Ameren Illinois (AILIN) 10-Q 2006 Q3 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 September 30, 2006

OR

(   )  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 November 1, 2006, was as follows:

Ameren Corporation	Common stock, $.01 par value per share - 206,262,150
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	57
Item 3.    Quantitative and Qualitative Disclosures About Market Risk	82
Item 4.    Controls and Procedures	85
PART II Other Information
Item 1.     Legal Proceedings	85
Item 1A.Risk Factors	86
Item 2.     Unregistered Sales of Equity Securities and Use of Proceeds	90
Item 6.     Exhibits	90
Signatures	92

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.”

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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 is a power marketing and risk management agent for affiliated companies. Beginning in 2007, Ameren Energy will only serve UE.

Ameren Illinois utilities - CIPS, CILCO and IP.

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 and Marketing Company parent.

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

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

Dynegy - Dynegy Inc.

DYPM - Dynegy Power Marketing, Inc., a Dynegy subsidiary.

EEI - Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary (40% owned by UE and 40% owned by Development Company) that operates non-rate-regulated electric generation and electric 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.

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

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

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

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

Fitch - Fitch Ratings, a credit rating agency.

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.

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

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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 Transitional Funding Trust Notes 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. This agreement will terminate on December 31, 2006.

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 for Genco, AERG and EEI primarily for periods over one year.

Medina Valley - AmerenEnergyMedina Valley Cogen (No. 4) LLC and its subsidiaries, which are all Development Company subsidiaries and 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.

Missouri Regulated - A financial reporting segment consisting of all the operations of UE’s business except for UE’s 40% interest in EEI and other non-rate-regulated activities.

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.

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

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.

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

_________________________________________________

FORWARD-LOOKING STATEMENTS

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

6

as the outcome of UE, CIPS, CILCO and IP rate proceedings or the enactment of an extension of an electric rate freeze or similar action that impairs the full and timely recovery

of costs in Illinois;

·   the impact of the termination of the JDA;

·   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 and affiliates to meet their obligations with respect to contracts and financial instruments;

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

·   legal and administrative proceedings; and

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

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

7

PART I.   FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions, except per share amounts)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Operating Revenues:
Electric	$	1,767		$	1,732		$	4,356		$	4,257
Gas		143			149			904			819
Other		-			-			-			3
Total operating revenues		1,910			1,881			5,260			5,079
Operating Expenses:
Fuel and purchased power		623			634			1,672			1,524
Gas purchased for resale		84			90			641			550
Other operations and maintenance		395			392			1,137			1,112
Depreciation and amortization		162			158			489			472
Taxes other than income taxes		99			98			302			284
Total operating expenses		1,363			1,372			4,241			3,942
Operating Income		547			509			1,019			1,137
Other Income and Expenses:
Miscellaneous income		5			6			13			19
Miscellaneous expense		(3	)		(1	)		(4	)		(7	)
Total other income		2			5			9			12
Interest Charges		82			70			238			221
Income Before Income Taxes, Minority Interest
and Preferred Dividends of Subsidiaries		467			444			790			928
Income Taxes		161			159			273			330
Income Before Minority Interest and Preferred
Dividends of Subsidiaries		306			285			517			598
Minority Interest and Preferred Dividends
of Subsidiaries		(13	)		(5	)		(31	)		(12	)
Net Income	$	293		$	280		$	486		$	586
Earnings per Common Share – Basic and Diluted	$	1.42		$	1.37		$	2.37		$	2.94
Dividends per Common Share	$	0.635		$	0.635		$	1.905		$	1.905
Average Common Shares Outstanding		205.9			203.8			205.4			199.6

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

8

AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except per share amounts)
	September 30,			December 31,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	34		$	96
Accounts receivable – trade (less allowance for doubtful
accounts of $13 and $22, respectively)		463			552
Unbilled revenue		267			382
Miscellaneous accounts and notes receivable		116			31
Materials and supplies		710			572
Other current assets		147			185
Total current assets		1,737			1,818
Property and Plant, Net		14,028			13,572
Investments and Other Assets:
Investments in leveraged leases		31			50
Nuclear decommissioning trust fund		271			250
Goodwill		976			976
Intangible assets		228			246
Other assets		753			419
Regulatory assets		806			831
Total investments and other assets		3,065			2,772
TOTAL ASSETS	$	18,830		$	18,162
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	465		$	96
Short-term debt		311			193
Accounts and wages payable		382			706
Taxes accrued		249			131
Other current liabilities		433			361
Total current liabilities		1,840			1,487
Long-term Debt, Net		5,349			5,354
Preferred Stock of Subsidiary Subject to Mandatory Redemption		18			19
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,013			1,969
Accumulated deferred investment tax credits		121			129
Regulatory liabilities		1,205			1,132
Asset retirement obligations		538			518
Accrued pension and other postretirement benefits		840			760
Other deferred credits and liabilities		144			218
Total deferred credits and other liabilities		4,861			4,726
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption		195			195
Minority Interest in Consolidated Subsidiaries		19			17
Commitments and Contingencies (Notes 2, 8 and 9)
Stockholders' Equity:
Common stock, $.01 par value, 400.0 shares authorized,
206.2 and 204.7 shares outstanding, respectively		2			2
Other paid-in capital, principally premium on common stock		4,478			4,399
Retained earnings		2,094			1,999
Accumulated other comprehensive loss		(23	)		(24	)
Other		(3	)		(12	)
Total stockholders’ equity		6,548			6,364
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	18,830		$	18,162

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

9

AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Nine Months Ended
	September 30,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	486		$	586
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		507			499
Amortization of nuclear fuel		26			25
Amortization of debt issuance costs and premium/discounts		12			11
Deferred income taxes and investment tax credits, net		7			83
Loss on sale of leveraged leases		4			-
Gain on sales of emission allowances		(25	)		(4	)
Minority interest		23			1
Other		17			3
Changes in assets and liabilities, excluding the effects of acquisitions:
Receivables, net		157			(1	)
Materials and supplies		(136	)		(94	)
Accounts and wages payable		(289	)		(72	)
Taxes accrued		148			172
Assets, other		(97	)		(28	)
Liabilities, other		101			(11	)
Pension and other postretirement benefit obligations, net		89			7
Net cash provided by operating activities		1,030			1,177
Cash Flows From Investing Activities:
Capital expenditures		(666	)		(660	)
Acquisitions, net of cash acquired		-			12
CT acquisitions		(292	)		-
Nuclear fuel expenditures		(37	)		(16	)
Proceeds from sale of leveraged leases		11			-
Purchases of emission allowances		(38	)		(92	)
Sales of emission allowances		12			4
Other		5			16
Net cash used in investing activities		(1,005	)		(736	)
Cash Flows From Financing Activities:
Dividends on common stock		(391	)		(383	)
Capital issuance costs		(4	)		(4	)
Short-term debt, net		118			(394	)
Borrowings from credit facility		40			-
Dividends paid to minority interest		(21	)		-
Redemptions, repurchases, and maturities:
Long-term debt		(138	)		(262	)
Preferred stock		(1	)		(1	)
Issuances:
Common stock		78			430
Long-term debt		232			382
Net cash used in financing activities		(87	)		(232	)
Net change in cash and cash equivalents		(62	)		209
Cash and cash equivalents at beginning of year		96			69
Cash and cash equivalents at end of period	$	34		$	278

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

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UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Operating Revenues:
Electric	$	836		$	876		$	2,090		$	2,134
Gas		20			19			111			120
Other		1			-			2			-
Total operating revenues		857			895			2,203			2,254
Operating Expenses:
Fuel and purchased power		214			261			598			586
Gas purchased for resale		10			8			66			66
Other operations and maintenance		214			199			581			573
Depreciation and amortization		82			79			243			231
Taxes other than income taxes		66			66			184			180
Total operating expenses		586			613			1,672			1,636
Operating Income		271			282			531			618
Other Income and Expenses:
Miscellaneous income		2			3			6			12
Miscellaneous expense		(3	)		(2	)		(7	)		(6	)
Total other income (expense)		(1	)		1			(1	)		6
Interest Charges		35			29			107			81
Income Before Income Taxes and Equity
in Income of Unconsolidated Investment		235			254			423			543
Income Taxes		92			91			161			193
Income Before Equity in Income
of Unconsolidated Investment		143			163			262			350
Equity in Income of Unconsolidated Investment		23			1			47			3
Net Income		166			164			309			353
Preferred Stock Dividends		1			1			4			4
Net Income Available to Common Stockholder	$	165		$	163		$	305		$	349

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

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UNION ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except per share amounts)
	September 30,			December 31,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	2		$	20
Accounts receivable – trade (less allowance for doubtful
accounts of $5 and $6, respectively)		196			190
Unbilled revenue		105			133
Miscellaneous accounts and notes receivable		84			7
Accounts receivable – affiliates		35			53
Current portion of intercompany note receivable – CIPS		-			6
Materials and supplies		236			199
Other current assets		59			57
Total current assets		717			665
Property and Plant, Net		7,756			7,379
Investments and Other Assets:
Nuclear decommissioning trust fund		271			250
Intercompany note receivable – CIPS		-			61
Intangible assets		63			63
Other assets		565			269
Regulatory assets		562			590
Total investments and other assets		1,461			1,233
TOTAL ASSETS	$	9,934		$	9,277
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	10		$	4
Short-term debt		208			80
Accounts and wages payable		119			274
Accounts payable – affiliates		141			134
Taxes accrued		214			59
Other current liabilities		176			96
Total current liabilities		868			647
Long-term Debt, Net		2,932			2,698
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,286			1,277
Accumulated deferred investment tax credits		91			96
Regulatory liabilities		815			802
Asset retirement obligations		484			466
Accrued pension and other postretirement benefits		238			203
Other deferred credits and liabilities		51			72
Total deferred credits and other liabilities		2,965			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		736			733
Retained earnings		1,839			1,689
Accumulated other comprehensive loss		(30	)		(30	)
Total stockholders' equity		3,169			3,016
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,934		$	9,277

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

12

UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Nine Months Ended September 30,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	309		$	353
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		243			231
Amortization of nuclear fuel		26			25
Amortization of debt issuance costs and premium/discounts		4			3
Deferred income taxes and investment tax credits, net		(10	)		27
Gain on sales of emission allowances		(2	)		(2	)
Other		-			12
Changes in assets and liabilities:
Receivables, net		(34	)		(96	)
Materials and supplies		(35	)		2
Accounts and wages payable		(127	)		44
Taxes accrued		174			130
Assets, other		(52	)		(14	)
Liabilities, other		62			(2	)
Pension and other postretirement benefit obligations, net		35			(1	)
Net cash provided by operating activities		593			712
Cash Flows From Investing Activities:
Capital expenditures		(325	)		(388	)
CT acquisitions from nonaffiliates		(292	)		-
CT acquisitions from Genco		-			(241	)
Nuclear fuel expenditures		(37	)		(16	)
Changes in money pool advances		-			-
Proceeds from intercompany note receivable - CIPS		67			-
Sales of emission allowances		2			2
Other		1			10
Net cash used in investing activities		(584	)		(633	)
Cash Flows From Financing Activities:
Dividends on common stock		(154	)		(209	)
Dividends on preferred stock		(4	)		(4	)
Capital issuance costs		-			(3	)
Changes in short-term debt, net		128			(375	)
Changes in money pool borrowings		-			79
Issuance of long-term debt		-			382
Capital contribution from parent		3			4
Net cash used in financing activities		(27	)		(126	)
Net change in cash and cash equivalents		(18	)		(47	)
Cash and cash equivalents at beginning of year		20			48
Cash and cash equivalents at end of period	$	2		$	1

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

13

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF INCOME
(Unaudited) (In millions)
	Three Months Ended September 30,					Nine Months Ended September 30,
		2006		2005			2006			2005
Operating Revenues:
Electric	$	228	$	244		$	569		$	542
Gas		23		22			150			133
Other		3		1			4			2
Total operating revenues		254		267			723			677
Operating Expenses:
Purchased power		125		140			355			331
Gas purchased for resale		11		12			99			86
Other operations and maintenance		41		39			117			109
Depreciation and amortization		16		17			47			45
Taxes other than income taxes		9		9			30			24
Total operating expenses		202		217			648			595
Operating Income		52		50			75			82
Other Income and Expenses:
Miscellaneous income		4		4			13			13
Miscellaneous expense		-		(1	)		(1	)		(5	)
Total other income		4		3			12			8
Interest Charges		8		7			23			22
Income Before Income Taxes		48		46			64			68
Income Taxes		19		15			21			22
Net Income		29		31			43			46
Preferred Stock Dividends		1		1			2			2
Net Income Available to Common Stockholder	$	28	$	30		$	41		$	44

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

14

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
BALANCE SHEET
(Unaudited) (In millions)
	September 30,			December 31,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	-		$	-
Accounts receivable – trade (less allowance for doubtful
accounts of $2 and $4, respectively)		58			70
Unbilled revenue		44			71
Accounts receivable – affiliates		4			18
Current portion of intercompany note receivable – Genco		37			34
Current portion of intercompany tax receivable – Genco		10			10
Advances to money pool		18			-
Materials and supplies		82			75
Other current assets		22			28
Total current assets		275			306
Property and Plant, Net		1,150			1,130
Investments and Other Assets:
Intercompany note receivable – Genco		126			163
Intercompany tax receivable – Genco		118			125
Other assets		31			24
Regulatory assets		35			36
Total investments and other assets		310			348
TOTAL ASSETS	$	1,735		$	1,784
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	-		$	20
Accounts and wages payable		31			36
Accounts payable – affiliates		65			65
Borrowings from money pool		-			2
Current portion of intercompany note payable – UE		-			6
Taxes accrued		28			26
Other current liabilities		43			43
Total current liabilities		167			198
Long-term Debt, Net		471			410
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net		289			302
Intercompany note payable – UE		-			61
Regulatory liabilities		218			208
Accrued pension and other postretirement benefits		13			7
Other deferred credits and liabilities		21			29
Total deferred credits and other liabilities		541			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		190			189
Preferred stock not subject to mandatory redemption		50			50
Retained earnings		321			329
Accumulated other comprehensive income (loss)		(5	)		1
Total stockholders' equity		556			569
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,735		$	1,784

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

15

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Nine Months Ended September 30,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	43		$	46
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		47			45
Amortization of debt issuance costs and premium/discounts		1			1
Deferred income taxes and investment tax credits, net		(27	)		(5	)
Other		1			1
Changes in assets and liabilities:
Receivables, net		60			21
Materials and supplies		(7	)		(25	)
Accounts and wages payable		(5	)		39
Taxes accrued		8			16
Assets, other		-			(32	)
Liabilities, other		-			41
Pension and other postretirement obligations, net		6			-
Net cash provided by operating activities		127			148
Cash Flows From Investing Activities:
Capital expenditures		(63	)		(41	)
Proceeds from intercompany note receivable – Genco		34			52
Changes in money pool advances		(18	)		(51	)
Net cash used in investing activities		(47	)		(40	)
Cash Flows From Financing Activities:
Dividends on common stock		(50	)		(21	)
Dividends on preferred stock		(2	)		(2	)
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	)		-
Issuance of long-term debt		61			-
Capital contribution from parent		1			1
Net cash used in financing activities		(80	)		(110	)
Net change in cash and cash equivalents		-			(2	)
Cash and cash equivalents at beginning of year		-			2
Cash and cash equivalents at end of period	$	-		$	-

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

16

AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Operating Revenues:
Electric	$	259	$	287	$	744	$	777
Other		-		2		-		2
Total operating revenues		259		289		744		779
Operating Expenses:
Fuel and purchased power		170		162		485		398
Other operations and maintenance		34		32		113		108
Depreciation and amortization		18		18		53		55
Taxes other than income taxes		3		4		14		7
Total operating expenses		225		216		665		568
Operating Income		34		73		79		211
Other Income:
Miscellaneous income		-		-		-		1
Total other income		-		-		-		1
Interest Charges		15		17		45		57
Income Before Income Taxes		19		56		34		155
Income Taxes		-		24		7		61
Net Income	$	19	$	32	$	27	$	94

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

17

AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except shares)
	September 30,			December 31,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	2		$	-
Accounts receivable – affiliates		143			102
Accounts receivable – trade		18			29
Materials and supplies		103			73
Other current assets		4			1
Total current assets		270			205
Property and Plant, Net		1,512			1,514
Intangible Assets		81			79
Other Assets		27			13
TOTAL ASSETS	$	1,890		$	1,811
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current portion of intercompany note payable – CIPS	$	37		$	34
Borrowings from money pool		216			203
Accounts and wages payable		25			41
Accounts payable – affiliates		84			60
Current portion of intercompany tax payable – CIPS		10			10
Taxes accrued		24			37
Other current liabilities		32			16
Total current liabilities		428			401
Long-term Debt, Net		474			474
Intercompany Note Payable – CIPS		126			163
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		161			156
Accumulated deferred investment tax credits		9			10
Intercompany tax payable – CIPS		118			125
Asset retirement obligations		30			29
Accrued pension and other postretirement benefits		12			8
Other deferred credits and liabilities		2			1
Total deferred credits and other liabilities		332			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		378			228
Retained earnings		154			220
Accumulated other comprehensive loss		(2	)		(4	)
Total stockholder's equity		530			444
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	1,890		$	1,811

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

18

AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Nine Months Ended September 30,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	27		$	94
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		78			78
Amortization of debt issuance costs and discounts		-			1
Deferred income taxes and investment tax credits, net		7			35
Gain on sales of emission allowances		(1	)		(1	)
Other		1			(21	)
Changes in assets and liabilities:
Accounts receivable		(30	)		(10	)
Materials and supplies		(30	)		(8	)
Accounts and wages payable		13			59
Taxes accrued, net		(9	)		(35	)
Assets, other		(16	)		6
Liabilities, other		2			7
Pension and other postretirement benefit obligations, net		4			-
Net cash provided by operating activities		46			205
Cash Flows From Investing Activities:
Capital expenditures		(55	)		(52	)
Proceeds from asset sale to UE		-			241
Changes in money pool advances		-			(65	)
Purchases of emission allowances		(26	)		(71	)
Sales of emission allowances		1			1
Net cash provided by (used in) investing activities		(80	)		54
Cash Flows From Financing Activities:
Dividends on common stock		(93	)		(59	)
Changes in money pool borrowings		13			(116	)
Repayment of intercompany notes payable – CIPS and Ameren		(34	)		(86	)
Capital contribution from parent		150			1
Net cash provided by (used in) financing activities		36			(260	)
Net change in cash and cash equivalents		2			(1	)
Cash and cash equivalents at beginning of year		-			1
Cash and cash equivalents at end of period	$	2		$	-

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

19

CILCORP INC.
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)
	Three Months Ended September 30,						Nine Months Ended September 30,
		2006			2005			2006			2005
Operating Revenues:
Electric	$	119		$	116		$	309		$	309
Gas		38			41			236			215
Other		1			2			1			4
Total operating revenues		158			159			546			528
Operating Expenses:
Fuel and purchased power		43			54			104			126
Gas purchased for resale		24			27			175			150
Other operations and maintenance		41			41			130			122
Depreciation and amortization		18			18			59			54
Taxes other than income taxes		5			4			18			15
Total operating expenses		131			144			486			467
Operating Income		27			15			60			61
Other Income and Expenses:
Miscellaneous income		-			-			1			-
Miscellaneous expense		(2	)		(2	)		(4	)		(7	)
Total other expenses		(2	)		(2	)		(3	)		(7	)
Interest Charges		13			12			38			37
Income Before Income Taxes & Preferred
Dividends of Subsidiaries		12			1			19			17
Income Tax Benefit		(1	)		(5	)		(4	)		(1	)
Income Before Preferred Dividends of Subsidiaries		13			6			23			18
Preferred Dividends of Subsidiaries		-			1			1			2
Net Income	$	13		$	5		$	22		$	16

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

20

CILCORP INC.
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except shares)
	September 30,		December 31,
	2006		2005
ASSETS
Current Assets:
Cash and cash equivalents	$	3	$	3
Accounts receivable – trade (less allowance for doubtful
accounts of $3 and $5, respectively)		35		61
Unbilled revenue		33		59
Accounts receivables – affiliates		21		18
Note receivable – Resources Company		-		42
Materials and supplies		107		85
Other current assets		34		50
Total current assets		233		318
Property and Plant, Net		1,218		1,212
Investments and Other Assets:
Investments in leveraged leases		-		21
Goodwill		575		575
Intangible assets		50		62
Other assets		16		35
Regulatory assets		12		11
Total investments and other assets		653		704
TOTAL ASSETS	$	2,104	$	2,234
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt	$	50	$	-
Borrowings from money pool		62		154
Intercompany note payable – Ameren		156		186
Accounts and wages payable		35		81
Accounts payable – affiliates		16		28
Other current liabilities		61		55
Total current liabilities		380		504
Long-term Debt, Net		584		534
Preferred Stock of Subsidiary Subject to Mandatory Redemption		18		19
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		159		163
Accumulated deferred investment tax credits		8		9
Regulatory liabilities		50		41
Accrued pension and other postretirement benefits		253		251
Other deferred credits and liabilities		17		31
Total deferred credits and other liabilities		487		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		15		-
Accumulated other comprehensive income		3		23
Total stockholder's equity		616		663
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	2,104	$	2,234

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

21

CILCORP INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Nine Months Ended
	September 30,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	22		$	16
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		74			74
Deferred income taxes and investment tax credits		8			(19	)
Loss on sale of leveraged lease investments		4			-
Gain on sales of emission allowances		-			(1	)
Other		1			1
Changes in assets and liabilities:
Receivables, net		49			20
Materials and supplies		(22	)		(17	)
Accounts and wages payable		(52	)		(9	)
Taxes accrued		(9	)		(8	)
Assets, other		24			9
Liabilities, other		(4	)		9
Pension and postretirement benefit obligations, net		4			2
Net cash provided by operating activities		99			77
Cash Flows From Investing Activities:
Capital expenditures		(70	)		(71	)
Proceeds from note receivable - Resources Company		42			-
Proceeds from sale of leveraged leases		11			-
Purchases of emissions allowances		(12	)		(21	)
Sales of emission allowances		1			1
Other		-			4
Net cash used in investing activities		(28	)		(87	)
Cash Flows From Financing Activities:
Dividends on common stock		(50	)		(30	)
Capital issuance costs		(2	)		-
Changes in money pool borrowings		(92	)		(85	)
Proceeds (repayment) - intercompany note payable - Ameren		(30	)		28
Borrowings from credit facility		40			-
Redemptions, repurchases, and maturities:
Long-term debt		(32	)		(6	)
Preferred stock		(1	)		(1	)
Issuance of long-term debt		96			-
Capital contribution from parent		-			101
Net cash provided by (used in) financing activities		(71	)		7
Net change in cash and cash equivalents		-			(3	)
Cash and cash equivalents at beginning of year		3			7
Cash and cash equivalents at end of period	$	3		$	4

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

22

CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Operating Revenues:
Electric	$	119		$	117		$	309		$	309
Gas		38			41			236			212
Other		-			1			1			1
Total operating revenues		157			159			546			522
Operating Expenses:
Fuel and purchased power		39			49			95			117
Gas purchased for resale		24			27			175			146
Other operations and maintenance		41			44			134			128
Depreciation and amortization		18			17			52			50
Taxes other than income taxes		4			4			17			14
Total operating expenses		126			141			473			455
Operating Income		31			18			73			67
Other Expenses:
Miscellaneous expense		(2	)		(2	)		(4	)		(5	)
Total other expenses		(2	)		(2	)		(4	)		(5	)
Interest Charges		4			3			13			10
Income Before Income Taxes		25			13			56			52
Income Taxes		6			2			12			15
Net Income		19			11			44			37
Preferred Stock Dividends		-			1			1			2
Net Income Available to Common Stockholder	$	19		$	10		$	43		$	35

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

23

CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions)
	September 30,			December 31,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	2		$	2
Accounts receivable – trade (less allowance for doubtful
accounts of $3 and $5, respectively)		35			61
Unbilled revenue		33			59
Accounts receivable – affiliates		15			14
Materials and supplies		107			87
Other current assets		36			43
Total current assets		228			266
Property and Plant, Net		1,232			1,214
Investments in Leveraged Leases		-			21
Intangible Assets		4			4
Other Assets		22			41
Regulatory Assets		12			11
TOTAL ASSETS	$	1,498		$	1,557
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	50		$	-
Borrowings from money pool		62			161
Accounts and wages payable		35			81
Accounts payable – affiliates		31			26
Other current liabilities		46			48
Total current liabilities		224			316
Long-term Debt, Net		188			122
Preferred Stock Subject to Mandatory Redemption		18			19
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		166			167
Accumulated deferred investment tax credits		8			8
Regulatory liabilities		201			187
Accrued pension and other postretirement benefits		155			146
Other deferred credits and liabilities		18			30
Total deferred credits and other liabilities		548			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		414			415
Retained earnings		97			119
Accumulated other comprehensive income (loss)		(10	)		9
Total stockholders' equity		520			562
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,498		$	1,557

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

24

CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Nine Months Ended
	September 30,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	44		$	37
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		61			64
Deferred income taxes and investment tax credits		15			(5	)
Loss on sale of leveraged leases		6			-
Gain on sales of emission allowances		-			(1	)
Other		-			6
Changes in assets and liabilities:
Receivables, net		51			30
Materials and supplies		(20	)		(15	)
Accounts and wages payable		(35	)		-
Taxes accrued		(17	)		(17	)
Assets, other		14			-
Liabilities, other		(6	)		(9	)
Pension and postretirement benefit obligations, net		9			11
Net cash provided by operating activities		122			101
Cash Flows From Investing Activities:
Capital expenditures		(70	)		(71	)
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		(70	)		(91	)
Cash Flows From Financing Activities:
Dividends on common stock		(65	)		(20	)
Dividends on preferred stock		(1	)		(2	)
Capital issuance costs		(2	)		-
Changes in money pool borrowings		(99	)		(88	)
Borrowings from credit facility		40			-
Redemptions, repurchases, and maturities:
Long-term debt		(20	)		-
Preferred stock		(1	)		(1	)
Issuance of long-term debt		96			-
Capital contribution from parent		-			101
Net cash used in financing activities		(52	)		(10	)
Net change in cash and cash equivalents		-			-
Cash and cash equivalents at beginning of year		2			2
Cash and cash equivalents at end of period	$	2		$	2

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

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ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)
	Three Months Ended September 30,					Nine Months Ended September 30,
	2006			2005		2006			2005
Operating Revenues:
Electric	$	375		$	358	$	888		$	861
Gas		59			61		381			331
Other		1			1		2			1
Total operating revenues		435			420		1,271			1,193
Operating Expenses:
Purchased power		213			187		561			509
Gas purchased for resale		35			37		272			227
Other operations and maintenance		68			64		188			166
Depreciation and amortization		20			19		57			59
Taxes other than income taxes		14			14		52			54
Total operating expenses		350			321		1,130			1,015
Operating Income		85			99		141			178
Other Income and Expenses:
Miscellaneous income		2			2		4			6
Miscellaneous expense		(1	)		-		(3	)		(1	)
Total other income		1			2		1			5
Interest Charges		13			11		37			32
Income Before Income Taxes		73			90		105			151
Income Taxes		30			36		42			60
Net Income		43			54		63			91
Preferred Stock Dividends		1			1		2			2
Net Income Available to Common Stockholder	$	42		$	53	$	61		$	89

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

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ILLINOIS POWER COMPANY
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions)
	September 30,			December 31,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	-		$	-
Accounts receivable - trade (less allowance for doubtful
accounts of $3 and $8, respectively)		111			155
Unbilled revenue		82			118
Accounts receivable – affiliates		25			5
Materials and supplies		156			122
Other current assets		13			31
Total current assets		387			431
Property and Plant, Net		2,098			2,035
Investments and Other Assets:
Investment in IP SPT		8			7
Goodwill		326			326
Other assets		64			44
Regulatory assets		197			194
Accumulated deferred income taxes		-			19
Total investments and other assets		595			590
TOTAL ASSETS	$	3,080		$	3,056
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt to IP SPT	$	55		$	72
Borrowings from money pool		110			75
Accounts and wages payable		95			145
Accounts payable – affiliates		14			29
Taxes accrued		13			15
Other current liabilities		97			135
Total current liabilities		384			471
Long-term Debt, Net		773			704
Long-term Debt to IP SPT		115			184
Deferred Credits and Other Liabilities:
Regulatory liabilities		121			80
Accrued pension and other postretirement benefits		259			255
Other deferred credits and other noncurrent liabilities		81			75
Total deferred credits and other liabilities		461			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		1,194			1,196
Preferred stock not subject to mandatory redemption		46			46
Retained earnings		108			46
Accumulated other comprehensive loss		(1	)		(1	)
Total stockholders’ equity		1,347			1,287
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,080		$	3,056

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

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ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)
	Nine Months Ended
	September 30,
	2006			2005
Cash Flows From Operating Activities:
Net income	$	63		$	91
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		18			31
Amortization of debt issuance costs and premium/discounts		3			2
Deferred income taxes		58			39
Changes in assets and liabilities:
Receivables, net		60			11
Materials and supplies		(34	)		(45	)
Accounts and wages payable		(64	)		34
Assets, other		(1	)		25
Liabilities, other		(5	)		15
Pension and other postretirement benefit obligations, net		8			4
Net cash provided by operating activities		106			207
Cash Flows From Investing Activities:
Capital expenditures		(126	)		(95	)
Changes in money pool advances		-			90
Other		(1	)		1
Net cash used in investing activities		(127	)		(4	)
Cash Flows From Financing Activities:
Dividends on common stock		-			(60	)
Dividends on preferred stock		(2	)		(2	)
Capital issuance costs		(1	)		-
Changes in money pool borrowings, net		35			-
Redemptions and repurchases of long-term debt		(69	)		(135	)
Issuances of long-term debt		75			-
Transitional funding trust notes overfunding		(17	)		(6	)
Net cash provided by (used in) financing activities		21			(203	)
Net change in cash and cash equivalents		-			-
Cash and cash equivalents at beginning of year		-			5
Cash and cash equivalents at end of period	$	-		$	5

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

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AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY (Consolidated)

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

AMEREN ENERGY GENERATING COMPANY (Consolidated)

CILCORP INC. (Consolidated)

CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)

ILLINOIS POWER COMPANY (Consolidated)

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

September 30, 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. The following table presents summarized financial information of EEI (in millions) for the three months and nine months ended September 30, 2006 and 2005.

	Three Months				Nine Months
		2006		2005		2006		2005
Operating revenues	$	105	$	43	$	290	$	127
Operating income		93		4		191		15
Net income		56		3		117		8

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 Statements 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. In the third quarter of 2006, Ameren, UE, CILCORP and CILCO changed their reportable segments. See further discussion in Note 12 - Segment Information.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three months and nine months ended September 30, 2006 and 2005, due to an immaterial number of stock options, restricted stock units and performance share units outstanding.

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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 replaced 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 September 30, 2006, and changes during the nine-month period ended September 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		-			-		13,538			51.29
Forfeitures		(881	)		56.07		(2,436	)		47.58
Vested(b)		(4,785	)		56.07		(213,198	)		43.38
Nonvested at September 30, 2006		344,974		$	56.07		373,373		$	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 the death of an employee 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 September 30, 2006 and 2005, respectively, and a related tax benefit of less than $1 million for the quarters ended September 30, 2006 and 2005. Ameren recorded compensation expense of $8 million and $5 million for each of the nine-month periods ended September 30, 2006 and 2005, respectively, and a related tax

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benefit of $1 million and $2 million for the nine-month periods ended September 30, 2006 and 2005, respectively. As of September 30, 2006, total compensation cost of $21 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 nine-month periods ended September 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.

SFAS No. 157, Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 clarifies that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. This standard is effective for Ameren as of the beginning of our 2008 fiscal year. We are still in the process of determining the impact the adoption of SFAS No. 157 will have on our results of operations, financial position and liquidity, if any; however, at this time, we do not expect the impact of adoption to be material.

SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R)

In September 2006, the FASB issued SFAS No. 158 requiring employers to recognize the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, as an asset or liability in their balance sheets and to recognize as a component of OCI, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost. SFAS No. 158 also requires additional disclosures in the notes to the financial statements. The recognition and disclosure provisions of SFAS No. 158 are effective for Ameren as of December 31, 2006. 

We are in the process of determining the impact the adoption of SFAS No. 158 will have on our financial position. However, based on the funded status of Ameren’s defined benefit postretirement plans as of December 31, 2005, the Ameren Companies would be required to recognize additional pension and other postretirement benefit obligations and write-off a pension-related intangible asset resulting in a charge to OCI. The following table presents the amounts that would have been recognized by the Ameren Companies as of December 31, 2005.

	Pension Benefit Obligations		Postretirement  Benefit Obligations		Intangible Asset
Ameren	$	234	$	308	$	(79	)
UE		150		197		(51	)
CIPS		23		31		(8	)
Genco		23		31		(8	)
CILCORP		21		28		(7	)
CILCO		21		28		(7	)
IP		17		21		(5	)

The Ameren Companies will 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 some of 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. The net result of increases and decreases to pension and other postretirement liabilities and assets, and the recognition of related deferred tax and regulatory assets will result in a charge to OCI and a decrease to common equity. The ultimate amounts recorded are highly dependent on a number of assumptions, including the discount rates in effect at December 31, 2006, the actual rate of return on our pension assets for 2006 and the tax effects of the adjustment. Changes in these assumptions since our last measurement date could increase or decrease the expected impact of implementing SFAS No. 158 in our consolidated financial statements at December 31, 2006.

Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (SAB 108)

In September 2006, the SEC staff issued SAB 108 requiring public companies to utilize a dual approach to assess the quantitative effects of financial misstatements. The dual approach includes both an income statement-focused

31

assessment and a balance sheet-focused assessment. SAB 108 is effective as of December 31, 2006, for errors that were not previously deemed material but are material under the guidance in SAB 108. While we are still in the process of determining the impact the adoption of SAB 108 will have on our results of operations, financial position and liquidity, we expect UE will make a pretax adjustment to increase its beginning retained earnings balance by $12 million and CIPS will make an adjustment to decrease its beginning retained earnings balance by $12 million. The adoption of SAB 108 will not have an impact on Ameren and we do not expect the adoption to have a material impact on the results of operations, financial position and liquidity of any of the Ameren Companies.

Revenue

Interchange Revenues

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

	Three Months				Nine Months
	2006		2005		2006		2005
Ameren(a)	$	183	$	105	$	533	$	359
UE		90		110		331		336
CIPS		-		9		2		26
Genco		39		56		129		165
CILCORP		4		-		23		26
CILCO		4		-		23		26
IP		-		-		-		(b	)

(a)   Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. Includes interchange revenues at Marketing Company and EEI of $103 million and $277 million for the three months and nine months ended September 30, 2006, respectively (2005 - $9 million and $24 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 nine months ended September 30, 2006 and 2005. See Note 7 - Related Party Transactions for further information on affiliate purchased power transactions.

	Three Months				Nine Months
	2006		2005		2006		2005
Ameren(a)	$	346	$	340	$	896	$	782
UE		64		102		199		206
CIPS		125		140		355		331
Genco		84		89		269		206
CILCORP		17		24		25		46
CILCO		17		24		25		46
IP		213		187		561		509

(a)   Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. Includes purchased power for EEI of $1 million and $4 million for the three months and nine months ended September 30, 2006, respectively (2005 - nil 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 and are therefore not included in our revenues and expenses. 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 nine months ended September 30, 2006 and 2005:

	Three Months				Nine Months
	2006		2005		2006		2005
Ameren	$	43	$	44	$	129	$	125
UE		35		35		87		84
CIPS		2		3		11		10
CILCORP		2		1		8		7
CILCO		2		1		8		7
IP		4		5		23		24

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:

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

·   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% common 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. Rules for the fuel and purchased power cost recovery mechanism were approved by the MoPSC on September 21, 2006, and are expected to be effective by the end of the year. 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. UE’s requests are subject to approval by the MoPSC.

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, with the consent of the Illinois utilities. 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. As part of Ameren’s acquisition of IP, IP entered into a power supply agreement with DYPM to supply about 70% of its electric customer requirements through the end of 2006. The remaining 30% of IP’s power needs are being supplied by other companies through contracts and open market purchases. See Note 7 - Related Party Transactions for a discussion of the affiliate power supply agreements. The following is a discussion of the current status of significant matters affecting our Illinois electric operations post-2006.

Illinois Power Procurement

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 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 that unanimously approved the Ameren Illinois utilities’ proposed power procurement auction and the related tariffs for the period commencing January 2, 2007, including the retail rates by which power supply costs would be passed through to customers. The order included 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;

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·   there is a limitation of 35% on the amount of power any single supplier can provide the Ameren Illinois utilities’ expected annual load. Ameren-affiliated companies are 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; and

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

In accordance with the January 2006 ICC order, the power procurement auction was held at the beginning of September 2006. On September 14, 2006, the ICC determined that it would not investigate the results of the auction to procure power for fixed-price customers, which include the vast majority of electric customers of CIPS, CILCO and IP. On September 15, 2006, the independent auction manager (NERA Economic Consulting) declared a successful result in the auction for fixed-price customers. The auction clearing price was approximately $65 per megawatthour for the fixed-price residential and small commercial product and approximately $85 per megawatthour for large commercial and industrial customers. Marketing Company was awarded sales in the auction. As a result of the large commercial and industrial customers’ auction price, it is expected that nearly all of these customers will choose a different supplier.

Certain Illinois legislators, the Illinois attorney general, the Illinois governor and other parties sought to block the power procurement auction and continue to challenge the auction and/or the recovery of costs for power supply resulting from the auction through rates to customers. Opponents of the power procurement auction and related tariffs claim 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. Opponents have claimed 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. CIPS, CILCO and IP have received favorable rulings from the ICC and the Circuit Court of Cook County, Illinois on opposition claims filed by the Illinois attorney general, CUB and ELPC.

Various parties, including CIPS, CILCO, IP, the Illinois attorney general, CUB and ELPC, have filed appeals with Illinois district appellate courts of the ICC’s denial of rehearing requests with respect to its January 2006 order. While CIPS, CILCO and IP are generally supportive of the ICC order, they filed a request for rehearing with regard to the provision of the January 2006 order requiring an annual, postauction prudence review to be performed by the ICC and in February 2006 appealed the ICC’s denial of the request to the appellate court for the Fourth District in Illinois. CIPS, CILCO and IP asserted in their request for rehearing that there is no basis for such a prudence review. In their requests for rehearing of the January 2006 ICC order and their appeals of the ICC’s denial of their requests filed with the First District Illinois appellate court in March and April 2006, the Illinois attorney general, CUB and ELPC assert that the Ameren Illinois utilities power procurement auction should be dismissed on the basis of arguments generally similar to those that they previously raised as discussed above. 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. These appeals are pending.

Delivery Service Rate Cases

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). Since most customers are currently taking service under a frozen bundled electric rate, which includes the cost of power, any delivery service revenue change may not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings when all customers transition to an electric delivery service rate effective January 2, 2007. 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 testimony, the Illinois attorney general accepted certain of the Ameren Illinois utilities’ positions, increasing its estimated aggregate recommended revenue increase from $70 million to approximately $110 million (CIPS - $3 million decrease, CILCO - $29 million increase and IP - $84 million increase). Other parties also made recommendations in the cases. In October 2006, the administrative law judges issued a proposed order, which included a recommended revenue increase for electric delivery service of $147 million in the aggregate (CIPS - $8 million, CILCO - $29 million and

IP - $110 million). The ICC has until November 25, 2006, to render a decision in these cases.

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Rate Freeze Extension Proposal

In February 2006, legislation was introduced in the Illinois House of Representatives that would extend the electric rate freeze in Illinois through 2010. On October 2, 2006, Speaker of the Illinois House of Representatives, Michael Madigan, sent a letter to Illinois Governor Rod Blagojevich asking the Illinois governor to call a special session of the Illinois General Assembly for the purpose of considering this rate freeze legislation. In response, the Illinois governor sent a letter indicating that once the votes to pass the legislation were in place he would immediately call for a special session of the legislature. The governor’s letter further provided that in the event a consensus among members of the General Assembly is not reached in the near future, he would call a special session in that event as well. The governor’s letter stated he continued to support legislation extending a rate freeze and would like to sign it into law as soon as possible. Copies of the speaker’s and governor’s letters appear as Exhibits 99.1 and 99.2, respectively, to the Current Report on Form 8-K dated October 4, 2006. On October 9, 2006, the Electric Utility Oversight Committee of the Illinois House of Representatives voted in favor of extending the electric rate freeze through 2010. The measure will need to be approved by the full Illinois House of Representatives and Illinois Senate, and signed by the Illinois governor before it could become law.

CIPS, CILCORP, CILCO and IP believe the proposed electric rate freeze legislation, if enacted, would have a material adverse effect on their results of operations, financial position and liquidity, including the financial insolvency of CIPS, CILCORP, CILCO and IP, as well as result in significant job losses and, without governmental intervention, significant disruptions in electric and gas service. Since Ameren’s Illinois utilities own almost no generation, the companies must purchase power from the competitive market to provide customers’ energy needs. If the rate freeze were extended, the Ameren Illinois utilities estimate they would spend in the aggregate approximately $1 billion annually more for power than they could charge their customers (CIPS - $415 million, CILCO - $175 million, IP - $410 million). It is likely that the Ameren Illinois utilities’ credit ratings would be downgraded to deep junk status if rate freeze legislation was enacted.  Moody's has also indicated that upon rate freeze legislation, or similar legislation that restricts the recovery of costs in a timely manner, passing the Illinois House of Representatives (even if prior to passage in the Illinois Senate or enactment into law), it may consider additional credit ratings downgrades with regard to one or more of the Ameren Companies.  With such credit ratings, we believe CIPS, CILCORP, CILCO and IP would be faced with potential collateral and prepayment requirements for products and services, such as power and natural gas, and would quickly run out of cash and available credit and be unable to borrow. We believe this would lead to the Ameren Illinois utilities and CILCORP being financially insolvent by February 2007, or sooner. In reaction to intensified political discussion in Illinois regarding electric rate freeze extension legislation, in October 2006 S&P downgraded the short- and long-term credit ratings of the Ameren Companies and kept the Ameren Companies on credit watch with negative implications; Moody’s placed the long-term debt credit ratings of the Ameren Companies under review for possible downgrade; and Fitch placed the ratings of Ameren, CIPS, CILCORP, CILCO and IP on rating watch negative.

Electric Rate Increase Phase-in Plans

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 and small to mid-size commercial customers to address the significant increases in customer rates for the Ameren Illinois utilities beginning in 2007. The Ameren Illinois utilities believe that a rate increase phase-in plan would need to allow for full and timely recovery of all deferred costs in a manner that supports investment-grade credit ratings for CIPS, CILCO and IP.

CIPS, CILCO and IP filed two proposed plans with the ICC to mitigate the impact of expected higher electric rates for residential customers. The Customer Elect Payment Plan (the Opt-In Plan), which these Ameren Illinois utilities filed with the ICC in October 2006, would allow residential customers the choice on an individual basis to either pay the full amount of higher electricity costs in 2007 or to phase in increases over a period of years. Under this plan, increases would be phased in at an annual maximum increase of 15 percent over three years or until the full amount of the rate increase is reached, whichever is earlier. At the end of the phase-in period, customers would have three years to repay the deferred costs at a carrying charge interest rate of 6.5 percent. As part of this filing, CIPS, CILCO and IP have proposed to make an additional contribution of $5 million to their Dollar More and Warm Neighbors programs, which provide bill paying assistance, energy conservation materials and rebates for energy efficient equipment if this plan is approved.

Earlier in 2006, the Ameren Illinois utilities filed with the ICC a rate increase phase-in and revenue securitization plan for residential customers for the deferral of power supply costs for 2007 and 2008. Unlike the Opt-In Plan, legislation would be needed for this plan to become effective, and the plan would apply to all residential customers (i.e. participation would not be voluntary). In July 2006, the Illinois attorney general filed a motion with the ICC to dismiss this plan. In July 2006, the administrative law judge denied the Illinois attorney general’s motion. In March 2006, legislation was introduced in the Illinois House of Representatives that would allow the

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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. This approach has the effect of spreading over the life of the bonds, a period of up to 10 years, the significant initial electric rate increase for residential customers that would otherwise be necessary to pay the power supply costs on a current basis. This legislation was not adopted during the spring session.

Summary

We are unable to predict the results of the court appeals of the January 2006 ICC order approving CIPS’, CILCO’s and IP’s power procurement auction and the related tariffs, nor can we predict the actions the Illinois General Assembly and governor may take which may impact electric rates or the power procurement process for CIPS, CILCO and IP after the expiration of the current Illinois electric rate freeze on January 1, 2007, and power supply contracts on December 31, 2006. 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 would result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a significant drop in credit ratings to deep junk status, a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, significant risk of disruption in electric and gas service, significant job losses, and financial insolvency. In addition, Ameren, CILCORP and IP could be required to record a one-time charge for goodwill impairment related to goodwill that was recorded when Ameren acquired these companies. As of September 30, 2006, Ameren, CILCORP and IP had $976 million, $575 million and $326 million, respectively, of goodwill recorded on their balance sheets. Furthermore, if the Ameren Illinois utilities are unable to recover their costs from customers, the utilities could be required to cease applying SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”, which allows CIPS, CILCO and IP to defer certain costs pursuant to actions of rate regulators. This would result in the elimination of all regulatory assets recorded by CIPS, CILCORP, CILCO and IP on their balance sheets and a one-time extraordinary charge on their statements of income that could be material. As of September 30, 2006, CIPS, CILCORP, CILCO and IP had $35 million, $12 million, $12 million and $197 million, respectively, recorded as regulatory assets on their balance sheets.

Ameren, CIPS, CILCORP, CILCO and IP continue to explore a number of legal and regulatory actions, strategies and alternatives to address these Illinois electric issues. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their financial interests, including seeking the protection of the bankruptcy courts. There can be no assurance that Ameren, CIPS, CILCORP, CILCO and IP 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, CIPS, CILCORP, CILCO and IP 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 by the end of 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 $3 million and $17 million transfer of electric margins from Genco to UE during the three months and nine months ended September 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 was accepted by the FERC in September 2006.

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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 to supply power 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 their interests in four remaining leveraged lease assets.

NOTE 3 - CREDIT FACILITIES AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, 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 September 30, 2006, and December 31, 2005, respectively:

	Ameren			UE
September 30, 2006:
Average daily borrowings outstanding during 2006	$	276		$	246
Weighted-average interest rate during 2006		5.06	%		5.05	%
Peak short-term borrowings during 2006	$	602		$	470
Peak interest rate during 2006		5.55	%		5.55	%

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		Ameren			UE
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 September 30, 2006, Ameren and certain of its subsidiaries had $1.65 billion of committed credit facilities, consisting of two facilities as described below, each maturing in July 2010, in the amounts of $1.15 billion and $500 million.

Ameren could directly borrow under the $1.15 billion facility up to the entire amount of the facility; UE could directly borrow under this facility up to $500 million on a 364-day basis; Genco could directly borrow under this facility up to $150 million on a 364-day basis; and until July 13, 2006, CIPS, CILCO and IP could also each directly borrow under this facility up to $150 million, 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 current 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 had borrowing authority under this facility effective July 13, 2006, but remained parties to the agreement until September 8, 2006 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 continue to 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 and effective September 8, 2006, for CIPS, CILCO and IP upon the receipt of regulatory approvals and the issuance by CIPS, CILCO and IP of mortgage bonds as security as described below. Once CIPS, CILCO and IP were authorized to borrow under this new facility, they were removed as parties to the $1.15 billion credit facility.

The obligations of each borrower under the new $500 million 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. In September 2006, AERG drew a $40 million Eurodollar loan under this credit facility at an interest rate of 6.7%. 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.

The obligations of CIPS, CILCO and IP under the new facility are secured by the issuance on September 8, 2006, of mortgage bonds by each such utility under its respective mortgage indenture in the amounts of $135 million, $150 million and $150 million, respectively. 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 power plants 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 September 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

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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 may access the committed credit facilities. CIPS, CILCO and IP borrow from each other through the utility money pool agreement subject to applicable regulatory short-term borrowing authorizations. While UE and Ameren Services are parties to the utility money pool agreement, they are not currently borrowing or lending under the agreement. Ameren Services administers the utility money pool and tracks internal and external funds separately. Ameren and AERG may participate in the utility money pool only as lenders. The availability of funds is effectively 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 nine months ended September 30, 2006, was 5.4% and 5.0%, respectively (2005 - 3.5% and 3.0%, respectively).

Non-state-regulated Ameren subsidiaries, including Genco and AERG, have the ability, subject to Ameren authorization, to access funding from Ameren’s $1.15 billion credit facility 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 nine months ended September 30, 2006, was 4.8% and 4.6%, respectively (2005 - 4.1% and 5.9%, 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 nine months ended September 30, 2006 and 2005.

Indebtedness Provisions and Other Covenants

The bank credit facilities described above 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. With the termination of CIPS, CILCO and IP as parties to this agreement on September 8, 2006, they are no longer considered subsidiaries for purposes of the cross-default provisions nor are CILCORP or AERG.

Under the amended $1.15 billion credit facility, restrictions apply limiting investments in and other transfers to CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries by Ameren and certain subsidiaries. Additionally, 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.

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, except in the case of CILCORP, 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 will be limited to capital stock dividend payments of $10 million per year each, while such below investment-grade credit rating is in effect. 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

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dividend payment limitation. 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. As of September 30, 2006, AERG failed to meet the debt-to-operating cash flow ratio test in the facility and, therefore, is currently limited in its ability to pay dividends. CIPS, CILCO and IP are not currently limited in their dividend payments by this provision of the $500 million 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 September 30, 2006, the ratio of total indebtedness to total capitalization, calculated in accordance with the provisions of the $1.15 billion credit facility for Ameren, UE and Genco was 50%, 47% and 51%, respectively. The ratio for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the provisions of the $500 million credit facility, were 47%, 55%, 37%, 44% and 25%, respectively.

None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At September 30, 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 0.4 million new shares of common stock valued at $21 million and 1.5 million new shares valued at $78 million in the three months and nine months ended September 30, 2006, respectively.

UE

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.

See Note 3 - Credit Facilities and Liquidity regarding first mortgage bonds issued by CIPS in September 2006 as security for its obligations under the $500 million credit facility.

CILCORP

In March 2006, CILCORP repurchased $2 million in principal amount of its 9.375% senior bonds 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 $4 million (2005 - $6 million) for the three months and nine months ended September 30, 2006, respectively, and was included as a reduction to interest expense in the Consolidated Statements of Income of Ameren and CILCORP. See Note 3 - Credit Facilities and Liquidity regarding CILCORP’s pledge of the common stock of CILCO as security for CILCORP’s obligations under the $500 million credit facility.

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%

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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 to reduce short-term money pool borrowings and, in July 2006, to redeem CILCO’s $20 million 7.73% secured medium-term notes due 2025. CILCO commenced the offer to exchange registered secured notes for the outstanding unregistered senior secured notes under the related registration rights agreement on October 18, 2006. Unless extended, the exchange offer will expire on November 16, 2006.

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.

See Note 3 - Credit Facilities and Liquidity regarding first mortgage bonds issued by CILCO and the mortgage and security interest in its power plants issued by AERG in September 2006 as security for their respective obligations under the $500 million credit facility.

IP

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. IP commenced the offer to exchange registered secured notes for the outstanding unregistered senior secured notes under the related registration rights agreement on October 18, 2006. Unless extended, the exchange offer will expire on November 16, 2006.

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 - $3 million and $10 million (2005 - $12 million) for the three months and nine months ended September 30, 2006, respectively, and was included as a reduction to interest expense in the Consolidated Statements of Income of Ameren and IP.

See Note 3 - Credit Facilities and Liquidity regarding mortgage bonds issued by IP in September 2006 as security for its obligations under the $500 million credit facility.

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 September 30, 2006, at an assumed interest and dividend rate of 7%.

	Required Interest Coverage Ratio(a)(b)			Actual Interest Coverage Ratio		Bonds Issuable(c)(d)		Required Dividend Coverage Ratio(e)		Actual Dividend Coverage Ratio		Preferred Stock Issuable
UE		2.0			4.4		2,150		2.5		41.4		1,319
CIPS		2.0			4.0		149		1.5		2.2		210
CILCO		2.0(f	)		9.1		200		2.5		17.4		166(g	)
IP		2.0			5.7		620		1.5		2.5		420

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

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

(c)   Amount of bonds issuable based on either meeting required coverage ratios or unfunded property additions and retired bonds, whichever is more restrictive.

(d)   Amounts are net of future bonding capacity restrictions agreed to by CIPS, CILCO and IP under the $500 million credit facility entered into by these companies. See Note 3 - Credit Facilities and Liquidity for further discussion.

(e)   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.

(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 nine months ended September 30, 2006, CILCO had earnings equivalent to at least 44% of the principal amount of all mortgage bonds outstanding.

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

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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 $1.8 billion of free and unrestricted retained earnings at September 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. On October 5, 2006, S&P downgraded IP’s credit ratings to the lowest investment-grade

rating and placed them on credit watch with negative implications. On October 10, 2006, Moody’s placed IP’s long-term credit ratings under review for possible downgrade. If 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 September 30, 2006, $33,000 of the 11.50% Series mortgage bonds due 2010 were outstanding. The bonds become callable in December 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 September 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)	3.9	≤60%	50%
CILCORP(c)	≥2.2	2.6	≤67%	40%

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

(b)   Ratio excludes amounts payable under Genco’s intercompany note to CIPS 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 September 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 nine months ended September 30, 2006 and 2005:

	Three Months						Nine Months
	2006			2005			2006			2005
Ameren:(a)
Miscellaneous income:
Interest and dividend income	$	2		$	3		$	5		$	5
Allowance for equity funds used during construction		1			3			2			10
Other		2			-			6			4
Total miscellaneous income	$	5		$	6		$	13		$	19
Miscellaneous expense:
Other	$	(3	)	$	(1	)	$	(4	)	$	(7	)
Total miscellaneous expense	$	(3	)	$	(1	)	$	(4	)	$	(7	)
UE:
Miscellaneous income:
Interest and dividend income	$	-		$	-		$	2		$	-
Allowance for equity funds used during construction		1			3			1			9
Other		1			-			3			3
Total miscellaneous income	$	2		$	3		$	6		$	12

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Three Months		Nine Months
2006	2005	2006	2005

Miscellaneous expense:
Other	$	(3	)	$	(2	)	$	(7	)	$	(6	)
Total miscellaneous expense	$	(3	)	$	(2	)	$	(7	)	$	(6	)

CIPS:
Miscellaneous income:
Interest and dividend income	$	4		$	4		$	12		$	13
Other		-			-			1			-
Total miscellaneous income	$	4		$	4		$	13		$	13
Miscellaneous expense:
Other	$	-		$	(1	)	$	(1	)	$	(5	)
Total miscellaneous expense	$	-		$	(1	)	$	(1	)	$	(5	)
Genco:
Miscellaneous income:
Other	$	-		$	-		$	-		$	1
Total miscellaneous income	$	-		$	-		$	-		$	1
CILCORP:
Miscellaneous income:
Interest and dividend income	$	-		$	-		$	1		$	-
Total miscellaneous income	$	-		$	-		$	1		$	-
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(4	)	$	(7	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(4	)	$	(7	)
CILCO:
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(4	)	$	(5	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(4	)	$	(5	)
IP:
Miscellaneous income:
Interest and dividend income	$	1		$	1		$	2		$	3
Allowance for equity funds used during construction		-			-			-			1
Other		1			1			2			2
Total miscellaneous income	$	2		$	2		$	4		$	6
Miscellaneous expense:
Other	$	(1	)	$	-		$	(3	)	$	(1	)
Total miscellaneous expense	$	(1	)	$	-		$	(3	)	$	(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 SO₂ emissionallowances, 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 being delivered or settled, resulting in a $3 million gain for Ameren, a $2 million gain for UE, and a $1 million gain for Genco for the three months ended September 30, 2006 (2005 - $1 million loss for Ameren, $1 million loss for UE, $1 million loss for Genco), and a $2 million gain for Ameren, a $2 million gain for UE, and a $2 million loss for IP for the nine months ended September 30, 2006 (2005 - $2 million gain for Ameren, $1 million loss for UE).

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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 September 30, 2006:

	Ameren(a)			UE		CIPS		Genco			CILCORP/ CILCO		IP
Derivative instruments carrying value:
Total assets	$	79		$	11	$	2	$	3		$	9	$	5
Total deferred credits and liabilities		16			6		-		1			-		1
Gains (losses) deferred in Accumulated OCI:
Power forwards and swaps(b)		54			7		-		3			-		(1	)
Interest rate swaps(c)		3			-		-		3			-		-
Gas swaps and futures contracts(d)		9			1		2		-			9		-
SO2 futures contracts		(1	)		-		-		(1	)		-		-

(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, including $30 million over the next year.

(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 2011.

Other Derivatives

The following table presents the net change in market value for the three months and nine months ended September 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						Nine Months
Gains (Losses)	2006			2005			2006			2005
SO2 options and swaps:
Ameren	$	1		$	(4	)	$	(2	)	$	(10	)
UE		1			(4	)		3			(5	)
Genco		-			-			(4	)		(5	)
CILCORP/CILCO		-			-			(1	)		-
Coal Options:
Ameren		(1	)		-			(2	)		1
UE		(1	)		1			(2	)		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 nine months ended September 30, 2006 and 2005:

	Three Months				Nine Months
	2006		2005		2006		2005
Genco sales to Marketing Company		5,820		6,788		16,707		16,884
Marketing Company sales to CIPS		3,424		3,565		9,500		8,118
EEI sales to UE		-		789		-		2,230
EEI sales to CIPS		-		394		-		1,337
EEI sales to IP		-		433		-		1,227

The agreement under which EEI 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.

In accordance with the January 2006 ICC order discussed in Note 2 - Rate and Regulatory Matters, a power procurement auction was held at the beginning of September 2006 to procure power for CIPS, CILCO and IP after current power supply contracts expire on December 31, 2006. On September 15, 2006, the independent auction manager (NERA Economic Consulting) declared a successful result in the auction for fixed-price customers. In conjunction with the auction, there is a limitation of 35% on the amount of power any single supplier can provide of the Ameren Illinois utilities’ expected annual load. Ameren-affiliated companies are

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considered one supplier for the purposes of this limitation. Marketing Company was awarded contracts in the auction.

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 on July 7, 2006, UE, CIPS and Genco mutually consented to waive the one-year termination notice requirement of the JDA and agreed to terminate it on December 31, 2006. This action with respect to the JDA was accepted by the FERC in September 2006.

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

	Three Months				Nine Months
	2006		2005		2006		2005
UE sales to Genco		2,073		2,361		7,507		8,807
Genco sales to UE		898		636		2,615		2,365

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

	Three Months				Nine Months
	2006		2005		2006		2005
UE	$	15	$	18	$	73	$	97
Genco		5		9		22		56
Total	$	20	$	27	$	95	$	153

Money Pools

See Note 3 - Credit Facilities 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 $10 million (2005 - $12 million) for the three months and nine months ended September 30, 2006 and 2005.

In June 2006, CIPS repaid in full the remaining balance under its May 2005, $67 million subordinated promissory note to UE.

The average interest rate on CILCORP’s note payable to Ameren was 4.8% and 4.5% for the three months and nine months ended September 30, 2006, respectively (2005 - 4.1% and 6.7%, respectively). CILCORP recorded interest expense of $2 million (2005 - $1 million) and $6 million (2005 - $4 million) for the three months and nine months ended September 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 nine months ended September 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 above in Note 3 - Credit Facilities and Liquidity of this report.

			Three Months															Nine Months
Agreement		UE			CIPS			Genco			CILCORP(a)				IP			UE			CIPS			Genco		CILCORP(a)				IP
Operating Revenues:
Power supply agreement	2006		$	(b	)	$	(b	)	$	216		$	(c	)	$	(b	)	$	(b	)	$	(b	)	$	605		$	5		$	(b	)
with Marketing Company	2005			(b	)		8			229			2			(b	)		(b	)		25			603			23			(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			35			(b	)		23			(b	)		(b	)		156			(b	)		69			(b	)		(b	)
	2005			50			(b	)		26			(b	)		(b	)		147			(b	)		57			(b	)		(b	)
Total Operating	2006		$	35		$	(b	)	$	239		$	(c	)	$	(b	)	$	156		$	(b	)	$	674		$	5		$	(b	)
Revenues	2005			50			8			255			2			(b	)		147			25			660			23			(b	)
Fuel and Purchased Power:
JDA	2006		$	23		$	(b	)	$	35		$	(b	)	$	(b	)	$	69		$	(b	)	$	156		$	(b	)	$	(b	)
	2005			26			(b	)		50			(b	)		(b	)		57			(b	)		147			(b	)		(b	)

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		Three Months															Nine Months
Agreement		UE			CIPS			Genco			CILCORP(a)				IP			UE			CIPS			Genco		CILCORP(a)				IP
Power supply agreement	2006	$	(b	)	$	118		$	(b	)	$	1		$	(b	)	$	(b	)	$	337		$	(b	)	$	1		$	(b	)
with Marketing Company	2005		(b	)		121			2			3			(b	)		4			291			4			10			(b	)
Power supply agreement with EEI	2005		16			8			(b	)		(b	)		13			46			25			(b	)		(b	)		40
Executory tolling agreement	2006		(b	)		(b	)		(b	)		9			(b	)		(b	)		(b	)		(b	)		29			(b	)
with Medina Valley	2005		(b	)		(b	)		(b	)		9			(b	)		(b	)		(b	)		(b	)		27			(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	$	23		$	118		$	35		$	10		$	(b	)	$	69		$	337		$	156		$	30		$	(b	)
Purchased Power	2005		42			129			52			12			13			107			316			151			37			40
Other Operating Expenses:
Ameren Services support	2006	$	34		$	12		$	7		$	12		$	18		$	103		$	36		$	18		$	37		$	54
services agreement	2005		38			10			5			9			20			119			32			15			30			42
Ameren Energy support	2006		2			(b	)		1			(b	)		(b	)		6			(b	)		2			(b	)		(b	)
services agreement	2005		1			(b	)		1			(b	)		(b	)		3			(b	)		2			(b	)		(b	)
AFS support services	2006		1			(c	)		(c	)		(c	)		1			3			1			1			1			2
agreement	2005		1			(c	)		1			1			(c	)		3			1			2			2			1
Total Other	2006	$	37		$	12		$	8		$	12		$	19		$	112		$	37		$	21		$	38		$	56
Operating Expenses	2005		40			10			7			10			20			125			33			19			32			43
Interest Income (Expense):
Money pool borrowings	2006	$	(c	)	$	(1	)	$	3		$	1		$	1		$	(c	)	$	(2	)	$	8		$	4		$	2
(advances)	2005		2			(1	)		(1	)		1			(1	)		4			(1	)		2			3			(3	)

(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 September 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)	$	24
Replacement power:
Nuclear Electric Insurance Ltd.	$	490	(e)	$	9

(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.

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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 Ameren and UE’s results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. In addition, we have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. For a complete listing of our obligations and commitments, see 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 September 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 September 30, 2006:

	2006		2007		2008		2009		2010		Thereafter(a)
Ameren(b)	$	116	$	582	$	568	$	432	$	267	$	77
UE		64		311		283		227		174		77
Genco		22		145		170		143		50		-
CILCORP/CILCO		18		49		41		30		21		-

(a)   Commitments for coal are until 2011.

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

As of September 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 September 30, 2006:

	2006		2007		2008		2009		2010		Thereafter(a)
Ameren(b)	$	210	$	587	$	427	$	290	$	182	$	248
UE		20		67		57		38		26		75
CIPS		30		126		106		71		51		100
Genco		4		22		19		8		8		10
CILCORP/CILCO		86		147		107		60		32		33
IP		61		214		135		111		65		29

(a)   Commitments for natural gas are until 2016.

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

As of September 30, 2006, the long-term commitments for the purchase of electricity have increased from amounts previously disclosed as of December 31, 2005, as a result of power supply contracts obtained by CIPS, CILCO and IP in September 2006 through the operation of the competitive power procurement auction in Illinois for fixed-price customers, which include the vast majority of electric customers of these Ameren Illinois utilities. See Note 2 - Rate and Regulatory Matters for information on the Illinois power procurement auction and related matters, including pending court appeals that challenge the auction process and the recovery by utilities through rates to customers of costs for power supply resulting from the auction.

CIPS, CILCO and IP obtained power supply contracts through the September 2006 auction with terms of 17 months, 29 months and 41 months to serve, commencing January 1, 2007, the electric load requirements of fixed-price residential and small commercial customers with less than one megawatt of demand. CIPS, CILCO and IP obtained 17-month-term electric power supply contracts to serve the load requirements of commercial and industrial fixed-price customers with one megawatt or greater demand commencing January 1, 2007. Under these contracts, the electric suppliers are responsible for providing to CIPS, CILCO and IP energy, capacity, certain transmission, volumetric risk management and other services necessary for the Ameren Illinois utilities to serve the load of customers at an all inclusive fixed price.

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Through the Illinois auction held in September 2006, CIPS, CILCO and IP contracted for their anticipated fixed-price loads for residential and small commercial customers (less than one megawatt of demand) as follows:

	Term Ending
	May 31, 2008		May 31, 2009		May 31, 2010
Term	17 Months		29 Months		41 Months
Load in megawatts(a)		1,822		1,874		1,874
$ per megawatthour	$	64.77	$	64.75	$	66.05

(a)   Represents 2007 peak forecast load for CIPS, CILCO and IP in the aggregate. Actual load could be different due to customers electing not to purchase power pursuant to the power procurement auction and receive power from a different supplier, and weather, among other things.

Through the Illinois auction held in September 2006, CIPS, CILCO and IP contracted for their anticipated fixed-price loads for large commercial and industrial customers (one megawatt of demand or higher) as follows:

	Term Ending
	May 31, 2008
Term	17 Months
Load in megawatts(a)		1,920
$ per megawatthour	$	84.95

(a)   Represents 2007 peak forecast load for CIPS, CILCO and IP in the aggregate. Actual load could be different due to customers having 30 to 50 days after the date the auction was declared successful (September 15, 2006) to elect not to participate and receive power from a different supplier, and weather, among other things.

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. 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 subject to public review and comment. We do not expect the state regulations to be finalized until the first quarter of 2007. The Illinois EPA-proposed rules for mercury are significantly stricter than the federal rules. Illinois has also proposed Clean Air Interstate Rule program rules for NO_x that are more stringent than the federal program. The Missouri Department of Natural Resources is expected to formally propose rules to implement the federal Clean Air Mercury and Clean Air Interstate Rules in November 2006. 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) Illinois’ mercury regulations as revised pursuant to an agreement between Genco, CILCO, EEI, and the Illinois EPA. Under the agreement, Illinois generators may delay the compliance date for mercury reductions in exchange for accelerating the installation of NO_x and SO₂ controls. In November 2006, these mercury regulations were approved by the Illinois Pollution Control Board and are now pending before the Joint Committee on Administrative Review. The agreement with the Illinois EPA will also restrict purchasing SO₂ and 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 states of Illinois and Missouri must also develop attainment plans to meet the federal 8-hour ozone ambient standard by June 2007 and the federal 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

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alternative plan to comply with this standard, the cost impact could be material to UE. Illinois is planning to impose additional requirements beyond the Clean Air Interstate Rule as part of the attainment plans for ozone and fine particulate. At this time, we are unable to determine the impact state actions 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 September 30, 2006.

	SO2(a)		NOx(b)		Book Value
UE		1.816		605	$	63
Genco		0.677		16,227		81
CILCO		0.322		3,798		51
EEI		0.300		5,594		33

(a)   Vintages are from 2006 to 2016. Each company possesses additional allowances for use in periods beyond 2016. Units are in millions of SO₂ allowances (currently one allowance equals one ton emitted).

(b)   Vintages are from 2006 to 2008. Units are in NO_x allowances (one allowance equals one ton emitted).  

The following table presents the distribution by company and year of the NO_x emission allowances that were allocated by the Illinois EPA on September 12, 2006 for 2007 and 2008.

	2007(a)		2008(a)
UE		156		130
Genco		4,656		4,679
CILCO		2,052		2,053
EEI		2,746		2,713

(a)   These NO_x allowances are included in the total allowances table above.

Allocations of NO_x allowances for UE’s Missouri generating facilities will be 10,178 tons per emissions season in 2007 and 2008. UE, Genco, CILCO and EEI expect to use a substantial portion of the SO₂ and NO_x allowances for ongoing operations. 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. Information responsive to the EPA’s request has been submitted but we cannot predict the outcome of this matter.

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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 September 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 September 30, 2006, CIPS, CILCO and IP had recorded liabilities of $26 million, $3 million and $65 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 law enacted in Missouri in 2005 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 September 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 September 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

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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 September 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 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. Reports issued by outside experts hired by UE to review the cause of the incident and by FERC staff indicate design, construction and human error as causes of the breach. In their report, UE’s outside experts concluded that restoration of the upper reservoir, if undertaken, will require a complete rebuild of the entire dam with a completely different design concept, not simply a repair of the breached area.

The FERC investigation of the incident has been completed. In October 2006, the FERC approved a stipulation and consent agreement between UE and the FERC’s Office of Enforcement that resolves all issues arising from an investigation that the FERC’s Office of Enforcement conducted into alleged violations of license conditions and FERC regulations by UE as the licensee of the Taum Sauk hydroelectric facility that may have contributed to the breach of the upper reservoir. As part of the stipulation and consent agreement, UE agreed, among other things, to: (i) pay a civil penalty of $10 million; (ii) pay $5 million into an interest-bearing escrow account to fund project enhancements at or near the Taum Sauk facility; and (iii) implement and comply with a new dam safety program developed in connection with the settlement. As a result of $8 million having previously been accrued with respect to the FERC’s investigation in the second quarter of 2006, UE’s after-tax charge to earnings in the third quarter ended September 30, 2006, related to this stipulation and consent agreement was limited to $7 million.

Investigations by state authorities of the incident have not concluded. The facility will remain out of service until reviews by 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 at least all of 2008, if not longer.

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, including rebuilding the plant, will be covered by insurance. UE expects the total cost for damage and liabilities, excluding costs to rebuild the facility, resulting from the Taum Sauk incident to range from $106 million to $126 million. As of September 30, 2006, UE had paid $38 million and accrued a $68 million liability, including costs resulting from the FERC stipulation and consent discussed above, while expensing $18 million and recording an $88 million receivable due from insurance companies. As of September 30, 2006, UE has received $12 million from insurance companies reducing the insurance receivable balance to $76 million. 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 authorities. Until the reviews conducted by state 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 185 parties are named in some pending cases and as few as six in others. However, in the cases that were pending as of September 30, 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.

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From July 1, 2006, through September 30, 2006, six additional asbestos-related lawsuits were filed against Ameren, UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois. Two lawsuits were dismissed and five were settled. The following table presents the status as of September 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		316		31		170		130		2		39		150
Settled		100		-		51		43		-		11		50
Dismissed		145		24		93		47		2		6		65
Pending		71		7		26		40		-		22		35

(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 September 30, 2006, five asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

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 paid for 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.

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 2017. 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. Discovery of tritium releases in 2006 at the Callaway nuclear plant may result in an increased estimate for decommissioning when the next study is conducted. 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.

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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 nine months ended September 30, 2006 and 2005, is shown below for the Ameren Companies:

	Three Months						Nine Months
	2006			2005			2006			2005
Ameren:(a)
Net income	$	293		$	280		$	486		$	586
Unrealized gain on derivative hedging instruments, net of taxes of $12, $11, $9 and $22, respectively		23			15			19			33
Reclassification adjustments for (gains) included in net income, net of taxes of $6, $2, $11 and $3, respectively		(10	)		(2	)		(18	)		(5	)
Total comprehensive income, net of taxes	$	306		$	293		$	487		$	614
UE:
Net income	$	166		$	164		$	309		$	353
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $3, $(2), $2 and $ -, respectively		4			(4	)		3			(1	)
Reclassification adjustments for (gains) included in net income, net of taxes         of $1, $ -, $2 and $ -, respectively		(1	)		(1	)		(3	)		(1	)
Total comprehensive income, net of taxes	$	169		$	159		$	309		$	351
CIPS:
Net income	$	29		$	31		$	43		$	46
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $ -, $4, $(1) and $7, respectively		-			7			(2	)		11
Reclassification adjustments for (gains) included in net income, net of taxes         of $1, $1, $3 and $1, respectively		(1	)		(1	)		(4	)		(2	)
Total comprehensive income, net of taxes	$	28			37		$	37		$	55
Genco:
Net income	$	19		$	32		$	27		$	94
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $1, $(3), $1 and $(3), respectively		1			(5	)		2			(6	)
Total comprehensive income, net of taxes	$	20		$	27		$	29		$	88
CILCORP:
Net income	$	13		$	5		$	22		$	16
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $1, $13, $(6) and $19, respectively		2			19			(10	)		31
Reclassification adjustments for (gains) included in net income, net of taxes of $4, $ -, $7 and $ -, respectively		(6	)		(1	)		(10	)		-
Total comprehensive income, net of taxes	$	9		$	23		$	2		$	47
CILCO:
Net income	$	19		$	11		$	44		$	37
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $1, $13, $(6), and $20, respectively		2			19			(9	)		30
Reclassification adjustments for (gains) included in net income, net of taxes of $4, $ -, $7 and $1, respectively		(6	)		(1	)		(10	)		(1	)
Total comprehensive income, net of taxes	$	15		$	29		$	25		$	66
IP:
Net income	$	43		$	54		$	63		$	91
Unrealized (loss) on derivative hedging instruments, net of (benefit) of $ -, $ -, $ - and $ -, respectively		-			-			(1	)		-
Reclassification adjustments for losses included in net income, net of (benefit) of $ -, $ -, $(1) and $ -, respectively		-			-			1			-
Total comprehensive income, net of taxes	$	43		$	54		$	63		$	91

(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 the new contribution requirements in the recently passed Pension Protection Act of 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2009 at which time we would expect a required contribution of $100 million to $150 million. Required contributions of $150 million to $200 million each year are also

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expected for 2010 and 2011. 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.

The following tables present the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three months and nine months ended September 30, 2006 and 2005:

	Pension Benefits(a)
	Three Months						Nine Months
	2006			2005			2006			2005
Service cost	$	16		$	14		$	47		$	43
Interest cost		43			41			129			124
Expected return on plan assets		(49	)		(45	)		(147	)		(136	)
Amortization of:
Prior service cost		3			3			8			8
Actuarial loss		10			9			31			28
Net periodic benefit cost	$	23		$	22		$	68		$	67

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

	Postretirement Benefits(a)
	Three Months						Nine Months
	2006			2005			2006			2005
Service cost	$	5		$	5		$	16		$	16
Interest cost		18			17			51			53
Expected return on plan assets		(12	)		(11	)		(35	)		(34	)
Amortization of:
Transition obligation		-			1			1			2
Prior service cost		(2	)		(2	)		(5	)		(4	)
Actuarial loss		9			9			26			28
Net periodic benefit cost	$	18		$	19		$	54		$	61

(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 proportionate 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 nine months ended September 30, 2006 and 2005:

	Pension Costs
	Three Months				Nine Months
	2006		2005		2006		2005
UE	$	13	$	13	$	39	$	39
CIPS		3		3		9		9
Genco		2		2		6		6
CILCORP		3		3		8		9
CILCO		4		5		11		14
IP		2		1		6		4

	Postretirement Costs
	Three Months				Nine Months
	2006		2005		2006		2005
UE	$	9	$	11	$	28	$	33
CIPS		2		2		6		8
Genco		1		1		3		3
CILCORP		3		2		7		8
CILCO		4		3		11		12
IP		3		3		10		9

NOTE 12 - SEGMENT INFORMATION

Prior to the third quarter of 2006, Ameren reported one segment, Utility Operations, comprising electric generation and electric and gas transmission and distribution operations, with Other including Ameren holding company activity. As a result of the following changes in circumstances, Ameren, UE, CILCORP and CILCO changed their segments in the third quarter of 2006:

·   the Ameren Companies’ chief operating decision-making group began to assess performance and allocate resources based on a new segment structure and made

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related organizational and management reporting changes in the third quarter of 2006;

·   electric generation deregulation in Illinois, which is currently scheduled to become effective January 1, 2007;

·   the expiration of affiliate power supply agreements for CIPS and CILCO, and other supply agreements for IP on December 31, 2006;

·   the July 2006 termination of the JDA among UE, Genco and CIPS effective December 31, 2006; and

·   the September 2006 completion of a state-wide auction to procure power for CIPS, CILCO and IP for 2007 and beyond, Marketing Company's sale in that auction of power being acquired from Genco and AERG.

Ameren determined in the third quarter of 2006 that it has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 - Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI and other non-rate regulated activities, which are included in Other. The Illinois Regulated segment for Ameren consists of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO, and IP, as described in Note 1 - Summary of Significant Accounting Policies. The Non-rate-regulated Generation segment for Ameren primarily consists of the operations or activities of Genco, the CILCORP holding company, AERG, EEI, and Marketing Company. Other primarily includes Ameren holding company activities and the leasing activities of CILCORP, AERG, Resources Company, and CIPSCO Investment Company.

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

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

Prior period presentation has been adjusted for comparative purposes.

The following table presents information about the reported revenues and net income of Ameren for the three months and nine months ended September 30, 2006 and 2005, and total assets as of September 30, 2006 and December 31, 2005.

Three Months	Missouri Regulated		Illinois Regulated		Non-rate-regulated Generation		Other			Intersegment Eliminations			Consolidated
2006:
External revenues	$	813	$	836	$	261	$	-		$	-		$	1,910
Intersegment revenues		44		7		212		-			(263	)		-
Net income(a)		142		83		61		7			-			293
2005:
External revenues	$	828	$	835	$	217	$	1		$	-		$	1,881
Intersegment revenues		67		11		246		-			(324	)		-
Net income(a)		162		96		27		(5	)		-			280
Nine Months
2006:
External revenues	$	2,024	$	2,501	$	735	$	-		$	-		$	5,260
Intersegment revenues		179		17		603		-			(799	)		-
Net income(a)		258		125		100		3			-			486
2005:
External revenues	$	2,075	$	2,338	$	659	$	7		$	-		$	5,079
Intersegment revenues		179		30		640		-			(849	)		-
Net income(a)		346		159		89		(8	)		-			586
As of September 30, 2006:
Total assets	$	9,910	$	5,986	$	3,650	$	1,813		$	(2,529	)	$	18,830
As of December 31, 2005:
Total assets		9,261		6,073		3,731		1,949			(2,852	)		18,162

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

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The following table presents information about the reported revenues and net income of UE for the three months and nine months ended September 30, 2006 and 2005, and total assets as of September 30, 2006 and December 31, 2005.

Three Months	Missouri Regulated		Other (a)		Consolidated UE
2006:
Revenues	$	857	$	-	$	857
Net income(b)		142		23		165
2005:
Revenues	$	895	$	-	$	895
Net income(b)		162		1		163
Nine Months
2006:
Revenues	$	2,203	$	-	$	2,203
Net income(b)		258		47		305
2005:
Revenues	$	2,254	$	-	$	2,254
Net income(b)		346		3		349
As of September 30, 2006:
Total assets	$	9,910	$	24	$	9,934
As of December 31, 2005:
Total assets		9,261		16		9,277

(a)   Includes 40% interest in EEI and other non-rate-regulated activities.

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

The following table presents information about the reported revenues and net income of CILCORP for the three months and nine months ended September 30, 2006 and 2005, and total assets as of September 30, 2006 and December 31, 2005.

Three Months	Illinois Regulated		Non-rate-regulated Generation			CILCORP Other			Intersegment Eliminations			Consolidated CILCORP
2006:
External revenues	$	154	$	3		$	1		$	-		$	158
Intersegment revenues		-		56			-			(56	)		-
Net income(a)		11		2			-			-			13
2005:
External revenues	$	159	$	-		$	-		$	-		$	159
Intersegment revenues		-		54			-			(54	)		-
Net income(a)		12		(8	)		1			-			5
Nine Months
2006:
External revenues	$	523	$	23		$	-		$	-		$	546
Intersegment revenues		-		139			-			(139	)		-
Net income(a)		22		4			(4	)		-			22
2005:
External revenues	$	498	$	24		$	6		$	-		$	528
Intersegment revenues		-		140			-			(140	)		-
Net income(a)		26		(12	)		2			-			16
As of September 30, 2006:
Total assets(b)	$	1,169	$	1,157		$	4		$	(226	)	$	2,104
As of December 31, 2005:
Total assets(b)		1,231		1,201			4			(202	)		2,234

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

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

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The following table presents information about the reported revenues and net income of CILCO for the three months and nine months ended September 30, 2006 and 2005, and total assets as of September 30, 2006 and December 31, 2005.

Three Months	Illinois Regulated		Non-rate-regulated Generation			CILCO Other			Intersegment Eliminations			Consolidated CILCO
2006:
External revenues	$	154	$	3		$	-		$	-		$	157
Intersegment revenues		-		56			-			(56	)		-
Net income(a)		11		8			-			-			19
2005:
External revenues	$	159	$	-		$	-		$	-		$	159
Intersegment revenues		-		54			-			(54	)		-
Net income(a)		12		(2	)		-			-			10
Nine Months
2006:
External revenues	$	523	$	23		$	-		$	-		$	546
Intersegment revenues		-		139			-			(139	)		-
Net income(a)		22		24			(3	)		-			43
2005:
External revenues	$	498	$	24		$	-		$	-		$	522
Intersegment revenues		-		140			-			(140	)		-
Net income(a)		26		9			-			-			35
As of September 30, 2006:
Total assets	$	949	$	565		$	1		$	(17	)	$	1,498
As of December 31, 2005:
Total assets		1,008		563			1			(15	)		1,557

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

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

OVERVIEW

Ameren Executive Summary

Ameren’s earnings in 2006 have been significantly impacted by higher fuel and transportation costs due primarily to increased coal and related transportation costs, severe storm-related customer outages, an unplanned outage at UE’s Callaway nuclear plant and milder winter and summer weather than 2005. In addition, Ameren incurred additional costs of operating in the MISO Day Two Energy Market in the first nine months of 2006 because MISO Day Two operations did not commence until the second quarter last year. However, the costs of MISO Day Two operations in the third quarter of 2006 were lower than the year-ago period. Incremental costs resulting from the December 2005 breach of the upper reservoir at UE’s Taum Sauk hydroelectric pumped-storage plant also negatively impacted earnings in the third quarter and first nine months of 2006. In the third quarter, UE settled issues relating to the reservoir breach with federal authorities, but the breach is still being investigated by state authorities. Increased margins from interchange sales and organic growth compared to the third quarter and first nine months of last year positively influenced 2006 earnings.

In Illinois, there has been significant regulatory and legislative activity as we approach the scheduled end of a 10-year electric rate freeze and the expiration of power supply contracts. In electric delivery service rate filings made in December 2005, CIPS, CILCO and IP requested a total combined annual electric revenue increase of approximately $200 million. In early October, the administrative law judges in our delivery service cases recommended an aggregate $147 million increase in electric rates. The ICC has until late November to render a decision in these cases.

Since the Ameren Illinois utilities own almost no generation and their supply contracts expire at the end of this year, in September, an ICC-approved procurement auction for post-2006 power requirements for these companies was held. The supply contracts from this auction resulted in market prices for power which are above those prices currently reflected in customer rates. Due to potential Illinois rate increases of 40% to 55% there have been calls by some key lawmakers, including the Illinois governor, for a three-year extension of the rate freeze in Illinois. We believe an extension of the rate freeze is without legal merit, and 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 all of the Ameren Companies. If an extension of the rate freeze were to occur, the Ameren Illinois utilities estimate they would spend approximately $1 billion more annually for power than they could charge their customers. As has been clearly demonstrated by recent actions and statements by the credit rating agencies, if the electric rate freeze in Illinois is extended, the credit ratings of the Ameren Illinois utilities and CILCORP will be slashed to

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deep junk status. These credit ratings will immediately trigger collateral and other funding requirements. We believe such funding requirements, combined with the inability to recover costs through rates to customers, would cause the Ameren Illinois utilities to exhaust their available cash and credit and be unable to borrow. Ameren believes this would lead to the Ameren Illinois utilities and CILCORP being financially insolvent by February 2007, or sooner. Any decision or action that impairs the ability of CIPS, CILCO, and IP to fully recover costs from their electric customers in a timely manner would result in material adverse consequences for Ameren, CIPS, CILCORP, CILCO, and IP. CIPS, CILCO and IP remain steadfastly committed to working with key stakeholders to develop a constructive solution that would mitigate the impact of these rate increases on our Illinois residential customers, yet still provide for full and timely recovery of costs. This year the Ameren Illinois utilities filed two different plans with the ICC that would allow expected electric rate increases to be phased in over time. These utilities are hopeful that these plans will provide a constructive solution to lessen the impact of the expected rate increases on Illinois customers.

In early July 2006, 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 rate 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. A decision from the MoPSC on both rate case filings is expected no later than June 2007. The resolution of these regulatory matters in Illinois and Missouri will have a significant impact on earnings for the Ameren Companies in 2007 and beyond.

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. 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.

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. 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. In September 2006, the MoPSC approved rules for a fuel and purchased power cost recovery mechanism, which are expected to become effective by the end of 2006. UE has requested approval of a fuel and purchased power cost recovery mechanism as a part of its

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current electric rate case. 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 including the forward sale of power and purchase of fuel to reduce our exposure to the volatility of commodities 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 increased to $293 million, or $1.42 per share, in the third quarter of 2006 from $280 million, or $1.37 per share, in the third quarter of 2005. Ameren’s net income decreased to $486 million, or $2.37 per share, for the nine months ended September 30, 2006, from earnings of $586 million, or $2.94 per share, in the first nine months of 2005.

Earnings were negatively impacted for the three-month and nine-month periods by the costs and lost electric margins associated with outages caused by severe storms, lower prices for interchange sales, milder weather conditions, and costs associated with an upper reservoir breach in December 2005 at UE’s Taum Sauk plant. In the third quarter of 2005, we began a scheduled refueling and maintenance outage at UE’s Callaway nuclear plant and recorded an impairment of an aircraft leveraged lease; items that did not recur in 2006. The nine-month period was also unfavorably impacted by an unscheduled outage at UE’s Callaway nuclear plant in the second quarter of 2006 and increased fuel and purchased power costs, including incremental costs of operating in the MISO Day Two Energy Market. An increase in the number of common shares outstanding in the current-year periods further reduced Ameren’s earnings per share. Increased margins on interchange sales at EEI and organic growth reduced the impact of these unfavorable items on current year earnings.

Prior to the third quarter of 2006, Ameren reported one segment, Utility Operations, comprising electric generation and electric and gas transmission and distribution operations, with Other including Ameren holding company activity. As a result of the following changes in circumstances, Ameren, UE, CILCORP and CILCO changed their segments in the third quarter of 2006:

·   the Ameren Companies’ chief operating decision-making group began to assess the performance and allocate resources based on a new segment structure and made related organizational and management reporting changes in the third quarter of 2006;

·   electric generation deregulation in Illinois, which is currently scheduled to become effective January 1, 2007;

·   the expiration of affiliate power supply agreements for CIPS and CILCO, and other supply agreements for IP on December 31, 2006;

·   the July 2006 termination of the JDA among UE, Genco and CIPS effective December 31, 2006; and

·   the September 2006 completion of a state-wide auction to procure power for CIPS, CILCO and IP for 2007 and beyond, and Marketing Company's sale in that auction of power being acquired from Genco and AERG.

Prior period presentation has been adjusted for comparative purposes.

Ameren determined in the third quarter of 2006 that it has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. UE determined that it has one reportable segment: Missouri Regulated. CILCORP and CILCO determined that they have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. A discussion of changes in components of net income between periods by business segment is provided below where material. See Note 12 - Segment Information to our financial statements under Part I, Item 1, of this report for further discussion of Ameren’s, UE’s, CILCORP’s and CILCO’s business segments.

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Because it is a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren’s principal subsidiaries to Ameren’s consolidated net income for the three months and nine months ended September 30, 2006 and 2005:

	Three Months					Nine Months
		2006		2005			2006		2005
Net income (loss):
UE(a)(b)	$	165	$	163		$	305	$	349
CIPS		28		30			41		44
Genco(a)		19		32			27		94
CILCORP(a)		13		5			22		16
IP		42		53			61		89
Other(c)		26		(3	)		30		(6	)
Ameren net income	$	293	$	280		$	486	$	586

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

UE:	2006 - $9 million, $43 million
	2005 - $7 million, $53 million
Genco:	2006 - $2 million, $13 million
	2005 - $3 million, $31 million
CILCORP:	2006 - $2 million, $14 million
	2005 - $2 million, $11 million

(b)   Includes earnings from a non-rate-regulated 40% interest in EEI.

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

RESULTS OF OPERATIONS

Margins

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

Three Months		Ameren(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Electric revenue change:
Effect of weather (estimate)	$	(30	)	$	(10	)	$	(5	)	$	-		$	(6	)	$	(6	)	$	(9	)
Storm-related outages		(3	)		(2	)		(2	)		2			-			-			(1	)
Wholesale contracts(b)		(18	)		-			-			(18	)		-			-			-
Interchange revenues(c)		69			(26	)		(9	)		(19	)		4			4			-
Growth and other (estimate)		17			(2	)		-			7			5			4			27
Total	$	35		$	(40	)	$	(16	)	$	(28	)	$	3		$	2		$	17
Fuel and purchased power change:
Fuel:
Generation and other	$	29		$	14		$	-		$	9		$	8		$	7		$	-
Sales of emissions allowances		(2	)		-			-			(21	)		-			-			-
Price		(8	)		(4	)		-			-			(4	)		(4	)		-
Purchased power		(6	)		38			15			5			7			7			(26	)
Storm-related energy costs		(2	)		(1	)		-			(1	)		-			-			-
Total	$	11		$	47		$	15		$	(8	)	$	11		$	10		$	(26	)
Net change in electric margins	$	46		$	7		$	(1	)	$	(36	)	$	14		$	12		$	(9	)
Net change in gas margins	$	-		$	(1	)	$	2		$	-		$	-		$	-		$	-
Nine Months
Electric revenue change:
Effect of weather (estimate)	$	(60	)	$	(24	)	$	(12	)	$	-		$	(9	)	$	(9	)	$	(15	)
Storm-related outages		(9	)		(8	)		(2	)		2			-			-			(1	)
Noranda		46			46			-			-			-			-			-
Illinois service territory transfer		3			(38	)		41			34			-			-			-
Wholesale contracts(b)		(54	)		-			-			(54	)		-			-			-
Interchange revenues(c)		171			(5	)		(24	)		(38	)		(3	)		(3	)		-
Growth and other (estimate)		2			(15	)		24			23			12			12			43
Total	$	99		$	(44	)	$	27		$	(33	)	$	-		$	-		$	27

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Nine Months		Ameren(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Fuel and purchased power change:
Fuel:
Generation and other	$	22		$	13		$	-		$	12		$	8		$	8		$	-
Sale of emissions allowances		(2	)		-			-			(21	)		-			-			-
Price		(55	)		(34	)		-			(14	)		(7	)		(7	)		-
Purchased power		(114	)		7			(24	)		(63	)		21			21			(52	)
Storm-related energy costs		1			2			-			(1	)		-			-			-
Total	$	(148	)	$	(12	)	$	(24	)	$	(87	)	$	22		$	22		$	(52	)
Net change in electric margins	$	(49	)	$	(56	)	$	3		$	(120	)	$	22		$	22		$	(25	)
Net change in gas margins	$	(6	)	$	(9	)	$	4		$	-		$	(4	)	$	(5	)	$	5

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

(b)   Represents several wholesale contracts that expired in 2005 and were not renewed.

(c)   Excludes the impact from storm-related outages.

The table below presents the favorable (unfavorable) variations in electric and gas margins and non-utility revenues by segment for Ameren for the three months and nine months ended September 30, 2006, compared with the same periods in 2005.

Three Months	Missouri Regulated			Illinois Regulated			Non-rate-regulated Generation			Other			Intersegment Eliminations			Consolidated
Electric margin change	$	7		$	(10	)	$	54		$	-		$	(5	)	$	46
Gas margin change		(1	)		2			-			-			(1	)		-
Other revenues (Non-utility)		1			1			(1	)		(3	)		2			-
Total	$	7		$	(7	)	$	53		$	(3	)	$	(4	)	$	46
Nine Months
Electric margin change	$	(56	)	$	(20	)	$	40		$	-		$	(13	)	$	(49	)
Gas margin change		(9	)		4			-			-			(1	)		(6	)
Other revenues (Non-utility)		2			3			(5	)		(5	)		2			(3	)
Total	$	(63	)	$	(13	)	$	35		$	(5	)	$	(12	)	$	(58	)

Ameren

Ameren’s electric margin increased by $46 million, or 4%, for the three months and decreased $49 million, or 2%, for the nine months ended September 30, 2006, compared with the same periods in 2005. The following items had a favorable impact on electric margins for the third quarter and first nine months of 2006 as compared to the year-ago periods:

·   an increase in margins on interchange sales of $59 million, or 181%, and $121 million, or 67%, over the prior three and nine-month periods primarily because of the expiration of EEI’s affiliate cost-based power supply contract on December 31, 2005;

·   organic growth and industrial customers switching back to Illinois tariff rates because of the expiration of power contracts with suppliers;

·   sales to Noranda, which commenced on June 1, 2005, that increased electric margin by approximately $20 million at UE for the first nine months;

·   lower emissions allowance costs totaling $10 million for both the quarter and nine months ended September 30, 2006; and

·   MISO Day Two Energy Market costs which were $5 million lower for the three months ended September 30, 2006, compared with the same period in 2005.

The following items had an unfavorable impact on electric margins for the third quarter and first nine months of 2006 as compared to the year-ago periods:

·   unfavorable weather conditions as evidenced by a 10% decline in cooling degree-days for both the three months and nine months ended September 30, 2006, and a 9% decrease in heating degree-days for the nine months ended September 30, 2006, compared with the same period in 2005;

·   severe storm-related outages which negatively impacted electric sales and resulted in an estimated net reduction in overall electric margin of $5 million and $8 million in the third quarter and the nine months ended September 30, 2006;

·   wholesale margins which were approximately $8 million lower for the nine months ended September 30, 2006 due primarily to the expiration of several large contracts in 2005;

·   incremental fees of $4 million levied by FERC for the nine months ended September 30, 2006, upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant;

·   a 7% increase in the third quarter and 11% increase for the first nine months of 2006 in coal and transportation prices;

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·   MISO Day Two Energy Market costs which were $16 million higher for the nine months ended September 30, 2006, compared with the same periods in 2005 as this market did not begin until the second quarter of 2005;

·   reduced margins because of the unavailability of UE’s Taum Sauk hydroelectric plant totaling an estimated $10 million and $20 million in the third quarter and first nine months of 2006;

·   reduced margins from UE’s other hydroelectric generation due to drought-like conditions across the central and southern portions of Missouri totaling approximately $5 million for the third quarter and $24 million for the nine months ended September 30, 2006, as compared to prior periods;

·   an unscheduled outage in the second quarter of 2006 at UE’s Callaway nuclear plant, which reduced electric margins by an estimated $20 million. In the third quarter of 2005, there was a scheduled refueling and maintenance outage that reduced electric margins by $4 million. The lack of a similar outage in the third quarter of 2006 benefited current year electric margins; and

·   reduced transmission service revenues primarily due to elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.

Ameren’s gas margins were flat for the three months and decreased by $6 million, or 2%, for the nine months ended September 30, 2006, compared with the same periods in 2005, respectively.

Ameren’s decrease in gas margins for the nine months ended September 30, 2006, compared with the same period in 2005, was primarily due to mild weather conditions as evidenced by a 9% decrease in heating degree-days. Weather-sensitive residential and commercial gas sales volumes decreased 9% and 8%, respectively, for the nine months ended September 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 nine months of 2006.

Missouri Regulated

UE

UE’s electric margin increased by $7 million, or 1%, for three months and decreased by $56 million, or 4%, for the nine months ended September 30, 2006, compared to the same periods in 2005. The increase in the electric margin for the three months ended September 30, 2006, was primarily due to:

·   the lack of a scheduled Callaway nuclear plant refueling and maintenance outage in 2006; and

·   decreased MISO Day Two Energy Market costs totaling $6 million.

Factors that reduced the increase in electric margin for the three months and contributed to the decrease in electric margins for the nine months ended September 30, 2006, as compared to the same periods in the prior year were as follows:

·   unfavorable weather conditions as evidenced by a 6% decline in cooling degree-days for the three months and 8% decline for the nine months ended September 30, 2006;

·   severe spring and summer storms in 2006 caused outages which reduced electric sales and resulted in an estimated net reduction in overall electric margin of $3 million for the third quarter and $6 million for the first nine months of 2006;

·   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 an estimated $22 million for the first nine months of 2006 with no impact on the third quarter of 2006;

·   lower margins on interchange sales as a result of lower power prices in the third quarter and first nine months of 2006. Average interchange revenue realization per kilowatthour was 50% and 9% lower for the third quarter and first nine months of 2006, respectively. 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 $3 million and $17 million in incremental margins on interchange sales for UE for the three months and nine months ended September 30, 2006, respectively;

·   a 4% and 11% increase in coal and related transportation prices for the third quarter and first nine months of 2006;

·   fees of $4 million levied by FERC for the nine months ended September 30, 2006, for generation benefits provided to UE’s Osage hydroelectric plant;

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

·   reduced electric margins from UE’s other hydroelectric generation due to drought-like conditions across the central and southern portions of Missouri;

·   unscheduled outage at UE’s Callaway nuclear plant in the second quarter of 2006;

·   MISO Day Two Energy Market costs, which were $8 million higher for the first nine months of 2006 as this market did not begin until the second quarter of 2005;

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

·   reduced transmission service revenues primarily due to elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.

The decrease in UE’s electric margins for the nine months ended September 30, 2006, compared with the same period in 2005, was reduced by increased sales to Noranda and the lack of a scheduled Callaway refueling and maintenance outage in 2006.

UE’s gas margin decreased by $1 million, or 9%, for the three months and $9 million, or 17%, for the nine months ended September 30, 2006, compared with the same periods in 2005. UE’s decrease in gas margins was due to mild winter weather conditions, as evidenced by a 9% decrease in heating degree-days for the nine months ended September 30, 2006. In addition, UE’s gas margin was negatively impacted by the transfer of UE’s Illinois service territory to CIPS in May 2005, which reduced gas margins by $3 million for the nine months ended September 30, 2006, compared with the same period in 2005.

Illinois Regulated

Illinois Regulated’s electric margin decreased by $10 million, or 3%, for the three months and $20 million, or 3%, for the nine months ended September 30, 2006, compared with the same periods in 2005.

Illinois Regulated’s gas margin increased by $2 million, or 4%, for the three months and $4 million, or 2%, for the nine months ended September 30, 2006.

CIPS

CIPS’ electric margin decreased by $1 million, or 1%, for the three months and increased by $3 million, or 1%, for the nine months ended September 30, 2006, compared to the same periods in 2005. The increase in electric margins for the first nine months of 2006 was primarily because of:

·   the transfer to CIPS of UE’s Illinois service territory on May 2, 2005, which generated incremental electric margins of $4 million for the first nine months of 2006, and

·   customers switching back to CIPS from Marketing Company in 2006 because tariff rates were below market rates for power.

CIPS’ increase in electric margins was reduced by the following factors for the third quarter and first nine months of 2006, compared to the same periods in 2005, as follows:

·   increased MISO Day Two Energy Market costs, totaling $2 million for the nine months ended September 30, 2006, compared with the same period in 2005 as this market did not begin until the second quarter of 2005;

·   severe summer storms caused outages that reduced electric sales and resulted in an estimated net reduction in electric margin of $2 million for the three months and nine months ended September 30, 2006;

·   unfavorable weather conditions as evidenced by a 12% and 8% decrease in cooling degree-days for the third quarter and first nine months of 2006; and

·   reduced transmission service revenues primarily due to elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.

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 $9 million and $24 million for the three months and nine months ended September 30, 2006.

CIPS’ gas margin increased by $2 million for the three months and $4 million, or 9%, for the nine months ended September 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 winter weather as evidenced by an 11% decrease in heating degree-days for the nine months ended September 30, 2006, as compared with the same period in 2005.

CILCO (Illinois Regulated)

The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for the three months and nine months ended September 30, 2006, as compared with the same periods in 2005:

	Three Months			Nine Months
CILCO (Illinois Regulated)	$	(1	)	$	2
CILCO (AERG)		13			20
Total change in electric margin	$	12		$	22

CILCO’s Illinois Regulated electric margin decreased by $1 million, or 2%, for the three months ended September 30, 2006, as compared to the year-ago period, primarily because of unfavorable weather conditions as evidenced by a 19% decrease in cooling degree-days.

CILCO’s Illinois Regulated electric margin increased by $2 million, or 2%, for the nine months ended September 30, 2006, compared to the same periods in 2005. The increase in electric margins was primarily because of:

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·   increased native load growth, primarily in the industrial sector, and

·   lower MISO Day Two Energy Market costs.

The increase in CILCO’s (Illinois Regulated) electric margins for the nine months ended September 30, 2006, was reduced by the impact of unfavorable weather conditions as evidenced by the decrease in cooling degree-days and a 6% decrease in heating degree-days.

See Non-rate-regulated Generation under Results of Operations for a detailed explanation of CILCO’s (AERG) change in electric margin for the three months and nine months ended September 30, 2006, as compared with the same periods in 2005.

CILCO’s (Illinois Regulated) gas margin was flat for the three months and decreased by $5 million, or 8%, for the nine months ended September 30, 2006, compared to the same periods in 2005. This decrease was primarily as a result of the mild winter weather conditions in CILCO’s service territory.

IP

IP’s electric margin decreased by $9 million, or 5%, for the three months and $25 million, or 7%, for the nine months ended September 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;

·   reduced transmission service revenues primarily due to the elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market;

·   unfavorable weather conditions, including a 12% and 10% decrease in cooling degree-days for the three months and nine months ended September 30, 2006, compared with the same periods in 2006; and

·   severe summer storms caused outages that reduced electric sales and resulted in an estimated net reduction in electric margin of $1 million for the three months and nine months ended September 30, 2006.

The decrease in IP’s electric margins in the third quarter and first nine months of 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 and lower transmission expenses due, in part, to a $6 million favorable settlement of disputed ancillary charges with MISO.

IP’s gas margin was flat for the three months and increased by $5 million, or 5%, for the nine months ended September 30, 2006, compared to the same periods in 2005. The increase in the nine months ended September 30, 2006, was primarily because of a rate increase effective in May 2005 that added revenues of $6 million in 2006. This increase was reduced by the extremely mild winter weather conditions as evidenced by a 10% decrease in heating degree-days in the first nine months of 2006 as compared with the year-ago period in IP’s service territory.

Non-rate-regulated Generation

Non-rate-regulated Generation’s electric margins increased by $54 million, or 32%, for the three months and $40 million, or 7%, for the nine months ended September 30, 2006, compared with the same periods in 2005.

Genco

Genco’s electric margin decreased by $36 million, or 29%, and $120 million, or 32%, for the three months and nine months ended September 30, 2006, compared with the same periods in 2005, primarily because of:

·   lower wholesale margins as Genco purchased additional power at higher costs due, in part, to the expiration of the coal-based power supply contract between EEI and its affiliates on December 31, 2005;

·   higher net emission allowance costs because of a $21 million gain at Genco in the third quarter of 2005 resulting from the nonmonetary swap of certain earlier vintage year SO₂ emission allowances for later vintage year allowances;

·   a 7% and 9% increase in coal and transportation prices for the three months and nine months ended September 30, 2006, compared with the same periods in 2005;

·   reduced plant availability of major coal-fired units in 2006;

·   lower margins on interchange sales for the three months and nine months ended September 30, 2006, compared with the same periods in 2005, primarily because of lower power prices, and a $3 million and $17 million reduction in 2006 due to the amendment of the JDA among UE, Genco and CIPS; and

·   higher MISO Day Two Market costs totaling $5 million for the third quarter and $11 million for the first nine months of 2006 as this market did not begin until the second quarter of 2005.

Genco’s decrease in electric margins was reduced by an increase in electric margins 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.

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CILCO (AERG)

For the three- and nine-month periods ended September 30, 2006, AERG’s electric margin increased by $13 million, or 97%, for the three months and $20 million, or 29%, for the nine months ended September 30, 2006, compared with 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 $3 million and $7 million for the third quarter and first nine months of 2006, respectively; and

·   an increase in margins on interchange sales of $5 million for the first nine months of 2006, due in part to improved plant availability.

EEI

EEI’s electric margins increased by $87 million for the three months and $179 million for the nine months ended September 30, 2006, compared with the same periods in 2005 primarily because of the increase in margins on interchange sales resulting from the expiration of its affiliate cost-based sales contract on December 31, 2005, and its replacement with a market-based sales contract.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren

Three months - Other operations and maintenance expenses were comparable between periods. We experienced the most damaging storms in the company’s history in our service territory this summer resulting in the loss of power to approximately 950,000 electric customers and expenses of $23 million. In addition, incremental costs of $7 million as a result of the December 2005 Taum Sauk plant incident increased 2006 third quarter other operations and maintenance expenses. Reducing the impact of this unfavorable item was decreased bad debt expense and an impairment of $10 million recorded in the prior-year period related to an investment in an aircraft leveraged lease with Delta Air Lines, Inc. due to its Chapter 11 bankruptcy filing in September 2005. No such impairment occurred in the current year period.

Nine months - Other operations and maintenance expenses increased $25 million primarily because of storm expenditures in the current year as discussed above, $17 million of costs related to the December 2005 reservoir breach at UE’s Taum Sauk plant, and losses on sales of leveraged lease assets in the second quarter of 2006 that increased other operations and maintenance expenses by $7 million. Additionally, higher power plant maintenance expenses due to the timing of maintenance outages and an increase in legal fees for environmental issues and general litigation resulted in increased other operations and maintenance expenses. Reducing the impact of these items was a reduction in bad debt expense and injuries and damages expense along with the impairment of the Delta Air Lines, Inc. leveraged lease recorded in the prior year, which did not recur in the current year, as discussed above.

Variations in other operations and maintenance expenses at Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three months and nine months ended September 30, 2006, compared with the same periods in 2005 were as follows:

Missouri Regulated

UE

Three months - Other operations and maintenance expenses increased $15 million primarily because of repair expenditures related to severe storms in UE’s service territory this summer of $16 million. Additionally, incremental costs of $7 million were recorded related to the December 2005 Taum Sauk plant incident because of a settlement with FERC resolving all potential federal liability. Reducing the impact of these unfavorable items were lower employee benefit costs and legal fees. Additionally, in the third quarter of 2005, we began a scheduled refueling and maintenance outage at UE’s Callaway nuclear plant, resulting in maintenance expenses of $3 million, which did not recur this year.

Nine months - Other operations and maintenance expenses increased $8 million primarily because of storm repair expenditures, as noted above, and incremental costs associated with the Taum Sauk incident of $17 million. Reducing the impact of these unfavorable items were decreased other operations and maintenance expenses of $7 million resulting from the transfer of UE’s Illinois service territory to CIPS in May 2005. Additionally, lower injuries and damages expenses, due in part to the settlement of claims, decreased bad debt expense and employee benefit costs, and the lack of a scheduled Callaway refueling and maintenance outage, as noted above, resulted in a reduction in other operations and maintenance expenses.

Illinois Regulated

Other operations and maintenance expenses increased $3 million and $27 million in Illinois Regulated primarily at IP for the three months and nine months ended September 30, 2006, respectively, compared with the same periods in 2005.

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CIPS

Three months - Other operations and maintenance expenses were comparable between periods as storm repair expenditures in the current period were offset by a reduction in bad debt expense.

Nine months - Other operations and maintenance expenses increased $8 million primarily because of storm repair expenditures and the transfer of UE’s Illinois service territory to CIPS in May 2005, which resulted in additional other operations and maintenance expenses of $7 million. The negative effect of these items was reduced by lower bad debt expense.

CILCO (Illinois Regulated)

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

Nine months - Other operations and maintenance expenses decreased $3 million primarily because of lower employee benefit costs, partially offset by increased legal fees.

IP

Three months - Other operations and maintenance expenses increased $4 million primarily because of storm repair expenditures of $4 million in the current period and increased injuries and damages expenses, partially offset by decreased labor costs.

Nine months - Other operations and maintenance expenses increased $22 million primarily because of storm repair expenditures, along with higher rental expenses and injuries and damages expenses. The negative effect of these items was reduced by lower labor costs.

Non-rate-regulated Generation

Other operations and maintenance expenses were comparable at Non-rate-regulated Generation in the third quarter of this year compared to the third quarter of the prior year. Other operations and maintenance expenses increased $11 million for the nine months ended September 30, 2006, compared with the same period in 2005, primarily at Genco.

Genco

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

Nine months - Other operations and maintenance expenses increased $5 million primarily because of higher maintenance expenses resulting from increased power plant maintenance outages in the current-year period.

CILCORP (Parent Company Only), EEI & CILCO (AERG)

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

Other

Three months - In the third quarter of 2005, Ameren recorded an impairment of $10 million at a nonregistrant subsidiary related to an investment in an aircraft leveraged lease to Delta Air Lines, Inc. due to its Chapter 11 bankruptcy filing in September 2005. No such impairment occurred in the current year period.

Nine months - In the second quarter of 2006, losses on sales of leveraged lease assets were recorded at CILCO. The leveraged lease losses in other operations and maintenance expenses were partially offset by a tax benefit reflected in income taxes. The lack of the 2005 leveraged lease impairment associated with Delta Air Lines, Inc. in the current year reduced the year-over-year impact of the leveraged lease losses for the first nine-months of 2006.

Depreciation and Amortization

Ameren

Three months - Depreciation and amortization expenses increased $4 million primarily because of capital additions.

Nine months - Depreciation and amortization expenses increased $17 million primarily as a result of capital additions and the impairment of an intangible asset associated with the CILCORP acquisition.

Variations in depreciation and amortization expenses at Ameren’s business segments for the three months and nine months ended September 30, 2006, compared with the same periods in 2005 were as follows:

Missouri Regulated

UE

Three months - Depreciation and amortization expenses increased $3 million primarily because of capital additions.

Nine months - Depreciation and amortization expenses increased $12 million 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 2005. Additionally, depreciation increased due to CTs transferred to UE from

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Genco in May 2005. Reducing the impact of these increases was a reduction of depreciation due to the transfer of property to CIPS as part of the Illinois service territory transfer in May 2005.

Illinois Regulated

Depreciation and amortization expenses were comparable at Illinois Regulated for the three months and nine months ended September 30, 2006, compared with the same periods in 2005.

CIPS

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

Nine months - Depreciation and amortization expenses increased $2 million primarily because of capital additions and depreciation on property transferred to CIPS from UE in the May 2005 Illinois service territory transfer.

CILCO (Illinois Regulated) & IP

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

Non-rate-regulated Generation

Depreciation and amortization expenses were comparable at Non-rate-regulated Generation in the third quarter of 2006 compared to the third quarter of last year. Depreciation and amortization expenses increased $3 million for the nine months ended September 30, 2006, compared with the same period in 2005.

Genco, EEI & CILCO (AERG)

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

CILCORP (Parent Company Only)

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

Nine months - Depreciation and amortization expenses increased $4 million primarily because of the recording of an impairment of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.

Taxes Other Than Income Taxes

Ameren

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

Nine months - Taxes other than income taxes increased $18 million primarily as a result of higher gross receipts and excise taxes and higher property taxes.

Variations in taxes other than income taxes at Ameren’s business segments for the three months and nine months ended September 30, 2006, compared with the same periods in 2005 were as follows:

Missouri Regulated

UE

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

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

Illinois Regulated

Taxes other than income taxes were comparable at Illinois Regulated in the third quarter of this year compared to the third quarter of the prior year. Taxes other than income taxes increased $8 million for the nine months ended September 30, 2006, compared with the same period in 2005.

CIPS

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

Nine months - Taxes other than income taxes increased $6 million primarily as a result of higher excise taxes.

CILCO (Illinois Regulated)

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

Nine months - Taxes other than income taxes increased $3 million primarily as a result of higher excise taxes.

IP

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

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Non-rate-regulated Generation

Taxes other than income taxes were comparable at Non-rate-regulated Generation in the third quarter of 2006 compared to the third quarter of the prior year. Taxes other than income taxes increased $8 million for the nine months ended September 30, 2006, compared with the same period in 2005, primarily at Genco.

Genco

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

Nine months - Taxes other than income taxes increased $7 million primarily because of higher property taxes due to a favorable court decision in the first quarter of 2005 that did not recur in 2006.

CILCORP (Parent Company Only), EEI & CILCO (AERG)

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

Other Income and Expenses

Ameren

Three months and nine months - Miscellaneous income decreased $1 million and $6 million primarily as a result of lower capitalization of equity funds used during construction in the current year periods. Miscellaneous expense increased $2 million in the third quarter primarily because of activity related to investments in low income housing credits. Miscellaneous expense decreased $3 million in the nine months primarily due to the write-off of unrecoverable natural gas costs in the prior year as noted below.

Variations in other income and expenses at Ameren’s, CILCORP’s and CILCO’s business segments for the three months and nine months ended September 30, 2006, compared with the same periods in 2005 were as follows:

Missouri Regulated

UE

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

Nine months - Miscellaneous income decreased $6 million primarily as a result of lower capitalization of equity funds used during construction in 2006. In the prior-year period, UE replaced steam generators and turbine rotors at the Callaway nuclear plant. Miscellaneous expense was comparable between periods.

Illinois Regulated

Other income and expenses were comparable at Illinois Regulated in the third quarter of 2006 compared to the third quarter of the prior year. Other income and expenses were favorable $3 million for the nine months ended September 30, 2006, compared with the same period in 2005.

CIPS

Three months - Miscellaneous income and miscellaneous expense were comparable between periods.

Nine months - Miscellaneous income was comparable between periods. Miscellaneous expense decreased $4 million primarily as a result of the write-off in 2005 of unrecoverable natural gas costs.

CILCO (Illinois Regulated)

Three months - Miscellaneous income and miscellaneous expense were comparable between periods.

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

IP

Three months - Miscellaneous income and miscellaneous expense were comparable between periods.

Nine months - Miscellaneous income decreased $2 million primarily because of lower capitalization of equity funds used during construction. Miscellaneous expenses increased $2 million primarily as a result of IP-related integration costs.

Non-rate-regulated Generation

Other income and expenses were comparable at Non-rate-regulated Generation for the three months and nine months ended September 30, 2006, compared with the same periods in 2005.

Genco, CILCORP (Parent Company Only), EEI & CILCO (AERG)

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

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Interest

Ameren

Three months and nine months - Interest expense increased $12 million and $17 million primarily because of items noted below.

Variations in interest expense at Ameren’s, CILCORP’s and CILCO’s business segments for the three months and nine months ended September 30, 2006, compared with the same periods in 2005 were as follows:

Missouri Regulated

UE

Three months and nine months - Interest expense increased $6 million and $26 million, respectively, 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, partially resulting from the purchase of CTs in the first quarter of 2006.

Illinois Regulated

Interest expense was comparable at Illinois Regulated in the third quarter of this year compared to the third quarter of the prior year. Interest expense increased $6 million for the nine months ended September 30, 2006, compared with the same period in 2005, principally at IP.

CIPS & CILCO (Illinois Regulated)

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

IP

Three months - Interest expense was comparable between periods.

Nine months - Interest expense increased $5 million primarily because of the issuance of $75 million of senior secured notes in June 2006 along with increased money pool borrowings.

Non-rate-regulated Generation

Interest expense was comparable at Non-rate-regulated Generation in the third quarter of 2006 compared to the third quarter of the prior year. Interest expense decreased $14 million for the nine months ended September 30, 2006, compared with the same period in 2005, principally at Genco.

Genco

Three months - Interest expense was comparable as a reduction in interest expense of $4 million resulting from the maturity of $225 million of senior notes in November 2005 was offset by increased money pool borrowings.

Nine months - Interest expense decreased $12 million primarily because of the maturity of the $225 million senior notes.

CILCORP (Parent Company Only)

Three months - Interest expense was comparable between periods.

Nine months - Interest expense was comparable as a decrease of $3 million due to the repurchase of $85 million of 8.70% senior notes in 2005 was offset by increased money pool borrowings.

EEI & CILCO (AERG)

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

Income Taxes

Ameren

Three months and nine months - Effective tax rate increased in the third quarter of the current year primarily because of items discussed below. Effective tax rate for the nine months was comparable to the prior-year period.

Variations in effective tax rates at Ameren’s, CILCORP’s and CILCO’s business segments for the three months and nine months ended September 30, 2006, compared with the same periods in 2005 were as follows:

Missouri Regulated

UE

Three months and nine months - Effective tax rate increased over the prior year primarily because of non-deductible items for tax purposes and an increase in reserves for uncertain tax positions.

Illinois Regulated

Effective tax rate increased at Illinois Regulated for the three months and nine months ended September 30, 2006, compared with the same periods in 2005.

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CIPS

Three months - Effective tax rate increased primarily because of the settlement of uncertain tax positions in the current year.

Nine months - Effective tax rates were comparable between periods.

CILCO (Illinois Regulated)

Three months and nine months - Effective tax rate increased primarily because of a reduction in a permanent deduction allowed for tax purposes that was not allowed for book purposes.

IP

Three months and nine months - Effective tax rates were comparable between periods.

Non-rate-regulated Generation

Effective tax rate decreased at Non-rate-regulated Generation for the three months and nine months ended September 30, 2006, compared with the same periods in 2005.

Genco

Three months and nine months - Effective tax rate decreased primarily because of the settlement of uncertain tax positions in the current year.

CILCORP (Parent Company Only)

Three months and nine months - Effective tax rates were comparable between periods.

CILCO (AERG)

Three months and nine months - Effective tax rate decreased primarily because of the settlement of uncertain tax positions in the current year.

EEI

Three months and nine months - Effective tax rates were comparable between periods.

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, UE, CIPS, CILCO and IP. For operating cash flows, Genco principally relies on power 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 expect to sell power previously sold under contracts expiring at the end of 2006 to Marketing Company, which has sold power through the Illinois power procurement auction and is selling power through other contracts with wholesale and retail customers. The amount of power that Genco, AERG, EEI, Marketing Company and their 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 available cash, commercial paper and credit facilities to support normal operations and other temporary capital requirements. The use of operating cash flows and short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at September 30, 2006, for Ameren, UE, Genco, CILCORP, CILCO and IP. The Ameren Companies will reduce their short-term borrowings with cash from operations or discretionarily with long-term borrowings. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for a discussion of an Illinois legislative proposal to freeze electric rates for CIPS, CILCO and IP. If such legislation is enacted, CIPS, CILCORP, CILCO and IP will not have enough operating cash flow to support normal operations.

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The following table presents net cash provided by (used in) operating, investing and financing activities for the nine months ended September 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)	$	1,030	$	1,177	$	(147	)	$	(1,005	)	$	(736	)	$	(269	)	$	(87	)	$	(232	)	$	145
UE		593		712		(119	)		(584	)		(633	)		49			(27	)		(126	)		99
CIPS		127		148		(21	)		(47	)		(40	)		(7	)		(80	)		(110	)		30
Genco		46		205		(159	)		(80	)		54			(134	)		36			(260	)		296
CILCORP		99		77		22			(28	)		(87	)		59			(71	)		7			(78	)
CILCO		122		101		21			(70	)		(91	)		21			(52	)		(10	)		(42	)
IP		106		207		(101	)		(127	)		(4	)		(123	)		21			(203	)		224

(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 nine months of 2006, as compared with the first nine months of 2005, due primarily to decreases in electric and gas margins, and higher other operations and maintenance expenses as discussed in Results of Operations, and a $133 million increase in income tax payments. In addition, there was an increase in cash used during the first nine months of 2006 for payment of 2005 costs, including real estate and property taxes, and annual incentive compensation that was more than it was a year ago because of increased 2005 earnings relative to performance targets. 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 and third quarters as a result of increased volume and per unit prices of coal inventory purchases because of the coal supply issues experienced in the 2005 period and higher prices for coal in the 2006 period. Reducing these 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 storm costs as discussed in Results of Operations, and cash used for working capital changes that primarily included increased payments of 2005 costs in the first nine months of 2006 as compared with the year-ago period as discussed above for Ameren. Also contributing to the decrease were operations and maintenance expenditures of $14 million related to severe spring and summer storms, increased income tax payments of $27 million compared to the year-ago period, increased interest payments of $37 million, and $26 million paid (net of insurance recoveries to date) as a result of the breach at the Taum Sauk hydroelectric facility. See Note 8 - Commitments and Contingencies - Pumped-storage Hydroelectric Facility Breach for more information.

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. Income tax payments increased $45 million 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 nine months of 2006 decreased compared to the 2005 period primarily because of lower operating margins as discussed in Results of Operations. Income tax payments decreased in 2006 by $35 million compared to 2005, and interest payments were lower in the 2006 period due to decreased debt outstanding.

Cash from operating activities increased for CILCORP and CILCO in the nine months ended September 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 periods.  In addition, income tax payments decreased $15 million for CILCO and $25 million for CILCORP. Partially offsetting these positive effects on cash were higher other operations and maintenance expenses as discussed in Results of Operations.

IP’s cash from operations decreased in the nine months ended September 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 net income tax refunds of $19 million in the 2006 period as compared with $32 million in the year-ago period, and cash used during the first nine months of 2006 for payment of 2005 costs including real estate and property taxes, and annual incentive compensation that was

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more than it was a year ago due to increased 2005 earnings relative to performance targets.

Cash Flows from Investing Activities

Ameren’s increase in cash used in investing activities was primarily because of UE’s 2006 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 were comparable in the first nine months of 2006 as compared with the year-ago period. Emission allowance purchases decreased $54 million in the first nine months of 2006 compared to the first nine months of 2005, while emission allowance sales increased $8 million. The sale of leveraged lease investments provided an $11 million benefit to Ameren’s cash from investing activities as discussed below.

UE’s cash used in investing activities decreased in the first nine months of 2006, compared to the same period in 2005, principally because of $67 million received from CIPS on an intercompany note. The cash effect of the $292 million in CT purchases discussed above was more than the prior year effect of the $241 million purchase of two CTs from Genco and the purchase of CT equipment from Development Company for $25 million. Excluding these transactions, UE’s capital expenditures decreased $38 million, despite $22 million expended as a result of the severe spring and summer storms.

CIPS’ cash used in investing activities increased for the nine months ended September 30, 2006, compared with the 2005 period. Capital expenditures increased $22 million. 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. Reducing these negative effects was a $33 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. In addition, $6 million was expended as a result of severe summer storms. CIPS’ remaining 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 nine months of 2006 compared to a net source of cash during the same period in 2005. This was due primarily to the 2005 sale of two CTs to UE in 2005 for $241 million. Purchases of emission allowances were $45 million less in the first nine months of 2006 compared to the first nine months of 2005, and changes in net money pool advances resulted in a $65 million increase in cash in the 2006 period as compared to the 2005 period.

CILCORP’s and CILCO’s cash used in investing activities decreased in the nine months ended September 30, 2006, compared with the same period in 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 nine months ended September 30, 2006, from the sale of its remaining leveraged lease investments. Emission allowance purchases were $9 million less in the first nine months of 2006 compared to the first nine months of 2005.

IP’s cash used in investing activities increased in the first nine months of 2006 compared to the same period in 2005, primarily because of the absence in the 2006 period of proceeds received in the first nine months of 2005 from repayments received for advances made to the money pool in prior periods. In addition, capital expenditures increased $31 million over the year-ago period, which includes $12 million as a result of severe summer storms, and increased expenditures 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 used in financing activities decreased for Ameren in the first nine months of 2006 from the year-ago period. Positive effects on cash included a net increase of $118 million in net short-term debt proceeds in the 2006 period, compared to net repayments of $394 million of short-term debt in the 2005 period, less long-term debt redemptions,

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repurchases and maturities of $124 million, and borrowings on its $500 million credit facility of $40 million in 2006. Negative effects on cash included a $150 million reduction in long-term debt proceeds compared to the year-ago period, and a $352 million reduction in proceeds from the issuance of common stock. The reduction in common stock proceeds was due to the issuance of 7.4 million shares in the 2005 period related to the settlement of a stock purchase obligation in Ameren’s adjustable conversion-rate equity security units.

UE’s cash used in financing activities decreased for the first nine months of 2006, compared to the same period last year. Net changes in short-term debt resulted in a $128 million positive effect on cash in 2006, but a $375 million negative effect on cash in 2005. In addition, dividend payments decreased $55 million in the 2006 period compared to 2005. Partially offsetting these positive effects on cash were a $382 million reduction in long-term debt issuances, and a $79 million decrease in money pool borrowings. Net cash from financing activities was principally used to fund the CT acquisitions.

CIPS’ cash used in financing activities decreased for the nine months ended September 30, 2006, as compared with the 2005 period. Cash was positively affected by a $66 million decrease in money pool repayments in the 2006 period. A $29 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 2006 issuance of $61 million of long-term debt was principally 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 nine months of 2006, compared to a net use of cash for the same period last year. This is primarily because in 2005, Genco used the $241 million from the CT sale to UE to make principal payments on intercompany notes with CIPS and Ameren, and to reduce its money pool borrowings, and then make advances to the money pool. In addition, $150 million of capital contributions received in 2006 from Ameren benefited Genco’s financing cash flows. These capital contributions were made to reduce Genco’s short-term debt. Reducing these positive effects on cash was a $34 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. The proceeds of this debt were used to redeem $20 million of long-term debt and to reduce money pool borrowings. In addition, CILCO’s subsidiary AERG borrowed $40 million in 2006 under the $500 million credit facility. These benefits in the 2006 period were partially offset by the absence in 2006 of a $101 million capital contribution received in the 2005 period from Ameren, which was made to reduce CILCO’s short-term debt. In addition, in 2006, CILCORP used cash of $32 million for redemptions, repurchases and maturities of long-term debt as compared with $6 million in the 2005 period. CILCORP’s net repayments of $30 million on its note payable to Ameren reduced its financing cash flow by $58 million as compared with the year-ago period because the 2005 period included net 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 nine months ended September 30, 2006, as compared with the year-ago period, were increased common stock dividends of $20 million and $45 million at CILCORP and CILCO, respectively, in the 2006 period as compared with the 2005 period.

IP had a net source of cash from financing activities in the first nine months of 2006, compared to a net use of cash in the same period of the prior year. This was primarily because of lower redemptions and repurchases of long-term debt of $66 million. More debt was repaid in 2005 to improve IP’s credit profile. Another positive effect on cash from financing activities was the absence in the 2006 period of $60 million of common stock dividend payments made in the 2005 period. IP issued $75 million of long-term debt in 2006 as compared with no long-term debt proceeds in the year-ago period. The proceeds were used to reduce money pool borrowings.

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 - Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report.

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The following table presents the committed bank credit facilities of the Ameren Companies and AERG as of October 31, 2006:

Credit Facility	Expiration		Amount Committed		Amount Available
Ameren:(a)
Multiyear revolving(b)(c)		July 2010	$	1,150	$	995
CIPS, CILCORP, CILCO, IP and AERG:
Multiyear revolving(d)		January 2010		500		215

(a)   Ameren’s $350 million revolving credit facility was terminated on July 14, 2006. See further discussion in Note 3 - Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report.

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

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

(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. Effective September 8, 2006, CIPS, CILCO, and IP became authorized to borrow and obtain letters of credit for their benefit under this facility. See Note 3 - Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report for discussion of this 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 September 30, 2006, Ameren had

$34 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, 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 nine months ended September 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.

	Month Issued, Redeemed,		Nine Months
	Repurchased or Matured		2006		2005
Issuances
Long-term debt
UE:(a)
5.00% Senior secured notes due 2020		January	$	-	$	85
5.30% Senior secured notes due 2037		July		-		297
CIPS:(b)
6.70% Senior secured notes due 2036		June		61		-
CILCO:(b)
Borrowings from credit facility(c)		September		40		-
6.20% Senior secured notes due 2016		June		54		-
6.70% Senior secured notes due 2036		June		42		-
IP:(b)
6.25% Senior secured notes due 2016		June		75		-
Total Ameren long-term debt issuances			$	272	$	382

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	Month Issued, Redeemed,	Nine Months
	Repurchased or Matured		2006		2005
Common stock
Ameren:
7,402,320 Shares at $46.61(d)	May	$	-	$	345
DRPlus and 401(k)(e)	Various		78		85
Total common stock issuances		$	78	$	430
Total Ameren long-term debt and common stock issuances		$	350	$	812
Redemptions, Repurchases and Maturities
Long-term debt and preferred stock
Ameren:
Senior notes due 2007(f)	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
CILCO:
7.73% First mortgage bonds due 2025	July		20		-
5.85% Series preferred stock	July		1		1
IP:
6.75% Mortgage bonds due 2005	March		-		70
Notes payable to IP SPT
5.54% Series due 2007	Various		86		-
5.38% Series due 2005	Various		-		71
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities		$	139		263

(a)   Ameren’s and UE’s long-term debt increased $240 million as a result of the first quarter 2006 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)   On September 8, 2006, CIPS, CILCO and IP issued mortgage bonds in the amounts of $135 million, $150 million and $150 million, respectively to secure their obligations under the $500 million credit facility. See Note 3 - Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report.

(c)   Represents borrowings made by AERG under the $500 million credit facility discussed in Note 3 - Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report.

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

(e)   Includes issuances of common stock of 1.5 million shares during the nine months ended September 30, 2006, under DRPlus and 401(k) plans.

(f)   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 September 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 6.6 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 September 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 - Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report for a discussion of the covenants and provisions contained in our 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 September 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

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will continue to have access to the capital markets. However, events beyond our control, such as the extension of the electric rate freeze in Illinois for CIPS, CILCO and IP, may create uncertainty in the capital markets. Such events would likely increase our cost of capital and adversely affect our ability to access the capital markets. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report.

Dividends

Dividends paid by Ameren to shareholders during the first nine months of 2006 totaled $391 million, or $1.905 per share (2005 - $383 million or $1.905 per share).

CILCO paid preferred stock dividends of less than $1 million on October 2, 2006. IP paid preferred stock dividends of approximately $1 million on November 1, 2006. The next preferred dividends are payable on November 15, 2006, December 29, 2006, January 2, 2007, and February 1, 2007, for UE, CIPS, CILCO and IP, respectively.

See Note 3 - Credit Facilities 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 September 30, 2006, except as discussed below with respect to the $500 million credit facility, none of these circumstances existed at the other Ameren Companies and as a result, they were allowed to pay dividends.

On July 14, 2006, CIPS, CILCORP, CILCO, IP, and AERG entered into a new $500 million multiyear, senior secured credit facility. This facility limits CIPS, CILCORP, CILCO or IP to capital stock dividend payments of $10 million per year each if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have a below investment-grade senior unsecured credit rating as defined in the new $500 million 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. As of September 30, 2006, AERG failed to meet the debt-to-operating cash flow ratio test in the facility and, therefore is limited in its ability to pay dividends to a maximum of $10 million per fiscal year. The other borrowers are not currently limited in their dividend payments by this provision of the new credit facility. See Note 3 - Credit Facilities and Liquidity to our financial statements 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 nine months ended September 30, 2006 and 2005.  

	Nine Months
	2006		2005
UE	$	154	$	209
CIPS		50		21
Genco		93		59
CILCORP(a)		50		30
IP		-		60
Nonregistrants		44		4
Dividends paid by Ameren	$	391	$	383

(a)   CILCO paid dividends of $65 million and $20 million for the nine months ended September 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, and Other Obligations in Note 8 - Commitments and Contingencies under Part I, Item 1, of this report. 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 $3,986 million, $1,419 million, $484 million, $601 million, $624 million, $624 million and $615 million, respectively, as of September 30, 2006. Total other obligations at September 30, 2006, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $4,439 million, $1,673 million, $615 million, $601 million, $736 million, $736 million and $797 million, respectively.

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Credit Ratings

S&P

On October 5, 2006, S&P, in reaction to the intensified political discussion in Illinois regarding electric rate freeze extension legislation, downgraded the principal credit ratings of the Ameren Companies as presented in the following table:

	From	To
Ameren:
Corporate credit rating	BBB+	BBB
Unsecured debt	BBB	BBB-
Commercial paper	A-2	A-3
UE:
Corporate credit rating	BBB+	BBB
Secured debt	BBB+	BBB
Unsecured debt	BBB	BBB-
Preferred stock	BBB-	BB+
Commercial paper	A-2	A-3
Genco:
Corporate credit rating	BBB+	BBB
Unsecured debt	BBB+	BBB
CIPS:
Corporate credit rating	BBB+	BBB-
Secured debt	A-	BBB
Unsecured debt	BBB	BB+
Preferred stock	BBB-	BB
CILCORP:
Corporate credit rating	BBB+	BBB-
Unsecured debt	BBB	BB+
CILCO:
Corporate credit rating	BBB+	BBB-
Secured debt	A-	BBB
Preferred stock	BBB-	BB
IP:
Corporate credit rating	BBB+	BBB-
Secured debt	BBB+	BBB-
Preferred stock	BBB-	BB

All of the S&P credit ratings for the Ameren Companies remain on credit watch with negative implications. According to S&P, it will continue to lower the Ameren Companies credit ratings if, in its opinion, the likelihood of Illinois legislation extending the electric rate freeze increases and if the legislation is passed, they will lower ratings on CIPS, CILCO, CILCORP and IP into the “B” category - a deep junk credit rating category.

Moody’s

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
Issuer rating	A2	A3
Commercial paper	P-1	P-2
CIPS:
Secured debt	A3	Baa2
Unsecured debt and issuer rating	Baa1	Baa3
CILCORP:
Unsecured debt	Baa3	Ba1
CILCO:
Secured debt	A3	Baa1
Issuer rating	Baa1	Baa2

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.

Moody’s confirmed the credit ratings of Ameren and IP, and Genco was unaffected. 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.

·   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.

On October 10, 2006, Moody’s placed the long-term credit ratings of Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP under review for possible downgrade, and affirmed the commercial paper ratings of Ameren and UE. Moody’s had removed the review for possible downgrade as part of its July 2006 actions. According to Moody’s, the review for possible downgrade was reinstituted by concerns that the timely recovery of increased utility costs may be impaired by legislative action in Illinois, specifically the rate freeze legislation discussed in Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report. Moody’s stated that enactment of the rate freeze legislation in Illinois would be expected to result in a multi-notch downgrade of the ratings of CIPS, CILCORP, CILCO and IP to speculative (sub-investment) grade, reflecting the severe impact such action would have on the utilities’ cash flow and liquidity.  Moody's has also indicated that upon rate freeze legislation, or similar legislation that restricts the recovery of costs in a timely manner, passing the Illinois House of Representatives (even if prior to passage in the Illinois Senate or enactment into law), it may consider additional credit ratings downgrades with regard to one or more of the Ameren Companies.

Fitch

On October 10, 2006, Fitch placed the credit ratings of Ameren, CIPS, CILCORP, CILCO and IP on rating watch negative. The ratings of UE and Genco were affirmed and not affected by these rating actions. The negative rating watch resulted from the heightened political rhetoric surrounding

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future utility rates in Illinois and uncertainty related to recovery of CIPS’, CILCORP’s, CILCO’s and IP’s purchased power costs.

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital. It may also increase the cost of borrowing and fuel, power and gas supply, among other things, resulting in a negative impact on earnings. For example, if at September 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 or prepay for certain trade obligations amounting to $234 million, $21 million, $24 million, $10 million, $43 million, $43 million, or $123 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease depending upon the credit ratings of the borrower and suppliers may request prepayment for products and services. 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:

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 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 appeals. The power procurement auction was held at the beginning of September 2006. On September 14, 2006, the ICC determined that it would not investigate the results of the auction to procure power for fixed-price customers, which include the vast majority of electric customers of CIPS, CILCO and IP. On September 15, 2006, the independent auction manager (NERA Economic Consulting) declared a successful result in the auction for fixed-price customers. The auction clearing price was approximately $65 per megawatthour for the fixed-price residential and small commercial product and approximately $85 per megawatthour for large commercial and industrial customers. Marketing Company participated in the auction with power being acquired from Genco and AERG, subject to an auction rules limitation of providing no more than 35% of a utility’s load, and was awarded sales in the auction. As a result of the large commercial and industrial customers’ auction price, it is expected that nearly all of these customers will choose a different supplier.

·   Power supplied by Genco and AERG to CIPS and CILCO, respectively, has 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. In 2005, Genco sold 3.3 million net megawatthours of power in the interchange market at an average market price of $47 per megawatthour. Genco currently expects to generate approximately 17.5 million megawatthours of power in 2007. By 2007, only 5.2 million megawatthours of Genco’s power will be covered by wholesale and retail electric power supply agreements that were in effect in 2005. 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. 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. Market prices on power supply contracts entered into by Marketing Company with power being acquired from Genco and AERG for sales for 2007 and beyond may vary from the Illinois auction price based on the contract type, when the contracts were entered into, and load shape of customers served under those contracts, among other things.

·   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). Since most customers are currently taking service under a frozen bundled electric rate, which includes the cost of power, any delivery service revenue change may not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings when all customers transition to an electric delivery service rate effective January 2, 2007. 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

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electric delivery services for the Ameren Illinois utilities aggregating $120 million (CIPS - $1 million, CILCO - $30 million and IP - $89 million). In testimony, the Illinois attorney general accepted certain of the Ameren Illinois utilities’ positions increasing its estimated aggregate recommended revenue increase from $70 million to approximately $110 million (CIPS - $3 million decrease, CILCO - $29 million increase and IP - $84 million increase). Other parties also made recommendations in the cases. In October 2006, the administrative law judges issued a proposed order, which included a recommended revenue increase for electric delivery service of $147 million in the aggregate (CIPS - $8 million, CILCO - $29 million and IP - $110 million). The ICC has until November 25, 2006, to render a decision in these cases.

·   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. Electric rates are expected to rise as a result of increased cost of power to be purchased on behalf of Ameren Illinois utilities’ customers based on the results of the Illinois power procurement auction held in early September 2006 and potential increases resulting from delivery service cases that are currently pending before the ICC. CIPS and IP residential rates are expected to increase approximately 40 percent over present rates, and CILCO residential rates are expected to increase approximately 55 percent over present rates. The amount of the actual increase will depend on outcomes for CIPS’, CILCO’s and IP’s pending electric delivery services revenue increase requests to the ICC, among other things.

·   Due to the magnitude of these increases, certain Illinois legislators, the Illinois attorney general, the Illinois governor and other parties sought to block the power procurement auction and continue to challenge the auction and/or the recovery of costs for power supply resulting from the auction through rates to customers. CIPS, CILCO and IP have received favorable rulings from the ICC and the Circuit Court of Cook County, Illinois on opposition claims filed by the Illinois attorney general, CUB and ELPC. 

·   On October 2, 2006, Speaker of the Illinois House of Representatives, Michael Madigan, sent a letter to Illinois Governor Rod Blagojevich asking the Illinois governor to call a special session of the Illinois General Assembly for the purpose of considering this rate freeze legislation. In response, the Illinois governor sent a letter indicating that once the votes to pass the legislation were in place he would immediately call for a special session of the legislature. The governor’s letter further provided that in the event a consensus among members of the General Assembly is not reached in the near future, he would call a special session in that event as well. The governor’s letter stated he continued to support legislation extending a rate freeze and would like to sign it into law as soon as possible. On October 9, 2006, the Electric Utility Oversight Committee of the Illinois House of Representatives voted in favor of extending the electric rate freeze through 2010. The measure will need to be approved by the full Illinois House of Representatives and Illinois Senate and signed by the Illinois governor before it can become law.

·   CIPS, CILCO and IP believe the proposed electric rate freeze extension would have a material adverse effect on the results of operations, financial position and liquidity, including the financial insolvency of CIPS, CILCORP, CILCO and IP, significant job losses and, without governmental intervention, significant disruptions in electric and gas service. Since Ameren’s Illinois utilities own almost no generation, the companies must purchase power from the competitive market to provide customers’ energy needs. If the rate freeze were extended, the Ameren Illinois utilities estimate they would spend in the aggregate approximately $1 billion annually more for power than they could charge their customers (CIPS - $415 million, CILCO - $175 million, IP - $410 million). It is likely that the Ameren Illinois utilities’ credit ratings would be downgraded to deep junk status if rate freeze legislation was enacted. Moody's has also indicated that upon rate freeze legislation, or similar legislation that restricts the recovery of costs in a timely manner, passing the Illinois House of Representatives (even if prior to passage in the Illinois Senate or enactment into law), it may consider additional credit ratings downgrades with regard to one or more of the Ameren Companies.

·   With such credit ratings, CIPS, CILCORP, CILCO and IP would be faced with potential collateral and prepayment requirements and would quickly run out of cash and available credit and be unable to borrow. We believe this would lead to the Ameren Illinois utilities being financially insolvent by February 2007, or sooner. Any decision or action that impairs the ability of CIPS, CILCO, and IP to fully recover costs from their electric customers in a timely manner would result in material adverse consequences for Ameren, CIPS, CILCORP, CILCO, and IP. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their financial interests, including seeking the protection of the bankruptcy courts.

·   CIPS, CILCORP, 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 and small to mid-size commercial customers to address the significant increases in customer rates for the Ameren Illinois utilities beginning in 2007. The Ameren Illinois utilities believe that a rate increase phase-in plan would need to allow for deferral of a portion of the power procurement

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costs, with provision for full and timely recovery of all deferred costs in a manner that supports investment-grade credit ratings for CIPS, CILCO and IP. CIPS, CILCO and IP filed two proposed plans with the ICC to mitigate the impact of expected higher electric rates for residential customers. See Note 2 - Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a further discussion of the proposed plans. 

·   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.

·   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. These companies expect to hedge 85% to 90% of estimated available 2007 generation by the end of 2006.

·   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 2005, deliveries from the Powder River Basin were restricted due to derailments, and while coal inventories are currently adequate, deliveries are still below desired levels because of railroad capacity limitations. 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 approximately 20% in 2007. Ameren’s nuclear fuel costs are expected to rise over the next few years. In 2007, nuclear fuel costs are expected to increase by 13% to 18%. 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 of this report for information about the percentage of fuel and transportation requirements that are price-hedged for 2006 through 2010.

·   In Illinois, we will also experience higher year-over-year purchased power expenses as the amortization of certain favorable purchase accounting adjustments associated with the IP acquisition is completed.

·   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. Rules for the fuel and purchased power cost recovery mechanism were approved by the MoPSC on September 21, 2006, and are expected to be effective by the end of the year. 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. UE’s requests are subject to approval by the MoPSC.

·   In the fourth quarter of 2006, Ameren expects to continue selling excess emission allowances, but in 2007, Ameren expects to reduce levels of emission allowance sales in order to retain remaining allowances for future compliance needs.

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 facility will remain out of service until reviews by state authorities are concluded, further analyses are completed, and input

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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 at least all of 2008, if not longer. 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, including rebuilding the plant, will be covered by insurance. UE expects the total cost for damage and liabilities, excluding costs to rebuild the facility, resulting from the Taum Sauk incident to range from $70 million to $90 million. As of September 30, 2006, UE had paid $38 million and accrued a $32 million liability, while expensing $18 million, and recording a $40 million receivable due from insurance companies. As of September 30, 2006, UE has received $12 million 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 authorities. Until the reviews conducted by state 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 and is expected to last 30 to 35 days. 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, among other things.

·   Bad debts may increase due to rising electric rates.

·   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.

·   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 2018. 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. 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. 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, which will most likely be higher. Genco will no longer receive the margins on sales that it made, which 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. 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. 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 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,

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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

·   Ameren expects to complete the sale of some leveraged lease investments in 2006.

·   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 September 30, 2006:

	Interest Expense			Net Income(a)
Ameren	$	13		$	(8	)
UE		6			(4	)
CIPS		(b	)		(b	)
Genco		2			(1	)
CILCORP		3			(2	)
CILCO		1			(1	)
IP		4			(3	)

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

(b)   Less than $1 million.

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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 September 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 September 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 $35 million at September 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 plans to hedge for price risk up to 80% of its available megawatthours. Genco and AERG participated 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 their past practice. By December 31, 2006, Genco and AERG will seek to hedge for price risk 85% to 90% of estimated 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 the Ameren Illinois utilities’ proposed power procurement auction and the related tariffs for the period commencing January 2, 2007, including the retail rates by which power supply costs would be passed through to customers. The power procurement auction was held at the beginning of September 2006. Marketing Company was awarded sales in the auction. 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, purchased power and environmental 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.

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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	%		100	%		65	%
Coal transportation		100			95			60
Nuclear fuel		100			100			70
Natural gas for generation		100			26			2
Natural gas for distribution(a)		(a	)		46			10
UE:
Coal		100	%		100	%		61	%
Coal transportation		100			99			79
Nuclear fuel		100			100			70
Natural gas for generation		100			6			1
Natural gas for distribution(a)		(a	)		52			9
CIPS:
Natural gas for distribution(a)		(a	)		56	%		19	%
Purchased power(b)		100			100			47
Genco:
Coal		100	%		100	%		76	%
Coal transportation		100			95			40
Natural gas for generation		100			47			5
CILCORP/CILCO:
Coal		100	%		100	%		63	%
Coal transportation		100			69			44
Natural gas for distribution(a)		(a	)		44			9
Purchased power(b)		100			100			47
IP:
Natural gas for distribution(a)		(a	)		43	%		8	%
Purchased power(b)		90			100			47

(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)   Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than 1 megawatt of demand as part of the Illinois power procurement auction held in early September 2006. Excluded from the percent hedged amount is purchased power for fixed-price large commercial and industrial customers with 1 megawatt of demand or higher who have 30 to 50 days after the date the auction was declared successful (September 15, 2006) to elect not to receive power from CIPS, CILCO or IP. However, regardless of whether customers choose a third-party supplier, the purchased power needed to serve this load is 100% price-hedged through May 31, 2008 due to the Illinois auction. Also excluded from the percent hedged amount is purchased power to serve large service real-time pricing customers as the auction results have not been finalized for this customer class. See Note 2 - Rate and Regulatory Matters and Note 8 - Commitments and Contingencies 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	$	6	$	(4	)	$	11	$	(7	)
UE		4		(2	)		3		(2	)
Genco		1		(1	)		4		(3	)
CILCORP/CILCO		1		(b	)		2		(1	)

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

(b)   Less than $1 million.

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.

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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 nine months ended September 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 five years.

	Ameren(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Three Months
Fair value of contracts at beginning of period, net	$	43		$	(2	)	$	4		$	1		$	18		$	2
Contracts realized or otherwise settled during the period		(14	)		(1	)		(1	)		(1	)		(6	)		-
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		34			8			(1	)		2			(3	)		2
Fair value of contracts outstanding at end of period, net	$	63		$	5		$	2		$	2		$	9		$	4
Nine Months
Fair value of contracts at beginning of period, net	$	69		$	(5	)	$	12		$	-		$	50		$	(2	)
Contracts realized or otherwise settled during the period		(40	)		(5	)		(6	)		-			(15	)		(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		33			14			(4	)		2			(26	)		8
Fair value of contracts outstanding at end of period, net	$	63		$	5		$	2		$	2		$	9		$	4

(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 September 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.

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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 UE, CIPS, CILCO and IP are allowed to charge are currently the subject of rate case proceedings and potential legislative action. The outcome of these proceedings and potential legislative action is largely outside of our control. Should these events result in the inability of UE, CIPS, CILCO or IP to recover their respective costs, it could have a material adverse effect on our future results of operations, financial position or liquidity. In particular, we believe a proposed electric rate freeze extension in Illinois would lead to CIPS, CILCORP, CILCO and IP being financially insolvent by February 2007, or sooner.

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

Increased costs and investments, when combined with rate reductions and moratoriums, have caused decreased returns in Ameren’s utility businesses. Ameren expects many of its operating expenses will continue to rise and further expects to continue to make significant investment in its energy infrastructure, which are the principal factors underlying its pending rate increase requests with the MoPSC and the ICC. We cannot predict the outcome of these rate case proceedings or potential Illinois legislative action to extend the rate freeze. 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 material adverse effect on our results of operations, financial position or liquidity.

Illinois

Electric Delivery Rate Cases

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. 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). Since most customers are currently taking service under a frozen bundled electric rate, which includes the cost of power, any delivery service revenue change may not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings when all customers transition to an electric delivery service rate effective January 2, 2007. 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 testimony, the Illinois attorney general recommended an aggregate revenue increase of approximately $110 million (CIPS - $3 million decrease, CILCO - $29 million increase and IP - $84 million increase). Other parties also made recommendations in the cases. In October 2006, the administrative law judges issued a proposed order, which included a recommended revenue increase for electric delivery service of $147 million in the aggregate (CIPS - $8 million, CILCO - $29 million and IP - $110 million). The ICC has until November 25, 2006, to render a decision in these cases. Without appropriate and timely rate relief, any new energy infrastructure investment could result in increased financing requirements for CIPS, CILCO and IP. The lack of full and timely recovery of these costs could have a material adverse effect on CIPS’, CILCORP’s, CILCO’s and IP’s results of operations, financial position or liquidity.

Potential Extension of Illinois Electric Rate Freeze and Recovery of Post-2006 Power Supply Costs

Consistent with the Illinois Customer Choice Law that froze electric rates for CIPS, CILCO and IP through January 1, 2007, these companies entered into power supply contracts that expire on December 31, 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers

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through a power procurement auction and the related tariffs to collect these costs from customers for the period commencing January 2, 2007. This approval is subject to pending court appeals. In accordance with the January 2006 ICC order, a power procurement auction was held in September 2006. Subsequently, the ICC determined that it would not investigate the results of the auction to procure power for fixed-price customers, and the independent auction manager declared a successful result in the auction for these fixed-price customers, which include the vast majority of electric customers of CIPS, CILCO and IP. Certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties sought to block the power procurement auction and continue to challenge the auction and/or the recovery of costs for power supply resulting from the auction through rates to customers. In February 2006, legislation was introduced in the Illinois House of Representatives that would extend the electric rate freeze in Illinois through 2010. On October 2, 2006, Speaker of the Illinois House of Representatives, Michael Madigan, sent a letter to Illinois Governor Rod Blagojevich asking the Illinois governor to call a special session of the Illinois General Assembly for the purpose of considering this rate freeze legislation. In response, the Illinois governor sent a letter indicating that once the votes to pass the legislation were in place he would immediately call for a special session of the legislature. The governor’s letter further provided that in the event a consensus among members of the General Assembly is not reached in the near future, he would call a special session in that event as well. The governor’s letter stated he continued to support legislation extending the rate freeze and would like to sign it into law as soon as possible. On October 9, 2006, the Electric Utility Oversight Committee of the Illinois House of Representatives voted in favor of extending the electric rate freeze through 2010. The measure will need to be approved by the full Illinois House of Representatives and Illinois Senate, and signed by the Illinois governor before it can become law.

CIPS, CILCORP, CILCO and IP believe the proposed electric rate freeze legislation, if enacted, would have a material adverse effect on their results of operations, financial position and liquidity, including the financial insolvency of CIPS, CILCORP, CILCO and IP, as well as result in significant job losses and, without governmental intervention, significant disruptions in electric and gas service. Since Ameren’s Illinois utilities own almost no generation, the companies must purchase power from the competitive market to provide customers’ energy needs. If the rate freeze were extended, the Ameren Illinois utilities estimate they would spend in the aggregate approximately $1 billion annually more for power than they could charge their customers (CIPS - $415 million, CILCO - $175 million, IP - $410 million). The major credit rating agencies have stated that the Ameren Illinois utilities’ and CILCORP’s credit ratings would be downgraded to deep junk status if rate freeze extension legislation is enacted. Moody's has also indicated that upon rate freeze legislation, or similar legislation that restricts the recovery of costs in a timely manner, passing the Illinois House of Representatives (even if prior to passage in the Illinois Senate or enactment into law), it may consider additional credit ratings downgrades with regard to one or more of the Ameren Companies.With such credit ratings, we believe CIPS, CILCORP, CILCO and IP would be faced with potential collateral and prepayment requirements for products and services, such as power and natural gas, and would quickly run out of cash and available credit and be unable to borrow. We believe this would lead to the Ameren Illinois utilities and CILCORP being financially insolvent by February 2007, or sooner. In reaction to intensified political discussion in Illinois regarding electric rate freeze extension legislation, in October 2006, S&P downgraded the short- and long-term credit ratings of the Ameren Companies and kept the Ameren Companies on credit watch with negative implications; Moody’s placed the long-term debt ratings of the Ameren Companies under review for possible downgrade; and Fitch placed the ratings of Ameren, CIPS, CILCORP, CILCO and IP on rating watch negative.

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 significant increases in customer rates for the Ameren Illinois utilities beginning in 2007. The Ameren Illinois utilities 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 investment-grade credit ratings for CIPS, CILCO and IP. However, even a rate phase-in plan that does not allow for the full and timely recovery of our costs could have a material adverse effect on CIPS’, CILCORP’s, CILCO’s and IP’s results of operations, financial position or liquidity.

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. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their legal and financial interests, including seeking the protection of the bankruptcy courts. However, there can be no assurance that Ameren and the Ameren Illinois utilities will prevail over the stated opposition of certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other stakeholders, or that the legal and regulatory actions, strategies and

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alternatives that Ameren and the Ameren Illinois utilities are considering will be successful.

We are unable to predict the results of the court appeals of the ICC order approving CIPS’, CILCO’s and IP’s power procurement auction and the related tariffs, nor can we predict the actions the Illinois General Assembly and governor may take which may impact electric rates or the power procurement process for CIPS, CILCO and IP after the expiration of the current Illinois electric rate freeze on January 1, 2007, and power supply contracts on December 31, 2006. Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover purchased power costs from their electric customers in a timely manner would result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a significant drop in credit ratings to deep junk status, a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, significant risk of disruption in electric and gas service, significant job losses, and financial insolvency. In addition, Ameren, CILCORP and IP could be required to record a charge for goodwill impairment related to goodwill that was recorded when Ameren acquired these companies. As of September 30, 2006, Ameren, CILCORP and IP had $976 million, $575 million and $326 million, respectively, of goodwill on their balance sheets. Furthermore, if the Ameren Illinois utilities are unable to recover their costs from customers, the utilities could be required to cease applying SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”, which allows CIPS, CILCORP, CILCO and IP to defer certain costs pursuant to actions of rate regulators and to recover such costs in rates charged to customers. This would result in the elimination of all regulatory assets recorded by CIPS, CILCORP, CILCO and IP on their balance sheets and a one-time extraordinary charge on their statements of income that could be material. As of September 30, 2006, CIPS, CILCORP, CILCO and IP had $35 million, $12 million, $12 million and $197 million, respectively, recorded as regulatory assets on their balance sheets.

Missouri

With the expiration of multi-year electric and gas rate moratoriums, effective July 1, 2006, UE filed requests with the MoPSC in July 2006 for an increase in electric rates of

$361 million and for an increase 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 electric and gas rate adjustments. A decision from the MoPSC is expected no later than June 2007.

UE does not currently have a rate adjustment clause in Missouri for its electric operations that would allow it to recover the costs for purchased power, increased fuel or infrastructure investment costs from customers. Therefore, insofar as UE has not hedged its fuel and power costs, UE is exposed to changes in fuel and power prices to the extent they exceed the costs embedded in current rates. In its Missouri electric rate case filed in July 2006, UE requested a fuel and purchased power cost recovery mechanism, which is still subject to MoPSC approval. UE also requested an environmental cost recovery mechanism as part of its current Missouri electric rate case, but rules have not been established for such a mechanism. Without appropriate and timely rate relief, any new energy infrastructure investment could result in increased financing requirements for UE. The lack of timely recovery of these costs could have a material adverse effect on UE’s results of operations, financial position or liquidity.

If the Illinois electric rate freeze is extended or the ability of CIPS, CILCO and IP to recover post-2006 power supply costs or increase electric delivery service rates that are the subject of pending rate cases is otherwise impaired, there may be a material adverse effect on Ameren, UE and Genco in addition to the Ameren Illinois utilities and CILCORP.

We believe the proposed rate freeze extension in Illinois, if enacted, would lead to CIPS, CILCORP, CILCO and IP being financially insolvent by February 2007, or sooner. Although the Ameren Companies are separate, independent legal entities with separate businesses, assets and liabilities, there is a risk that the financial insolvency of CIPS, CILCORP, CILCO and IP could have a materially adverse effect on Ameren, UE and Genco. In the event of an extension of the electric rate freeze in Illinois for CIPS, CILCO and IP, or subsequent financial insolvency of these companies, such events might increase Ameren’s, UE’s and Genco’s cost of capital or adversely affect the ability of these companies to access the capital markets, particularly during times of uncertainty in the capital markets, which could negatively affect their ability to maintain and expand their businesses. Moody’s, S&P and Fitch have each indicated that they would lower the credit ratings for CIPS, CILCORP, CILCO and IP to deep junk status if the electric rate freeze was extended reflecting the material impact such action would have on the cash flow and liquidity of these companies. It is possible that the rating agencies could decide to lower the credit ratings of Ameren, UE or Genco at the same time. Any adverse change in the ratings of Ameren, UE or Genco could also increase the cost of borrowing under credit facilities and suppliers may request prepayment for products and services (such as fuel, power and gas) or the posting of collateral.

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Commitments or amounts due from CIPS, CILCORP, CILCO and IP to Ameren, UE, and Genco may be unfulfilled or unpaid in the event of financial insolvency of these companies. In connection with the recent Illinois power procurement auction, Marketing Company agreed to sell power to CIPS, CILCO and IP that is expected to be supplied under contracts from Genco and AERG. In the event of the insolvency of CIPS, CILCORP, CILCO and IP, Genco, AERG or Marketing Company may not be able to recover the cost of power delivered to CIPS, CILCO and IP but not paid for prior to insolvency. Marketing Company’s commitments to sell power to CIPS, CILCO, IP and other unaffiliated parties also rely, in part, on power supplied by AERG. In the event of financial insolvency, AERG may not be able to deliver power it has committed to sell to Marketing Company potentially requiring Marketing Company to acquire power to meet its commitments at a higher cost.

In addition, dividends on Ameren’s common stock and the payment of Ameren’s other obligations, including its debt, depend on distributions made to it by its subsidiaries. In the event that CIPS, CILCORP, CILCO and IP become insolvent, they will not be able to make distributions to Ameren. As a result, the board of directors of Ameren may decide to rely more heavily on UE and Ameren’s unregulated operations to support dividends on Ameren’s common stock, or reduce or eliminate the payment of dividends. Moreover, the absence of distributions from the Illinois utilities and CILCORP could force Ameren to use other available sources of liquidity to service its debt obligations.

We cannot determine at this time whether the proposed rate freeze extension in Illinois that would lead to CIPS, CILCORP, CILCO and IP being financially insolvent by February 2007, or sooner, will occur. We also cannot determine what the resulting effect would be on Ameren, UE and Genco. However, the financial insolvency of CIPS, CILCO and IP could have a material adverse effect on the results of operations, financial position or liquidity of Ameren, UE and Genco.

Our counterparties may not meet their obligations to us.

We are exposed to the risk that counterparties to various arrangements (including our affiliates) who owe us money, energy, coal or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to replace or to sell the underlying commitment at then-current market prices. In such event, we might incur losses or our results of operations, financial position or liquidity could otherwise be adversely affected.

In connection with the expiration of existing power supply agreements at the end of 2006, the ICC approved a framework for electric utilities in Illinois, including CIPS, CILCO and IP, to procure power for use by their customers in 2007 through a power procurement auction and related tariffs, including the retail rates by which power supply costs would be passed through to customers. Commencing in 2007, Genco and AERG will be selling power previously sold under expiring contracts to Marketing Company, which sold power through the Illinois power procurement auction to CIPS, CILCO and IP and is selling power through other contracts with wholesale and retail customers. If the attempts by certain Illinois legislators, the Illinois attorney general, the Illinois governor and other parties to block the ability of CIPS, CILCO and IP to recover post-2006 power supply costs are successful, thereby triggering the financial insolvency of CIPS, CIILCORP, CILCO, and IP, Genco, AERG and Marketing Company may not be able to recover payment for power delivered to CIPS, CILCO and IP pursuant to the Illinois power procurement auction. An inability to recover such payments could have a material adverse effect on the results of operations, financial position, or liquidity of Ameren, Genco, AERG, and Marketing Company. In the event of the subsequent termination of the power supply contracts between Marketing Company and CIPS, CILCO and IP, Marketing Company would need to resell at then-current market prices the power previously committed to CIPS, CILCO and IP. We cannot predict whether there would be buyers for Marketing Company’s power or what the market prices will be at the time of any such sales.

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

The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:

Period	(a) Total Number of Shares (or Units) Purchased(a)		(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1 - July 31, 2006		1,950	$	50.84		-		-
August 1 - August 31, 2006		3,800		52.78		-		-
September 1 - September 30, 2006		-		-		-		-
Total		5,750	$	52.12		-		-

(a)   These 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.

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

Period	(a) Total Number of Shares (or Units) Purchased(a)			(b) Average Price Paid per Share (or Unit)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1 - July 31, 2006		11,000	$	100.00	-	-
August 1 - August 31, 2006		-		-	-	-
September 1 - September 30, 2006		-		-	-	-
Total		11,000	$	100.00	-	-

(a)   CILCO redeemed these shares of its 5.85% Class A preferred stock to satisfy the mandatory sinking fund redemption requirement for this series of preferred stock for 2006. CILCO does not have any publicly announced equity securities repurchase plans or programs.

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

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
Instruments Defining Rights of Security Holders
*4.1	CILCO	Registration Rights Agreement, dated as of June 14, 2006, among CILCO, Citigroup Global Markets, Inc. and Goldman, Sachs & Co., as representatives of the Initial Purchasers (as defined therein) (incorporated by reference to Exhibit 4(d) to CILCO’s Form S-4, File No. 333-137449)
*4.2	IP	Registration Rights Agreement, dated as of June 14, 2006, among IP, Goldman, Sachs & Co. and Lehman Brothers, Inc., as representatives of the Initial Purchasers (as defined therein) (incorporated by reference to Exhibit 4(d) to IP’s Form S-4, File No. 333-137448)
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

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Exhibit Designation	Registrant(s)	Nature of Exhibit
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
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

* Incorporated by reference herein as indicated.

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SIGNATURES

Pursuant to the requirements of the Exchange Act, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.

AMEREN CORPORATION

(Registrant)

          /s/ Martin J. Lyons              

Martin J. Lyons

Vice President and Controller

(Principal Accounting Officer)

UNION ELECTRIC COMPANY

(Registrant)

          /s/ Martin J. Lyons               

Martin J. Lyons

Vice President and Controller

(Principal Accounting Officer)

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

(Registrant)

          /s/ Martin J. Lyons               

Martin J. Lyons

Vice President and Controller

(Principal Accounting Officer)

AMEREN ENERGY GENERATING COMPANY

(Registrant)

          /s/ Martin J. Lyons               

Martin J. Lyons

Vice President and Controller

(Principal Accounting Officer)

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CILCORP INC.

(Registrant)

           /s/ Martin J. Lyons              

Martin J. Lyons

Vice President and Controller

(Principal Accounting Officer)

 CENTRAL ILLINOIS LIGHT COMPANY

(Registrant)

           /s/ Martin J. Lyons             

Martin J. Lyons

Vice President and Controller

(Principal Accounting Officer)

 ILLINOIS POWER COMPANY

(Registrant)

           /s/ Martin J. Lyons             

Martin J. Lyons

Vice President and Controller

(Principal Accounting Officer)

Date: November 9, 2006

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