lawsuit and claims for damages and other relief related to the breach. In addition, pursuant to the settlement agreement, UE is required to replace the breached upper reservoir with a new reservoir, subject to FERC authorization. UE received approval from FERC to rebuild the upper reservoir in August 2007 and began construction in November 2007. The estimated cost to rebuild the upper reservoir is in the range of $450 million. UE expects the Taum Sauk pumped-storage hydroelectric facility to be out of service through early 2010. UE believes that substantially all of the damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. As a result of this breach, UE is engaged in litigation initiated by certain private parties. We are unable to predict the timing or outcomes of this

litigation, or its possible effect on UE’s results of operation, financial position or liquidity. See Note 2 – Rate and Regulatory Matters and Note 9 – Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a further discussion of Taum Sauk matters.

UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage in the fall of 2008 is expected to last 25 to 30 days. During a scheduled outage, which occurs every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, versus non-outage years.

Over the next few years, we expect rising employee benefit costs as well as higher insurance and security costs associated with additional measures we have taken, or may need to take, at UE’s Callaway nuclear plant and at our other facilities. Insurance premiums may also increase as a result of insurance market conditions and loss experience, among other things.

·	Bad debts may increase due to rising electric and gas rates and economic conditions.

·	As we refinance our short-term and variable-rate debt into fixed-rate debt, financing costs may increase.

·	We are currently undertaking cost reduction and control initiatives associated with the strategic sourcing of purchases and streamlining of all aspects of our business.

Capital Expenditures

Between 2008 and 2017, Ameren estimated that certain Ameren Companies would be required to invest between $4 billion and $5 billion to retrofit their coal-fired power plants with pollution control equipment. Costs for these types of projects continue to escalate. However, because of the 2008 U.S. Court of Appeals for the District of Columbia decisions to vacate the Clean Air Interstate Rule and the Clean Air Mercury Rule, the timing and ultimate amount of these capital costs are under review at this time. Any pollution control investments will result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 45% of this investment was expected to be in Ameren’s regulated UE operations, and therefore was expected to be recoverable from ratepayers. The recoverability of amounts expended in non-rate-regulated operations will depend on whether market prices for power adjust as a result of 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. In December 2007, Ameren issued a report on how it is responding to the rising regulatory, competitive, and public pressure to significantly reduce CO2 and other emissions from current and proposed power plant operations. The report included Ameren’s climate change strategy and activities, current greenhouse gas emissions, and analysis with respect to plausible future greenhouse gas scenarios; it is available on Ameren’s Web site. Investments to control carbon emissions at Ameren’s coal-fired plants would significantly increase future capital expenditures and operation and maintenance expenses.

UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. At this time, UE does not expect to require new baseload generation capacity until 2018 to 2020. However, due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. In July 2008, UE filed a COLA with the NRC for a potential new nuclear plant at UE’s existing Callaway County, Missouri nuclear plant site. In addition, UE has also signed contracts for certain long lead-time equipment. Filing that COLA and entering into these contracts does not mean a decision has been made to build a nuclear plant. These are only the first steps in the regulatory licensing and procurement process and are necessary actions to preserve the option to develop a new nuclear plant. UE had to submit the COLA to the NRC in 2008 to be eligible for incentives available under provisions of the 2005 Energy Policy Act. We cannot predict whether or when the NRC will approve the COLA.

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

Over the next few years, we expect to make significant investments in our electric and gas infrastructure and to incur increased operations and maintenance expenses to improve overall system reliability. We are projecting higher labor and material costs for these capital expenditures. UE announced in July 2007 plans to spend $300 million over three years for underground cabling and reliability improvement, $135 million ($45 million per year) for tree-trimming, and $84 million over three years (approximately $28 million per year) for circuit and device inspection and repair. We would expect these costs or investments to be ultimately recovered in rates.

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

The Ameren Companies will incur significant capital expenditures over the next five years for compliance with environmental regulations and to make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Expenditures are expected to be funded primarily with debt.

Other

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

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

REGULATORY MATTERS

See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

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

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

Interest Rate Risk

We are exposed to market risk through changes in interest rates. The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable-rate debt outstanding at June 30, 2008:

	Interest Expense			Net Income(a)
Ameren	$	16		$	(10	)
UE		3			(2	)
CIPS	(b		)	(b		)
Genco		-			-
CILCORP		6			(4	)
CILCO		4			(2	)
IP		2			(1	)

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

(b)	Less than $1 million

The estimated changes above do not consider potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably act to further mitigate our

exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure.

Insured Auction-Rate Tax-exempt Bonds

Our auction-rate tax-exempt environmental improvement and pollution control revenue bonds issued for the benefit of UE, CIPS, CILCO and IP through governmental authorities were insured by “monoline” bond insurers. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8 of the Form 10-K for a description and details of this indebtedness. As a result of developments in the capital markets with respect to residential mortgage-backed securities and collateralized debt obligations, the credit rating agencies downgraded the monoline bond insurers’ credit ratings due to their insuring of such securities. As a result, since December 2007, our insured auction-rate bonds have similarly been downgraded. We experienced higher interest expense and/or “failed auctions” with respect to a portion of our auction-rate bonds. According to press reports, many other series of auction-rate securities similarly experienced “failed auctions.”

To mitigate the effect of these credit ratings downgrades and the resulting impact on the interest rates of our auction-rate tax-exempt environmental improvement and pollution control revenue bonds, we have redeemed all of UE’s, CIPS’, CILCO’s and IP’s outstanding auction-rate bonds except for UE’s 1992 Series and 1998 Series A, B and C bonds, which had an aggregate balance of $207 million at June 30, 2008, and interest rates ranging from 2.8% to 4.795% during the three months ended June 30, 2008 (2.8% to 4.9% during the six months ended June 30, 2008). In April 2008, UE and IP issued senior secured notes in the principal amount of $250 million and $337 million, respectively, to refinance their auction-rate indebtedness. See Note 4 – Long-term Debt and Equity Financings under Part I, Item 1 of this report for a description of these redemptions and refinancings.

Credit Risk

Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction.

Our physical and financial instruments are subject to credit risk consisting of trade accounts receivable and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. The Ameren Illinois Utilities’ past-due accounts receivable balances have increased significantly due to the increase in electric rates in Illinois, effective January 2, 2007, and a related increase in extended payment plan balances. The allowances for doubtful accounts of IP, CIPS, and CILCO have been increased to provide for the heightened credit risk associated with this increase in past-due accounts receivables. The Ameren Illinois Utilities will continue to monitor the impact of increased electric rates on customer collections and make adjustments to their allowances for doubtful accounts, as deemed necessary, to ensure that such allowances are adequate to cover estimated uncollectible customer account balances. At June 30, 2008, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. UE, CIPS, Genco, CILCO, AERG, IP, AFS and Marketing Company may have credit exposure associated with interchange or wholesale purchase and sale activity with nonaffiliated companies. At June 30, 2008, UE’s, CIPS’, Genco’s, CILCO’s, AERG’s, IP’s, AFS’ and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading counterparties was $2 million, net of collateral (2007 – less than $1 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program that involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged lease. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $62 million at June 30, 2008 (2007 - $33 million).

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

Equity Price Risk

Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, including the rate of return on plan assets. To the

extent the value of plan assets declines, the effect would be reflected in net income and OCI, 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 structured forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of UE, Genco, AERG and EEI is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.

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

	Net Income(a)
Ameren(b)	$	(16	)
UE		(7	)
Genco		(4	)
CILCO (AERG)		(1	)
EEI		(6	)

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

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

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

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

Transportation costs for coal and natural gas can be a significant portion of fuel costs. We typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. Natural gas transportation expenses for Ameren’s gas distribution utility companies and the gas-fired generation units of UE, Genco, AERG and EEI are regulated by FERC through approved tariffs governing the rates, terms and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements held by Ameren Companies include rights to extend the contracts prior to the termination of the primary term. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates for our requirements.

The following table presents the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of CIPS, CILCO and IP, which own no generation, that are price-hedged over the remainder of 2008 through 2012, as of June 30, 2008:

	2008			2009			2010 – 2012
Ameren:
Coal		99	%		99	%	46	%
Coal transportation		100			82		17
Nuclear fuel		100			100		88
Natural gas for generation		50			4		-
Natural gas for distribution(a)		23			14		14
Purchased power for Illinois Regulated(b)		97			80		51

	2008			2009			2010 – 2012
UE:
Coal		100	%		100	%	52	%
Coal transportation		100			96		31
Nuclear fuel		100			100		88
Natural gas for generation		45			6		-
Natural gas for distribution(a)		24			12		4
CIPS:
Natural gas for distribution(a)		20	%		17	%	5	%
Purchased power(b)		97			80		51
Genco:
Coal		99	%		100	%	34	%
Coal transportation		100			98		-
Natural gas for generation		73			-		-
CILCORP/CILCO:
Coal (AERG)		94	%		90	%	37	%
Coal transportation (AERG)		100			69		-
Natural gas for distribution(a)		25			12		21
Purchased power(b)		97			80		51
IP:
Natural gas for distribution(a)		24	%		16	%	17	%
Purchased power(b)		97			80		51
EEI:
Coal		100	%		100	%	53	%
Coal transportation		100			-		-

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

(b)

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

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

	Coal					Transportation
	Fuel Expense		Net Income(a)			Fuel Expense		Net Income(a)
Ameren(b)	$	37	$	(23	)	$	22	$	(13	)
UE		14		(9	)		10		(6	)
Genco		14		(9	)		5		(3	)
CILCORP		6		(4	)		2		(1	)
CILCO (AERG)		6		(4	)		2		(1	)
EEI		3		(1	)		5		(3	)

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

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

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

In the event of a significant change in coal prices, UE, Genco, AERG and EEI would probably take actions to further mitigate their exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure or fuel sources.

See Note 9 – Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further information regarding the long-term commitments for the procurement of coal, natural gas and nuclear fuel.

Fair Value of Contracts

Most of our commodity contracts qualify for treatment as normal purchases and sales. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission allowances. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three months and six months ended June 30, 2008. We use various methods to determine the fair value of our contracts. In accordance with SFAS No. 157 hierarchy levels, our sources used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). All of these contracts have maturities of less than five years. See Note 7 – Fair Value

Measurements to our financial statements under Part I, Item 1, of this report for further information regarding the methods used to determine the fair value of these contracts.

	Ameren(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Three Months
Fair value of contracts at beginning of period, net	$	13		$	(1	)	$	58		$	(14	)	$	40		$	102
Contracts realized or otherwise settled during the period		(27	)		(3	)		(3	)		5			(6	)		(8	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		21			(2	)		7			-			2			5
Other changes in fair value		116			17			50			13			41			96
Fair value of contracts outstanding at end of period, net	$	123		$	11		$	112		$	4		$	77		$	195
Six Months
Fair value of contracts at beginning of period, net	$	13		$	7		$	38		$	(4	)	$	21		$	55
Contracts realized or otherwise settled during the period		(32	)		(6	)		(3	)		5			(7	)		(4	)
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		36			(3	)		7			1			2			3
Other changes in fair value		106			13			70			2			61			141
Fair value of contracts outstanding at end of period, net	$	123		$	11		$	112		$	4		$	77		$	195

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

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

Sources of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years		Maturity in Excess of 5 Years		Total Fair Value
Ameren:
Level 1	$	2		$	-		$	-	$	-	$	2
Level 2(a)		(64	)		(17	)		-		-		(81	)
Level 3(b)		99			96			7		-		202
Total	$	37		$	79		$	7	$	-	$	123
UE:
Level 1	$	-		$	-		$	-	$	-	$	-
Level 2(a)		(28	)		(1	)		-		-		(29	)
Level 3(b)		33			6			1		-		40
Total	$	5		$	5		$	1	$	-	$	11
CIPS:
Level 1	$	-		$	-		$	-	$	-	$	-
Level 2(a)		-			-			-		-		-
Level 3(b)		37			50			25		-		112
Total	$	37		$	50		$	25	$	-	$	112
Genco:
Level 1	$	-		$	-		$	-	$	-	$	-
Level 2(a)		-			-			-		-		-
Level 3(b)		4			-			-		-		4
Total	$	4		$	-		$	-	$	-	$	4
CILCORP/CILCO:
Level 1	$	-		$	-		$	-	$	-	$	-
Level 2(a)		-			-			-		-		-
Level 3(b)		32			33			12		-		77
Total	$	32		$	33		$	12	$	-	$	77
IP:
Level 1	$	-		$	-		$	-	$	-	$	-
Level 2(a)		-			-			-		-		-
Level 3(b)		73			88			34		-		195
Total	$	73		$	88		$	34	$	-	$	195

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

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

ITEM 4 and ITEM 4T. CONTROLS AND PROCEDURES.

(a)	Evaluation of Disclosure Controls and Procedures

As of June 30, 2008, evaluations were performed, under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.

(b)	Change in Internal Controls

There has been no change in any of the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, each of their internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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

In March and May 2008, Caterpillar Inc., in conjunction with other industrial customers as a coalition, filed testimony in the November 2007 rate cases filed by CIPS, CILCO and IP with the ICC to modify their electric and natural gas delivery service rates. Caterpillar Inc., in its testimony, opposed CILCO’s and IP’s filings on issues regarding rate design, revenue requirements, return on equity and cost recovery mechanisms, among others. Douglas R. Oberhelman is an executive officer of Caterpillar Inc. and a member of the board of directors of Ameren. Mr. Oberhelman did not participate in Ameren’s board and committee deliberations relating to these matters.

In April 2008, The Boeing Company, in conjunction with other industrial customers as a coalition, intervened in the MoPSC proceeding relating to UE’s pending request for an increase in its electric service rates. James C. Johnson is an officer of The Boeing Company and a member of the board of directors of Ameren. Mr. Johnson did not participate in Ameren’s board and committee deliberations relating to this matter.

For additional information on legal and administrative proceedings, see Note 2 – Rate and Regulatory Matters, Note 8 – Related Party Transactions and Note 9 – Commitments and Contingencies to our financial statements under Part I, Item 1 of this report.

ITEM 1A. RISK FACTORS.

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

Failure to retain and attract key officers and other skilled professional and technical employees could have an adverse effect on our operations.

Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. A significant portion of our workforce is nearing retirement, including many employees with specialized skills such as maintaining and servicing our electric and natural gas infrastructure and operating our generating units. Our inability to retain and recruit qualified employees could adversely affect our results of operations.

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, 2008	4,437	$ 45.45	-	-
May 1 – May 31, 2008	-	-	-	-
June 1 – June 30, 2008	-	-	-	-
Total	4,437	$ 45.45	-	-

(a)

Included in April were 4,187 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren’s obligation upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998, as amended. Also included in April were 250 shares of Ameren common stock purchased by Ameren from employee participants to satisfy participants’ tax obligations incurred by the release of restricted shares of Ameren common stock under Ameren’s Long-term Incentive Plan of 1998. Ameren does not have any publicly announced equity securities repurchase plans or programs.

None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the April 1 to June 30, 2008 period.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Ameren

At Ameren’s annual meeting of shareholders held on April 22, 2008, the following matters were presented to the meeting for a vote and the results of such voting are as follows:

Item (1) Election of 11 directors (comprising Ameren's full Board of Directors) to serve until the next annual meeting of shareholders in 2009.

Name	For	Withheld	Broker Non-Votes(a)
Stephen F. Brauer	177,485,438	4,014,368	-
Susan S. Elliott	177,272,822	4,226,984	-
Walter J. Galvin	177,540,798	3,959,008	-
Gayle P. W. Jackson	177,500,222	3,999,584	-
James C. Johnson	177,439,140	4,060,666	-
Charles W. Mueller	177,009,109	4,490,697	-
Douglas R. Oberhelman	177,354,420	4,145,386	-
Gary L. Rainwater	176,991,219	4,508,587	-
Harvey Saligman	176,878,439	4,621,367	-
Patrick T. Stokes	177,347,025	4,152,781	-
Jack D. Woodard	177,250,277	4,249,529	-

(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 accountants for the fiscal year ending December 31, 2008.

For	Against	Abstain	Broker Non-Votes(a)
177,719,424	1,394,269	2,386,113	-

(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)
13,314,278	121,764,076	13,942,985	32,478,467

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

At UE’s annual meeting of shareholders held on April 22, 2008, the following individuals (comprising UE’s full Board of Directors at that time) were elected to serve until the next annual meeting of shareholders in 2009: Warner L. Baxter, Daniel F. Cole, Richard J. Mark, Charles D. Naslund, Steven R. Sullivan and Thomas R. Voss. 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 22, 2008, the following individuals (comprising CIPS’ full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2009: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole 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 22, 2008, the following individuals (comprising CILCO’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2009: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole and Steven R. Sullivan. Each individual received 13,563,871 votes for election and no withheld votes or broker non-votes.

At IP’s annual meeting of shareholders held on April 22, 2008, the following individuals (comprising IP’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2009: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole 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.

ITEM 6. EXHIBITS.

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

Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
By-Laws
3.1(ii)	UE	By-Laws of UE as amended July 28, 2008	July 29, 2008 Form 8-K, Exhibit 3.1(ii), File No. 1-2967
3.2(ii)	CIPS	By-Laws of CIPS as amended July 28, 2008	July 29, 2008 Form 8-K, Exhibit 3.2(ii), File No. 1-3672
3.3(ii)	CILCO	By-Laws of CILCO as amended July 28, 2008	July 29, 2008 Form 8-K, Exhibit 3.3(ii), File No. 1-2732
3.4(ii)	IP	By-Laws of IP as amended July 28, 2008	July 29, 2008 Form 8-K, Exhibit 3.4(ii), File No. 1-3004
Instruments Defining Rights of Securities Holders, Including Indentures
4.1	Ameren	First Supplemental Indenture dated as of May 19, 2008 amending the Ameren Indenture dated as of December, 2001 and effecting the resignation of The Bank of New York, as trustee and appointment of The Bank of New York Mellon Trust Company, N.A. as successor trustee
4.2	Ameren UE	UE Company Order dated June 19, 2008, establishing the 6.70% Senior Secured Notes due 2019 (including the global note)	June 19, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.3	Ameren UE	Supplemental Indenture dated as of June 1, 2008 by and between UE and The Bank of New York Mellon, as trustee under the Indenture of Mortgage and Deed of Trust dated June 15, 1937, as amended, relating to UE First Mortgage Bonds, Senior Notes Series MM securing UE 6.70% Senior Secured Notes due 2019	June 19, 2008 Form 8-K, Exhibit 4.5, File No. 1-2967
Material Contracts
10.1	Ameren Companies	* Ameren Supplemental Retirement Plan amended and restated effective January 1, 2008, dated June 13, 2008
10.2	Ameren Companies	* Ameren 2008 Deferred Compensation Plan
10.3	Ameren	* Ameren Deferred Compensation Plan for members of the Board of Directors amended and restated effective January 1, 2009, dated June 13, 2008
10.4	Ameren	Credit Agreement dated as of June 25, 2008, between Ameren and JPMorgan Chase Bank, N.A., as agent	June 27, 2008 Form 8-K, Exhibit 10.1, File No. 1-14756
Statement re: Computation of Ratios
12.1	Ameren	Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	UE	UE’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements

Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
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
32.2	UE	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of UE

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

* Management compensatory plan or arrangement.

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