Ameren Illinois 10Q 2006 Q2 Quarterly report

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, 2006

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

of the Securities Exchange Act of 1934

for the transition period from ____ to____.

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

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

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

1-3672	Central Illinois Public Service Company	37-0211380
	(Illinois Corporation)
	607 East Adams Street
	Springfield, Illinois 62739
	(217) 523-3600

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

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

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

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

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

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

	Large Accelerated Filer	Accelerated Filer	Non-Accelerated Filer
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, 2006, was as follows:

Ameren Corporation	Common stock, $.01 par value per share - 205,866,928

Union Electric Company	Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant) - 102,123,834

Central Illinois Public Service Company	Common stock, no par value, held by Ameren Corporation (parent company of the registrant) - 25,452,373

Ameren Energy Generating Company	Common stock, no par value, held by Ameren Energy Development Company (parent company of the registrant and indirect subsidiary of Ameren Corporation) - 2,000

CILCORP Inc.	Common stock, no par value, held by Ameren Corporation (parent company of the registrant) - 1,000

Central Illinois Light Company	Common stock, no par value, held by CILCORP Inc. (parent company of the registrant and subsidiary of Ameren Corporation) - 13,563,871

Illinois Power Company	Common stock, no par value, held by Ameren Corporation (parent company of the registrant) - 23,000,000

OMISSION OF CERTAIN INFORMATION

Ameren Energy Generating Company and CILCORP Inc. meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this form with the reduced disclosure format allowed under that General Instruction.

This combined Form 10-Q is separately filed by Ameren Corporation, Union Electric Company, Central Illinois Public Service Company, Ameren Energy Generating Company, CILCORP Inc., Central Illinois Light Company, and Illinois Power Company. Each registrant hereto is filing on its own behalf all of the information contained in this quarterly report that relates to such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

TABLE OF CONTENTS

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

Forward-looking Statements.............................................................................................................................................................................................................................................................	6

PART I Financial Information

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

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations...........................................................................................................................	53
Item 3. Quantitative and Qualitative Disclosures About Market Risk................................................................................................................................................................................	72
Item 4. Controls and Procedures...............................................................................................................................................................................................................................................	75

PART II Other Information

Item 1. Legal Proceedings...........................................................................................................................................................................................................................................................	75
Item 1A Risk Factors.....................................................................................................................................................................................................................................................................	75
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.................................................................................................................................................................................	77
Item 4. Submission of Matters to a Vote of Security Holders...............................................................................................................................................................................................	78
Item 6. Exhibits.............................................................................................................................................................................................................................................................................	79

Signatures............................................................................................................................................................................................................................................................................................	81

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 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. Forward-looking statements should be read with the cautionary statements and important factors included on page 6 of this Form 10-Q under the heading “Forward-looking Statements.”

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 Development Company subsidiary that procures fuel and natural gas and manages the related risks for the Ameren Companies.

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

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

Ameren Energy - Ameren Energy, Inc., an Ameren Corporation subsidiary that serves as a power marketing and risk management agent for UE and Genco primarily for transactions of less than one year.

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

APB - Accounting Principles Board.

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

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

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

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

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

CUB - Citizens Utility Board.

Development Company - Ameren Energy Development Company, a Resources Company subsidiary and Genco parent, which primarily develops and constructs generating facilities for Genco.

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 (40% owned by UE and 40% owned by Development Company) that operates electric generation and transmission facilities in Illinois. The remaining 20% is owned by Kentucky Utilities Company.

ELPC - Environmental Law and Policy Center.

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 specific period.

ERISA - Employee Retirement Income Security Act of 1974, as amended.

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

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

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

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

GAAP - Generally accepted accounting principles in the United States.

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

Gigawatthour - One thousand megawatthours.

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 the Illinois utility businesses and 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 EPA - Illinois Environmental Protection Agency, a state government agency.

IP - Illinois Power Company, an Ameren Corporation subsidiary that was acquired from Dynegy on September 30,

2004. IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenIP.

IP SPT - Illinois Power Special Purpose Trust, which was created as a subsidiary of Illinois Power Securitization Limited Liability Company to issue TFNs as allowed under the Illinois Customer Choice Law. Pursuant to FIN 46R, IP SPT is a variable-interest entity, as the equity investment is not sufficient to permit IP SPT to finance its activities without additional subordinated debt.

JDA - The joint dispatch agreement among UE, CIPS, and Genco under which UE and Genco jointly dispatch electric generation.

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 Development Company subsidiary that markets power, primarily for periods over one year.

Medina Valley - AmerenEnergy Medina Valley Cogen (No. 4) LLC and its subsidiaries, which are all Development Company subsidiaries, which indirectly own a 40-megawatt gas-fired electric generation plant.

Megawatthour - One thousand kilowatthours.

MGP - Manufactured gas plant.

MISO - Midwest Independent Transmission System Operator, Inc.

MISO Day Two Energy Market - A market that began operating on April 1, 2005. It uses market-based pricing, incorporating transmission congestion and line losses, to compensate market participants for power. The previous system required generators to make advance reservations for transmission service.

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

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

MoPSC - Missouri Public Service Commission, a state agency that regulates the Missouri utility business and operations of UE.

NO_x - Nitrogen oxide.

Noranda - Noranda Aluminum, Inc.

NYMEX - New York Mercantile Exchange.

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

PUHCA 1935 - The Public Utility Holding Company Act of 1935, which was repealed, effective February 8, 2006, by the Energy Policy Act of 2005 that was enacted on August 8, 2005.

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

Resources Company - Ameren Energy Resources Company, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Development Company, Genco, Marketing Company, AFS, and Medina Valley.

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 Illinois’ deregulation legislation. 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.

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

·	regulatory or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of UE, CIPS, CILCO and IP rate proceedings;

·	the impact of the termination of the joint dispatch agreement among UE, CIPS, and Genco;

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

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

·	the effects of participation in the MISO;

the availability of fuel such as coal, natural gas and enriched uranium used to produce electricity; the 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;

·	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 its future operation;

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

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

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

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

·	changes in the energy markets, environmental laws or regulations, interest rates, or other factors that could adversely affect assumptions in connection with the IP acquisition;

·	the impact of conditions imposed by regulators in connection with their approval of Ameren’s acquisition of IP;

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

·	the cost and availability of transmission capacity 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 publicly update or revise any forward-looking statements to reflect new information or future events.

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

	Three Months Ended June 30,						Six Months Ended June 30,
		2006			2005			2006			2005
Operating Revenues:
Electric	$	1,378		$	1,407		$	2,589		$	2,529
Gas		172			174			761			670
Other		-			3			-			4
Total operating revenues		1,550			1,584			3,350			3,203

Operating Expenses:
Fuel and purchased power		524			485			1,049			894
Gas purchased for resale		104			106			557			460
Other operations and maintenance		394			375			742			720
Depreciation and amortization		162			157			327			314
Taxes other than income taxes		90			95			203			186
Total operating expenses		1,274			1,218			2,878			2,574

Operating Income		276			366			472			629

Other Income and Expenses:
Miscellaneous income		4			6			8			13
Miscellaneous expense		(1	)		(6	)		(1	)		(7	)
Total other income		3			-			7			6

Interest Charges		80			77			156			151

Income Before Income Taxes, Minority Interest
and Preferred Dividends of Subsidiaries		199			289			323			484

Income Taxes		68			100			112			171

Income Before Minority Interest and Preferred
Dividends of Subsidiaries		131			189			211			313

Minority Interest and Preferred Dividends
of Subsidiaries		(8	)		(4	)		(18	)		(7	)

Net Income	$	123		$	185		$	193		$	306

Earnings per Common Share – Basic and Diluted	$	0.60		$	0.93		$	0.94		$	1.55
Dividends per Common Share	$	0.635		$	0.635		$	1.27		$	1.27
Average Common Shares Outstanding		205.4			199.7			205.1			197.5

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

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

	June 30,			December 31,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	51		$	96
Accounts receivable – trade (less allowance for doubtful
accounts of $25 and $22, respectively)		409			552
Unbilled revenue		355			382
Miscellaneous accounts and notes receivable		71			31
Materials and supplies		549			572
Other current assets		110			185
Total current assets		1,545			1,818
Property and Plant, Net		13,920			13,572
Investments and Other Assets:
Investments in leveraged leases		32			50
Nuclear decommissioning trust fund		257			250
Goodwill		976			976
Intangible assets		250			246
Other assets		643			419
Regulatory assets		827			831
Total investments and other assets		2,985			2,772
TOTAL ASSETS	$	18,450		$	18,162

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	124		$	96
Short-term debt		397			193
Accounts and wages payable		404			706
Taxes accrued		97			131
Other current liabilities		386			361
Total current liabilities		1,408			1,487
Long-term Debt, Net		5,705			5,354
Preferred Stock of Subsidiary Subject to Mandatory Redemption		19			19
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,958			1,969
Accumulated deferred investment tax credits		123			129
Regulatory liabilities		1,173			1,132
Asset retirement obligations		531			518
Accrued pension and other postretirement benefits		800			760
Other deferred credits and liabilities		174			218
Total deferred credits and other liabilities		4,759			4,726
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption		195			195
Minority Interest in Consolidated Subsidiaries		15			17
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholders' Equity:
Common stock, $.01 par value, 400.0 shares authorized,
205.8 and 204.7 shares outstanding, respectively		2			2
Other paid-in capital, principally premium on common stock		4,457			4,399
Retained earnings		1,932			1,999
Accumulated other comprehensive loss		(36	)		(24	)
Other		(6	)		(12	)
Total stockholders’ equity		6,349			6,364
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	18,450		$	18,162

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,
		2006			2005
Cash Flows From Operating Activities:
Net income	$	193		$	306
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		340			299
Amortization of nuclear fuel		16			17
Amortization of debt issuance costs and premium/discounts		7			7
Deferred income taxes and investment tax credits, net		(19	)		66
Loss on sale of leveraged leases		4			-
Minority interest		12			1
Other		1			-
Changes in assets and liabilities, excluding the effects of acquisitions:
Receivables, net		168			(8	)
Materials and supplies		25			46
Accounts and wages payable		(258	)		(163	)
Taxes accrued		(33	)		112
Assets, other		58			11
Liabilities, other		10			1
Pension and other postretirement benefit obligations, net		46			54
Net cash provided by operating activities		570			749

Cash Flows From Investing Activities:
Capital expenditures		(406	)		(442	)
CT acquisitions		(292	)		-
Nuclear fuel expenditures		(25	)		(13	)
Proceeds from sale of leveraged leases		11			-
Purchases of emission allowances		(38	)		(92	)
Sales of emission allowances		4			4
Other		-			12
Net cash used in investing activities		(746	)		(531	)

Cash Flows From Financing Activities:
Dividends on common stock		(260	)		(253	)
Capital issuance costs		(2	)		(1	)
Short-term debt, net		204			(256	)
Dividends paid to minority interest		(14	)		-
Redemptions, repurchases, and maturities:
Long-term debt		(86	)		(237	)
Issuances:
Common stock		57			402
Long-term debt		232			85
Net cash provided by (used in) financing activities		131			(260	)

Net change in cash and cash equivalents		(45	)		(42	)
Cash and cash equivalents at beginning of year		96			69
Cash and cash equivalents at end of period	$	51		$	27

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,
		2006			2005			2006			2005
Operating Revenues:
Electric	$	687		$	726		$	1,254		$	1,259
Gas		22			26			91			101
Other		1			-			1			-
Total operating revenues		710			752			1,346			1,360

Operating Expenses:
Fuel and purchased power		192			182			384			326
Gas purchased for resale		12			13			56			58
Other operations and maintenance		196			193			367			374
Depreciation and amortization		81			76			161			152
Taxes other than income taxes		59			59			118			114
Total operating expenses		540			523			1,086			1,024

Operating Income		170			229			260			336

Other Income and Expenses:
Miscellaneous income		1			2			4			9
Miscellaneous expense		(2	)		(2	)		(4	)		(4	)
Total other income (expense)		(1	)		-			-			5

Interest Charges		37			27			72			52

Income Before Income Taxes and Equity
in Income of Unconsolidated Investment		132			202			188			289

Income Taxes		50			71			69			102

Income Before Equity in Income
of Unconsolidated Investment		82			131			119			187

Equity in Income of Unconsolidated Investment		10			1			24			2

Net Income		92			132			143			189

Preferred Stock Dividends		2			2			3			3

Net Income Available to Common Stockholder	$	90		$	130		$	140		$	186

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,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	1		$	20
Accounts receivable – trade (less allowance for doubtful
accounts of $6 and $6, respectively)		141			190
Unbilled revenue		176			133
Miscellaneous accounts and notes receivable		58			7
Accounts receivable – affiliates		26			53
Current portion of intercompany note receivable – CIPS		-			6
Materials and supplies		214			199
Other current assets		49			57
Total current assets		665			665
Property and Plant, Net		7,696			7,379
Investments and Other Assets:
Nuclear decommissioning trust fund		257			250
Intercompany note receivable – CIPS		-			61
Intangible assets		63			63
Other assets		496			269
Regulatory assets		583			590
Total investments and other assets		1,399			1,233
TOTAL ASSETS	$	9,760		$	9,277

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	11		$	4
Short-term debt		364			80
Accounts and wages payable		90			274
Accounts and wages payable – affiliates		83			134
Taxes accrued		113			59
Other current liabilities		148			96
Total current liabilities		809			647
Long-term Debt, Net		2,931			2,698
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,293			1,277
Accumulated deferred investment tax credits		92			96
Regulatory liabilities		811			802
Asset retirement obligations		478			466
Accrued pension and other postretirement benefits		221			203
Other deferred credits and liabilities		56			72
Total deferred credits and other liabilities		2,951			2,916
Commitments and Contingencies (Notes 2, 8 and 9)
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		734			733
Retained earnings		1,744			1,689
Accumulated other comprehensive loss		(33	)		(30	)
Total stockholders' equity		3,069			3,016
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,760		$	9,277

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,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	143		$	189
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		161			152
Amortization of nuclear fuel		16			17
Amortization of debt issuance costs and premium/discounts		3			3
Deferred income taxes and investment tax credits, net		11			30
Other		(5	)		(8	)
Changes in assets and liabilities:
Receivables, net		(15	)		(114	)
Materials and supplies		(13	)		5
Accounts and wages payable		(206	)		(61	)
Taxes accrued		54			111
Assets, other		25			(3	)
Liabilities, other		35			11
Pension and other postretirement benefit obligations, net		18			21
Net cash provided by operating activities		227			353

Cash Flows From Investing Activities:
Capital expenditures		(197	)		(248	)
CT acquisitions from non-affiliates		(292	)		-
CT acquisitions from Genco		-			(241	)
Nuclear fuel expenditures		(25	)		(13	)
Sales of emission allowances		2			2
Other		1			8
Net cash used in investing activities		(511	)		(492	)

Cash Flows From Financing Activities:
Dividends on common stock		(84	)		(135	)
Dividends on preferred stock		(3	)		(3	)
Proceeds from intercompany note receivable - CIPS		67			-
Changes in short-term debt, net		284			(237	)
Changes in money pool borrowings		-			380
Issuance of long-term debt		-			85
Capital contribution from parent		1			2
Net cash provided by financing activities		265			92

Net change in cash and cash equivalents		(19	)		(47	)
Cash and cash equivalents at beginning of year		20			48
Cash and cash equivalents at end of period	$	1		$	1

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 June 30,					Six Months Ended June 30,
	2006		2005			2006			2005
Operating Revenues:
Electric	$	181	$	171		$	341		$	299
Gas		30		27			127			111
Other		1		-			1			-
Total operating revenues		212		198			469			410

Operating Expenses:
Purchased power		113		105			230			191
Gas purchased for resale		16		15			88			74
Other operations and maintenance		38		37			76			70
Depreciation and amortization		15		15			31			28
Taxes other than income taxes		9		7			21			15
Total operating expenses		191		179			446			378

Operating Income		21		19			23			32

Other Income and Expenses:
Miscellaneous income		4		4			9			9
Miscellaneous expense		-		(4	)		(1	)		(4	)
Total other income		4		-			8			5

Interest Charges		8		8			15			15

Income Before Income Taxes		17		11			16			22

Income Taxes		2		4			2			7

Net Income		15		7			14			15

Preferred Stock Dividends		-		-			1			1

Net Income Available to Common Stockholder	$	15	$	7		$	13		$	14

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
BALANCE SHEET
(Unaudited) (In millions)
	June 30,			December 31,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	1		$	-
Accounts receivable – trade (less allowance for doubtful
accounts of $4 and $4, respectively)		57			70
Unbilled revenue		57			71
Accounts receivable – affiliates		11			18
Current portion of intercompany note receivable – Genco		37			34
Current portion of intercompany tax receivable – Genco		10			10
Advances to money pool		17			-
Materials and supplies		54			75
Other current assets		19			28
Total current assets		263			306
Property and Plant, Net		1,141			1,130
Investments and Other Assets:
Intercompany note receivable – Genco		126			163
Intercompany tax receivable – Genco		120			125
Other assets		15			24
Regulatory assets		35			36
Total investments and other assets		296			348
TOTAL ASSETS	$	1,700		$	1,784

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	-		$	20
Accounts and wages payable		26			36
Accounts and wages payable – affiliates		65			65
Borrowings from money pool		-			2
Current portion of intercompany note payable – UE		-			6
Taxes accrued		7			26
Other current liabilities		37			43
Total current liabilities		135			198
Long-term Debt, Net		471			410
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net		295			302
Intercompany note payable – UE		-			61
Regulatory liabilities		209			208
Other deferred credits and liabilities		39			36
Total deferred credits and other liabilities		543			607
Commitments and Contingencies (Notes 2 and 8)
Stockholders' Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding		-			-
Other paid-in capital		189			189
Preferred stock not subject to mandatory redemption		50			50
Retained earnings		316			329
Accumulated other comprehensive income (loss)		(4	)		1
Total stockholders' equity		551			569
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,700		$	1,784

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

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

	Six Months Ended June 30,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	14		$	15
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		31			28
Deferred income taxes and investment tax credits, net		(16	)		(7	)
Other		(1	)		(4	)
Changes in assets and liabilities:
Receivables, net		39			10
Materials and supplies		21			7
Accounts and wages payable		(9	)		17
Taxes accrued		(19	)		11
Assets, other		22			10
Liabilities, other		(3	)		5
Pension and other postretirement benefit obligations, net		-			4
Net cash provided by operating activities		79			96

Cash Flows From Investing Activities:
Capital expenditures		(40	)		(24	)
Proceeds from intercompany note receivable – Genco		34			52
Changes in money pool advances		(17	)		(28	)
Net cash used in investing activities		(23	)		-

Cash Flows From Financing Activities:
Dividends on common stock		(25	)		(9	)
Dividends on preferred stock		(1	)		(1	)
Capital issuance costs		(1	)		-
Changes in money pool borrowings		(2	)		(68	)
Redemptions, repurchases, and maturities:
Long-term debt		(20	)		(20	)
Intercompany note payable - UE		(67	)		-
Issuances:
Long-term debt		61			-
Capital contribution from parent		-			1
Net cash used in financing activities		(55	)		(97	)

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

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

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Operating Revenues:
Electric	$	238	$	266	$	485	$	491
Total operating revenues		238		266		485		491

Operating Expenses:
Fuel and purchased power		150		138		315		237
Other operations and maintenance		47		38		79		76
Depreciation and amortization		17		18		35		37
Taxes other than income taxes		5		5		11		3
Total operating expenses		219		199		440		353

Operating Income		19		67		45		138

Other Income:
Miscellaneous income		-		1		-		1
Total other income		-		1		-		1

Interest Charges		15		19		30		40

Income Before Income Taxes		4		49		15		99

Income Taxes		2		18		7		37

Net Income	$	2	$	31	$	8	$	62

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,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	1		$	-
Accounts receivable – affiliates		97			102
Accounts receivable		7			29
Materials and supplies		99			73
Other current assets		1			1
Total current assets		205			205
Property and Plant, Net		1,505			1,514
Intangible Assets		90			79
Other Assets		13			13
TOTAL ASSETS	$	1,813		$	1,811

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current portion of intercompany note payable – CIPS	$	37		$	34
Borrowings from money pool		260			203
Accounts and wages payable		27			41
Accounts and wages payable – affiliates		97			60
Current portion of intercompany tax payable – CIPS		10			10
Taxes accrued		14			37
Other current liabilities		23			16
Total current liabilities		468			401
Long-term Debt, Net		474			474
Intercompany Note Payable – CIPS		126			163
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		142			156
Accumulated deferred investment tax credits		9			10
Intercompany tax payable – CIPS		120			125
Asset retirement obligations		29			29
Accrued pension and other postretirement benefits		11			8
Other deferred credits and liabilities		2			1
Total deferred credits and other liabilities		313			329
Commitments and Contingencies (Notes 2 and 8)
Stockholder's Equity:
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding		-			-
Other paid-in capital		278			228
Retained earnings		157			220
Accumulated other comprehensive loss		(3	)		(4	)
Total stockholder's equity		432			444
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	1,813		$	1,811

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,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	8		$	62
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		51			47
Amortization of debt issuance costs and discounts		-			1
Deferred income taxes and investment tax credits, net		(8	)		16
Other		(1	)		-
Changes in assets and liabilities:
Accounts receivable		27			(16	)
Materials and supplies		(26	)		(6	)
Accounts and wages payable		28			40
Taxes accrued, net		(23	)		(12	)
Assets, other		-			6
Liabilities, other		(4	)		(9	)
Pension and other postretirement benefit obligations, net		3			3
Net cash provided by operating activities		55			132

Cash Flows From Investing Activities:
Capital expenditures		(31	)		(43	)
Proceeds from asset sale to UE		-			241
Changes in money pool advances		-			(26	)
Purchases of emission allowances		(26	)		(71	)
Sales of emission allowances		1			1
Net cash provided by (used in) investing activities		(56	)		102

Cash Flows From Financing Activities:
Dividends on common stock		(71	)		(34	)
Changes in money pool borrowings		57			(116	)
Redemptions, repurchases, and maturities:
Intercompany note payable – CIPS and Ameren		(34	)		(86	)
Capital contribution from parent		50			1
Net cash provided by (used in) financing activities		2			(235	)

Net change in cash and cash equivalents		1			(1	)
Cash and cash equivalents at beginning of year		-			1
Cash and cash equivalents at end of period	$	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,
		2006			2005			2006			2005
Operating Revenues:
Electric	$	98		$	100		$	190		$	193
Gas		48			46			198			174
Other		-			1			-			2
Total operating revenues		146			147			388			369

Operating Expenses:
Fuel and purchased power		35			39			61			72
Gas purchased for resale		32			29			151			123
Other operations and maintenance		48			39			89			81
Depreciation and amortization		19			18			41			36
Taxes other than income taxes		4			4			13			11
Total operating expenses		138			129			355			323

Operating Income		8			18			33			46

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

Interest Charges		13			13			25			25

Income (Loss) Before Income Taxes & Preferred
Dividends of Subsidiaries		(5	)		2			7			16

Income Taxes (Benefit)		(6	)		-			(3	)		4

Income Before Preferred Dividends of Subsidiaries		1			2			10			12

Preferred Dividends of Subsidiaries		-			-			1			1

Net Income	$	1		$	2		$	9		$	11

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,
	2006		2005
ASSETS
Current Assets:
Cash and cash equivalents	$	23	$	3
Accounts receivable – trade (less allowance for doubtful
accounts of $6 and $5, respectively)		44		61
Unbilled revenue		34		59
Accounts receivables – affiliates		5		18
Note receivable – Resources Company		-		42
Materials and supplies		65		85
Other current assets		43		50
Total current assets		214		318
Property and Plant, Net		1,209		1,212
Investments and Other Assets:
Investments in leveraged leases		-		21
Goodwill		575		575
Intangible assets		58		62
Other assets		19		35
Regulatory assets		11		11
Total investments and other assets		663		704
TOTAL ASSETS	$	2,086	$	2,234

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt	$	50	$	-
Borrowings from money pool		65		154
Intercompany note payable – Ameren		156		186
Accounts and wages payable		33		81
Accounts and wages payable – affiliates		44		28
Other current liabilities		51		55
Total current liabilities		399		504
Long-term Debt, Net		565		534
Preferred Stock of Subsidiary Subject to Mandatory Redemption		19		19
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		151		163
Accumulated deferred investment tax credits		8		9
Regulatory liabilities		46		41
Accrued pension and other postretirement benefits		250		251
Other deferred credits and liabilities		22		31
Total deferred credits and other liabilities		477		495
Preferred Stock of Subsidiary Not Subject to Mandatory Redemption		19		19
Commitments and Contingencies (Notes 2 and 8)
Stockholder's Equity:
Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding		-		-
Other paid-in capital		598		640
Retained earnings		1		-
Accumulated other comprehensive income		8		23
Total stockholder's equity		607		663
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	2,086	$	2,234

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,
		2006			2005
Cash Flows From Operating Activities:
Net income	$	9		$	11
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		50			51
Deferred income taxes and investment tax credits		(4	)		(13	)
Loss on sale of leveraged lease investments		4			-
Other		(1	)		(3	)
Changes in assets and liabilities:
Receivables, net		55			23
Materials and supplies		20			16
Accounts and wages payable		(26	)		(35	)
Taxes accrued		(13	)		(4	)
Assets, other		20			(1	)
Liabilities, other		(9	)		3
Pension and postretirement benefit obligations, net		1			7
Net cash provided by operating activities		106			55

Cash Flows From Investing Activities:
Capital expenditures		(42	)		(47	)
Proceeds from note receivable - Resources Company		42			-
Changes in money pool advances		-			3
Proceeds from sale of leveraged leases		11			-
Purchases of emission allowances		(12	)		(21	)
Sales of emission allowances		1			1
Net cash provided by (used in) investing activities		-			(64	)

Cash Flows From Financing Activities:
Dividends on common stock		(50	)		(30	)
Capital issuance costs		(1	)		-
Changes in money pool borrowings		(89	)		(82	)
Proceeds (repayment) - note payable - Ameren		(30	)		22
Redemptions, repurchases, and maturities:
Long-term debt		(12	)		(6	)
Issuance of long-term debt		96			-
Capital contribution from parent		-			101
Net cash provided by (used in) financing activities		(86	)		5

Net change in cash and cash equivalents		20			(4	)
Cash and cash equivalents at beginning of year		3			7
Cash and cash equivalents at end of period	$	23		$	3

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,
	2006			2005			2006			2005
Operating Revenues:
Electric	$	98		$	99		$	190		$	192
Gas		48			46			198			171
Total operating revenues		146			145			388			363

Operating Expenses:
Fuel and purchased power		31			37			56			68
Gas purchased for resale		32			28			151			119
Other operations and maintenance		52			40			93			84
Depreciation and amortization		17			16			34			33
Taxes other than income taxes		4			4			13			10
Total operating expenses		136			125			347			314

Operating Income		10			20			41			49

Other Expenses:
Miscellaneous expense		(1	)		(2	)		(2	)		(3	)
Total other expenses		(1	)		(2	)		(2	)		(3	)

Interest Charges		4			3			8			7

Income Before Income Taxes		5			15			31			39

Income Taxes (Benefit)		(3	)		5			6			13

Net Income		8			10			25			26

Preferred Stock Dividends		1			-			1			1

Net Income Available to Common Stockholder	$	7		$	10		$	24		$	25

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,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	22		$	2
Accounts receivable – trade (less allowance for doubtful
accounts of $6 and $5, respectively)		45			61
Unbilled revenue		34			59
Accounts receivable – affiliates		2			14
Materials and supplies		65			87
Other current assets		40			43
Total current assets		208			266
Property and Plant, Net		1,219			1,214
Investments in Leveraged Leases		-			21
Intangible Assets		7			4
Other Assets		25			41
Regulatory Assets		11			11
TOTAL ASSETS	$	1,470		$	1,557

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	50		$	-
Borrowings from money pool		66			161
Accounts and wages payable		32			81
Accounts and wages payable – affiliates		43			26
Other current liabilities		44			48
Total current liabilities		235			316
Long-term Debt, Net		168			122
Preferred Stock Subject to Mandatory Redemption		19			19
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		153			167
Accumulated deferred investment tax credits		8			8
Regulatory liabilities		195			187
Accrued pension and other postretirement benefits		150			146
Other deferred credits and liabilities		22			30
Total deferred credits and other liabilities		528			538
Commitments and Contingencies (Notes 2 and 8)
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		413			415
Retained earnings		93			119
Accumulated other comprehensive income (loss)		(5	)		9
Total stockholders' equity		520			562
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,470		$	1,557

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,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	25		$	26
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		40			42
Deferred income taxes and investment tax credits		(3	)		(8	)
Loss on sale of leveraged leases		6			-
Other		(1	)		3
Changes in assets and liabilities:
Receivables, net		53			22
Materials and supplies		22			17
Accounts and wages payable		(26	)		(32	)
Taxes accrued		(17	)		-
Assets, other		15			(1	)
Liabilities, other		(5	)		(5	)
Pension and postretirement benefit obligations, net		4			13
Net cash provided by operating activities		113			77

Cash Flows From Investing Activities:
Capital expenditures		(42	)		(47	)
Proceeds from sale of leveraged leases		11			-
Purchases of emission allowances		(12	)		(21	)
Sales of emission allowances		1			1
Net cash used in investing activities		(42	)		(67	)

Cash Flows From Financing Activities:
Dividends on common stock		(50	)		(20	)
Dividends on preferred stock		(1	)		(1	)
Capital issuance costs		(1	)		-
Changes in money pool borrowings		(95	)		(91	)
Issuance of long-term debt		96			-
Capital contribution from parent		-			101
Net cash used in financing activities		(51	)		(11	)

Net change in cash and cash equivalents		20			(1	)
Cash and cash equivalents at beginning of year		2			2
Cash and cash equivalents at end of period	$	22		$	1

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 June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Operating Revenues:
Electric	$	271		$	268		$	513		$	503
Gas		67			73			322			270
Other		1			-			1			-
Total operating revenues		339			341			836			773

Operating Expenses:
Purchased power		171			165			348			322
Gas purchased for resale		36			44			237			190
Other operations and maintenance		61			60			120			102
Depreciation and amortization		18			19			37			40
Taxes other than income taxes		16			18			38			40
Total operating expenses		302			306			780			694

Operating Income		37			35			56			79

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

Interest Charges		12			11			24			21

Income Before Income Taxes		25			25			32			61

Income Taxes		9			10			12			24

Net Income		16			15			20			37

Preferred Stock Dividends		-			-			1			1

Net Income Available to Common Stockholder	$	16		$	15		$	19		$	36

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,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	1		$	-
Accounts receivable (less allowance for doubtful
accounts of $8 and $8, respectively)		114			155
Unbilled revenue		85			118
Accounts receivable – affiliates		13			5
Materials and supplies		91			122
Other current assets		13			31
Total current assets		317			431
Property and Plant, Net		2,075			2,035
Investments and Other Assets:
Investment in IP SPT		7			7
Goodwill		326			326
Other assets		52			44
Regulatory assets		198			194
Accumulated deferred income taxes		-			19
Total investments and other assets		583			590
TOTAL ASSETS	$	2,975		$	3,056

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt to IP SPT	$	64		$	72
Borrowings from money pool		54			75
Accounts and wages payable		93			145
Accounts and wages payable – affiliates		18			29
Taxes accrued		-			15
Other current liabilities		105			135
Total current liabilities		334			471
Long-term Debt, Net		776			704
Long-term Debt to IP SPT		138			184
Deferred Credits and Other Liabilities:
Regulatory liabilities		108			80
Accrued pension and other postretirement benefits		256			255
Other deferred credits and other noncurrent liabilities		57			75
Total deferred credits and other liabilities		421			410
Commitments and Contingencies (Notes 2 and 8)
Stockholders’ Equity:
Common stock, no par value, 100.0 shares authorized – 23.0 shares outstanding		-			-
Other paid-in-capital		1,196			1,196
Preferred stock not subject to mandatory redemption		46			46
Retained earnings		65			46
Accumulated other comprehensive loss		(1	)		(1	)
Total stockholders’ equity		1,306			1,287
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,975		$	3,056

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,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	20		$	37
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		15			9
Amortization of debt issuance costs and premium/discounts		2			2
Deferred income taxes		20			39
Changes in assets and liabilities:
Receivables, net		66			40
Materials and supplies		31			20
Accounts and wages payable		(61	)		1
Assets, other		12			(19	)
Liabilities, other		(24	)		16
Pension and other postretirement benefit obligations, net		5			4
Net cash provided by operating activities		86			149

Cash Flows From Investing Activities:
Capital expenditures		(83	)		(61	)
Changes in money pool advances		-			69
Net cash provided by (used in) investing activities		(83	)		8

Cash Flows From Financing Activities:
Dividends on common stock		-			(40	)
Dividends on preferred stock		(1	)		(1	)
Capital issuance costs		(1	)		-
Changes in money pool borrowings, net		(21	)		-
Redemptions and repurchases of long-term debt		(46	)		(113	)
Issuances of long-term debt		75			-
Transitional funding trust notes overfunding		(8	)		(3	)
Net cash used in financing activities		(2	)		(157	)

Net change in cash and cash equivalents		1			-
Cash and cash equivalents at beginning of year		-			5
Cash and cash equivalents at end of period	$	1		$	5

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, 2006

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 was registered with the SEC as a public utility holding company under PUHCA 1935 until that act was repealed effective February 8, 2006. Ameren’s primary asset is the common stock of its subsidiaries. Ameren’s subsidiaries, which are separate, independent legal entities with separate businesses, assets and liabilities, operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses and non-rate-regulated electric generation businesses in Missouri and Illinois, as discussed below. Dividends on Ameren’s common stock 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 primarily 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 through UE and Development Company, which each own 40% of EEI. Ameren consolidates EEI for financial reporting purposes, while UE reports EEI under the equity method. EEI is a significant equity investment of UE, as determined by SEC rules. The following table presents summarized financial information of EEI (in millions) for the three months and six months ended June 30, 2006 and 2005.

	Three Months				Six Months
	2006		2005		2006		2005
Operating revenues	$	88	$	42	$	184	$	84
Operating income		42		6		98		11
Net income		26		3		60		5

The financial statements of the Ameren Companies (except CIPS) are prepared on a consolidated basis and therefore include the accounts of their majority-owned subsidiaries, as applicable. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results for a full year. Certain reclassifications have been made to make prior period financial statements conform to 2006 reporting including the reclassification of emission allowance purchases and sales from Operating Activities to Investing Activities on the Statement of Cash Flows for Ameren, UE, Genco, CILCORP and CILCO. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005.

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, 2006 and 2005, due to an immaterial number of stock options, restricted stock units and performance share units outstanding.

Accounting Changes and Other Matters

SFAS No. 123 (revised 2004), Share-based Payment

Effective January 1, 2003, Ameren adopted the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-based Compensation” (SFAS 123), by using the prospective method of adoption under SFAS No. 148, “Accounting for Stock-based Compensation - Transition and Disclosure,” for all employee awards granted or with terms modified on or after January 1, 2003.

Effective January 1, 2006, Ameren adopted SFAS No. 123 (revised 2004) “Share-based Payment” (SFAS 123R), which revises SFAS 123 and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS 123R requires companies to measure the cost of employee services received in exchange for an award of equity instruments by the grant-date fair value of the award. Ameren adopted SFAS 123R utilizing the modified prospective application. Under the modified prospective approach, SFAS 123R applies to all awards granted or modified after the effective date.

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

In the first quarter of 2006, Ameren’s Board of Directors approved the 2006 Omnibus Incentive Compensation Plan (“2006 Plan”), subject to shareholder approval, which was obtained on May 2, 2006. The 2006 Plan prospectively replaces the Long-term Incentive Plan of 1998, as amended (“1998 Plan”), effective May 2, 2006. The 2006 Plan provides for a maximum number of 4,000,000 common shares available for grant to eligible employees and directors. No new awards may be granted under the 1998 Plan; however, previously granted awards continue to vest or be exercisable in accordance with their original terms and conditions. The 2006 Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.

A summary of nonvested shares as of June 30, 2006, and changes during the six-month period ended June 30, 2006, under the 1998 Plan and the 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, 2006		-		$	-		575,469		$	44.91
Granted^(a)		350,640			56.07		-			-
Dividends on restricted shares		-			-		9,124			50.44
Forfeitures		-			-		(2,436	)		47.58
Vested^(b)		(1,319	)		56.07		(213,198	)		43.38
Nonvested at June 30, 2006		349,321		$	56.07		368,959		$	45.79

(a)

Includes 220,434 performance share units (“share units”) granted to certain executive and non-executive officers and other eligible employees in February 2006 under the 1998 Plan and 130,206 share units granted in February 2006 under the 2006 Plan to certain executive officers subject to shareholder approval, which was obtained on May 2, 2006. The share units granted under the 2006 Plan were not considered as granted until approved by shareholders. Accordingly, compensation expense recognition for these awards commenced in May 2006.

(b)	Share units issued under the 1998 Plan vested due to employee death and 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.

A share unit will vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, Ameren has achieved certain performance goals and the individual remains employed by Ameren. The exact number of shares issued pursuant to a share unit will vary from 0% to 200% of the target award depending on actual company performance relative to the performance goals. If a share unit vests, Ameren will issue the related shares to the employee two years after vesting, but dividends on the shares will be paid to the employee at the same time they are paid to other shareholders.

The fair value of each share unit awarded in February 2006 under the 1998 Plan was determined to be $56.07 based on Ameren’s closing common share price of $50.69 per share at the grant date and lattice simulations utilized to estimate expected share payout based on Ameren’s attainment of certain financial measures relative to the designated peer group. The significant assumptions utilized to calculate fair value also included a three-year risk-free rate of 4.65%, dividend yields ranging from 2.3% to 4.6% for the peer group, volatility ranging from 13.87% to 22.45% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend over the performance period. The fair value of each share unit granted in May 2006 under the 2006 Plan was determined to be $56.07 based on assumptions similar to the February 2006 grant.

Ameren recorded compensation expense of $3 million and $1 million for the quarters ended June 30, 2006 and 2005, respectively, and a related tax benefit of less than $1 million and $2 million for the quarters ended June 30, 2006 and 2005, respectively. Ameren recorded compensation expense of $5 million and $3 million for each of the six month periods ended June 30, 2006 and 2005, respectively, and a related

tax benefit of less than $1 million and $2 million for the six month periods ended June 30, 2006 and 2005, respectively. As of June 30, 2006, total compensation cost of $24 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 3 years.

Ameren has not granted any stock options subsequent to its adoption of SFAS 123, and the options granted prior to the SFAS 123 adoption were fully expensed during 2004. Therefore, there is no expense from stock options for the three and six month periods ended June 30, 2006, and there is no pro forma expense for the year-ago periods. See Note 1 - Summary of Significant Accounting Policies and Note 12 - Stock-based Compensation in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005, for additional information.

FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48)

FIN 48 establishes that the financial statement effects of a tax position taken or expected to be taken in a tax return are to be recognized in the financial statements when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. In addition, FIN 48 requires expanded disclosure with respect to the uncertainty in income taxes and is effective as of the beginning of our 2007 fiscal year. We are still in the process of determining the impact the adoption of FIN 48 will have on our results of operations, financial position and liquidity; however, at this time, we do not expect the impact of adoption to be material.

Proposed SFAS on Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)

Issued in March 2006, this proposed SFAS would require employers to recognize the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, in their balance sheets. Existing unrecognized net gains and losses and unrecognized prior-service costs and credits, as well as any new gains and losses and new prior-service costs and credits, would be recognized as part of the balance sheet net pension asset or liability, with a corresponding credit or charge to OCI. Existing unrecognized net transition assets or obligations would also be recognized as part of the balance sheet pension and other postretirement benefit asset or liability, but the corresponding adjustment upon adoption would be to retained earnings. If approved, the standard would require Ameren to recognize additional pension and other postretirement benefit obligations of approximately $234 million and $308 million, respectively, and write-off a $79 million pension-related intangible asset, based on the funded status of Ameren’s defined benefit postretirement plans as of December 31, 2005. Ameren would also be required to record a deferred tax benefit associated with the temporary differences between the liabilities recognized for book and tax purposes. In addition, to the extent Ameren determines that it is probable that the additional liabilities will be recoverable through rates charged by Ameren’s rate-regulated businesses (UE, CIPS, CILCO and IP), a regulatory asset may be recorded. If approved in its current format, the provisions of this proposed SFAS would be applied retroactively for the year ending December 31, 2006.

Revenue

Interchange Revenues

The following table presents the interchange revenues included in Operating Revenues - Electric for the three months and six months ended June 30, 2006 and 2005. See Note 7 - Related Party Transactions for further information on affiliate interchange revenues.

	Three Months					Six Months
	2006		2005			2006		2005
Ameren^(a)	$	158	$	148		$	350	$	254
UE		103		129			241		226
CIPS		1		8			2		17
Genco		41		67			90		109
CILCORP		9		11			19		26
CILCO		9		11			19		26
IP		-		(b	)		-		(b	)

(a)

Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. Includes interchange revenues at Marketing Company and EEI of $85 million and $174 million for the three months and six months ended June 30, 2006, respectively (2005 - $8 million and $15 million, respectively).

(b)	Less than $1 million.

Purchased Power

The following table presents the purchased power expenses included in Operating Expenses - Fuel and Purchased Power for the three months and six months ended June 30, 2006 and 2005. See Note 7 - Related Party Transactions for further information on affiliate purchased power transactions.

	Three Months				Six Months
	2006		2005		2006		2005
Ameren^(a)	$	277	$	244	$	550	$	442
UE		68		66		135		104
CIPS		113		105		230		191
Genco		89		68		185		117
CILCORP		6		13		8		22
CILCO		6		13		8		22
IP		171		165		348		322

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. Includes purchased power for EEI of $2 million and $3 million for the three months and six months ended June 30, 2006, respectively (2005 - $1 million and $1 million, respectively).

Excise Taxes

Excise taxes reflected on Missouri electric, Missouri gas, and Illinois gas customer bills are imposed on us. They are recorded gross in Operating Revenues and Taxes Other than Income Taxes on each company’s statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer. They are recorded as tax collections payable and included in Other Current Liabilities. 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, 2006 and 2005:

	Three Months				Six Months
	2006		2005		2006		2005
Ameren	$	39	$	41	$	85	$	81
UE		27		28		52		50
CIPS		3		2		9		7
CILCORP		2		3		6		5
CILCO		2		3		6		5
IP		7		8		18		19

Asset Retirement Obligations

AROs at Ameren and UE increased compared to December 31, 2005 to reflect the accretion of obligations to their fair values.

NOTE 2 - RATE AND REGULATORY MATTERS

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

Missouri

Electric

With the expiration of an electric rate moratorium that provided for no changes in UE’s electric rates before July 1, 2006, UE filed in July 2006 a request with the MoPSC for an increase in base rates for electric service. UE’s filing included a proposed average increase in electric rates of 17.7% or $361 million. UE is proposing to limit the increase on residential rates to 10%, allocating requested revenue amounts above that level to other customer classes. This rate increase filing was based on a test year ended June 30, 2006, and included known and measurable items through January 1, 2007. Since UE’s last electric rate case in 2002, UE has invested approximately $2.5 billion in its electric operations. Those investments included more than $700 million for 2,600 megawatts of new generation to meet growing customer power demands. UE’s electric rate request includes, among other items, the following features:

·	A requested return on equity of 12%, and a rate base of $5.8 billion with a capital structure including about 52% equity.

·	A request for fuel, purchased power, and environmental cost recovery mechanisms under the provisions of a Missouri state law enacted in 2005. See MoPSC Rulemaking Proceeding below in this Note for additional information.

·	A proposed alternative mechanism for the MoPSC’s consideration to share off-system sales margins with ratepayers.

·	An increase in depreciation rates.

·	Renewable energy proposals, including the addition of 100 megawatts of renewable energy by 2010.

·	Commitments to offer low income energy assistance and energy conservation programs.

·	Costs incurred related to the December 2005 failure of UE’s Taum Sauk pumped-storage hydroelectric plant for the clean-up of a nearby park, reimbursement of state costs and resolution of individuals’ claims were excluded from the revenue increase request.

The MoPSC staff and other stakeholders will review UE’s rate adjustment request and, after their analyses, may also make recommendations as to electric rate adjustments. A decision from the MoPSC is expected no later than June 2007.

Gas

In July 2006, UE filed a request with the MoPSC for an $11 million increase in natural gas delivery rates, based on an 11.5% return on equity, and a rate base of $200 million with a capital structure including about 52% equity. The MoPSC staff and other stakeholders will review UE’s rate adjustment request and, after their analyses, may also make recommendations as to gas rate adjustments. A decision from the MoPSC is expected no later than June 2007.

MoPSC Rulemaking Proceeding

In July 2005, a new law was enacted that enables the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri’s utilities. The law also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental cost recovery mechanism and prudency reviews, among other things. The proposed rules implementing the fuel and purchased power surcharge were filed with the Missouri Secretary of State in June 2006. The public comment period on these rules ends on September 7, 2006. Rules for the fuel and purchased power cost recovery mechanism are expected to be effective by December 31, 2006. We are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted. UE requested fuel, purchased power and environmental cost

recovery mechanisms in its electric rate case filed with the MoPSC in July 2006.

Illinois

Electric

By 2002, the power market for Illinois residential, commercial and industrial customers of UE (whose Illinois utility business was transferred to CIPS in 2005), CIPS, CILCO and IP was opened to alternative electric suppliers under the Illinois Customer Choice Law. Under the Illinois Customer Choice Law, UE, CIPS, CILCO and IP rates initially were frozen through January 1, 2005. An amendment to the Illinois Customer Choice Law extended the rate freeze through January 1, 2007. As a result of this extension, and pursuant to ICC orders, CIPS and Marketing Company extended their power supply agreements through December 31, 2006, as did CILCO and AERG. See Note 7 - Related Party Transactions for a discussion of the affiliate power supply agreements.

During 2004, the ICC conducted workshops to seek input from interested parties on the framework for retail electric rate determination and power procurement after the current Illinois electric rate freeze expires on January 1, 2007, and supply contracts expire on December 31, 2006.

In February 2005, CIPS, CILCO and IP filed with the ICC a proposed process for power procurement through an ICC-monitored auction, including, among other things, a rate mechanism to pass power supply costs directly through to customers. The form of power supply would meet the full requirements of each utility, and the risk of fluctuations in power supply requirements would be borne by the supplier. On January 24, 2006, the ICC issued an order which unanimously approved the Ameren Illinois utilities’ proposed power procurement auction and the related tariffs, including the retail rates by which power supply costs would be passed through to customers. The order includes the following key findings and provisions:

·	The auction proposal is reasonably designed to enable CIPS, CILCO and IP to procure power supply in a competitive and least-cost manner.

·	The first auction is to take place in the first 10 days of September 2006.

There is a limitation of 35% on the amount of power any single supplier can provide the Ameren Illinois utilities’ expected annual load. Genco and AERG, through Marketing Company, and UE will have the opportunity to participate in the power procurement auction for 2007, subject to this limit. Ameren-affiliated companies would be considered one supplier for purposes of this limitation.

·	Requires a portfolio of one-, two-, and three-year supply contracts.

·	Allows full cost recovery through a rate mechanism.

·	Requires an annual, postauction prudence review by the ICC.

On January 26, 2006, CIPS, CILCO and IP filed with the ICC a request for rehearing with regard to the provision of the January 2006 order, which requires an annual, postauction prudence review to be performed by the ICC. CIPS, CILCO and IP asserted in their request that there is no basis for such a prudence review. In February 2006, the ICC denied this request for rehearing, and CIPS, CILCO and IP filed an appeal in the appellate court for the Fourth District in Illinois on February 9, 2006.

Certain Illinois legislators, the Illinois attorney general, the Illinois governor and other parties have sought and continue to seek to block the power procurement auction and/or the recovery of related costs for power supply resulting from the auction through rates to customers. In May 2005, the Illinois attorney general, the CUB and the ELPC filed a motion to dismiss the Ameren Illinois utilities’ proposed power procurement auction with the ICC on the basis that the ICC did not have authority to approve market-based rates for electric service that have not been “declared competitive” pursuant to Section 16-113 of the Illinois Public Utilities Act. This motion and a subsequent appeal were denied by the administrative law judge in the case and by the ICC, respectively.

In September 2005, Illinois Governor Rod Blagojevich sent a letter to the ICC expressing his opposition to CIPS’, CILCO’s and IP’s proposed power procurement auction process and requesting dismissal of the pending proceeding for approval of such process. CIPS, CILCO and IP responded to the governor's letter citing legal deficiencies in his position and the potential adverse consequences that could result if his position is ultimately sustained. Copies of the governor’s letter and the Ameren Illinois utilities’ response letter appear as Exhibits 99.1 and 99.2, respectively, to the Current Report on Form 8-K dated September 15, 2005. Also in September 2005, the Illinois attorney general, the Cook County state’s attorney, the CUB and the ELPC filed a complaint in the Circuit Court of Cook County, Illinois, against the ICC and the individual ICC commissioners making claims similar to those included in their motion to dismiss that was denied. The complaint asked the court to determine that the ICC lacks authority to approve the auction proposal. It sought injunctive relief prohibiting the ICC from approving the proposals by CIPS, CILCO and IP. On January 20, 2006, the Circuit Court of Cook County, Illinois, entered an order dismissing the complaint with prejudice.

Both the Illinois governor's letter and the attorney general's lawsuit discussed in the previous paragraph assert that the energy component of CIPS’, CILCO’s and IP’s retail rates for electricity should not be based on the costs to

procure energy and capacity in the wholesale market. Although CIPS, CILCO and IP have received favorable rulings from the ICC and the Circuit Court of Cook County with respect to their proposals, we anticipate that certain Illinois legislators, the Illinois attorney general, the Illinois governor, and others will persist in their efforts to block the power procurement auction and the recovery of related costs through rates to customers. In February 2006, the Illinois attorney general, CUB and ELPC filed with the ICC requests for a rehearing of the ICC’s January 24, 2006, order approving the Ameren Illinois utilities power procurement auction and related tariffs. Their arguments for a rehearing were generally similar to those that they previously raised as discussed above. In March 2006, the ICC denied these requests for rehearing. In March and April 2006, these parties filed appeals in the appellate court for the First District in Illinois. In June 2006, the Illinois attorney general filed a petition with the Supreme Court of Illinois seeking a direct and expedited review of appeals filed with Illinois district courts by various parties of the ICC’s January 2006 order approving the Illinois power procurement auction and a stay on implementation of the order. In this petition, the Illinois attorney general raised similar arguments to those previously raised as discussed above. In August 2006, the Supreme Court of Illinois denied the Illinois attorney general’s petition and ordered that the appeals be consolidated in the appellate court for the Second District in Illinois. The matter is still pending. We are unable to predict whether such efforts will ultimately be successful. Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner could result in material adverse consequences to Ameren and the Ameren Illinois utilities. As noted in their response letter to the Illinois governor, these consequences could include a significant drop in credit ratings (possibly to below investment-grade status), a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, impaired customer service, job losses, and financial insolvency.

With regard to the delivery service component of customer rates, CIPS, CILCO and IP filed rate cases with the ICC in December 2005 to modify their electric delivery service rates effective January 2, 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $202 million in the aggregate (CIPS - $14 million, CILCO - $43 million and IP - $145 million). To mitigate the impact of these requested increases on residential customers, CILCO and IP proposed a two-year phase-in with increases for average residential delivery rates capped in the first year. The phase-in would decrease requested rate increases by $10 million and $36 million for CILCO and IP, respectively, in the first year. In June 2006, the ICC staff filed rebuttal testimony recommending increases in revenues for electric delivery services for the Ameren Illinois utilities aggregating $120 million (CIPS - $1 million, CILCO - $30 million and IP - $89 million). In April 2006, the Illinois attorney general recommended increases in revenues for electric delivery services aggregating $71 million for the Ameren Illinois utilities (CIPS - $7 million decrease, CILCO - $19 million increase and IP - $59 million increase). In subsequent testimony, the Illinois attorney general accepted certain of the Ameren Illinois utilities’ positions increasing the estimated aggregate recommended revenue increase to $100 million. Other parties also made recommendations in the case. The ICC has until November 2006 to render a decision in these rate cases.

The Illinois legislature held hearings in 2005 and 2006 regarding the framework for retail rate determination and power procurement. In February 2006, legislation was introduced in the Illinois House of Representatives that would extend the electric rate freeze in Illinois through 2010. CIPS, CILCO and IP strongly believe that an extension of the electric rate freeze in Illinois would not be in the best interests of any of the Ameren Illinois utilities or their customers and have been working with key stakeholders in Illinois to develop a constructive rate increase phase-in plan for residential customers to address the potential significant increases in customer rates for the Ameren Illinois utilities beginning in 2007. We believe that a rate increase phase-in plan would need to allow for deferral of a portion of the power procurement costs, with provision for full and timely recovery of all deferred costs in a manner that supports solid investment-grade credit ratings for CIPS, CILCO and IP. We believe a rate increase phase-in plan, providing for deferral of costs with certainty of full and timely recovery of any deferred costs, would require legislation in Illinois. In March 2006, legislation was introduced in the Illinois House of Representatives that would allow the deferral of a portion of the power procurement costs and would authorize the ICC to permit a utility with fewer than one million retail customers to form special purpose finance vehicles to issue securitization bonds to recover the deferred costs, with interest. CIPS, CILCO and IP each have less than one million retail customers. Securitization would allow these special purpose vehicles to issue debt securities and use the proceeds to pay the utilities immediately upon issuance of the bonds for the deferred power costs for which the utilities did not receive reimbursement from customers during a phase-in deferral period. Customers would fund, through dedicated charges included on their electric bills, a future payment stream that would be used to service the securitized debt. In effect, through these dedicated charges utility customers would pay in the future for power used, but not paid for, during a phase-in deferral period. This approach has the effect of spreading over the life of the bonds, a period of up to 10 years, the potentially significant initial electric rate increase for residential customers that would otherwise be necessary to pay the power procurement costs on a current basis. If passed, this legislation would assist our Ameren Illinois utilities in maintaining their financial integrity while allowing them to

recover costs from customers over a longer term. We cannot predict what actions, if any, the Illinois legislature may ultimately take. In June 2006, the Ameren Illinois utilities filed with the ICC a rate increase phase-in and revenue securitization plan for residential customers similar to the proposed legislation outlined above that would relate to the deferral of power and supply costs for 2007 and 2008. Legislation would be needed for this plan to become effective. In July 2006, the Illinois attorney general filed a motion with the ICC to dismiss this plan. The Ameren Illinois utilities responded in July 2006 and the matter is currently pending before the ICC. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren.

Ameren, CIPS, CILCO and IP will continue to explore a number of legal and regulatory actions, strategies and alternatives to address these Illinois electric issues. There can be no assurance that Ameren and the Ameren Illinois utilities will prevail over the stated opposition by certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other stakeholders, or that the legal and regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois utilities are considering will be successful.

Federal

Hydroelectric License Renewal

In May 2005, UE, the U.S. Department of the Interior and various state agencies reached a settlement agreement that is expected to lead to FERC’s relicensing of UE’s Osage hydroelectric plant for another 40 years. The settlement must be approved by FERC. Approval and relicensure are expected in 2006. The current FERC license expired on February 28, 2006. Operations are permitted to continue under the expired license until the license renewal is approved.

Joint Dispatch Agreement

See Note 7 - Related Party Transactions for a description of the JDA among UE, CIPS and Genco.

January 2006 JDA Amendment

As a result of the February 2005 MoPSC order approving the transfer of UE’s Illinois service territory to CIPS that was completed on May 2, 2005, the provision in the JDA that determines the allocation between UE and Genco of margins from short-term sales of excess generation to third parties had to be modified. Specifically, the MoPSC order required an amendment so that margins on third-party short-term power sales of excess generation would be allocated between UE and Genco based on generation output, not on load requirements, as the agreement had provided. In March 2006, FERC approved the amendment filed by UE, CIPS and Genco, effective January 10, 2006. This change in the allocation methodology resulted in a $5 million and $14 million transfer of electric margins from Genco to UE during the three months and six months ended June 30, 2006, respectively.

Termination of JDA

On July 7, 2006, UE, CIPS and Genco mutually consented to waive a one-year termination notice requirement of the JDA and agreed to terminate it on December 31, 2006. This action with respect to the JDA will require acceptance by the FERC, a request for which was filed on August 1, 2006.

The benefits of the JDA to UE and Genco have changed recently due to the emergence of transparent wholesale markets, the dispatching of generation being conducted by MISO, and changes to the Illinois regulatory framework, among other things. As a result, UE believes the benefit it will receive from retaining the power it was transferring under the JDA to Genco at incremental cost will exceed the benefit it would have received from being able to call upon Genco's generation under the JDA at incremental cost. Since UE was prepared to immediately provide Genco with one-year notice of termination in June 2006, Genco believes the potential benefit it could receive from being able to call upon UE's generation through June 2007 is outweighed by, among other things, the negative consequences associated with the continued existence of the JDA past December 31, 2006. In particular, Genco believes that the JDA is no longer necessary or effective in dispatching Genco's generation jointly with that of UE due to changes in the marketplace for the sale of electricity, including the MISO Day Two Energy Market, and the centralized dispatching of generation by MISO. Additionally, the JDA is based on a combined control area for the UE and CIPS transmission facilities located in Missouri and Illinois, respectively. This combined control area creates operational inefficiencies for Genco to effectively participate through Marketing Company in the Illinois power procurement auction beginning January 1, 2007. In conjunction with terminating the JDA, Ameren's transmission-owning entities intend to restructure their control areas so as to have one control area in Missouri for UE's transmission facilities and one in Illinois for the transmission facilities of CIPS, CILCO and IP.

As a result of the termination of the JDA on December 31, 2006, UE and Genco will no longer have the obligation to provide power to each other. In 2005, Genco received from UE under the JDA net transfers of 8.7 million megawatthours of power at an average price of $18 per megawatthour and generated 14.2 million megawatthours of power from its plants at an average cost of approximately $18 per megawatthour. This power, along with 2.0 million megawatthours purchased from EEI, was used in 2005 to supply CIPS' load and other

wholesale and retail customers at an average selling price of $35 per megawatthour. In 2005, Genco also sold 3.3 million net megawatthours of power in the interchange market at an average price of $47 per megawatthour. Upon termination of the JDA, Genco will no longer receive the margins on sales that were supplied with power from UE.

Ameren's and UE’s earnings will be affected by the termination of the JDA when UE's rates are adjusted by the MoPSC. As discussed under Missouri Electric in this Note, UE filed a request in July 2006 with the MoPSC to increase its electric rates by $361 million. UE's requested increase is net of the decrease in its revenue requirement resulting from increased margins expected to result from the termination of the JDA.

The ultimate impact of the termination of the JDA and the MoPSC’s treatment of the effects of such termination in UE’s current rate case proceeding on the Ameren Companies’ results of operations, financial position, or liquidity cannot be predicted at this time.

Leveraged Leases

Ameren owns interests in certain assets that were acquired through the acquisition of CILCORP and financed as leveraged leases. By an order dated April 15, 2004, issued pursuant to PUHCA 1935, the SEC determined that certain nonutility interests and investments of CILCORP and its subsidiaries, including investments in several leveraged leases, are not retainable by Ameren. The April 2004 SEC order required that Ameren cause its subsidiaries to sell or otherwise dispose of the nonretainable interests. The nonretainable interests primarily consist of lease interests in commercial real estate properties and equipment. The SEC approved the divestiture transaction structure proposed by Ameren in December 2005.

Ameren, CILCORP and CILCO recognized net after-tax losses of $4 million, $4 million and $6 million, respectively, from the sale of two leveraged leases in the second quarter of 2006.

Ameren and several of its registrant and nonregistrant subsidiaries are pursuing the sale of its interests in its remaining four leveraged lease assets.

NOTE 3 - SHORT-TERM BORROWINGS AND LIQUIDITY

Short-term borrowings typically consist of commercial paper issuances and drawings under committed bank credit facilities.

The following table summarizes the short-term borrowing activity and relevant interest rates as of June 30, 2006 and December 31, 2005, respectively:

	Ameren			UE
June 30, 2006:
Average daily borrowings outstanding during 2006	$	272		$	258
Weighted-average interest rate during 2006		4.87	%		4.88	%
Peak short-term borrowings during 2006	$	586		$	470
Peak interest rate during 2006		5.50	%		5.50	%
December 31, 2005:
Average daily borrowings outstanding during 2005	$	162		$	135
Weighted-average interest rate during 2005		3.02	%		2.87	%
Peak short-term borrowings during 2005	$	578		$	424
Peak interest rate during 2005		4.71	%		4.52	%

At June 30, 2006, Ameren had $1.5 billion of committed credit facilities, consisting of two facilities each maturing in July 2010, in the amounts of $1.15 billion and $350 million. The entire amount of the $1.15 billion facility was available to Ameren; UE could directly borrow under this facility up to $500 million on a 364-day basis; and CIPS, Genco, CILCO, and IP could also each directly borrow under this facility up to $150 million, also on a 364-day basis.

On July 14, 2006, the $1.15 billion credit facility was amended. The amended facility will terminate on July 14, 2010 with respect to Ameren. UE and Genco will continue to have the option to seek an annual renewal on a 364-day basis after their initial termination dates. Effective July 13, 2006, the termination date for UE and Genco was extended to July 12, 2007. CIPS, CILCO and IP no longer have borrowing authority under this facility effective July 13, 2006, but temporarily remain parties to the agreement as discussed in the indebtedness provisions and other covenants section below. Under the amended facility, Ameren will continue to have $1.15 billion of borrowing availability. UE and Genco will have $500 million and $150 million, respectively, of borrowing availability.

Under the amended $1.15 billion credit facility, the principal amount of each revolving loan will be due and payable no later than the final maturity of the facility in the case of Ameren and the last day of the then applicable

364-day period in the case of UE and Genco. The principal amount of each loan will be due and payable at the end of the interest period applicable to it, which shall not be later than the final maturity date of the facility. Swingline loans will be made on same-day notice and will mature five business days after they are made.

Ameren, UE and Genco will use the proceeds of any borrowings under the amended facility for general corporate purposes, including for working capital, commercial paper liquidity support and to fund loans under the Ameren money pool arrangements. See Exhibit 10.1 to the Current Report on Form 8-K, dated July 18, 2006, for a copy of the amended facility.

On July 14, 2006, CIPS, CILCORP, CILCO, IP and AERG entered into a new $500 million multiyear, senior secured credit facility. Borrowing authority under this facility was effective immediately for AERG and CILCORP. The ability of CIPS, CILCO and IP to borrow under this facility is subject to the receipt of necessary regulatory approvals, which are expected to be received in the third quarter of 2006, and the issuance by CIPS, CILCO and IP of mortgage bonds as security as described below. These companies will continue to have access to short-term funding via Ameren’s utility money pool and other intercompany borrowing arrangements. Once CIPS, CILCO and IP are able to borrow under this new facility, they will be removed as parties to the $1.15 billion credit facility.

The obligations of each borrower under the new facility are several and not joint, and are not guaranteed by Ameren or any other subsidiary of Ameren. The maximum amount available to each borrower, including for issuance of letters of credit on its behalf, is limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $150 million, IP - $150 million and AERG - $200 million. The borrowing companies will use the proceeds of any borrowings for working capital and other general corporate purposes; however, a portion of the borrowings by AERG may be limited to financing or refinancing the development, management and operation of any of its projects or assets. The new facility will terminate on January 14, 2010.

Subject to the receipt of regulatory approval, the obligations of CIPS, CILCO and IP under the new facility will be secured by the issuance of mortgage bonds by each such utility under its respective mortgage indenture. The obligations of CILCORP under the facility are secured by a pledge of the common stock of CILCO. The obligations of AERG are secured by a mortgage and security interest in its E.D. Edwards and Duck Creek generating stations and related licenses, permits and similar rights. See Exhibit 10.2 to the Current Report on Form 8-K, dated July 18, 2006, for a copy of the new facility.

As a condition to the amendment of the $1.15 billion credit facility and the closing of the new $500 million credit facility, effective July 14, 2006, Ameren terminated its $350 million credit facility. Ameren was the only borrower under this agreement, and there was no early termination penalty.

The $1.15 billion credit facility, and the $350 million credit facility, prior to its termination, were used to support our commercial paper programs that include all outstanding external short-term debt of Ameren and UE as of June 30, 2006 and December 31, 2005. The $1.15 billion amended facility will continue to support Ameren’s and UE’s commercial paper programs. Access to the $1.15 billion credit facility and the $500 million credit facility for the Ameren Companies are subject to reduction as they are used by affiliates.

In April 2006, EEI’s $20 million bank credit facility expired and was not renewed.

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.

Through the utility money pool, the pool participants can access the committed credit facility at Ameren. The availability of funds is determined by funding requirement limits established by regulatory authorizations. The average interest rate for borrowing under the utility money pool for the three months and six months ended June 30, 2006, was 5.0% and 4.7%, respectively (2005 - 3.0% and 2.7%, respectively).

Non-state-regulated Ameren subsidiaries, including Genco and AERG, have the ability to access funding from Ameren’s credit facilities through a non-state-regulated subsidiary money pool agreement subject to applicable regulatory short-term borrowing authorizations. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months and six months ended June 30, 2006, was 4.6% and 4.5%, respectively (2005 - 5.5% and 6.9%, respectively).

The total amount available to the money pool participants at any time is reduced by the amount of borrowings by their affiliates under existing agreements and is increased to the extent that other pool participants advance surplus funds to the money pool.

See Note 7 - 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, 2006 and 2005.

Indebtedness Provisions and Other Covenants

Ameren’s bank credit facilities contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets, and merge with other entities. As discussed

above, the $1.15 billion credit facility was amended effective July 14, 2006. The provisions in the amended facility are similar to those in the prior facility, including the covenant that limits total indebtedness of Ameren, UE and Genco to 65% of total capitalization pursuant to a calculation defined in the facility. Exceeding these debt levels would result in a default under the credit arrangements.

The amended $1.15 billion credit facility also contains default provisions similar to those in the prior facility, including cross defaults, with respect to a borrower under the facility, that can result from the occurrence of an event of default under any other facility covering indebtedness of that borrower or certain of its subsidiaries in excess of $50 million in the aggregate. The obligations of Ameren, UE and Genco under the amended facility remain several and not joint, and except under limited circumstances, the obligations of UE and Genco are not guaranteed by Ameren or any other subsidiary. Once CIPS, CILCO and IP are no longer parties to this agreement, which occurs when they obtain the ability to borrow under their new facility as discussed above, they will no longer be considered subsidiaries for purposes of the cross default provisions. This is expected to occur in the third quarter of 2006.

Under the amended $1.15 billion credit facility, (i) restrictions apply limiting investments in and other transfers to CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries by Ameren and certain subsidiaries and (ii) CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries are excluded for purposes of determining compliance with the 65% total consolidated indebtedness to total consolidated capitalization financial covenant that remains in the amended facility. These restrictions, as well as the capitalization financial covenant, will continue to apply to CIPS, CILCO and IP until such time as each ceases to be subject to the covenants of the amended facility. CIPS, CILCO and IP will continue to be subject to the covenants of the amended facility until such time as the conditions to their borrowing under the new $500 million credit facility are satisfied and they have provided notice of termination of their status under the amended facility, both of which are expected to occur in the third quarter of 2006.

The new $500 million credit facility entered into by CIPS, CILCORP, CILCO, IP and AERG, discussed above, limits the indebtedness of each borrower to 65% of consolidated total capitalization pursuant to a calculation set forth in the facility. Events of default under this facility apply separately to each borrower (and, subject to exceptions, their subsidiaries), and an event of default under this facility does not constitute an event of default under the amended $1.15 billion credit facility and vice versa. In addition, 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 by either Moody’s or S&P, then such borrower may not make any dividend or distribution on any shares of its capital stock while such below investment-grade credit rating is in effect. A similar restriction applies to AERG if its debt to operating cash flow ratio, as set forth in the facility, is below a specified ratio. Notwithstanding the two prior sentences, each borrower may make dividends or distributions on shares of its capital stock during any fiscal year of such borrower not to exceed $10 million. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured long-term debt credit rating to below investment-grade causing it to be subject to this dividend payment limitation. The other borrowers are not currently limited in their dividend payments by this provision of the new credit facility.

This new facility also limits the amount of other secured indebtedness issuable by each borrower as follows: for CIPS, CILCO and IP, other secured debt is limited to that permitted under their respective mortgage indentures. For CILCORP, other secured debt is limited to $550 million secured by the pledge of CILCO stock, and for AERG, other secured debt is limited to $200 million secured on an equal basis with its obligations under the new facility. The new facility provides that CIPS, CILCO and IP will agree to reserve future bonding capacity under their respective mortgage indentures (that is, agree to forego the issuance of additional mortgage bonds otherwise permitted under the terms of each mortgage indenture) in the following amounts: CIPS, prior to December 31, 2007 - $50 million, on and after December 31, 2007 but prior to December 31, 2008 - $100 million, on and after December 31, 2008 - $150 million; CILCO - $25 million; and IP - $100 million. In addition, the new credit facility prohibits CILCO from issuing any preferred stock if after giving effect to such issuance the aggregate liquidation value of all CILCO preferred stock issued after July 14, 2006 would exceed $50 million.

As of June 30, 2006, the ratio of total indebtedness to total capitalization (calculated in accordance with the provisions of the credit facilities in effect at that time) for Ameren, UE, CIPS, Genco, CILCO, and IP was 50%, 51%, 47%, 56%, 36% and 44%, respectively.

None of Ameren’s revolving credit facilities or financing arrangements contain credit rating triggers. At June 30, 2006, the Ameren Companies were in compliance with their credit facility provisions and covenants.

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) plans, pursuant to effective SEC Form S-8 registration statements, Ameren issued a total of 0.6 million new shares of common stock valued at $30 million and 1.1 million new shares valued at $57 million in the three months and six months ended June 30, 2006, respectively.

UE’s debt increased $240 million in the first quarter of 2006 as a result of the capital lease assigned to it in connection with the acquisition from affiliates of NRG Energy, Inc. of a 640-megawatt CT facility located in Audrain County, Missouri. No capital was raised as a result of UE’s assumption of the lease obligations.

CIPS

In June 2006, CIPS issued and sold, pursuant to an effective SEC Form S-3 registration statement, $61 million of 6.70% senior secured notes due June 15, 2036, with interest payable semi-annually on June 15 and December 15 of each year, beginning in December 2006. These notes are secured by first mortgage bonds, which are subject to fallaway provisions, as defined in the related financing agreements. CIPS received net proceeds of $60 million, which were used, among other funds, to repay in full CIPS’ intercompany note payable to UE.

Also in June 2006, $20 million of CIPS’ 7.05% first mortgage bonds matured and were retired.

CILCORP

In March 2006, CILCORP repurchased $2 million in principal amount of its 9.375% senior notes due 2029, and in April 2006, CILCORP repurchased an additional $7 million in principal amount of these bonds.

In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $1 million (2005 - $2 million) and $3 million (2005 - $4 million) for the three months and six months ended June 30, 2006, respectively, and was included in interest expense in the Consolidated Statements of Income of Ameren and CILCORP.

In July 2006, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. The redemption satisfied CILCO’s mandatory sinking fund redemption requirement for this series of preferred stock for 2006.

CILCO

In June 2006, CILCO issued and sold with registration rights in a private placement $54 million of 6.20% senior secured notes due June 15, 2016 and $42 million of 6.70% senior secured notes due June 15, 2036, both with interest payable semi-annually on June 15 and December 15 of each year, beginning in December 2006. These notes are secured

by first mortgage bonds, which are subject to fallaway provisions, as defined in the related financing agreements. CILCO received total net proceeds of $95 million which were used in July 2006 to redeem CILCO’s $20 million 7.73% secured medium-term notes due 2025 and to reduce short-term money pool borrowings.

In June 2006, IP issued and sold with registration rights in a private placement $75 million of 6.25% senior secured notes due June 15, 2016, with interest payable semi-annually on June 15 and December 15 of each year, beginning in December 2006. These notes are secured by mortgage bonds, which are subject to fallaway provisions as defined in the related financing agreements. IP received net proceeds of $74 million, which were used to reduce short-term money pool borrowings.

In conjunction with Ameren’s acquisition of IP, IP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $3 million (2005 - $4 million) and $7 million (2005 - $9 million) for the three months and six months ended June 30, 2006, respectively, and was included in interest expense in the Consolidated Statements of Income of Ameren and IP.

Indenture Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indenture provisions and other covenants. See Note 6 - Long-term Debt and Equity Financings in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005, for a detailed description of those provisions.

UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends along with bonds and preferred stock issuable based on the 12 months ended June 30, 2006, at an assumed interest and dividend rate of 7%.

	Required Interest Coverage Ratio^(a)		Actual Interest Coverage Ratio		Bonds Issuable^(b)(c)		Required Dividend Coverage Ratio^(d)		Actual Dividend Coverage Ratio		Preferred Stock Issuable
UE		2.0		4.4	$	2,217		2.5		44.5	$	1,426
CIPS		2.0^(e)		3.8		191		1.5		2.2		215
CILCO		2.0^(e)(f)		9.0		355		2.5		12.5		113^(g)
IP		2.0		5.6		645^(h)		1.5		2.7		521

(a) Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued.

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

(c) See Note 3 - Short-term Borrowings and Liquidity for a discussion regarding restrictions on the issuance of bonds by CIPS, CILCO and IP under the $500 million credit

facility entered into by these companies.

(d) 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.

(e) Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.

(f) 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, 2006, CILCO had earnings equivalent to at least 35% of the principal amount of all mortgage

bonds outstanding.

(g) See Note 3 - Short-term Borrowings and Liquidity for a discussion regarding a restriction on the issuance of preferred stock by CILCO under the $500 million credit facility.

(h) In addition to the coverage test based on property additions, IP has the ability to issue bonds based upon retired bond capacity, for which no earnings coverage test is required.

In addition, 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 retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.7 billion of free and unrestricted retained earnings at June 30, 2006.

The ICC order approving Ameren’s acquisition of IP contains a provision that gives IP the ability to declare and pay $80 million of dividends on its common stock in 2005 and $160 million of dividends on its common stock cumulatively through 2006, provided IP has achieved an investment-grade credit rating from S&P or Moody’s. If, however, IP’s $550 million principal amount of 11.50% Series mortgage bonds due 2010 are not eliminated by December 31, 2006, IP may not thereafter declare or pay common dividends without seeking authority from the ICC. As of June 30, 2006, $33,000 of the 11.50% Series mortgage bonds due 2010 were outstanding. The bonds are callable at the end of 2006.

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, make certain principal or interest payments, make certain loans to affiliates, or incur additional indebtedness. The following table summarizes these ratios for the 12 months ended June 30, 2006:

	Required Interest Coverage Ratio	Actual Interest Coverage Ratio	Required Debt-to- Capital Ratio	Actual Debt-to- Capital Ratio
Genco^(a)	≥1.75^(b)	5.1	≤60%	55%
CILCORP^(c)	≥2.2	2.4	≤67%	39%

(a)

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

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

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

Off-Balance-Sheet Arrangements

At June 30, 2006, 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, 2006 and 2005:

	Three Months						Six Months
	2006			2005			2006			2005
Ameren:^(a)
Miscellaneous income:
Interest and dividend income	$	1		$	1		$	3		$	2
Allowance for equity funds used during construction		-			3			1			7
Other		3			2			4			4
Total miscellaneous income	$	4		$	6		$	8		$	13
Miscellaneous expense:
Other	$	(1	)	$	(6	)	$	(1	)	$	(7	)
Total miscellaneous expense	$	(1	)	$	(6	)	$	(1	)	$	(7	)
UE:
Miscellaneous income:
Interest and dividend income	$	1		$	-		$	2		$	-
Allowance for equity funds used during construction		-			1			1			6
Other		-			1			1			3
Total miscellaneous income	$	1		$	2		$	4		$	9
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(4	)	$	(4	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(4	)	$	(4	)
CIPS:
Miscellaneous income:
Interest and dividend income	$	4		$	4		$	8		$	9
Other		-			-			1			-
Total miscellaneous income	$	4		$	4		$	9		$	9
Miscellaneous expense:
Other	$	-		$	(4	)	$	(1	)	$	(4	)
Total miscellaneous expense	$	-		$	(4	)	$	(1	)	$	(4	)
Genco:
Miscellaneous income:
Other	$	-		$	1		$	-		$	1
Total miscellaneous income	$	-		$	1		$	-		$	1
CILCORP:
Miscellaneous income:
Interest and dividend income	$	1		$	-		$	1		$	-
Total miscellaneous income	$	1		$	-		$	1		$	-
Miscellaneous expense:
Other	$	(1	)	$	(3	)	$	(2	)	$	(5	)
Total miscellaneous expense	$	(1	)	$	(3	)	$	(2	)	$	(5	)
CILCO:
Miscellaneous expense:
Other	$	(1	)	$	(2	)	$	(2	)	$	(3	)
Total miscellaneous expense	$	(1	)	$	(2	)	$	(2	)	$	(3	)
IP:
Miscellaneous income:
Interest and dividend income	$	1		$	1		$	1		$	2
Allowance for equity funds used during construction		-			1			-			1
Other		-			-			1			1
Total miscellaneous income	$	1		$	2		$	2		$	4
Miscellaneous expense:
Other	$	(1	)	$	(1	)	$	(2	)	$	(1	)
Total miscellaneous expense	$	(1	)	$	(1	)	$	(2	)	$	(1	)

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

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

The pretax net gain or loss on power forward hedges is included in Operating Revenues - Electric, and the pretax net gain or loss on hedges related to SO₂emissionallowances, fuel or power supply, and natural gas are included in Operating Expenses - Fuel and Purchased Power. This pretax net gain or 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 going to delivery or settlement, resulting in a $2 million gain for Ameren for the three months ended June 30, 2006 (2005 - $1 million gain for Ameren) and a $1 million loss for Ameren, a $1 million loss for Genco and a $2 million loss for IP for the six months ended June 30, 2006 (2005 - $3 million gain for Ameren, $1 million gain for Genco).

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 for cash flow hedges as of June 30, 2006:

	Ameren^(a)		UE		CIPS		Genco		CILCORP/ CILCO		IP
Derivative instruments carrying value:
Total assets	$	59	$	4	$	4	$	1	$	18	$	4
Total deferred credits and liabilities		16		6		-		-		-		2
Gains (losses) deferred in Accumulated OCI:
Power forwards and swaps^(b)		23		1		-		1		-		(2	)
Interest rate swaps^(c)		4		-		-		4		-		-
Gas swaps and futures contracts^(d)		22		2		4		-		17		-

(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 four years.

(c)	Represents a gain associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity and the gain in OCI is amortized over a 10-year period that began in June 2002.

(d)	Represents gains associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through March 2008.

Other Derivatives

The following table presents the net change in market value for the three months and six months ended June 30, 2006 and 2005, of option and swap transactions used to manage our positions in SO₂ allowances. Certain of these transactions are treated as nonhedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The net change in the market value of power options is recorded in Operating Revenues - Electric, while the net change in the market value of coal, heating oil and SO₂ options and swaps is recorded as Operating Expenses - Fuel and Purchased Power.

	Three Months					Six Months
Gains (Losses)	2006			2005		2006			2005
SO₂ options and swaps:
Ameren	$	(2	)	$	-	$	(3	)	$	(6	)
UE		(1	)		-		2			(1	)
Genco		(1	)		-		(4	)		(5	)
CILCO/CILCORP		-			-		(1	)		-
Coal Options:
Ameren		(1	)		-		(1	)		-
UE		(1	)		-		(1	)		-

NOTE 7 - RELATED PARTY TRANSACTIONS

The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005. Below are updates to several of these related party agreements.

Electric Power Supply 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, 2006 and 2005:

	Three Months				Six Months
	2006		2005		2006		2005
Genco sales to Marketing Company		5,296		5,196		10,887		10,096
Marketing Company sales to CIPS		2,997		2,497		6,076		4,553
EEI sales to UE		-		744		-		1,441
EEI sales to CIPS		-		371		-		943
EEI sales to IP		-		381		-		794

The EEI agreement that supplied power to UE, CIPS (which resold its entitlement to Marketing Company) and IP expired on December 31, 2005. EEI billed residual amounts under this contract in the first quarter of 2006 of $3 million, $2 million and $1 million to UE, CIPS and IP, respectively. CIPS’ obligation to pay the residual amount of $2 million was transferred to Marketing Company, to which CIPS had sold power supplied by EEI under the agreement. Beginning January 1, 2006, EEI entered into a new agreement to sell 100% of its capacity and energy to Marketing Company at market prices through December 31, 2015.

Joint Dispatch Agreement

UE and Genco jointly dispatch electric generation under the JDA among UE, CIPS and Genco. UE and Genco have

the option to serve their load requirements from their own generation first, and then each may give its affiliates access to any available generation at incremental cost. Any excess generation not used by UE or Genco to serve load requirements is sold to third parties on a short-term basis through Ameren Energy, which serves as each affiliate’s agent. To allocate power costs between UE and Genco, an intercompany sale is recorded by the company sourcing the power to the other company. Ameren Energy also acts as an agent on behalf of UE and Genco to purchase power when they require it. As further discussed in Note 2 - Rate and Regulatory Matters, in January 2006, the allocation methodology in the JDA for margins on short-term sales of excess generation to third parties between UE and Genco was modified, and in July 2006, UE, CIPS and Genco mutually consented to waive the one-year termination notice requirement and agreed to terminate the JDA on December 31, 2006, pending acceptance by FERC.

The following table presents the amount of gigawatthour sales under the JDA for the three months and six months ended June 30, 2006 and 2005:

	Three Months		Six Months
	2006	2005	2006	2005
UE sales to Genco	2,639	3,814	5,434	6,763
Genco sales to UE	1,111	1,219	1,717	1,816

The following table presents the short-term power sales margins under the JDA for UE and Genco for the three months and six months ended June 30, 2006 and 2005:

	Three Months		Six Months
	2006	2005	2006	2005
UE	$ 25	$ 43	$ 58	$ 79
Genco	5	27	17	47
Total	$ 30	$ 70	$ 75	$ 126

Money Pools

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

Intercompany Promissory Notes

Genco’s subordinated note payable to CIPS associated with the transfer 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 $3 million (2005 - $4 million) and $7 million (2005 - $8 million) for the three months and six months ended June 30, 2006 and 2005.

In June 2006, CIPS repaid in full its May 2005 $67 million subordinated promissory note to UE. UE and CIPS recorded interest income and expense, respectively, of less than $1 million (2005 - less than $1 million) and $1 million (2005 - less than $1 million) for the three months and six months ended June 30, 2006, respectively, related to this note.

The average interest rate on CILCORP’s note payable to Ameren was 4.6% and 4.3% for the three months and six months ended June 30, 2006, respectively (2005 - 5.5% and 6.9%, respectively). CILCORP recorded interest expense of $2 million (2005 - $1 million) and $4 million (2005 - $3 million) for the three months and six months ended June 30, 2006, respectively.

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, 2006 and 2005. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8 of the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005, and the money pool arrangements discussed in Note 3 - Short-term Borrowings and Liquidity.

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

Operating Revenues:
Power supply agreement	2006	$	(b	)	$	(b	)	$	194		$	1		$	(b	)	$	(b	)	$	(b	)	$	389		$	5		$	(b	)
with Marketing Company	2005		(b	)		8			195			6			(b	)		(b	)		17			374			21			(b	)

Power supply agreement with EEI	2005		(c	)		(b	)		(c	)		(b	)		(b	)		(c	)		(b	)		(c	)		(b	)		(b	)

UE and Genco gas	2006		(c	)		(b	)		(b	)		(b	)		(b	)		(c	)		(b	)		(b	)		(b	)		(b	)
transportation agreement	2005		(c	)		(b	)		(b	)		(b	)		(b	)		(c	)		(b	)		(b	)		(b	)		(b	)

JDA	2006		49			(b	)		27			(b	)		(b	)		121			(b	)		46			(b	)		(b	)
	2005		56			(b	)		21			(b	)		(b	)		97			(b	)		31			(b	)		(b	)
Total Operating	2006	$	49		$	(b	)	$	221		$	1		$	(b	)	$	121		$	(b	)	$	435		$	5		$	(b	)
Revenues	2005		56			8			216			6			(b	)		97			17			405			21			(b	)

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

Fuel and Purchased Power:
JDA	2006	$	27		$	(b	)	$	49		$	(b	)	$	(b	)	$	46		$	(b	)	$	121		$	(b	)	$	(b	)
	2005		21			(b	)		56			(b	)		(b	)		31			(b	)		97			(b	)		(b	)

Power supply agreement	2006		(b	)		111			(b	)		(c	)		(b	)		(b	)		219			(b	)		(c	)		(b	)
with Marketing Company	2005		2			94			(c	)		4			(b	)		4			170			2			7			(b	)

Power supply agreement with EEI	2005		16			8			(b	)		(b	)		13			30			17			(b	)		(b	)		27

Executory tolling agreement with	2006		(b	)		(b	)		(b	)		7			(b	)		(b	)		(b	)		(b	)		20			(b	)
Medina Valley	2005		(b	)		(b	)		(b	)		8			(b	)		(b	)		(b	)		(b	)		18			(b	)

UE and Genco gas	2006		(b	)		(b	)		(c	)		(b	)		(b	)		(b	)		(b	)		(c	)		(b	)		(b	)
transportation agreement	2005		(b	)		(b	)		(c	)		(b	)		(b	)		(b	)		(b	)		(c	)		(b	)		(b	)

Total Fuel and	2006	$	27		$	111		$	49		$	7		$	(b	)	$	46		$	219		$	121		$	20		$	(b	)
Purchased Power	2005		39			102			56			12			13			65			187			99			25			27

Other Operating Expenses:
Ameren Services support	2006	$	36		$	13		$	6		$	13		$	19		$	69		$	24		$	11		$	25		$	36
services agreement	2005		40			11			5			9			22			81			22			10			21			22

Ameren Energy support	2006		2			(b	)		(c	)		(b	)		(b	)		4			(b	)		1			(b	)		(b	)
services agreement	2005		1			(b	)		(c	)		(b	)		(b	)		2			(b	)		1			(b	)		(b	)

AFS support services	2006		1			1			(c	)		1			(c	)		2			1			1			1			1
agreement	2005		1			1			(c	)		(c	)		1			2			1			1			1			1

Total Other	2006	$	39		$	14		$	6		$	14		$	19		$	75		$	25		$	13		$	26		$	37
Operating Expenses	2005		42			12			5			9			23			85			23			12			22			23

Interest Income (Expense):
Money pool borrowings	2006	$	(c	)	$	(1	)	$	3		$	1		$	(c	)	$	(c	)	$	(1	)	$	5		$	3		$	1
(advances)	2005		2			(c	)		1			1			(1	)		2			(c	)		3			2			(2	)

(a)	Amounts represent CILCORP and CILCO activity.

(b)	Not applicable.

(c)	Amount less than $1 million.

NOTE 8 - COMMITMENTS AND CONTINGENCIES

As a result of issues generated in the course of daily business, we are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies, 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 an adverse material effect on our results of operations, financial position, or liquidity.

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 3 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005.

Callaway Nuclear Plant

The following table presents insurance coverage at UE’s Callaway nuclear plant at June 30, 2006:

Type and Source of Coverage	Maximum Coverages		Maximum Assessments for Single Incidents
Public liability:
American Nuclear Insurers	$	300		$	-
Pool participation		10,461			101^(a)
	$	10,761^(b)		$	101
Nuclear worker liability:
American Nuclear Insurers	$	300^(c)		$	4
Property damage:
Nuclear Electric Insurance Ltd.	$	2,750^(d)		$	21
Replacement power:
Nuclear Electric Insurance Ltd.	$	490^(e)		$	7

(a)

Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. 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.

(b)	Limit of liability for each incident under Price-Anderson.

(c)	Industry limit for potential liability from workers claiming exposure to the hazards of nuclear radiation.

(d)	Includes premature decommissioning costs.

(e)	Weekly indemnity of $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 weeks thereafter.

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

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

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. In addition, we have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005.

As of June 30, 2006, the commitments for the procurement of coal have changed from amounts previously disclosed as of December 31, 2005. The following table presents the total estimated coal purchase commitments at June 30, 2006:

	2006		2007			2008		2009		2010		Thereafter^(a)
Ameren^(b)	$	609	$	498	��	$	507	$	404	$	238	$	77
UE		344		289			251		213		159		77
Genco		129		100			154		136		42		-
CILCORP/CILCO		61		36			35		27		18		-

(a)	Commitments for coal are until 2011.

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

As of June 30, 2006, the commitments for the procurement of natural gas have changed from amounts previously disclosed as of December 31, 2005. The following table presents the total estimated natural gas purchase commitments at June 30, 2006:

	2006		2007		2008		2009		2010		Thereafter^(a)
Ameren^(b)	$	373	$	580	$	407	$	237	$	148	$	249
UE		57		65		60		39		26		74
CIPS		62		119		87		58		40		105
Genco		11		24		20		8		8		10
CILCORP/CILCO		89		147		107		60		32		33
IP		141		213		131		71		41		25

(a)	Commitments for natural gas are until 2016.

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

Environmental Matters

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

Clean Air Act

In May 2005, the EPA issued final regulations with respect to SO₂ and NO_x emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule) from coal-fired power plants. The new rules will require significant reductions in these emissions from UE, Genco, CILCO and EEI power plants in phases, beginning in 2009. States are required to finalize rules to implement the federal Clean Air Interstate Rule and Clean Air Mercury Rule by September and November 2006, respectively. While the federal rules mandate a specific emissions cap for SO₂, NO_x and mercury emissions by state from utility boilers, the states have considerable flexibility in allocating emission allowances to individual utility boilers. In addition, a state may choose to hold back certain emission allowances for growth or other reasons, and it may implement a more stringent program than the federal program. Illinois and Missouri are developing proposed rules that will be subjected to public review and comment. We do not expect the state regulations to be finalized until late 2006. The Illinois EPA proposed rules for mercury significantly stricter than the federal rules. An implementation plan from Missouri regulators is still under review and consideration and could result in significantly higher costs than estimated for UE below. The table below presents preliminary estimated capital costs based on current technology to comply with both (1) the federal Clean Air Interstate Rule and Clean Air MercuryRule through 2016, and (2) a proposed agreement between Genco, CILCO, EEI, and the Illinois EPA on a multi-pollutant strategy for NO_x, SO₂, mercury and fine particulates. This agreement, which was entered into in July 2006 and is subject to approval by the Illinois Pollution Control Board, addresses the Illinois EPA's proposed stricter rules for mercury and will result in a significant amount of additional NO_x, SO₂and mercury control equipment being installed to reduce these emissions. The agreement with the Illinois EPA will also restrict purchasing SO₂and NO_x emission allowances to meet specific allowed emission rates set forth in the agreement and resulted in a $600 million increase in estimated expenditures for the period of 2006 to 2016. These estimates could change based on new technology, variations in costs of material or labor, alternative compliance strategies or state rulemaking to implement the federal rules, among other reasons. The timing of estimated capital costs may also be influenced by whether emission credits are used to comply with the proposed rules, thereby deferring capital investment.

	2006	2007 - 2010	2011 - 2016	Total
Ameren	$80	$1,225 - $1,615	$1,350 - $1,750	$2,655 - $3,445
UE	60	365 - 505	750 - 1,040	1,175 - 1,605
Genco	10	555 - 720	305 - 320	870 - 1,050
CILCO	5	260 - 330	145 - 200	410 - 535
EEI	5	55 - 75	190 - 235	250 - 315

The state of Missouri must also develop a plan to meet the new fine particulate ambient standard by April 2008. The costs reflected in the table assume that emission controls required for the Clean Air Interstate Rule regulations will be sufficient to meet this new standard in the St. Louis region. Should Missouri develop an alternative plan to comply with this standard, the cost impact could be material to UE. At this time, we are unable to determine the impact such a state action would have on our results of operations, financial position, or liquidity.

Emission Credits

Both federal and state laws require significant reductions in SO₂ and NO_x emissions that result from burning fossil fuels. The Clean Air Act and NO_x Budget Trading Program created marketable commodities called allowances. Currently each allowance gives the owner the right to emit one ton of SO₂ or NO_x. All existing generating facilities have been allocated allowances that are 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 NO_x Budget Trading Program limits emissions of NO_x during the ozone season (May through September). The NO_x Budget Trading Program has applied to all electric generating units in Illinois since the beginning of 2004; it will apply to the eastern third of Missouri, where UE’s coal-fired power plants are located, beginning in 2007. Our generating facilities are expected to comply with the NO_x limits through the use and purchase of allowances or through the application of pollution control technology, including low-NO_x burners, over-fire air systems, combustion

optimization, rich reagent injection, selective noncatalytic reduction and selective catalytic reduction systems.

The following table presents the tons of SO₂ and NO_x emission allowances held and the related SO₂ and NO_x book values that are carried as intangible assets as of June 30, 2006.

	SO₂ ^(a)		NO_x ^(b)		Book Value
UE		1,850,000		387	$	63
Genco		690,000		10,334		89
CILCO		330,000		1,206		58
EEI		360,000		1,935		40

(a)	Vintages are from 2006 to 2016. Each company possesses additional allowances for use in periods beyond 2016.

(b)	Vintages are from 2006 to 2008.

The Illinois EPA has not yet issued any NO_x emission allowance allocations for 2007 and 2008. UE, Genco, CILCO and EEI expect to use a substantial portion of the SO₂ and NO_x allowances for ongoing operations. Allocations of NO_x allowances for Missouri generating facilities will be 10,178 tons per season in 2007 and 2008. New environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment and the level of operations will have a significant impact on the amount of allowances actually required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO₂ emissions by requiring a change in the way Acid Rain Program allowances are surrendered. The current Acid Rain Program requires the surrender of one SO₂ allowance for every ton of SO₂ that is emitted. The Clean Air Interstate Rule program will require that SO₂ allowances be surrendered at a ratio of two allowances for every ton of emission in 2010 through 2014. Beginning in 2015, the Clean Air Interstate Rule program will require SO₂ allowances to be surrendered at a ratio of 2.86 allowances for every ton of emission.

New Source Review

The EPA has been conducting an enforcement initiative in an effort to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were 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. All of these facilities are coal-fired power plants. The information request required Genco to provide responses to specific EPA questions regarding certain projects and maintenance activities to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standard requirements of the Clean Air Act. This information request is being complied with, but we cannot predict the outcome of this matter.

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

As of June 30, 2006, CIPS, CILCO and IP owned or were otherwise responsible for 14, four and 25 former MGP sites, respectively, in Illinois. All of these sites are in various stages of investigation, evaluation and remediation. Under its current schedule, Ameren anticipates that remediation at these sites should be completed by 2015. The ICC permits each company to recover remediation and litigation costs associated with their former MGP sites in Illinois from their Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred, and costs are subject to annual reconciliation review by the ICC. As of June 30, 2006, CIPS, CILCO and IP had recorded liabilities of $26 million, $3 million and $66 million, respectively, to represent estimated minimum obligations.

In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. UE does not currently have a rate rider mechanism in effect in Missouri that permits remediation costs associated with MGP sites to be recovered from utility customers. See Note 2 - Rate and Regulatory Matters for information on a recently enacted law in Missouri enabling the MoPSC to put in place environmental cost recovery mechanisms for Missouri utilities. UE does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs. Because of the unknown and unique characteristics of each site (such as amount and type of residues present, physical characteristics of the site, and the environmental risk) and uncertain regulatory requirements, we are not able to determine the maximum liability for the remediation of these sites. As of June 30, 2006, UE had recorded $10 million to represent its estimated minimum obligation for MGP sites. 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, 2006, UE had recorded $5 million to represent its estimated minimum obligation for these sites. At this time, we are unable to determine what portion of these costs, if any, will be eligible for recovery from insurance carriers.

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

In October 2002, UE was included in a Unilateral Administrative Order issued by the EPA listing potentially liable parties for groundwater contamination for a portion of the Sauget Area 2 site. The Unilateral Administrative Order encompasses the groundwater contamination releasing to the Mississippi River adjacent to Solutia’s former chemical waste landfill and the resulting impact area in the Mississippi River. UE was asked to participate in response to activities that involve the installation of a barrier wall around a chemical waste site and three recovery wells to divert groundwater flow. The projected cost for this remedy method ranges from $25 million to $30 million. In November 2002, UE sent a letter to the EPA asserting its defenses to the Unilateral Administrative Order and requesting its removal from the list of potentially responsible parties under the Unilateral Administrative Order. Solutia agreed to comply with the Unilateral Administrative Order. However, in December 2003, Solutia filed for bankruptcy protection and it is now seeking to discharge its environmental liabilities. In March 2004, Pharmacia Corporation, the former parent company of Solutia, confirmed its intent to comply with the EPA’s Unilateral Administrative Order.

The status of future remediation at Sauget Area 2 and compliance with the Unilateral Administrative Order is uncertain, so we are unable to predict the ultimate impact of the Sauget Area 2 site on our results of operations, financial position, or liquidity. In December 2004, the U.S. Supreme Court, in Cooper Industries, Inc., vs. Aviall Services, Inc., limited the circumstances under which potentially responsible parties could assert cost-recovery claims against other potentially responsible parties. As a result of this ruling, it is possible that UE may not be able to recover from other potentially responsible parties the costs it incurs in complying with EPA orders. Any liability or responsibility that may be imposed on UE as a result of this Sauget, Illinois, environmental matter was not transferred to CIPS as a part of UE’s May 2005 Illinois utility service territory transfer to CIPS.

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 $3 million at June 30, 2006, 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 and, in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine the impact these activities may have on our results of operations, financial position, or liquidity.

Pumped-storage Hydroelectric Facility Breach

In late May 2006, the FERC released a report by an Independent Panel of Consultants on the technical reasons for the December breach. The report cited the primary cause of the Taum Sauk breach as overtopping of the upper reservoir dam due to improperly maintained and installed water level monitors. The report stated that the monitors became loose and indicated reservoir levels lower than actual levels. In addition, the panel found emergency backup sensors proved ineffective because they were set at an elevation above the lowest points along the parapet wall on the top of the reservoir. As a result, the sensors failed their protection role because their location enabled the overtopping to occur before the probes could trigger a shutdown. The report stated that another factor contributing to the overtopping was that UE typically operated with high water levels of one foot below the top of the parapet wall, which was not enough to take into account possible mistakes in project operation. A secondary cause, the report said, was the marginally stable dumped

“dirty” (silt, sands and gravels) rockfill embankment and associated parapet wall.

The facility will remain out of service until reviews by FERC and state authorities are concluded, further analyses are completed, and input is received from key stakeholders as to how and whether to rebuild the facility. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through most, if not all, of 2008.

UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all of the damage and liabilities caused by the breach will be covered by insurance. UE expects the total cost for damage and liabilities resulting from the Taum Sauk incident to range from $63 million to $83 million. As of June 30, 2006, UE had paid $27 million and accrued a $36 million liability, while expensing $11 million and recording a $52 million receivable due from insurance companies. No amounts have been recognized in the financial statements relating to estimated costs to repair or rebuild the facility. 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 may be subject to litigation by private parties or by state or federal authorities. Until the reviews conducted by state and federal authorities have concluded, the insurance review is completed, a decision whether the plant will be rebuilt is made, and future regulatory treatment for the plant is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.

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 129 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, 2006, the average number of parties is 67.

The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and most former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a Dynegy subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS and CILCO contractually agreed to indemnify Genco and AERG for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages in excess of $50,000, which, if proved, typically would be shared among the named defendants.

From April 1, 2006, through June 30, 2006, seven additional asbestos-related lawsuits were filed against Ameren, UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois. Three lawsuits were dismissed and two were settled. The following table presents the status as of June 30, 2006, 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		310		31		166		125		2		36		144
Settled		95		-		48		39		-		10		48
Dismissed		143		22		92		46		2		6		63
Pending		72		9		26		40		-		20		33

(a)	Addition of the numbers in the individual columns does not equal the total column because some of the lawsuits name multiple Ameren entities as defendants.

As of June 30, 2006, six asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

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

The ICC order approving Ameren’s acquisition of IP effective September 30, 2004, also approved a tariff rider to recover the costs of IP’s asbestos-related litigation claims, subject to the following terms. Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will be recovered by IP from a $20 million trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy. 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.

Retiree Medical Plan Litigation

In June 2003, 20 retirees and surviving spouses of retirees of various Ameren companies (the plaintiffs) filed a complaint in the U.S. District Court, Southern District of Illinois, against Ameren, UE, CIPS, Genco and Ameren Services, and against our Retiree Medical Plan, and by an amended complaint, against our Group Medical Plan (the defendants). The retirees were members of various local labor unions of the IBEW and the IUOE. The complaint, referred to as Barnett et al., vs. Ameren Corporation, et al., alleged, among other things, that the defendants’ recent actions requiring retirees to pay a portion of their own health care premiums or increasing the premiums paid by dependents or surviving spouses of retirees violate ERISA and the Labor Management Relations Act of 1947 and constitute a breach of the defendants’ fiduciary duties. In February 2006, the U.S. Seventh Circuit Court of Appeals affirmed a district court’s granting of summary judgment in favor of the defendants. This decision is final and not subject to further appeal.

NOTE 9 - CALLAWAY NUCLEAR PLANT

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or ¹/₁₀ of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. 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. It is assumed that the Callaway nuclear plant site will be

decommissioned based on 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 2005, 2004 and 2003. 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. 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.

NOTE 10 - 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, 2006 and 2005, is shown below for the Ameren Companies:

	Three Months						Six Months
	2006			2005			2006			2005
Ameren:^(a)
Net income	$	123		$	185		$	193		$	306
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $7, $4, $(2) and $10, respectively		11			1			(4	)		18
Reclassification adjustments for (gains) included in net income, net of taxes of $2, $1, $5 and $1, respectively		(3	)		(2	)		(8	)		(2	)
Total comprehensive income, net of taxes	$	131		$	184		$	181		$	322
UE:
Net income	$	92		$	132		$	143		$	189
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $1, $-, $(1) and $2, respectively		1			(1	)		(1	)		3
Reclassification adjustments for (gains) included in net income, net of taxes of $1, $-, $2 and $-, respectively		(1	)		-			(3	)		-
Total comprehensive income, net of taxes	$	92		$	131		$	139		$	192

	Three Months						Six Months
		2006			2005			2006			2005
CIPS:
Net income	$	15		$	7		$	14		$	15
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $(1), $(1) and $3, respectively		-			(2	)		(2	)		4
Reclassification adjustments for (gains) included in net income, net of taxes of $1, $1, $2 and $ -, respectively		(1	)		(1	)		(3	)		(1	)
Total comprehensive income, net of taxes	$	14		$	4		$	9		$	18
Genco:
Net income	$	2		$	31		$	8		$	62
Unrealized (loss) on derivative hedging instruments, net of taxes of $-, $-, $- and $ -, respectively		-			-			-			(1	)
Total comprehensive income, net of taxes	$	2		$	31		$	8		$	61
CILCORP:
Net income	$	1		$	2		$	9		$	11
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(2), $(1), $(7) and $7, respectively		(3	)		(1	)		(11	)		12
Reclassification adjustments for (gains) losses included in net income, net of taxes of $-, $-, $3 and $-, respectively		-			(1	)		(4	)		1
Total comprehensive income (loss), net of taxes	$	(2	)	$	-		$	(6	)	$	24
CILCO:
Net income	$	8		$	10		$	25		$	26
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(2), $(1), $(7), and $7, respectively		(3	)		(1	)		(11	)		11
Reclassification adjustments for (gains) included in net income, net of taxes of $-, $-, $3 and $-, respectively		-			(1	)		(4	)		-
Total comprehensive income, net of taxes	$	5		$	8		$	10		$	37
IP:
Net income	$	16		$	15		$	20		$	37
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $-, $(1) and $-, respectively		-			-			(1	)		-
Reclassification adjustments for losses included in net income, net of taxes (benefit) of $-, $-, $(1) and $-, respectively		-			-			1			-
Total comprehensive income, net of taxes	$	16		$	15		$	20		$	37

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

NOTE 11 - RETIREMENT BENEFITS

Ameren’s pension plans are funded in compliance with income tax regulations and federal funding requirements. Based on our assumptions at December 31, 2005, and assuming continuation of the recently expired federal interest rate relief beyond 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2011 at which time we would expect a required contribution of $100 million to $150 million. If federal interest rate relief is not continued in its most recent form, $200 million to $300 million may need to be funded in 2009 to 2010 based on other recent federal legislative proposals. 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. Ameren is considering whether to make voluntary contributions in the second half of 2006.

Ameren made a contribution to its postretirement benefit plan of $37 million in the second quarter of 2006 as compared to $35 million in the second quarter of the prior year.

The following tables present 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, 2006 and 2005:

	Pension Benefits^(a)
	Three Months						Six Months
	2006			2005			2006			2005
Service cost	$	15		$	14		$	31		$	29
Interest cost		43			41			86			83
Expected return on plan assets		(49	)		(45	)		(98	)		(91	)
Amortization of:
Prior service cost		3			3			5			5
Actuarial loss		10			9			21			19
Net periodic benefit cost	$	22		$	22		$	45		$	45

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

	Postretirement Benefits^(a)
	Three Months						Six Months
	2006			2005			2006			2005
Service cost	$	5		$	5		$	11		$	11
Interest cost		15			17			33			36
Expected return on plan assets		(11	)		(11	)		(23	)		(23	)
Amortization of:
Transition obligation		1			1			1			1
Prior service cost		(2	)		(1	)		(3	)		(2	)
Actuarial loss		7			9			17			19
Net periodic benefit cost	$	15		$	20		$	36		$	42

(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 tables present the pension costs and the postretirement benefit costs incurred for the three months and six months ended June 30, 2006 and 2005:

	Pension Costs
	Three Months				Six Months
		2006		2005		2006		2005
UE	$	13	$	13	$	26	$	26
CIPS		3		3		6		6
Genco		1		2		3		4
CILCORP		3		3		5		6
CILCO		4		5		7		9
IP		2		1		4		3

	Postretirement Costs
	Three Months				Six Months
		2006		2005		2006		2005
UE	$	8	$	11	$	19	$	22
CIPS		2		3		5		6
Genco		1		1		2		2
CILCORP		1		2		4		6
CILCO		2		3		7		9
IP		3		3		7		6

NOTE 12 - SEGMENT INFORMATION

Ameren’s reportable segment Utility Operations comprises its electric generation and electric and gas transmission and distribution operations. It includes the operations of UE, CIPS, Genco, CILCORP, CILCO and IP. Ameren’s reportable segment Other consists of the parent holding company, Ameren Corporation.

The accounting policies for segment data are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data includes intersegment revenues, as well as a charge for allocating costs of administrative support services to each of the operating companies, which in each case is eliminated upon consolidation. Ameren Services allocates administrative support services based on various factors, such as head count, number of customers, and total assets.

The following table presents information about the reported revenues and net income of Ameren for the three months and six months ended June 30, 2006 and 2005:

	Utility Operations		Other			Reconciling Items^(a)			Total
Three Months 2006:
Operating revenues	$	1,982	$	-		$	(432	)	$	1,550
Net income		121		2			-			123
Three Months 2005:
Operating revenues	$	1,956	$	-		$	(372	)	$	1,584
Net income		186		(1	)		-			185
Six Months 2006:
Operating revenues	$	4,234	$	-		$	(884	)	$	3,350
Net income		192		1			-			193

Utility Operations

Other

Reconciling Items^(a)

Total

Six Months 2005:
Operating revenues	$	3,900	$	-		$	(697	)	$	3,203
Net income		311		(5	)		-			306

(a)	Elimination of intercompany revenues.

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

OVERVIEW

Ameren Executive Summary

Ameren’s second quarter and first half of 2006 earnings were lower than the strong earnings achieved last year. Several factors contributed to Ameren’s decreased earnings versus the year-ago periods. Electric margins were negatively impacted by higher fuel and purchased power costs due primarily to increased coal and related transportation costs, an unplanned outage at our Callaway nuclear plant and milder winter weather. In addition, Ameren incurred additional costs of operating in the MISO Day Two Energy Market in the first six months of 2006 because MISO Day Two operations did not commence until the second quarter last year. Incremental costs resulting from the December 2005 breach of the upper reservoir at UE’s Taum Sauk hydroelectric pumped-storage plant also negatively impacted second quarter and first half 2006 earnings. Significant planned power plant outages and some unplanned outages reduced second quarter 2006 earnings as compared to the prior-year period. These factors offset increased margins from interchange sales and organic growth compared to the second quarter and first six months of last year.

In Illinois, we are moving into a critical stage as the scheduled September 2006 power procurement auction fast approaches, the Illinois delivery service rate cases come to a close, and the Illinois fall legislative session commences in November. In delivery services rate filings made in late December 2005, CIPS, CILCO and IP requested a total combined annual electric revenue increase of approximately $200 million. In June 2006, the ICC staff filed rebuttal testimony recommending increases in revenues for electric delivery services for the Ameren Illinois utilities aggregating $120 million. The Illinois attorney general also filed rebuttal testimony, which we estimate would result in revenue increases aggregating approximately $100 million. The ICC has until November of this year to issue a final decision in these cases. As a result of the potential increases to ratepayers from these requested increases and the transition to market-based power costs, there have been two pieces of legislation proposed in Illinois. One proposal includes a potential extension of the rate freeze through 2010, which we believe is without legal merit. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power or other costs from their electric customers in a timely manner could result in material adverse consequences for these companies and Ameren. Following the introduction of the rate freeze proposal, a second separate and constructive piece of legislation was introduced, which authorized the issuance of securitization bonds. This approach has the effect of spreading over the life of the bonds, a period of up to 10 years, the potentially significant initial electric rate increase for residential customers that would otherwise be necessary to pay the power procurement costs on a current basis. In June 2006, CIPS, CILCO and IP filed a proposal with the ICC for a rate increase phase-in and revenue securitization plan for residential customers similar to the securitization legislation that was introduced that would result in deferral of power supply costs for 2007 and 2008.

In early July, UE filed requests with the MoPSC to increase base rates for electric service by $361 million and to increase base rates for gas service by $11 million. The primary drivers of the requested electric increase were significant investments in critical energy infrastructure, as well as significantly higher operating expenses. In conjunction with the filing of the electric rate case in Missouri, UE, CIPS and Genco mutually agreed to terminate the JDA on December 31, 2006. We expect a decision from the MoPSC on both filings by June 2007.

On July 19, 2006 and July 21, 2006, UE’s, CIPS’ and IP’s service territories were hit by severe storms, which included tornados, that resulted in the loss of power to approximately 700,000 customers combined. Through the dedication of a work force of 5,200 people, including our employees, contractors and utility workers from 13 states, we restored service to all of our customers within nine days. The full financial impact of these storms has not yet been determined, but UE, CIPS and IP have incurred unanticipated costs, and the loss of electric margins as a result of these devastating storms.

General

businesses, rate-regulated natural gas transmission and distribution businesses and non-rate-regulated electric generation businesses in Missouri and Illinois, as discussed below. Dividends on Ameren’s common stock depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part I, Item 1, of this report for a detailed description of our principal subsidiaries.

·	UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Before May 2, 2005, UE also operated those businesses in Illinois.

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

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

·	CILCO, a subsidiary of CILCORP (a holding company), operates a rate-regulated electric and natural gas transmission and distribution business and a primarily 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 weighted-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. Approximately 85% of Ameren’s 2005 revenues were directly subject to state and federal regulation. This regulation can have a material impact on the price we charge for our services. Our non-rate-regulated sales are subject to market conditions for power and with the expiration of Genco’s and AERG’s supply contracts with CIPS and CILCO at the end of 2006, these companies’ and Ameren’s earnings will be subject to increased volatility. 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 fuel or purchased power cost recovery mechanisms in Missouri or Illinois for our electric utility businesses, but we do have gas cost recovery mechanisms in each state for our gas delivery businesses. Since rates for UE, CIPS, CILCO and IP are regulated, cost decreases or increases will not be immediately reflected in rates. 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 risks and other risks inherent in our businesses. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Ameren’s net income decreased to $123 million, or 60 cents per share, in the second quarter of 2006 from $185 million, or 93 cents per share, in the second quarter of 2005. Ameren’s net income decreased $113 million to $193 million, or 94 cents per share, for the six months ended June 30, 2006, compared to earnings of $306 million, or $1.55 per share, in the first six months of 2005. Earnings were negatively impacted for the three-month and six-month periods by increased fuel and purchased power costs, milder weather, lower prices for interchange sales, an unscheduled outage at UE’s Callaway nuclear plant in the second quarter of 2006, costs associated with an upper reservoir breach in December 2005 at UE’s Taum Sauk plant and incremental costs of operating in the MISO Day Two Energy Market. Decreased availability of coal-fired power plants also reduced second quarter 2006 earnings as compared to the prior-year period. Additionally, an increase in the number of common shares outstanding in the current year periods reduced Ameren’s earnings per share. Increased margins on interchange sales at EEI and organic growth partially offset the impact of these unfavorable items on current year earnings.

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, 2006 and 2005:

	Three Months					Six Months
	2006			2005		2006		2005
Net income (loss):
UE^(a)	$	90		$	130	$	140	$	186
CIPS		15			7		13		14
Genco^(a)		2			31		8		62
CILCORP^(a)		1			2		9		11
IP		16			15		19		36
Other^(b)		(1	)		-		4		(3	)
Ameren net income	$	123		$	185	$	193	$	306

(a)	Includes earnings from market-based interchange power sales that provided the following contributions to net income for the three-month and six-month periods, respectively:

UE: 2006 - $14 million, $34 million

2005 - $25 million, $46 million

Genco: 2006 - $3 million, $10 million

2005 - $15 million, $27 million

CILCORP: 2006 - $5 million, $12 million

2005 - $4 million, $9 million

(b)	Includes earnings from non-rate-regulated operations and a 40% interest in EEI held by Resources Company, corporate general and administrative expenses, and intercompany eliminations.

Electric Operations

The following table presents the favorable (unfavorable) variations in electric margins, defined as electric revenues less fuel and purchased power costs, for the three months and six months ended June 30, 2006, as compared with the year-ago periods. We consider electric and interchange margins useful measures to analyze the change in profitability of our electric operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, electric and interchange margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Three Months	Ameren^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Electric revenue change:
Effect of weather (estimate)	$	(16	)	$	(8	)	$	(2	)	$	-		$	(2	)	$	(2	)	$	(4	)
Growth and other (estimate)		(23	)		(5	)		19			(2	)		2			3			7
Interchange revenues		10			(26	)		(7	)		(26	)		(2	)		(2	)		-
Total	$	(29	)	$	(39	)	$	10		$	(28	)	$	(2	)	$	(1	)	$	3
Fuel and purchased power change:
Fuel:
Generation and other	$	15		$	6		$	-		$	13		$	-		$	2		$	-
Price		(21	)		(14	)		-			(4	)		(3	)		(3	)		-
Purchased power		(33	)		(2	)		(8	)		(21	)		7			7			(6	)
Total	$	(39	)	$	(10	)	$	(8	)	$	(12	)	$	4		$	6		$	(6	)
Net change in electric margins	$	(68	)	$	(49	)	$	2		$	(40	)	$	2		$	5		$	(3	)
Six Months
Electric revenue change:
Effect of weather (estimate)	$	(30	)	$	(14	)	$	(7	)	$	-		$	(3	)	$	(3	)	$	(6	)
Growth and other (estimate)		(6	)		(6	)		64			13			7			8			16
Interchange revenues		96			15			(15	)		(19	)		(7	)		(7	)		-
Total	$	60		$	(5	)	$	42		$	(6	)	$	(3	)	$	(2	)	$	10
Fuel and purchased power change:
Fuel:
Generation and other	$	-		$	3		$	-		$	4		$	-		$	1		$	-
Price		(47	)		(30	)		-			(14	)		(3	)		(3	)		-
Purchased power		(108	)		(31	)		(39	)		(68	)		14			14			(26	)
Total	$	(155	)	$	(58	)	$	(39	)	$	(78	)	$	11		$	12		$	(26	)
Net change in electric margins	$	(95	)	$	(63	)	$	3		$	(84	)	$	8		$	10		$	(16	)

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

Ameren

Ameren’s electric margin decreased by $68 million, or 7%, and $95 million or 6%, for the three months and six months ended June 30, 2006, compared with the same periods in 2005. Ameren’s decrease in electric margins was impacted by:

unfavorable weather conditions as evidenced by an 8% decline in cooling degree-days for both the three months and six months ended June 30, 2006 and an 11% decrease in heating degree-days for the six months ended June 30, 2006, compared with the same periods in 2005. In addition, spring storms caused an unscheduled plant outage in the first quarter of 2006;

·	incremental fees of $6 million levied by FERC in the first quarter of 2006, upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant;

·	a 14% increase in both the second quarter and first half of 2006 in coal and transportation prices resulting from increased global demand for coal;

·	MISO Day Two Energy Market costs, which were comparable in the second quarter and $21 million higher for the six months ended June 30, 2006, compared with the same periods in 2005;

·	the unavailability of UE’s Taum Sauk hydroelectric plant totaling an estimated $4 million and $10 million in the second quarter and first half of 2006;

·	an unscheduled outage at UE’s Callaway nuclear plant, which reduced electric margins by an estimated $20 million, and planned and unplanned outages at certain of UE’s and Genco’s coal-fired plants, primarily in the second quarter of 2006;

·	lower wholesale margins of approximately $6 million and $12 million in the second quarter and first half of 2006 at Marketing Company as a result of the expiration of several large contracts in 2005; and

·	reduced transmission revenues due primarily to a decrease in Marketing Company’s non-service territory load for UE, CIPS, CILCORP, CILCO and IP.

The decrease in Ameren’s electric margins was partially offset by:

·	an increase in margins on interchange sales of $13 million or 17%, and $62 million or 42%, over the prior three and six month periods primarily because of the increased sale of power from EEI resulting from the expiration of its affiliate cost-based sales contract on December 31, 2005; and

·	sales to Noranda, which added approximately $11 million and $17 million in electric margins at UE for the second quarter and first six months of 2006, respectively.

UE’s electric margin decreased by $49 million, or 9%, and $63 million, or 7%, for the three months and six months ended June 30, 2006, compared to the same periods in 2005. The decrease in electric margins was due to:

·	unfavorable weather conditions as evidenced by a 10% decline in cooling degree-days for both the second quarter and the first half of the year and a 10% decrease in heating degree-days for the six months ended June 30, 2006 compared with the same period in 2005;

·	the transfer of UE’s Illinois service territory on May 2, 2005 to CIPS, which resulted in lost margins compared to the prior periods, totaling $6 million for the second quarter and $24 million for the first half of 2006;

lower margins on interchange sales as a result of power plant unavailability. However, margins on interchange sales benefited from the January 2006 amendment of the JDA. The MoPSC-required and FERC-approved change in the JDA methodology to base the allocation of third-party short-term power sales of excess generation on generation output instead of load requirements, effective January 10, 2006, resulted in $5 million and $14 million in incremental margins on interchange sales for UE for the three months and six months ended June 30, 2006, respectively.

·	an 11% and 14% increase in coal and related transportation prices for the second quarter and first six months of 2006, compared with the same periods in 2005;

·	incremental fees of $6 million levied by FERC in the first quarter of 2006 for generation benefits provided to UE’s Osage hydroelectric plant;

·	the unavailability of UE’s Taum Sauk hydroelectric plant;

·	unscheduled outages at UE’s Callaway nuclear plant and certain of its coal-fired plants primarily in the second quarter of 2006 compared with the same period in 2005;

·	MISO Day Two Energy Market costs, which were comparable for the three months ended June 30, 2006, and $14 million higher for the six months ended June 30, 2006, compared with the same periods in 2005; and

·	the expiration of a cost-based power supply contract with EEI on December 31, 2005.

The decrease in UE’s electric margins for the three months and six months ended June 30, 2006, compared with the same periods in 2005, was partially offset by sales to Noranda.

CIPS

CIPS’ electric margin increased by $2 million, or 3%, for the three months and $3 million, or 3%, for the six months

ended June 30, 2006, compared to the same periods in 2005, primarily because of:

·	the transfer to CIPS of UE’s Illinois service territory on May 2, 2005 which generated an incremental margin of $4 million in the second quarter and $16 million in the first half of 2006; and

·	customers switching back to CIPS from Marketing Company because tariff rates were below market rates for power.

CIPS’ increase in electric margin was reduced by increased MISO Day Two Energy Market costs, totaling $2 million for the six months ended June 30, 2006, compared with the same period in 2005. Unfavorable weather conditions as evidenced by a 13% decrease in heating degree-days also lowered CIPS’ electric margins for the six months ended June 30, 2006, compared with the same period in 2005.

Due to the expiration of CIPS’ cost-based power supply agreement with EEI in December 2005, where CIPS sold its entitlements under the agreement to Marketing Company, both interchange revenues and purchased power expenses decreased $7 million and $15 million for the three months and six months ended June 30, 2006.

Genco

Genco’s electric margin decreased by $40 million, or 31%, and $84 million, or 33%, for the three months and six months ended June 30, 2006, compared with the same periods in 2005, primarily because of:

·	lower wholesale margins as Genco purchased higher-cost power from affiliates and third parties to serve a greater load, primarily to supply power to serve the Illinois service territory transferred to CIPS in May 2005;

·	an 11% increase in coal and transportation prices for the three months and six months ended June 30, 2006, compared with the same periods in 2005;

·	a scheduled outage in the second quarter of a major coal-fired unit;

·	lower margins on interchange sales for the three months and six months ended June 30, 2006, compared with the same periods in 2005 primarily because of reduced power plant availability and a $5 million and $14 million reduction due to the amendment of the JDA between UE and Genco; and

·	higher emission allowance utilization costs.

Genco’s decrease in electric margins was reduced by an increase in revenues due to the May 2005 transfer of UE’s Illinois service territory to CIPS. Genco supplies CIPS’ power requirements through a power supply agreement with Marketing Company.

CILCORP and CILCO

For the three and six month periods ended June 30, 2006, CILCORP’s electric margin increased by $2 million, or 3%, and $8 million, or 7%, respectively, and CILCO’s electric margin increased $5 million, or 8%, and $10 million, or 8%, respectively, as compared to the same periods in 2005 primarily because of:

·	lower purchased power costs due to improved power plant availability;

·	decreases in emission allowance utilization expenses of $2 million and $3 million for the three and six month periods, respectively; and

·	increases in margins on interchange sales of $1 million and $5 million in the three and six month periods, respectively.

The increase in electric margins was reduced by higher MISO Day Two Energy Market costs and unfavorable weather conditions as evidenced by an 18% decrease in cooling degree-days for both the three and six month periods and an 8% decrease in heating degree-days for the six months ended June 30, 2006.

IP’s electric margin decreased by $3 million, or 3%, for the three months and $16 million, or 9%, for the six months ended June 30, 2006, compared with the same periods in 2005 primarily because of:

·	increased purchased power costs as a result of the expiration of its cost-based power supply agreement with EEI on December 31, 2005, and increased purchased power prices; and

·	unfavorable weather conditions including a 12% decrease in heating degree-days for the six months ended June 30, 2006.

The decrease in IP’s electric margins in the three months and six months ended June 30, 2006, was reduced by an increase in revenues as a result of customers switching back to IP because tariff rates were below market rates for power.

Gas Operations

The following table presents the favorable (unfavorable) variations in gas margins, defined as gas revenues less gas purchased for resale, for the three months and six months ended June 30, 2006, compared with the year-ago periods. We consider gas margin to be a useful measure of the change in profitability of our gas utility operations between periods. The table below complements the financial information we provide in accordance with GAAP. However, gas margin may not be a presentation defined under GAAP. Our presentation may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

	Three Months		Six Months
Ameren^(a)	$	-	$	(6)
UE		(3)		(8)
CIPS		2		2
CILCORP		(1)		(4)
CILCO		(2)		(5)
IP		2		5

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

Ameren

Ameren’s gas margin was comparable for the three months but decreased by $6 million, or 3%, for the six months ended June 30, 2006, over the same periods in 2005.

Ameren’s decrease in gas margin for the six months ended June 30, 2006, compared with the same period in 2005 was primarily due to mild weather conditions as evidenced by an 11% decrease in heating degree-days. Residential and commercial gas volume sales decreased 11% and 10%, respectively, for the six months ended June 30, 2006, compared with the same period in 2005. The decrease in gas margin was reduced by, among other things, the effect of an IP rate increase effective in May 2005 that added revenues of $6 million in the first half of 2006.

Ameren’s gas margin was positively impacted in the second quarter over the same period in 2005 by the effect of IP’s rate increase that added revenues of $2 million. The increase in gas margin was offset in part by mild weather conditions that reduced gas margins as heating degree-days were 16% below a mild 2005 second quarter.

UE’s gas margin decreased by $3 million, or 23%, for the three months and $8 million, or 19%, for the six months ended June 30, 2006, compared with the same periods in 2005. UE’s decrease in gas margins for the three months ended June 30, 2006, compared with the same period in 2005, was due to mild weather conditions, as evidenced by a 22% decrease in heating degree-days. UE’s decrease in gas margins for the six months ended June 30, 2006, compared with the same period in 2005, was due to the transfer of UE’s Illinois service territory to CIPS in May 2005, which reduced gas margins by $3 million, and mild weather conditions, as evidenced by a 10% decrease in heating degree-days in UE’s service territory. Residential and commercial gas sales decreased 39% and 22%, respectively, for the three months and 26% and 19%, respectively, for the six months ended June 30, 2006, compared with the same periods in 2005.

CIPS

CIPS’ gas margin increased by $2 million or 17%, for the three months and $2 million or 5%, for the six months ended June 30, 2006, as compared with the same periods in 2005 primarily because of the transfer to CIPS of UE’s Illinois service territory in May 2005. The increase in gas margin was reduced by extremely mild weather as evidenced by a 13% decrease in heating degree-days for the six months ended June 30, 2006, as compared with the same period in 2005.

CILCORP and CILCO

CILCORP’s and CILCO’s gas margins decreased by $1 million, or 6%, and $2 million, or 11%, respectively, for the three months and $4 million, or 8%, and $5 million, or 10%, respectively, for the six months ended June 30, 2006, over the same periods in 2005. This decrease was primarily as a result of mild weather conditions as heating degree-days in the six months ended June 30, 2006, were 8% below the number of days in the six months ended June 30, 2005 in CILCO’s service territory.

IP’s gas margin increased by $2 million, or 7%, for the three months and $5 million, or 6%, for the six months ended June 30, 2006, over the same periods in 2005, primarily because of a rate increase effective in May 2005 that added revenues of $2 million and $6 million, respectively. This increase was reduced by extremely mild weather conditions as evidenced by a 12% decrease in heating degree-days in the first half of 2006 as compared with the year-ago period in IP’s service territory. Residential and commercial gas sales decreased 9% and 7%, respectively, for the three months and 11% and 13%, respectively, for the six months ended June 30, 2006, compared with the same periods in 2005.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Variations in other operations and maintenance expenses at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months and six months - Other operations and maintenance expenses increased $19 million and $22 million primarily because of $10 million of costs in the second quarter of 2006 related to the December 2005 reservoir breach at UE’s Taum Sauk plant, losses on sales of leveraged lease assets in the second quarter of 2006 that increased other operations and maintenance expenses by $7 million, higher power plant maintenance expenses due to the timing of maintenance outages, an increase in legal fees for environmental issues and general litigation, and increased transmission and distribution expenses. Reducing the impact of these items in the second quarter of 2006 was a reduction in bad debt expense.

Three months - Other operations and maintenance expenses increased $3 million primarily because of incremental costs related to the Taum Sauk plant incident along with increased legal fees. Reducing the impact of these unfavorable items were reduced labor and employee benefit costs.

Six months - Other operations and maintenance expenses decreased $7 million primarily because of the transfer of UE’s Illinois service territory to CIPS in May 2005, which resulted in a decrease in other operations and maintenance expenses of $7 million. Additionally, lower injuries and damages expenses due in part to the settlement of claims and decreased labor and employee benefit costs resulted in a reduction in other operations and maintenance expenses. Reducing the impact of these favorable items were increased legal fees and additional costs related to the Taum Sauk plant incident.

CIPS

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

Six months - Other operations and maintenance expenses increased $6 million because of the transfer of UE’s Illinois service territory to CIPS in May 2005, which resulted in an increase in other operations and maintenance expenses of $7 million.

Genco

Three months and six months - Other operations and maintenance expenses increased $9 million and $3 million primarily because of higher maintenance expenses as a result of increased power plant maintenance outages in the current year periods.

CILCORP and CILCO

Three months and six months - Other operations and maintenance expenses increased $9 million and $8 million at CILCORP, and $12 million and $9 million at CILCO, primarily as a result of losses on sales of leveraged lease assets in the second quarter of 2006. The losses on leveraged leases in other operations and maintenance expenses were partially offset by a tax benefit reflected in income taxes.

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

Six months - Other operations and maintenance expenses increased $18 million primarily because of higher transmission and distribution, information technology, bad debt and rental expenses.

Depreciation and Amortization

Variations in depreciation and amortization expenses at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months - Depreciation and amortization expenses increased $5 million primarily because of capital additions.

Six months - Depreciation and amortization expenses increased $13 million primarily as a result of capital additions and the impairment of an intangible asset associated with the CILCORP acquisition.

Three months and six months - Depreciation and amortization expenses increased $5 million and $9 million, respectively, primarily because of capital additions, a portion of which were related to new steam generators and turbine rotors installed during the refueling and maintenance outage at the Callaway nuclear plant in the prior year. Additionally, depreciation increased $1 million and $3 million, respectively, in the three months and six months ended June 30, 2006, due to CTs transferred to UE from Genco in May 2005. Reducing the impact of these increases was a reduction of depreciation due to the transfer of property to CIPS in the Illinois service territory transfer in May 2005.

CIPS

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

Six months - Depreciation and amortization expenses increased $3 million primarily because of depreciation on property transferred to CIPS from UE in the prior-year Illinois service territory transfer along with capital additions.

CILCORP

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

Six months - Depreciation and amortization expenses increased $5 million primarily because of the impairment of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.

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

Six months - Depreciation and amortization expenses decreased $3 million primarily because of write-offs of software in the prior year.

Genco and CILCO

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

Taxes Other Than Income Taxes

Variations in taxes other than income taxes at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months - Taxes other than income taxes decreased $5 million primarily because of lower payroll taxes.

Six months - Taxes other than income taxes increased $17 million primarily as a result of higher gross receipts taxes and higher property taxes, primarily at Genco.

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

Six months - Taxes other than income taxes increased $4 million primarily as a result of higher gross receipts taxes.

CIPS

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

Six months - Taxes other than income taxes increased $6 million primarily as a result of higher gross receipts and excise taxes.

Genco

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

Six months - Taxes other than income taxes increased $8 million primarily because of higher property taxes due to an $8 million tax settlement that was received in the first quarter of 2005 that did not recur in 2006.

CILCORP and CILCO

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

Six months - Taxes other than income taxes increased $2 million and $3 million at CILCORP and CILCO, respectively, primarily as a result of higher excise taxes.

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

Other Income and Expenses

Variations in other income and expenses at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months and six months - Miscellaneous income decreased $2 million and $5 million primarily as a result of lower capitalization of equity funds used during construction in the current year periods. Miscellaneous expense decreased $5 million and $6 million primarily due to the write-off of unrecoverable natural gas costs in the prior year as noted below.

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

Six months - Miscellaneous income decreased $5 million primarily as a result of lower capitalization of equity funds used during construction in the current year period. Miscellaneous expense was comparable between periods.

CIPS

Three months and six months - Miscellaneous income was comparable between periods. Miscellaneous expense decreased $4 million and $3 million primarily as a result of the write-off of unrecoverable natural gas costs in the prior year.

CILCORP

Three and six months - Miscellaneous income was comparable between periods. Miscellaneous expense decreased $2 million and $3 million primarily as a result of the write-off of unrecoverable natural gas costs in the prior year.

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

Six months - Miscellaneous income decreased $2 million primarily as a result of lower capitalization of equity funds used during construction and reduced investment income in the current year period. Miscellaneous expense was comparable between periods.

Genco and CILCO

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

Interest

Variations in interest expense at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months and six months - Interest expense increased $3 million and $5 million primarily because of items noted below at the various Ameren Companies, partially offset by a reduction in interest expense resulting from the repurchase and retirement of Ameren’s $95 million of senior notes in February 2005.

Three months and six months - Interest expense increased $10 million and $20 million primarily because of the issuances of $300 million of senior secured notes in July 2005 and $260 million of senior secured notes in December 2005 along with increased short-term borrowings resulting from the purchase of CTs in the first quarter of 2006.

Genco

Three months and six months - Interest expense decreased $4 million and $10 million primarily because of the maturity of $225 million of senior notes in November 2005.

CIPS, CILCORP, CILCO and IP

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

Income Taxes

Variations in income tax expense at the Ameren Companies for the three months and six months ended June 30, 2006, compared with the same periods in 2005 were as follows:

Ameren

Three months and six months - Income taxes decreased primarily because of lower pretax income along with items noted below at the various Ameren Companies.

Three months and six months - Income taxes decreased primarily because of lower pretax income, partially offset by permanent tax items.

CIPS

Three months and six months - Income taxes decreased in the second quarter of 2006, despite higher pretax income, due to a favorable federal audit settlement. Income taxes decreased in the six months ended June 30, 2006, primarily because of lower pretax income and the favorable audit settlement.

Genco

Three months and six months - Income taxes decreased primarily because of lower pretax income.

CILCORP and CILCO

Three months and six months - Income taxes decreased primarily because of lower pretax income and a tax benefit related to leveraged lease sales.

Three months and six months - Income tax expense was comparable between periods for the three months. Income tax expense decreased in the six months of 2006 primarily because of lower pretax income.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO and IP) continue to be the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail-customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows for Ameren. For operating cash flows, Genco principally relies on sales to an affiliate under a contract expiring at the end of 2006 and sales to other wholesale and industrial customers under short and long-term contracts. Commencing in 2007, Genco and AERG intend to sell power previously sold under existing contracts through new contracts obtained through the Illinois power procurement auction or other contracts executed with wholesale and retail customers. The amount of power that Genco and its affiliates may supply to CIPS, CILCO and IP through the Illinois power procurement auction is limited to 35% of CIPS’, CILCO’s and IP’s annual load. In addition, each of the Ameren Companies plans to use short-term borrowings 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, 2006, for UE, Genco, CILCORP, CILCO and IP. The Ameren Companies will discretionarily reduce their short-term borrowings with cash from operations or with long-term borrowings.

The following table presents net cash provided by (used in) operating, investing and financing activities for the six months ended June 30, 2006 and 2005:

	Net Cash Provided By Operating Activities						Net Cash Provided By (Used In) Investing Activities						Net Cash Provided By (Used In) Financing Activities
	2006		2005		Variance		2006		2005		Variance		2006		2005		Variance
Ameren^(a)	$	570	$	749	$	(179)	$	(746)	$	(531)	$	(215)	$	131	$	(260)	$	391
UE		227		353		(126)		(511)		(492)		(19)		265		92		173
CIPS		79		96		(17)		(23)		-		(23)		(55)		(97)		42
Genco		55		132		(77)		(56)		102		(158)		2		(235)		237
CILCORP		106		55		51		-		(64)		64		(86)		5		(91)
CILCO		113		77		36		(42)		(67)		25		(51)		(11)		(40)
IP		86		149		(63)		(83)		8		(91)		(2)		(157)		155

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

Cash Flows from Operating Activities

Ameren’s cash from operations decreased in the first six months of 2006, as compared with the first six months of 2005, due primarily to decreases in electric and gas margins as discussed in Results of Operations above. Also contributing to the decrease was cash used during the first six months of 2006 for payment of 2005 year-end accruals including real estate and property taxes, annual incentive compensation that was more than it was a year ago because of increased 2005 earnings relative to performance targets, and trade payables that were higher than normal due to an unusually cold December 2005 and higher natural gas prices. The cash benefit from reduced natural gas inventories that resulted in the first quarter of 2006 due to the end of the winter heating season was offset in the second quarter as a result of increased volume and per unit prices of coal inventory purchases because of the alleviation of the coal supply issues experienced in the 2005 period and higher market prices for coal in the 2006 period. Reducing the negative impacts was the collection of higher-than-normal trade receivables caused by cold December 2005 weather during the winter heating season. The cash impact from trade receivables was more significant in the current period due to higher gas prices and colder December weather in 2005 as compared with the year-ago period.

At UE, cash from operating activities decreased in 2006 due to lower electric and gas margins and cash used for working capital changes that primarily included increased payments of year-end accruals in the first six months of 2006 as compared with the year-ago period as discussed above for Ameren. Also contributing to the decrease were increased income tax payments of $49 million compared to the year-ago period.

At CIPS, the negative cash effect of higher other operations and maintenance expenses and taxes other than income was partially offset by higher electric and gas margins, as discussed in Results of Operations. However, increased working capital investment also contributed to the decrease in cash from operations in the 2006 period as compared to the year ago period. The most significant change in working capital was a $35 million increase in income tax payments compared to the year-ago period. Partially offsetting this use of cash was an increase in collections of trade receivables as a result of colder December 2005 weather and higher gas prices compared to the year-ago period.

Genco’s cash from operating activities in the first six months of 2006 decreased compared to the 2005 period primarily because of lower operating margins as discussed in

Results of Operations. Interest payments were lower in the 2006 period due to decreased debt outstanding.

Cash from operating activities increased for CILCORP and CILCO in the six months ended June 30, 2006, compared with the same period of 2005 primarily because of higher electric margins as discussed in Results of Operations and an increase in collections of trade receivables as a result of colder December 2005 weather and higher gas prices compared to the year-ago period. Partially offsetting these positive effects on cash were higher other operations and maintenance expenses as discussed in Results of Operations. In addition, income tax payments increased $12 million for CILCO and decreased $3 million for CILCORP.

IP’s cash from operations decreased in the six months ended June 30, 2006, compared with the 2005 period due to lower electric margins and higher other operations and maintenance expenses as discussed above in Results of Operations. Also contributing to IP’s decreased operating cash flows in 2006 were income taxes paid of $6 million in the 2006 period as compared with income tax refunds of $9 million in the year-ago period, and cash used during the first six months of 2006 for payment of 2005 year-end accruals including real estate and property taxes, annual incentive compensation that was more than it was a year ago due to increased 2005 earnings relative to performance targets, and trade payables that were higher than normal due to an unusually cold December 2005 and higher natural gas prices.

Cash Flows from Investing Activities

Ameren’s increase in cash used in investing activities was primarily because of UE’s purchases of a 640-megawatt CT facility from affiliates of NRG Energy, Inc., and 510-megawatt and 340-megawatt CT facilities from subsidiaries of Aquila, Inc. for a total of $292 million. The CT purchases are intended to meet UE’s increased generating capacity needs and provide UE with additional flexibility in determining future base-load generating capacity additions.

Excluding CT purchases, Ameren’s capital expenditures decreased $36 million in the first six months of 2006 as compared with the year-ago period primarily because fewer capital resources were allocated to other projects due to the planned CT acquisitions. Excluding the CTs purchased from Genco and an additional $25 million used to purchase CT equipment from Development Company in the 2005 period, UE’s capital expenditures were only $26 million less in the first six months of 2006 as compared with the year-ago period. In addition, emission allowance purchases decreased $54 million in the first six months of 2006 compared to the first six months of 2005. The sale of leveraged lease investments provided an $11 million benefit to Ameren’s cash from investing activities as discussed below.

CIPS’ increase in cash used in investing activities for the six months ended June 30, 2006, over the 2005 period was due to a $16 million increase in capital expenditures. Also negatively impacting CIPS’ investing cash flow was an $18 million reduction in proceeds from CIPS’ note receivable from Genco in the 2006 period as compared with the 2005 period. The decrease in proceeds from Genco resulted from the May 1, 2005 amendment and restatement of the note. Partially offsetting these negative effects was an $11 million reduction of advances to the money pool in 2006 as compared with 2005. The increased capital expenditures resulted partly from CIPS’ expansion of its service territory because of its acquisition of UE’s Illinois utility operations in May 2005. CIPS’ capital expenditures were for projects to improve the reliability of its electric and gas transmission and distribution systems.

Genco had a net use of cash in investing activities for the first six months of 2006 compared to a net source of cash during the same period in 2005. This was due primarily to the 2005 transfer of two CTs to UE in 2005 for $241 million. Genco’s capital expenditures were lower for the six months ended June 30, 2006, compared with the 2005 period because 2005 included expenditures due to an extended planned outage at one of its power plants. Purchases of emission allowances were $45 million less in the first six months of 2006 compared to the first six months of 2005.

CILCORP’s cash from investing activities benefited from the repayment of Resources Company’s note payable of $42 million that originated from the 2005 transfer of leveraged leases from CILCORP to Resources Company. In addition, a subsidiary of CILCORP and CILCO generated cash from investing activities of $11 million in the six months ended June 30, 2006, from the sale of its remaining leverage lease investments. Emission allowance purchases were $9 million less in the first six months of 2006 compared to the first six months of 2005.

IP had a net use of cash in investing activities for the first six months of 2006 compared to a net source of cash in the prior-year period primarily because of the absence in the six month period ended June 30, 2006, of proceeds received in the first six months of 2005 from repayments received for advances made to the money pool in prior periods. In addition, capital expenditures increased $22 million over the year-ago period due to increased projects to maintain the reliability of IP’s electric and gas transmission and distribution systems.

See Note 8 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for a further discussion of future environmental capital investment estimates.

We continually review our generation portfolio and expected power needs. As a result, we could modify our 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

Cash from financing activities increased for Ameren in the first six months of 2006 from the year-ago period, primarily because of net short-term debt proceeds of $204 million, which were used to partially fund UE’s CT acquisitions, compared to net short-term debt repayments of $256 million in the year-ago period. Ameren’s cash from financing activities also increased from long-term debt issuances of $232 million at CIPS, CILCO and IP in 2006, which was significantly more than Ameren’s 2005 long-term debt issuances of $85 million. In addition, long-term debt redemptions, repurchases, and maturities decreased by $151 million in 2006, compared to the same period in 2005. Cash from stock proceeds was significantly less in the 2006 period because proceeds in the 2005 period included the issuance of 7.4 million shares of common stock related to the settlement of a stock purchase obligation in Ameren’s adjustable conversion-rate equity security units.

UE’s cash from financing activities increased for the six months ended June 30, 2006, as compared with the 2005 period, primarily because of a $284 million increase in net short-term debt proceeds in 2006 compared to combined net money pool and short-term debt proceeds of $143 million in the 2005 period, which resulted in a $141 million benefit in the 2006 period. In addition, $67 million was received from CIPS in payment of its intercompany note, and dividend payments decreased $51 million, both of which benefited cash from financing activities in the 2006 period as compared with the 2005 period. Net cash from financing activities was partially used to fund the CT acquisitions.

CIPS’ cash used in financing activities decreased for the six months ended June 30, 2006, as compared with the 2005 period, because of a $66 million decrease in payments to the money pool in the 2006 period. A $16 million increase in dividends to Ameren negatively impacted CIPS’ cash from financing activities in 2006 as compared to the year-ago period. CIPS’ second quarter issuance of $61 million of long-term debt had a minor net impact on cash from financing activities because the proceeds were used to repay CIPS’ outstanding balance on the intercompany note payable to UE that was originally issued with the transfer of UE’s Illinois service territory to CIPS in 2005.

Genco had net cash proceeds from financing activities for the first six months of 2006, compared to a net use of cash for the same period last year. This is primarily due to Genco having $57 million in net borrowings from the money pool in the 2006 period, compared to net repayments of $116 million in the prior year period. In addition, lower intercompany note payments of $52 million in the 2006 period, and a $50 million capital contribution received in 2006 from Ameren also benefited Genco’s financing cash flows. Partially offsetting these positive effects on cash was a $37 million increase in dividend payments in the 2006 period as compared with the 2005 period.

CILCORP’s and CILCO’s cash from financing activities benefited from CILCO’s long-term debt issuances that generated $96 million in the 2006 period, as compared with no long-term debt issuances in the 2005 period. However, this benefit in the 2006 period was completely offset by the absence in 2006 of a $101 million capital contribution received in the 2005 period. In addition, in 2006, CILCORP used cash of $12 million for open market debt repurchases as compared with $6 million of cash used for repurchases in the 2005 period. CILCORP’s repayments of $30 million on its note payable to Ameren reduced its financing cash flow by $52 million as compared with the year-ago period because the 2005 period included borrowings on this note that provided CILCORP with cash.

Also contributing to CILCORP’s and CILCO’s increase in cash used in financing activities for the six months ended June 30, 2006, as compared with the year-ago period, were increased common stock dividends of $20 million and $30 million at CILCORP and CILCO, respectively, in the 2006 period as compared with the 2005 period. In addition, net increases in cash for money pool repayments of $7 million and $4 million at CILCORP and CILCO, respectively, also negatively impacted cash in the 2006 period.

IP’s cash used in financing activities decreased for the six months ended June 30, 2006, as compared with the 2005 period, primarily because of lower redemptions and repurchases of long-term debt of $67 million and the absence in the 2006 period of $40 million of common stock dividend payments made in the 2005 period. IP’s 2006 cash from financing activities also benefited from the issuance of $75 million of long-term debt as compared with no long-term debt proceeds in the year-ago period. A portion of the 2006 long-term debt proceeds were used to repay short-term debt consisting of borrowings under Ameren’s utility money pool.

Short-term Borrowings and Liquidity

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, see Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report.

The following table presents the committed bank credit facilities of the Ameren Companies and AERG as of June 30, 2006, and July 14, 2006:

Credit Facility	Expiration		Amount Committed		Amount Available
Ameren:
Multiyear revolving^(a)(b)		July 2010	$	1,150	$	756
Multiyear revolving^(c)		July 2006		350		350
CIPS, CILCORP, CILCO, IP and AERG:
Multiyear revolving^(d)		January 2010		500		500

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

(b)

UE and Genco are also direct borrowers under this facility. CIPS, CILCO and IP were also direct borrowers under this agreement until July 13, 2006. See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for discussion of the amendment of this facility.

(c)	This credit facility was terminated on July 14, 2006.

(d)

This credit facility was entered into on July 14, 2006. The maximum amount available to each borrower, including for issuance of letters of credit, is limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $150 million, IP - $150 million and AERG - $200 million. The ability of CIPS, CILCO, and IP to borrow under this facility is subject to the receipt of necessary regulatory approvals. See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for discussion of the new credit facility.

In addition to committed credit facilities, a further source of liquidity for Ameren from time to time is available cash and cash equivalents. At June 30, 2006, Ameren had $51 million of cash and cash equivalents.

With the repeal of PUHCA 1935 in February 2006, the issuance of short-term debt securities by Ameren’s utility subsidiaries is now subject to approval by FERC under the Federal Power Act. In March 2006, FERC issued an order authorizing these subsidiaries to issue short-term debt securities subject to the following limits on outstanding balances: UE - $1 billion; CIPS - $250 million; and CILCO - $250 million. This authorization was effective as of April 1, 2006, and terminates on March 31, 2008.

Genco is also authorized by FERC in its March 2006 order to have up to $300 million of short-term debt outstanding at any time. IP, AERG and EEI have unlimited short-term debt authorization from FERC.

With the repeal of PUHCA 1935 in February 2006, the issuance of short-term debt securities by Ameren and CILCORP, which was previously subject to SEC approval under PUHCA 1935, is no longer subject to approval by any regulatory body.

Long-term Debt and Equity

The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt and preferred stock (net of any issuance discounts and including any redemption premiums) for the six months ended June 30, 2006 and 2005, for the Ameren Companies. For additional information, see Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.

			Six Months
	Month Issued, Redeemed, Repurchased or Matured		2006		2005
Issuances
Long-term debt
UE:^(a)
5.00% Senior secured notes due 2020		January	$	-	$	85
CIPS:
6.70% Senior secured notes due 2036		June		61		-
CILCO:
6.20% Senior secured notes due 2016		June		54		-
6.70% Senior secured notes due 2036		June		42		-
IP:
6.25% Senior secured notes due 2016		June		75		-
Total Ameren long-term debt issuances			$	232	$	85

			Six Months
	Month Issued, Redeemed, Repurchased or Matured		2006		2005
Common stock
Ameren:
7,402,320 Shares at $46.61^(b)	May	$	-	$	345
DRPlus and 401(k)^(c)	Various		57		57
Total common stock issuances		$	57	$	402
Total Ameren long-term debt and common stock issuances		$	289	$	487
Redemptions, Repurchases and Maturities
Long-term debt
Ameren:
Senior notes due 2007^(d)	February	$	-	$	95
CIPS:
7.05% First mortgage bonds due 2006	June		20		-
6.49% First mortgage bonds due 2005	June		-		20
CILCORP:
9.375% Senior notes due 2029	March/April		12		- -
8.70% Senior notes due 2009	May		-		6
IP:
6.75% First mortgage bonds due 2005	March		-		70
Notes payable to IP SPT
5.54% Series due 2007	Various		54		-
5.38% Series due 2005	Various		-		46
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities		$	86	$	237

(a)	Ameren’s and UE’s long-term debt increased $240 million as a result of the first quarter leasing transaction related to UE’s purchase of a 640-megawatt CT facility located in Audrain County, Missouri. No capital was raised as a result of UE’s assumption of the lease obligations.

(b)	Shares issued upon settlement of the purchase contracts, which were a component of the adjustable conversion-rate equity security units.

(c)	Includes issuances of common stock of 1.1 million shares during the six months ended June 30, 2006, under DRPlus and 401(k) plans.

(d)	Component of the adjustable conversion-rate equity security units.

The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain Ameren Companies as of June 30, 2006:

	Effective Date		Authorized Amount		Issued		Available
Ameren		June 2004	$	2,000	$	459	$	1,541
UE		October 2005		1,000		260		740
CIPS		May 2001		250		211		39

Ameren also has approximately 4.0 million shares of common stock available for issuance under various other SEC effective registration statements applicable to its DRPlus and 401(k) plans as of June 30, 2006.

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 meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

Indebtedness Provisions and Other Covenants

See Note 3 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1, of this report for a discussion of the covenants and provisions contained in Ameren’s bank credit facilities and applicable cross-default provisions. Also see Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ indenture agreements and articles of incorporation.

At June 30, 2006, the Ameren Companies were in compliance with their credit facility, 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. Our 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. Such events might increase our cost of capital or adversely affect our ability to access the capital markets.

Dividends

Dividends paid by Ameren to shareholders during the first six months of 2006 totaled $260 million, or $1.27 per share (2005 - $253 million or $1.27 per share).

UE paid preferred stock dividends of approximately $1 million on May 15, 2006. CIPS paid preferred stock dividends of approximately $1 million on June 30, 2006. CILCO paid preferred stock dividends of less than $1 million on July 3, 2006. IP paid preferred stock dividends of approximately $1 million on August 1, 2006. The next preferred dividends are payable on August 15, 2006, September 29, 2006, October 2, 2006 and November 1, 2006 for UE, CIPS, CILCO and IP, respectively.

See Note 3 - Short-term Borrowings and Liquidity and Note 4 - Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements, articles of incorporation and an ICC order that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At June 30, 2006, none of these circumstances existed and as a result, the Ameren Companies were allowed to pay dividends.

On July 14, 2006, CIPS, CILCORP, CILCO, IP, and AERG entered into a new $500 million credit facility which limits a borrower to capital stock dividend payments of $10 million per year if the borrower has a below investment-grade senior unsecured credit rating as defined in the new facility. With respect to AERG, which currently is not rated, the dividend restriction will not apply if its consolidated total debt to consolidated operating cash flow pursuant to a calculation defined in the facility is less than or equal to 3.0 to 1. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured credit rating to below investment-grade causing it to be subject to this dividend payment limitation. The other borrowers are not currently limited in their dividend payments by this provision of the new credit facility. See Note 3 - Short-term Borrowings and Liquidity under Part I, Item 1, of this report.

The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the six months ended June 30, 2006 and 2005.

	Six Months
	2006		2005
UE	$	84	$	135
CIPS		25		9
Genco		71		34
CILCORP^(a)		50		30
IP		-		40
Nonregistrants		30		5
Dividends paid by Ameren	$	260	$	253

(a)	CILCO paid dividends of $50 million and $20 million for the six months ended June 30, 2006 and 2005, respectively.

Contractual Obligations

For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005. See Note 11 - Retirement Benefits to our financial statements under Part I, Item 1, of this report for information regarding expected minimum funding levels for our pension plan.

Subsequent to December 31, 2005, obligations related to the procurement of coal and natural gas changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $4,327 million, $1,654 million, $471 million, $642 million, $645 million, $645 million and $622 million, respectively, as of June 30, 2006. Total other obligations at June 30, 2006, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $4,799 million, $1,929 million, $601 million, $642 million, $757 million, $757 million and $803 million, respectively.

Credit Ratings

On July 26, 2006, Moody’s downgraded the principal credit ratings of certain of the Ameren Companies as presented in the following table:

	From	To
UE:
Secured debt	A1	A2
Unsecured debt	A2	A3
Commercial paper	P-1	P-2
CIPS:
Secured debt	A3	Baa2
Unsecured debt	Baa1	Baa3
CILCORP:
Unsecured debt	Baa3	Ba1
CILCO:
Secured debt	A3	Baa1
Unsecured debt	Baa1	Baa2

Moody’s confirmed the credit ratings of Ameren and IP, and Genco was unaffected. Following these actions, Moody’s review for possible downgrade was removed and replaced with a negative outlook for Ameren, CIPS, CILCORP, CILCO and IP, and a stable outlook was assigned to UE and Genco.

According to Moody’s, the downgrade of UE was principally because of the following factors:

·	Weaker financial metrics due to higher operating costs and large capital expenditures for environmental compliance that are not currently being recovered from customers.

·	The likelihood that if the operating cash flow for Ameren’s Illinois utilities declines, Ameren may need to rely on UE and Ameren’s unregulated operations for a larger share of upstreamed dividends to meet parent company obligations.

According to Moody’s, the downgrade of CIPS, CILCORP and CILCO was principally because of the following factors:

·	A difficult political and regulatory environment in Illinois associated with the recovery of higher purchased power costs by electric utilities commencing January 1, 2007.

·	Moody’s expectation that the outcome in Illinois will involve a material regulatory deferral of recovery of higher power procurement costs.

There have been no other changes to the Ameren Companies’ credit ratings since the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005.

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital. It may also increase the cost of borrowing and fuel and power supply, among other things, resulting in a negative impact on earnings. For example, if at June 30, 2006, the Ameren Companies had a sub-investment-grade rating (less than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could have been required to post collateral for certain trade obligations amounting to $129 million, $15 million, $6 million, $6 million, $15 million, $15 million, or $70 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease with credit ratings. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

OUTLOOK

Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2006 and beyond:

On July 19, 2006 and July 21, 2006, UE’s, CIPS’ and IP’s service territories were hit by severe storms, which included tornados, that resulted in the loss of power to approximately 700,000 customers combined. Through the dedication of a work force of 5,200, including our employees, contractors and utility workers from 13 states, we restored service to all of our customers within nine days. The full financial impact of these storms has not yet been determined, but UE, CIPS and IP have incurred unanticipated costs and the loss of electric margins as a result of these devastating storms.

Revenues

·	By the end of 2006, electric rates for Ameren’s operating subsidiaries will have been fixed or declining for periods ranging from 15 years to 25 years. In 2006, electric rate adjustment moratoriums and power supply contracts expire in Ameren’s regulatory jurisdictions.

In July 2006, UE, CIPS and Genco mutually consented to terminate the JDA on December 31, 2006. Upon termination of the JDA, Genco will no longer receive the margins on sales that were supplied with power from UE. However, Genco will still have access to its own generation and expects to be able to sell this power at higher average prices than this power was sold for in 2005 because of the expiration of its power supply contract with CIPS and the expiration of contracts to supply other wholesale and retail customers on or before December 31, 2006. Ameren’s and UE’s earnings will be affected by the termination of the JDA when UE’s rates are adjusted by the MoPSC. UE’s requested electric rate increase filed in July 2006 is net of the decrease in its revenue requirement resulting from increased margins expected to result from the termination of the JDA. Termination of the JDA will require acceptance by FERC. See Note 2 - Rate and Regulatory Matters and Note 7 -

Related Party Transactions to our financial statements under Part I, Item 1, of this report for a further discussion of the JDA.

In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers in 2007 through an auction. This approval is subject to court appeal. Power supplied by Genco and AERG to CIPS and CILCO, respectively, have been subject to below-market-priced contracts. Most of Genco’s other wholesale and retail electric power supply agreements also expire during 2006 and substantially all of these are below market prices for similar contracts in 2006. Genco currently expects to generate approximately 17.5 million megawatthours of power in 2007. By 2007, only 5.2 million megawatthours of power covered by wholesale and retail electric power supply agreements that were in effect in 2005 will remain outstanding. These agreements have an average embedded selling price of $36 per megawatthour. All other power supply agreements in effect in 2005 will expire by the end of 2006 and any available generation in 2007 will be sold at prevailing market prices. AERG currently expects to generate approximately 7.0 million megawatthours of power in 2007 compared to 5.9 million megawatthours of power that was generated in 2005 at an average cost of approximately $15 per megawatthour. In 2005, this power was sold principally to CILCO at an average price of $32 per megawatthour. In addition, AERG sold 1 million net megawatthours of power in the interchange market at an average price of $38 per megawatthour in 2005. In 2007, all of AERG’s power will be sold at prevailing market prices.

Ameren expects the average residential electric rates for CIPS, CILCO and IP to increase significantly following the expiration of a rate freeze at the end of 2006. The amount of the increase will depend on outcomes for CIPS’, CILCO’s and IP’s pending electric delivery services revenue increase requests to the ICC and power supply costs that result from the proposed Illinois power procurement auction, among other things.

Certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties have sought and continue to seek various methods, including rate freeze legislation, to block the power procurement auction and/or the recovery of related costs for power supply resulting from the auction through rates to customers. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren. CIPS, CILCO and IP are willing to work with stakeholders to ease the burden of higher energy prices on residential customers through a rate increase phase-in plan, as long as such plan allows for the full and timely recovery of costs and does not adversely impact credit ratings. In March 2006, legislation was introduced in the Illinois House of Representatives that would allow the deferral of a portion of the power procurement costs and would authorize the ICC to permit a utility with fewer than one million retail customers to form special purpose finance vehicles to issue securitization bonds to recover the deferred costs, with interest. CIPS, CILCO and IP each have less than one million retail customers. In June 2006, CIPS, CILCO and IP filed a rate increase phase-in and revenue securitization plan with the ICC that was based on this proposed legislation that would relate to the deferral of power supply costs for 2007 and 2008.

The Ameren Illinois utilities filed proposed new tariffs with the ICC in December 2005 that would increase annual revenues from electric delivery services, effective January 2, 2007, by $156 million (CIPS - $14 million, CILCO - $33 million, IP - $109 million) per year commencing in 2007 and an additional $46 million (CILCO - $10 million, IP - $36 million) per year commencing in 2008. In June 2006, the ICC staff filed rebuttal testimony recommending increases in revenues for electric delivery services for the Ameren Illinois utilities aggregating $120 million (CIPS - $1 million, CILCO - $30 million and IP - $89 million). In April 2006, the Illinois attorney general and CUB recommended net increases in revenues for electric delivery services of $71 million for the Ameren Illinois utilities (CIPS - $7 million decrease, CILCO - $19 million increase and IP - $59 million increase). In subsequent testimony, the Illinois attorney general accepted certain of the Ameren Illinois utilities’ positions increasing the estimated aggregate recommended revenue increase to $100 million. Other parties also made recommendations in the case. The ICC has until November 2006 to render a decision in these rate cases. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.

In July 2006, UE filed requests with the MoPSC for an increase in electric rates of $361 million and in natural gas delivery rates of $11 million. The MoPSC staff and other stakeholders will review UE’s rate adjustment requests and, after their analyses, may also make recommendations as to rate adjustments. Generally, a proceeding to change rates in Missouri could take up to 11 months. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.

·	We expect continued economic growth in our service territory to benefit energy demand in 2006 and beyond, but higher energy prices could result in reduced demand from consumers.

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

·	Very volatile power prices in the Midwest affect the amount of revenues UE, Genco and CILCO (through AERG) can generate by marketing power into the

wholesale and interchange markets and influence the cost of power we purchase in the interchange markets.

·	On April 1, 2005, the MISO Day Two Energy Market began operating. The MISO Day Two Energy Market presents an opportunity for increased power sales from UE, Genco and CILCO power plants and improved access to power for UE, CIPS, CILCO and IP.

Fuel and Purchased Power

In 2005, 86% of Ameren’s electric generation (UE - 80%, Genco - 96%, CILCO - 99%) was supplied by its coal-fired power plants. About 88% of the coal used by these plants (UE - 96%, Genco - 67%, CILCO - 77%) was delivered by railroads from the Powder River Basin in Wyoming. In May 2005, the joint Burlington Northern-Union Pacific rail line in the Powder River Basin suffered two derailments due to unstable track conditions. As a result, the Federal Rail Administration placed slow orders, or speed restrictions, on sections of the line until the track could be made safe. Because of the railroad delivery problems, UE, Genco and CILCO received only about 90% to 95% of scheduled deliveries of Powder River Basin coal in 2005. The impact of the coal delivery issues on inventory levels was exacerbated by warm summer weather and high power prices, which caused UE, Genco and CILCO plants to run more and to burn record amounts of coal. Maintenance on the rail lines into the Powder River Basin is continuing in 2006, but is expected to have less of an impact on deliveries than in 2005. Further disruptions in coal deliveries could cause UE, Genco and CILCO to pursue a strategy that could include reducing sales of power during low-margin periods, utilizing higher-cost fuels to generate required electricity and purchasing power.

Ameren’s coal and related transportation costs are expected to increase 10% to 15% in 2006 and an additional 15% to 20% in 2007. In addition, power generation from higher-cost gas-fired plants is expected to increase in the next few years. See Item 3 - Quantitative and Qualitative Disclosures about Market Risk for information about the percentage of fuel and transportation requirements that are price-hedged for 2006 through 2010.

The MISO Day Two Energy Market resulted in significantly higher MISO-related costs in 2005. In part, these higher charges were due to volatile summer weather patterns and related loads. In addition, we attribute some of these higher charges to the relative infancy of the MISO Day Two Energy Market, suboptimal dispatching of power plants, and price volatility. We will continue to optimize our operations and work closely with MISO to ensure that the MISO Day Two Energy Market operates more efficiently and effectively in the future.

In July 2005, a new law was enacted that enables the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri’s utilities. The law also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental cost recovery mechanism, and prudency reviews, among other things. Detailed rules for the fuel and purchased power cost recovery mechanism are expected to be effective in the second half of 2006. We are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted. As part of its electric rate case filing in July 2006, UE requested the use of the fuel, purchased power, and environmental cost recovery mechanisms.

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. The incident is being investigated by FERC and state authorities. The facility will remain out of service until reviews by FERC and state authorities are concluded, further analyses are completed, and input is received from key stakeholders as to how and whether to rebuild the facility. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through most, if not all, of 2008. UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all of the damage and liabilities caused by the breach will be covered by insurance. UE expects the total cost for damage and liabilities resulting from the Taum Sauk incident to range from $63 million to $83 million. As of June 30, 2006, UE had paid $27 million and accrued a $36 million liability, while expensing $11 million, and recording a $52 million receivable due from insurance companies. No amounts have been recognized in the financial statements relating to estimated costs to repair or rebuild the facility. 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 may be subject to litigation by private parties or by state or federal authorities. Until the reviews conducted by state and federal authorities have concluded, the insurance review is completed, a decision whether the plant will be rebuilt is made, and future regulatory treatment for the plant is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.

·	UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in 2007. During an 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 our other facilities. Insurance premiums may also increase as a result of the Taum Sauk incident.

·	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

The EPA has issued more stringent emission limits on all coal-fired power plants. Between 2006 and 2016, Ameren expects that certain Ameren Companies will be required to invest between $2.7 billion and $3.4 billion to retrofit their power plants with pollution control equipment. More stringent state regulations could increase these costs. These investments will also result in higher ongoing operating expenses. Approximately 50% of this investment will be in Ameren’s regulated UE operations, and therefore it is 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 this increased investment.

In March 2006, UE completed the purchase of three gas-fired CT facilities with a capacity of nearly 1,500 megawatts in transactions valued at $292 million. The purchase of these facilities is designed to meet UE’s increased generating capacity needs and to provide additional flexibility in determining future baseload generating capacity additions. 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 at least 2015. 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 utilizing coal or nuclear power.

Affiliate Transactions

Due to a MoPSC order issued in conjunction with the transfer of UE’s Illinois service territory to CIPS, UE, CIPS, and Genco amended the JDA effective in January 2006. If such an amendment had been in effect in 2005, we believe it would have resulted in a transfer of electric margins from Genco to UE of $35 million to $45 million based on certain assumptions and historical results. On July 7, 2006, UE, CIPS and Genco mutually consented to waive the one-year termination notice requirement and agreed to terminate the JDA on December 31, 2006. As a result of the termination of the JDA, UE and Genco will no longer have the obligation to provide power to each other. UE will retain the power it was transferring under the JDA to Genco at incremental cost and be able to sell any excess power it has at market prices. Genco will no longer receive the margins on sales that it made, which were supplied with power from UE. Termination of the JDA will require acceptance by FERC. Ameren’s and UE’s earnings will be affected by the termination of the JDA when UE’s rates are adjusted by the MoPSC. See Risk Factors under Part II, Item 1A and Note 2 - Rate and Regulatory Matters and Note 7 - Related Party Transactions to our financial statements under Part I, Item 1, of this report for a discussion of the modification to the JDA ordered by the MoPSC and the effects of terminating the JDA.

On December 31, 2005, a power supply agreement with EEI for UE, CIPS (which resold its entitlement to Marketing Company) and IP expired. Power supplied under the agreement by EEI to UE, Marketing Company and IP was priced at EEI’s cost-based rates. Power previously supplied under this agreement to UE, Marketing Company and IP is being sold at market prices in 2006, which are above EEI’s cost-based rates and will continue to be sold at market prices in 2007. However, in 2006, UE, Genco (which supplies Marketing Company) and IP are replacing power previously received from EEI either through the use of their own higher-cost generation or higher-cost power purchases. In 2005, EEI generated 7.9 million megawatthours of power. UE, CIPS (which resold the power to Marketing Company) and IP purchased 3.0 million, 2.0 million and 1.2 million megawatthours, respectively, from EEI at an average price of $20 per megawatthour. The remaining generation was sold to EEI’s minority owner. The expiration of this agreement and the resulting decrease in UE’s margins and increase in its revenue requirement were reflected in UE’s July 2006 request to the MoPSC to increase electric rates.

Recent Acquisitions

·	Ameren, CILCORP, CILCO and IP expect to focus on realizing integration synergies associated with these acquisitions, including utilizing more economical fuels at CILCORP and CILCO and reducing administrative and operating expenses at IP.

Other

·	In August 2005, President George W. Bush signed into law the Energy Policy Act of 2005. This legislation includes several provisions that affect the Ameren Companies, including the repeal of PUHCA 1935 (under

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

The 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 non-derivative, 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.

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 within prudent risk parameters. Our risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers.

Except as discussed below, there have been no material changes to the quantitative and qualitative disclosures about market risk in the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005. See Item 7A under Part II of the 2005 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, 2006:

	Interest Expense		Net Income^(a)
Ameren	$	13	$	(8)
UE		8		(5)
CIPS		(b)		(b)
Genco		3		(2)
CILCORP		2		(1)
CILCO		1		(1)
IP		4		(2)

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

(b) Less than $1 million.

The model does 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.

Credit Risk

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

Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables, executory contracts with market risk exposures, and leveraged lease investments. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At June 30, 2006, no nonaffiliated customer represented greater than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. UE, Genco, AERG, IP and Marketing Company may have credit exposure associated with interchange purchase and sale activity with nonaffiliated companies. At June 30, 2006, UE’s, Genco’s, AERG’s, IP’s and Marketing Company’s combined credit exposure to non-investment-grade counterparties related to interchange purchases and sales was less than $1 million, net of collateral. 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 leases. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $27 million at June 30, 2006.

Equity Price Risk

Our costs of providing defined benefit retirement and postretirement plans are dependent on 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 to regulated and nonregulated electric customers. Most of Genco’s and AERG’s electric power sales agreements expire during 2006. EEI’s cost-based power supply agreements for nearly all of its power expired at the end of 2005. EEI has an agreement to sell 100% of its capacity and energy to Marketing Company through December 31, 2015. EEI currently does not expect to hedge for price risk a significant portion of its available megawatthours. Genco and AERG may participate jointly in the September 2006 Illinois power procurement auction through Marketing Company. Genco and AERG will also seek to sell power forward to wholesale, municipal and industrial customers as has been its past practice. Ultimately, Genco and AERG will seek to hedge for price risk the majority of available megawatthours for 2007 by December 31, 2006. 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).

CIPS, CILCO and IP have electric rate freezes in Illinois through January 1, 2007, and power supply contracts in place through December 31, 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers in 2007 through a September 2006 auction. The approved framework also allows for full cost recovery of power through a rate mechanism. UE’s electric rate freeze in Missouri expired June 30, 2006. In July 2006, UE filed for an increase in electric rates, including a request for a fuel and purchased power cost recovery mechanism. UE is also exposed to price risk on its interchange sales. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for further information.

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 virtually no generation, that are price-hedged over the remainder of 2006 through 2010:

	2006		2007		2008 - 2010
Ameren:
Coal		100%		95%		58%
Coal transportation		100		95		60
Nuclear fuel		100		100		70
Natural gas for generation		66		12		2
Natural gas for distribution^(a)		(a)		33		7
UE:
Coal		100%		95%		54%
Coal transportation		100		99		79
Nuclear fuel		100		100		70
Natural gas for generation		43		5		1
Natural gas for distribution^(a)		(a)		22		5
CIPS:
Natural gas for distribution^(a)		(a)		40%		15%
Purchased power^(b)		100		-		-
Genco:
Coal		100%		92%		69%
Coal transportation		100		95		39
Natural gas for generation		100		12		2
CILCORP/CILCO:
Coal		100%		97%		56%
Coal transportation		100		69		44
Natural gas for distribution^(a)		(a)		37		6
Purchased power^(b)		100		-		-

2006

2007

2008 - 2010

IP:
Natural gas for distribution^(a)	(a)	30%	5%
Purchased power^(b)	90	-	-

(a)

Represents the percentage of natural gas price-hedged for the peak winter season of November through March. The year 2006 represents the period January 2006 through March 2006 and therefore is non-applicable for this report. The year 2007 represents November 2006 through March 2007. This continues each successive year through March 2010.

(b)	Beginning in 2007, CIPS, CILCO and IP are expected to purchase all electric capacity and energy through a power procurement auction process approved by the ICC. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a discussion of this matter.

The following table shows how our total fuel expense might increase and how our 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 remainder of 2006 through 2010:

	Coal				Transportation
	Fuel Expense		Net Income^(a)		Fuel Expense		Net Income^(a)
Ameren	$	8	$	(5)	$	10	$	(6)
UE		5		(3)		3		(2)
Genco		2		(1)		4		(2)
CILCORP/CILCO		1		(1)		2		(1)

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

In the event of a significant change in coal prices, UE, Genco and CILCO would probably take actions to further mitigate their exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure or fuel sources. As discussed in Note 2 - Rate and Regulatory Matters under Part I, Item 1, of this report, Missouri legislation has been approved that could mitigate the impact of increased fuel cost at Ameren and UE through UE’s ability to recover these increases in rates.

See Note 8 - 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 normal sales. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three months and six months ended June 30, 2006. The sources used to determine the fair value of these contracts were active quotes, other external sources, and other modeling and valuation methods. All of these contracts have maturities of less than four years.

	Ameren^(a)		UE		CIPS		Genco		CILCORP/ CILCO		IP
Three Months
Fair value of contracts at beginning of period, net	$	30	$	(3)	$	6	$	-	$	24	$	2
Contracts realized or otherwise settled during the period		(14)		(2)		(2)		1		(5)		(1)
Changes in fair values attributable to changes in valuation technique and assumptions		-		-		-		-		-		-
Fair value of new contracts entered into during the period		-		-		-		-		-		-
Other changes in fair value		27		3		-		-		(1)		1
Fair value of contracts outstanding at end of period, net	$	43	$	(2)	$	4	$	1	$	18	$	2
Six Months
Fair value of contracts at beginning of period, net	$	69	$	(5)	$	12	$	-	$	50	$	(2)
Contracts realized or otherwise settled during the period		(26)		(4)		(5)		1		(9)		(2)
Changes in fair values attributable to changes in valuation technique and assumptions		-		-		-		-		-		-
Fair value of new contracts entered into during the period		1		1		-		-		-		-
Other changes in fair value		(1)		6		(3)		-		(23)		6
Fair value of contracts outstanding at end of period, net	$	43	$	(2)	$	4	$	1	$	18	$	2

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

ITEM 4. CONTROLS AND PROCEDURES.

(a)	Evaluation of Disclosure Controls and Procedures

As of June 30, 2006, the principal executive officer and principal financial officer of each of the Ameren Companies have evaluated the effectiveness of the design and operation of each registrant’s disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act). Upon making that evaluation, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to such registrant that is required in such registrant’s reports filed or submitted to the SEC under the Exchange Act, and are effective in ensuring that information required to be disclosed in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

(b)	Change in Internal Controls

There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting.

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 sub-stantial 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.

Note 2 - Rate and Regulatory Matters, Note 7 - Related Party Transactions and Note 8 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report contain information on legal and administrative proceedings which are incorporated by reference under this item.

ITEM 1A. RISK FACTORS.

The Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended December 31, 2005, 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 that Form 10-K.

The electric and gas rates that certain Ameren Companies are allowed to charge in Missouri and Illinois are largely set through 2006 and are currently the subject of various rate case proceedings. The outcome of these rate case proceedings, along with other actions of lawmakers and regulators that can significantly adversely affect our prospective earnings, liquidity, or business activities, are largely outside our control.

The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, or liquidity of the Ameren Companies. Our industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental entities outside of our control, including the MoPSC, the ICC, and FERC. Decisions made by these entities could have a material adverse impact on our businesses including our results of operations, financial position, or liquidity.

As a part of the settlement of UE’s Missouri electric rate case in August 2002, UE was subject to a rate moratorium that prohibited changes in its electric rates in Missouri before July 1, 2006. Furthermore, as part of the settlement of UE’s Missouri gas rate case, which was approved by the MoPSC in January 2004, UE agreed to make no changes in its gas delivery rates prior to July 1, 2006, with certain exceptions. With the expiration of these electric and gas rate moratoriums, UE filed in July 2006 requests with the MoPSC for an increase in electric rates of $361 million and an $11 million increase in natural gas delivery rates. The MoPSC staff and other stakeholders will review UE’s rate adjustment requests and, after their analyses, may also make recommendations as to electric

and gas rate adjustments. A decision from the MoPSC is expected no later than June 2007.

The ICC order approving Ameren’s acquisition of IP prohibited IP from filing for any increase in gas delivery rates effective before January 1, 2007, beyond IP’s then-pending request for a gas delivery rate increase. In addition, a provision of the Illinois Customer Choice Law related to the restructuring of the Illinois electric industry put a rate freeze into effect through January 1, 2007, for CIPS, CILCO and IP. This Illinois legislation also requires that 50% of the earnings from each respective jurisdiction in excess of certain levels be refunded to CIPS’, CILCO’s and IP’s Illinois customers through 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers in 2007 through an auction and related tariffs. This approval is subject to a pending court appeal. In addition, certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties have sought and continue to seek to block the power procurement auction and/or the recovery, through rates to customers, of related costs for power supply resulting from the auction. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren, including a significant drop in credit ratings (possibly to below investment-grade status), a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, impaired customer service, job losses, and financial insolvency.

The Illinois legislature held hearings in 2005 and 2006 regarding the framework for retail rate determination and power procurement. In February 2006, legislation was introduced in the Illinois House of Representatives that would extend the electric rate freeze in Illinois through 2010. CIPS, CILCO and IP strongly believe that an extension of the electric rate freeze in Illinois would not be in the best interests of any of the Ameren Illinois utilities or their customers and have been working with key stakeholders in Illinois to develop a constructive rate increase phase-in plan for residential customers to address the potential significant increases in customer rates for the Ameren Illinois utilities beginning in 2007. We believe that a rate increase phase-in plan would need to allow for deferral of a portion of the power procurement costs, with provision for full and timely recovery of all deferred costs in a manner that would not result in further reductions in credit ratings from December 31, 2005 levels. We believe a rate increase phase-in plan, providing for deferral of costs with certainty of full and timely recovery of any deferred costs, would require legislation in Illinois. In March 2006, legislation was introduced in the Illinois House of Representatives that would allow the deferral of a portion of the power procurement costs and would authorize the ICC to permit a utility with fewer than one million retail customers to form special purpose finance vehicles to issue securitization bonds to recover the deferred costs, with interest. CIPS, CILCO and IP each have less than one million retail customers. Securitization would allow these special purpose vehicles to issue debt securities and use the proceeds to pay the utilities immediately upon issuance of the bonds for the deferred power costs for which the utilities did not receive reimbursement from customers during a phase-in deferral period. Customers would fund, through dedicated charges included on their electric bills, a future payment stream that would be used to service the securitized debt. In effect, through these charges utility customers would pay in the future for power used, but not paid for, during a phase-in deferral period. This approach has the effect of spreading over the life of the bonds, a period of up to 10 years, the potentially significant initial electric rate increase for residential customers that would otherwise be necessary to pay the power procurement costs on a current basis. If passed, this legislation would assist our Ameren Illinois utilities in maintaining their financial integrity while allowing them to recover costs from customers over a longer term. We cannot predict what actions, if any, the Illinois legislature may ultimately take. In June 2006, the Ameren Illinois utilities filed with the ICC a rate increase phase-in and revenue securitization plan for residential customers similar to the legislation outlined above that would relate to the deferral of power and supply cost for 2007 and 2008. Legislation would be needed for this plan to become effective. In July 2006, the Illinois attorney general filed a motion with the ICC to dismiss this plan. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren.

In December 2005, the Ameren Illinois utilities filed proposed new tariffs with the ICC that would increase annual revenues from electric delivery services, effective January 2, 2007, based on a proposed residential rate phase-in plan, by $156 million (CIPS - $14 million, CILCO -

$33 million, IP - $109 million) per year commencing in 2007 and an additional $46 million (CILCO - $10 million, IP - $36 million) per year commencing in 2008. In June 2006, the ICC staff filed rebuttal testimony recommending increases in revenues for electric delivery services for the Ameren Illinois utilities aggregating $120 million (CIPS - $1 million, CILCO - $30 million and IP - $89 million). In April 2006, the Illinois attorney general recommended increases in revenues for electric delivery services aggregating $71 million for the Ameren Illinois utilities (CIPS - $7 million decrease, CILCO - $19 million increase and IP - $59 million increase). In subsequent testimony, the Illinois attorney general accepted certain of the Ameren Illinois utilities’ positions increasing the estimated aggregate recommended revenue increase to $100 million. Other parties also made recommendations in the case. The ICC has until November 2006 to render a decision in these rate cases.

As a part of the settlement of UE’s Missouri electric rate case in 2002, UE made a commitment to make $2.25 billion to $2.75 billion in critical energy infrastructure investments from January 1, 2002 through June 30, 2006. Ameren also committed IP to make between $275 million and $325 million in energy infrastructure investments over its first two years of ownership, in conjunction with the ICC’s approval of Ameren’s acquisition of IP. UE’s agreement to a rate moratorium in Missouri and CIPS’, CILCO’s and IP’s rate freezes mean that capital expenditures will not become recoverable in rates and will not earn a return until the resolution of the current rate case proceedings for UE, CIPS, CILCO and IP. In addition, without appropriate and timely rate relief, any new energy infrastructure investment could result in increased financing requirements for UE, CIPS, CILCO and IP. This could have a material impact on our results of operations, financial position, or liquidity.

The Ameren Companies do not currently have, in either Missouri or Illinois, a rate adjustment clause for their electric operations that would allow them to recover the costs for purchased power or increased fuel costs from customers. Therefore, insofar as we have not hedged our fuel and power costs, we are exposed to changes in fuel and power prices to the extent that fuel for our electric generating facilities and power to supply customers must be purchased on the open market. In its Missouri electric rate case filed in July 2006, UE requested a fuel and purchased power cost recovery mechanism.

Steps taken and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation. At the federal level, FERC has been mandating changes in the regulatory framework for transmission-owning public utilities such as UE, CIPS, CILCO and IP.

Principally because of rate reductions and moratoriums, increased costs and investments have caused decreased returns in Ameren’s utility businesses. Ameren expects many of its operating expenses to continue to rise and further expects to continue to make significant investment in its energy infrastructure, which is the principal factor underlying its pending rate increase requests with the MoPSC and the ICC. We cannot predict the outcome of these proceedings. In addition, in response to competitive, economic, political, legislative and

regulatory pressures, in connection with the resolution of our current rate case proceedings, or otherwise, we may be subject to further rate moratoriums, rate refunds, limits on rate increases or rate reductions, including phase-in plans. Any or all of these could have a significant adverse effect on our results of operations, financial position, or liquidity.

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, 2006		1,551	$	50.47		-		-
May 1 - May 31, 2006		428		49.87		-		-
June 1 - June 30, 2006		2,700		50.44		-		-
Total		4,679	$	50.40		-		-

(a)

Included in April was 1 share of Ameren common stock purchased to satisfy an employee’s tax obligation incurred with the vesting of a performance share unit and share distribution under Ameren’s Long-term Incentive Plan of 1998 upon the employee’s death. Included in May were 428 shares of Ameren common stock purchased in connection with the satisfaction of employee tax obligations incurred by the release of restricted shares of Ameren common stock under the Long-term Incentive Plan of 1998. The remaining shares of Ameren common stock were purchased in open-market transactions in satisfaction of Ameren’s obligation upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998. Ameren does not have any publicly announced equity securities repurchase plans or programs.

None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the April 1 to June 30, 2006 period.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Ameren

At Ameren’s annual meeting of shareholders held on May 2, 2006, 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 2007.

Name	For	Withheld	Broker Non-Votes^(a)
Susan S. Elliott	170,433,601	3,399,101	-
Gayle P.W. Jackson	170,555,732	3,276,970	-
James C. Johnson	170,503,619	3,329,083	-
Richard A. Liddy	169,543,114	4,289,588	-
Gordon R. Lohman	169,700,926	4,131,776	-
Richard A. Lumpkin	169,743,607	4,089,095	-
Charles W. Mueller	170,429,775	3,402,927	-
Douglas R. Oberhelman	169,918,926	3,913,776	-
Gary L. Rainwater	170,153,917	3,678,785	-
Harvey Saligman	169,812,589	4,020,113	-
Patrick T. Stokes	170,012,820	3,819,882	-

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

Item (2) Ameren proposal regarding approval of the 2006 Omnibus Incentive Compensation Plan.

For	Against	Abstain	Broker Non-Votes^(a)
113,160,592	11,497,749	3,295,718	65,213,786

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

Item (3) Ameren proposal regarding ratification of the appointment of PricewaterhouseCoopers LLP as Ameren’s independent auditors for the fiscal year ending December 31, 2006.

For	Against	Abstain	Broker Non-Votes^(a)
167,748,938	2,015,561	1,822,316	21,553,105

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

Item (4) Shareholder proposal requesting an evaluation of a 20-year extension of UE’s Callaway nuclear plant operating license.

For	Against	Abstain	Broker Non-Votes^(a)
9,084,767	106,585,670	12,364,615	65,132,792

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

At UE’s annual meeting of shareholders held on May 2, 2006, the following individuals (comprising UE’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2007: Warner L. Baxter, Daniel F. Cole, Richard J. Mark, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and David A. Whiteley. 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 May 2, 2006, the following individuals (comprising CIPS’ full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2007: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and David A. Whiteley. 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 May 2, 2006, the following individuals (comprising CILCO’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2007: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and David A. Whiteley. 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 May 2, 2006, the following individuals (comprising IP’s full Board of Directors) were elected to serve until the next annual meeting of shareholders in 2007: Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss and David A. Whiteley. 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.

(a) Exhibits. The documents listed below are being filed on behalf of Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP as indicated.

Exhibit Designation	Registrant(s)	Nature of Exhibit
Material Contracts
10.1	Ameren Companies	June 9, 2006 Revised Schedule 1 to Amended and Restated Ameren Corporation Change of Control Severance Plan previously filed as Exhibit 10.5 to February 16, 2006 Form 8-K
Statement re: Computation of Ratios

12.1	Ameren	Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2	UE	UE’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3	CIPS	CIPS’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.4	Genco	Genco’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.5	CILCORP	CILCORP’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.6	CILCO	CILCO’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements
12.7	IP	IP’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements

Rule 13a-14(a) / 15d-14(a) Certifications
31.1	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2	Ameren	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3	UE CIPS CILCORP CILCO IP	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE, CIPS, CILCORP, CILCO and IP
31.4	UE CIPS Genco CILCORP CILCO IP	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE, CIPS, Genco, CILCORP, CILCO and IP
31.5	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco

Exhibit Designation

Registrant(s)

Nature of Exhibit

Section 1350 Certifications
32.1	Ameren UE CIPS CILCORP CILCO IP	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren, UE, CIPS, CILCORP, CILCO and IP
32.2	Genco	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco

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

Vice President and Controller