Ameren Illinois Co - Quarter Report: 2007 September (Form 10-Q)

ameren10q09302007.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

of the Securities Exchange Act of 1934

for the Quarterly Period Ended September 30, 2007

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

of the Securities Exchange Act of 1934

for the transition period from __ to __.

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

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

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

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

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

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

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

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

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

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, 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, 2007, was as follows:

Ameren Corporation	Common stock, $.01 par value per share – 208,009,159

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 .........................................................................................................................................................	83
Item 4. Controls and Procedures ........................................................................................................................................................................................................................	87

PART II Other Information

Item 1. Legal Proceedings ..................................................................................................................................................................................................................................	87
Item 1A.Risk Factors ..............................................................................................................................................................................................................................................	88
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds .........................................................................................................................................................	91
Item 6. Exhibits ......................................................................................................................................................................................................................................................	91

Signatures ................................................................................................................................................................................................................................................................	93

This Form 10-Q contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions. Forward-looking statements should be read with the cautionary statements and important factors included on page 6 of this Form 10-Q under the heading “Forward-looking Statements.”

GLOSSARY OF TERMS AND ABBREVIATIONS

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

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

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

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

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

Ameren Energy – Ameren Energy, Inc., an Ameren Corporation subsidiary that is a power marketing and risk management agent for UE.

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

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

ARO– Asset retirement obligations.

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

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

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

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

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

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

CUB – Citizens Utility Board.

Development Company – Ameren Energy Development Company, which is a Resources Company subsidiary, and parent of Genco, Marketing Company and AFS.

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

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

Dynegy – Dynegy Inc.

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

Form 10-K – The combined Annual Report on Form 10-K for the year ended December 31, 2006, filed by the Ameren Companies with the SEC.

FSP– FASB Staff Position, which provides application guidance on FASB literature.

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

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 the rate-regulated operations of CIPS, CILCO and IP.

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

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

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

IP – Illinois Power Company, an Ameren Corporation subsidiary. IP operates a rate-regulated electric and natural

gas transmission and distribution business in Illinois as AmerenIP.

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

IP LLC– Illinois Power Securitization Limited Liability Company, which is a special-purpose Delaware limited-liability company. Under FIN 46R, Consolidation of Variable-interest Entities, IP LLC was no longer consolidated within IP’s financial statements as of December 31, 2003.

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

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

Megawatthour – One thousand kilowatthours.

MGP – Manufactured gas plant.

MISO – Midwest Independent Transmission System Operator, Inc.

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

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 for 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.

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

NYMEX – New York Mercantile Exchange.

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

Off-system– Revenues from non-native load sales.

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

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, enacted as part of the Energy Policy Act of 2005, effective February 8, 2006.

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

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

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

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

SO₂– Sulfur dioxide.

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

TVA– Tennessee Valley Authority, a public power authority.

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

_________________________________________________

FORWARD-LOOKING STATEMENTS

Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are

based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:

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

·	uncertainty as to the effect of implementation of the Illinois electric settlement agreement on Ameren, the Ameren Illinois Utilities, Genco and AERG, including implementation of the new power procurement process in Illinois for 2008 and 2009;

·	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 occurred when the electric rate freeze and power supply contracts expired in Illinois at the end of 2006;

·	the effects of participation in the MISO;

the 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 the plant’s future operation;

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

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

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

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

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

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

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

·	legal and administrative proceedings; and

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

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

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Operating Revenues:
Electric	$	1,872		$	1,767		$	4,844		$	4,356
Gas		125			143			895			904
Total operating revenues		1,997			1,910			5,739			5,260

Operating Expenses:
Fuel		338			277			864			776
Purchased power		419			346			1,106			896
Gas purchased for resale		68			84			622			641
Other operations and maintenance		427			395			1,249			1,141
Depreciation and amortization		169			162			514			485
Taxes other than income taxes		97			99			295			302
Total operating expenses		1,518			1,363			4,650			4,241

Operating Income		479			547			1,089			1,019

Other Income and Expenses:
Miscellaneous income		20			12			54			29
Miscellaneous expense		(6	)		(3	)		(10	)		(4	)
Total other income		14			9			44			25

Interest Charges		110			89			316			254

Income Before Income Taxes, Minority Interest
and Preferred Dividends of Subsidiaries		383			467			817			790

Income Taxes		130			161			279			273
Income Before Minority Interest and Preferred
Dividends of Subsidiaries		253			306			538			517

Minority Interest and Preferred Dividends of Subsidiaries		9			13			28			31
Net Income	$	244		$	293		$	510		$	486

Earnings per Common Share – Basic and Diluted	$	1.18		$	1.42		$	2.46		$	2.37

Dividends per Common Share	$	0.635		$	0.635		$	1.905		$	1.905
Average Common Shares Outstanding		207.6			205.9			207.1			205.4

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

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

	September 30,		December 31,
	2007		2006
ASSETS
Current Assets:
Cash and cash equivalents	$	170	$	137
Accounts receivable – trade (less allowance for doubtful
accounts of $26 and $11, respectively)		691		418
Unbilled revenue		263		309
Miscellaneous accounts and notes receivable		258		160
Materials and supplies		757		647
Other current assets		202		203
Total current assets		2,341		1,874
Property and Plant, Net		14,729		14,286
Investments and Other Assets:
Nuclear decommissioning trust fund		301		285
Goodwill		831		831
Intangible assets		197		217
Other assets		683		654
Regulatory assets		1,323		1,431
Total investments and other assets		3,335		3,418
TOTAL ASSETS	$	20,405	$	19,578

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	203	$	456
Short-term debt		1,202		612
Accounts and wages payable		415		671
Taxes accrued		136		58
Other current liabilities		548		406
Total current liabilities		2,504		2,203
Long-term Debt, Net		5,486		5,285
Preferred Stock of Subsidiary Subject to Mandatory Redemption		16		17
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,055		2,144
Accumulated deferred investment tax credits		111		118
Regulatory liabilities		1,241		1,234
Asset retirement obligations		571		549
Accrued pension and other postretirement benefits		1,058		1,065
Other deferred credits and liabilities		392		169
Total deferred credits and other liabilities		5,428		5,279
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption		195		195
Minority Interest in Consolidated Subsidiaries		20		16
Commitments and Contingencies (Notes 2, 8, and 9)
Stockholders' Equity:
Common stock, $.01 par value, 400.0 shares authorized –
shares outstanding of 208.0 and 206.6, respectively		2		2
Other paid-in capital, principally premium on common stock		4,579		4,495
Retained earnings		2,134		2,024
Accumulated other comprehensive income		41		62
Total stockholders’ equity		6,756		6,583
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	20,405	$	19,578

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

AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited) (In millions)

	Nine Months Ended
	September 30,
	2007			2006
Cash Flows From Operating Activities:
Net income	$	510		$	486
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sales of emission allowances		(7	)		(25	)
Depreciation and amortization		537			507
Amortization of nuclear fuel		26			26
Amortization of debt issuance costs and premium/discounts		14			12
Deferred income taxes and investment tax credits, net		18			7
Loss on sale of noncore properties		-			4
Minority interest		20			23
Other		10			17
Changes in assets and liabilities:
Receivables		(320	)		157
Materials and supplies		(110	)		(136	)
Accounts and wages payable		(113	)		(260	)
Taxes accrued		75			148
Assets, other		(20	)		(87	)
Liabilities, other		193			101
Pension and other postretirement benefit obligations		87			89
Net cash provided by operating activities		920			1,069

Cash Flows From Investing Activities:
Capital expenditures		(1,035	)		(693	)
CT acquisitions		-			(292	)
Nuclear fuel expenditures		(39	)		(37	)
Proceeds from sale of noncore properties		-			11
Purchases of securities – nuclear decommissioning trust fund		(110	)		(78	)
Sales of securities – nuclear decommissioning trust fund		98			68
Purchases of emission allowances		(12	)		(38	)
Sales of emission allowances		5			12
Other		-			3
Net cash used in investing activities		(1,093	)		(1,044	)

Cash Flows From Financing Activities:
Dividends on common stock		(395	)		(391	)
Capital issuance costs		(3	)		(4	)
Short-term debt, net		590			158
Dividends paid to minority interest		(16	)		(21	)
Redemptions, repurchases, and maturities:
Long-term debt		(465	)		(138	)
Preferred stock		(1	)		(1	)
Issuances:
Common stock		71			78
Long-term debt		425			232
Net cash provided by (used in) financing activities		206			(87	)
Net change in cash and cash equivalents		33			(62	)
Cash and cash equivalents at beginning of year		137			96
Cash and cash equivalents at end of period	$	170		$	34

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

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Operating Revenues:
Electric - excluding off-system	$	835		$	746		$	1,865		$	1,759
Electric - off-system		92			90			303			331
Gas		18			20			123			111
Other		-			1			1			2
Total operating revenues		945			857			2,292			2,203

Operating Expenses:
Fuel		179			150			447			399
Purchased power		71			64			140			199
Gas purchased for resale		9			10			73			66
Other operations and maintenance		218			214			667			581
Depreciation and amortization		81			82			252			243
Taxes other than income taxes		70			66			187			184
Total operating expenses		628			586			1,766			1,672

Operating Income		317			271			526			531

Other Income and Expenses:
Miscellaneous income		9			9			28			22
Miscellaneous expense		(5	)		(3	)		(9	)		(7	)
Total other income		4			6			19			15

Interest Charges		49			42			146			123

Income Before Income Taxes and Equity
in Income of Unconsolidated Investment		272			235			399			423

Income Taxes		93			92			132			161

Income Before Equity in Income
of Unconsolidated Investment		179			143			267			262

Equity in Income of Unconsolidated Investment,
Net of Taxes		14			23			40			47

Net Income		193			166			307			309

Preferred Stock Dividends		1			1			4			4
Net Income Available to Common Stockholder	$	192		$	165		$	303		$	305

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

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

	September 30,		December 31,
	2007		2006
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	1
Accounts receivable – trade (less allowance for doubtful
accounts of $6 and $6, respectively)		242		145
Unbilled revenue		127		120
Miscellaneous accounts and notes receivable		207		128
Advances to money pool		13		18
Accounts receivable – affiliates		32		33
Materials and supplies		285		236
Other current assets		58		45
Total current assets		964		726
Property and Plant, Net		8,078		7,882
Investments and Other Assets:
Nuclear decommissioning trust fund		301		285
Intangible assets		60		58
Other assets		476		526
Regulatory assets		784		810
Total investments and other assets		1,621		1,679
TOTAL ASSETS	$	10,663	$	10,287

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	152	$	5
Short-term debt		92		234
Intercompany note payable – Ameren		57		77
Accounts and wages payable		172		313
Accounts payable – affiliates		143		185
Taxes accrued		206		66
Other current liabilities		226		191
Total current liabilities		1,048		1,071
Long-term Debt, Net		3,212		2,934
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,279		1,293
Accumulated deferred investment tax credits		86		89
Regulatory liabilities		850		827
Asset retirement obligations		511		491
Accrued pension and other postretirement benefits		375		374
Other deferred credits and liabilities		83		55
Total deferred credits and other liabilities		3,184		3,129
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		744		739
Retained earnings		1,843		1,783
Accumulated other comprehensive income		8		7
Total stockholders' equity		3,219		3,153
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	10,663	$	10,287

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

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

	Nine Months Ended
	September 30,
	2007			2006
Cash Flows From Operating Activities:
Net income	$	307		$	309
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sales of emission allowances		(5	)		(2	)
Depreciation and amortization		252			243
Amortization of nuclear fuel		26			26
Amortization of debt issuance costs and premium/discounts		4			4
Deferred income taxes and investment tax credits, net		19			(10	)
Other		1			-
Changes in assets and liabilities:
Receivables		(182	)		(34	)
Materials and supplies		(49	)		(35	)
Accounts and wages payable		(97	)		(110	)
Taxes accrued		140			174
Assets, other		60			(42	)
Liabilities, other		16			62
Pension and other postretirement obligations		27			35
Net cash provided by operating activities		519			620

Cash Flows From Investing Activities:
Capital expenditures		(493	)		(341	)
CT acquisitions		-			(292	)
Nuclear fuel expenditures		(39	)		(37	)
Changes in money pool advances		5			-
Proceeds from intercompany note receivable – CIPS		-			67
Purchases of securities – nuclear decommissioning trust fund		(110	)		(78	)
Sales of securities – nuclear decommissioning trust fund		98			68
Sales of emission allowances		4			2
Net cash used in investing activities		(535	)		(611	)

Cash Flows From Financing Activities:
Dividends on common stock		(246	)		(154	)
Dividends on preferred stock		(4	)		(4	)
Capital issuance costs		(3	)		-
Short-term debt, net		(142	)		128
Intercompany note payable – Ameren, net		(20	)		-
Issuances of long-term debt		425			-
Capital contribution from parent		5			3
Net cash provided by (used in) financing activities		15			(27	)
Net change in cash and cash equivalents		(1	)		(18	)
Cash and cash equivalents at beginning of year		1			20
Cash and cash equivalents at end of period	$	-		$	2

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

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007			2006		2007			2006
Operating Revenues:
Electric	$	201		$	228	$	605		$	569
Gas		22			23		159			150
Other		1			3		3			4
Total operating revenues		224			254		767			723

Operating Expenses:
Purchased power		142			125		416			355
Gas purchased for resale		12			11		107			99
Other operations and maintenance		40			41		124			117
Depreciation and amortization		16			16		49			47
Taxes other than income taxes		6			9		24			30
Total operating expenses		216			202		720			648

Operating Income		8			52		47			75

Other Income and Expenses:
Miscellaneous income		5			4		13			13
Miscellaneous expense		(1	)		-		(2	)		(1	)
Total other income		4			4		11			12

Interest Charges		10			8		28			23

Income Before Income Taxes		2			48		30			64

Income Taxes		1			19		11			21

Net Income		1			29		19			43

Preferred Stock Dividends		1			1		2			2

Net Income Available to Common Stockholder	$	-		$	28	$	17		$	41

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

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

	September 30,		December 31,
	2007		2006
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	6
Accounts receivable – trade (less allowance for doubtful
accounts of $6 and $2, respectively)		66		55
Unbilled revenue		36		43
Accounts receivable – affiliates		50		10
Current portion of intercompany note receivable – Genco		39		37
Current portion of intercompany tax receivable – Genco		9		9
Advances to money pool		95		1
Materials and supplies		78		71
Other current assets		53		46
Total current assets		427		278
Property and Plant, Net		1,167		1,155
Investments and Other Assets:
Intercompany note receivable – Genco		87		126
Intercompany tax receivable – Genco		107		115
Other assets		32		27
Regulatory assets		132		146
Total investments and other assets		358		414
TOTAL ASSETS	$	1,952	$	1,847

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Short-term debt	$	135	$	35
Accounts and wages payable		36		36
Accounts payable – affiliates		51		81
Taxes accrued		4		10
Other current liabilities		71		36
Total current liabilities		297		198
Long-term Debt, Net		471		471
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net		274		297
Regulatory liabilities		229		224
Accrued pension and other postretirement benefits		83		90
Other deferred credits and liabilities		38		24
Total deferred credits and other liabilities		624		635
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		191		190
Preferred stock not subject to mandatory redemption		50		50
Retained earnings		319		302
Accumulated other comprehensive income		-		1
Total stockholders' equity		560		543
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,952	$	1,847

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

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

	Nine Months Ended
	September 30,
	2007			2006
Cash Flows From Operating Activities:
Net income	$	19		$	43
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		49			47
Amortization of debt issuance costs and premium/discounts		1			1
Deferred income taxes and investment tax credits, net		(13	)		(27	)
Other		-			1
Changes in assets and liabilities:
Receivables		(36	)		60
Materials and supplies		(7	)		(7	)
Accounts and wages payable		(27	)		(5	)
Taxes accrued		(6	)		8
Assets, other		(8	)		-
Liabilities, other		34			-
Pension and other postretirement obligations		5			6
Net cash provided by operating activities		11			127

Cash Flows From Investing Activities:
Capital expenditures		(58	)		(63	)
Proceeds from intercompany note receivable – Genco		37			34
Changes in money pool advances		(94	)		(18	)
Net cash used in investing activities		(115	)		(47	)

Cash Flows From Financing Activities:
Dividends on common stock		-			(50	)
Dividends on preferred stock		(2	)		(2	)
Capital issuance costs		-			(1	)
Short-term debt, net		100			-
Changes in money pool borrowings		-			(2	)
Redemptions, repurchases, and maturities:
Long-term debt		-			(20	)
Intercompany note payable – UE		-			(67	)
Issuances of long-term debt		-			61
Capital contribution from parent		1			1
Net cash provided by (used in) financing activities		99			(80	)
Net change in cash and cash equivalents		(5	)		-
Cash and cash equivalents at beginning of year		6			-
Cash and cash equivalents at end of period	$	1		$	-

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

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Operating Revenues	$	221	$	259	$	649	$	744

Operating Expenses:
Fuel		102		86		257		216
Purchased power		1		84		23		269
Other operations and maintenance		39		34		122		113
Depreciation and amortization		18		18		54		53
Taxes other than income taxes		5		3		15		14
Total operating expenses		165		225		471		665

Operating Income		56		34		178		79

Miscellaneous Income		-		-		1		-

Interest Charges		15		15		43		45

Income Before Income Taxes		41		19		136		34

Income Taxes		16		-		52		7

Net Income	$	25	$	19	$	84	$	27

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

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

	September 30,			December 31,
	2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	2		$	1
Accounts receivable – affiliates		114			96
Accounts receivable – trade		15			19
Materials and supplies		97			96
Other current assets		17			5
Total current assets		245			217
Property and Plant, Net		1,594			1,539
Intangible Assets		57			74
Other Assets		18			20
TOTAL ASSETS	$	1,914		$	1,850

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Short-term debt	$	75		$	-
Current portion of intercompany note payable – CIPS		39			37
Borrowings from money pool		108			123
Accounts and wages payable		36			52
Accounts payable – affiliates		49			66
Current portion of intercompany tax payable – CIPS		9			9
Taxes accrued		15			22
Other current liabilities		31			22
Total current liabilities		362			331
Long-term Debt, Net		474			474
Intercompany Note Payable – CIPS		87			126
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		153			165
Accumulated deferred investment tax credits		8			9
Intercompany tax payable – CIPS		107			115
Asset retirement obligations		31			31
Accrued pension and other postretirement benefits		41			34
Other deferred credits and liabilities		45			2
Total deferred credits and other liabilities		385			356
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		503			428
Retained earnings		127			156
Accumulated other comprehensive loss		(24	)		(21	)
Total stockholder's equity		606			563
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	1,914		$	1,850

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

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

	Nine Months Ended
	September 30,
	2007			2006
Cash Flows From Operating Activities:
Net income	$	84		$	27
Adjustments to reconcile net income to net cash
provided by operating activities:
Gain on sales of emission allowances		(1	)		(1	)
Depreciation and amortization		79			78
Deferred income taxes and investment tax credits, net		28			7
Other		(1	)		1
Changes in assets and liabilities:
Receivables		(14	)		(30	)
Materials and supplies		(1	)		(30	)
Accounts and wages payable		(12	)		16
Taxes accrued, net		(7	)		(9	)
Assets, other		(12	)		(16	)
Liabilities, other		5			2
Pension and other postretirement obligations		5			4
Net cash provided by operating activities		153			49

Cash Flows From Investing Activities:
Capital expenditures		(131	)		(58	)
Purchases of emission allowances		(7	)		(26	)
Sales of emission allowances		1			1
Net cash used in investing activities		(137	)		(83	)

Cash Flows From Financing Activities:
Dividends on common stock		(113	)		(93	)
Short-term debt, net		75			-
Changes in money pool borrowings		(15	)		13
Intercompany notes payable – CIPS		(37	)		(34	)
Capital contribution from parent		75			150
Net cash provided by (used in) financing activities		(15	)		36
Net change in cash and cash equivalents		1			2
Cash and cash equivalents at beginning of year		1			-
Cash and cash equivalents at end of period	$	2		$	2

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

CILCORP INC.
CONSOLIDATED STATEMENT OF INCOME
(Unaudited) (In millions)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Operating Revenues:
Electric	$	170		$	119		$	507		$	309
Gas		36			38			231			236
Other		-			1			1			1
Total operating revenues		206			158			739			546

Operating Expenses:
Fuel		21			26			58			79
Purchased power		74			17			206			25
Gas purchased for resale		21			24			166			175
Other operations and maintenance		48			41			135			134
Depreciation and amortization		20			18			58			55
Taxes other than income taxes		3			5			17			18
Total operating expenses		187			131			640			486

Operating Income		19			27			99			60

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

Interest Charges		17			13			46			38

Income Before Income Taxes and Preferred
Dividends of Subsidiaries		2			12			52			19

Income Taxes (Benefit)		1			(1	)		17			(4	)

Income Before Preferred Dividends of Subsidiaries		1			13			35			23

Preferred Dividends of Subsidiaries		-			-			1			1

Net Income	$	1		$	13		$	34		$	22

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

CILCORP INC.
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions, except shares)

	September 30,		December 31,
	2007		2006

ASSETS
Current Assets:
Cash and cash equivalents	$	84	$	4
Accounts receivable – trade (less allowance for doubtful
accounts of $3 and $1, respectively)		51		47
Unbilled revenue		29		45
Accounts receivable – affiliates		66		10
Advances to money pool		-		42
Materials and supplies		111		93
Other current assets		50		42
Total current assets		391		283
Property and Plant, Net		1,401		1,277
Investments and Other Assets:
Goodwill		542		542
Intangible assets		42		48
Other assets		22		16
Regulatory assets		55		75
Total investments and other assets		661		681
TOTAL ASSETS	$	2,453	$	2,241

LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt	$	-	$	50
Short-term debt		540		215
Intercompany note payable – Ameren		-		73
Accounts and wages payable		31		54
Accounts payable – affiliates		44		60
Taxes accrued		2		3
Other current liabilities		80		58
Total current liabilities		697		513
Long-term Debt, Net		538		542
Preferred Stock of Subsidiary Subject to Mandatory Redemption		16		17
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		189		201
Accumulated deferred investment tax credits		6		7
Regulatory liabilities		74		73
Accrued pension and other postretirement benefits		154		171
Other deferred credits and liabilities		57		27
Total deferred credits and other liabilities		480		479
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		627		627
Retained earnings		45		11
Accumulated other comprehensive income		31		33
Total stockholder's equity		703		671
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	2,453	$	2,241

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

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


	Nine Months Ended
	September 30,
	2007			2006
Cash Flows From Operating Activities:
Net income	$	34		$	22
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		60			74
Amortization of debt issuance costs and premium/discounts		1			-
Deferred income taxes and investment tax credits		2			8
Loss on sale of noncore properties		-			4
Other		-			1
Changes in assets and liabilities:
Receivables		(38	)		49
Materials and supplies		(18	)		(22	)
Accounts and wages payable		(29	)		(47	)
Taxes accrued		(3	)		(9	)
Assets, other		(16	)		24
Liabilities, other		22			(4	)
Pension and postretirement benefit obligations		5			4
Net cash provided by operating activities		20			104

Cash Flows From Investing Activities:
Capital expenditures		(183	)		(75	)
Proceeds from note receivable – Resources Company		-			42
Proceeds from sale of noncore properties		-			11
Changes in money pool advances		42			-
Purchases of emission allowances		-			(12	)
Sales of emission allowances		-			1
Net cash used in investing activities		(141	)		(33	)

Cash Flows From Financing Activities:
Dividends on common stock		-			(50	)
Capital issuance costs		-			(2	)
Short-term debt, net		325			-
Changes in money pool borrowings		-			(92	)
Intercompany note payable – Ameren, net		(73	)		(30	)
Borrowings from credit facility		-			40
Redemptions, repurchases, and maturities:
Long-term debt		(50	)		(32	)
Preferred stock		(1	)		(1	)
Issuances of long-term debt		-			96
Net cash provided by (used in) financing activities		201			(71	)

Net change in cash and cash equivalents		80			-
Cash and cash equivalents at beginning of year		4			3
Cash and cash equivalents at end of period	$	84		$	3

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Operating Revenues:
Electric	$	170		$	119		$	507		$	309
Gas		36			38			231			236
Other		-			-			1			1
Total operating revenues		206			157			739			546

Operating Expenses:
Fuel		18			22			52			70
Purchased power		74			17			206			25
Gas purchased for resale		21			24			166			175
Other operations and maintenance		46			41			133			134
Depreciation and amortization		18			18			54			52
Taxes other than income taxes		4			4			17			17
Total operating expenses		181			126			628			473

Operating Income		25			31			111			73

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

Interest Charges		8			4			19			13

Income Before Income Taxes		17			25			91			56

Income Taxes		7			6			33			12

Net Income		10			19			58			44

Preferred Stock Dividends		-			-			1			1

Net Income Available to Common Stockholder	$	10		$	19		$	57		$	43

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

CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
(Unaudited) (In millions)


	September 30,		December 31,
	2007		2006
ASSETS
Current Assets:
Cash and cash equivalents	$	72	$	3
Accounts receivable – trade (less allowance for doubtful
accounts of $3 and $1, respectively)		51		47
Unbilled revenue		29		45
Accounts receivable – affiliates		59		9
Advances to money pool		-		42
Materials and supplies		111		93
Other current assets		45		32
Total current assets		367		271
Property and Plant, Net		1,400		1,275
Intangible Assets		1		2
Other Assets		25		18
Regulatory Assets		55		75
TOTAL ASSETS	$	1,848	$	1,641

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt	$	-	$	50
Short-term debt		365		165
Accounts and wages payable		30		54
Accounts payable – affiliates		44		47
Taxes accrued		2		3
Other current liabilities		63		47
Total current liabilities		504		366
Long-term Debt, Net		148		148
Preferred Stock Subject to Mandatory Redemption		16		17
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		156		166
Accumulated deferred investment tax credits		6		7
Regulatory liabilities		204		206
Accrued pension and other postretirement benefits		154		171
Other deferred credits and liabilities		57		25
Total deferred credits and other liabilities		577		575
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		429		415
Retained earnings		155		99
Accumulated other comprehensive income		-		2
Total stockholders' equity		603		535
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,848	$	1,641

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

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

	Nine Months Ended
	September 30,
	2007			2006
Cash Flows From Operating Activities:
Net income	$	58		$	44
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		55			61
Amortization of debt issuance costs and premium/discounts		1			-
Deferred income taxes and investment tax credits, net		4			15
Loss on sale of noncore properties		-			6
Changes in assets and liabilities:
Receivables		(32	)		51
Materials and supplies		(18	)		(20	)
Accounts and wages payable		(17	)		(30	)
Taxes accrued		(3	)		(17	)
Assets, other		(21	)		14
Liabilities, other		16			(6	)
Pension and postretirement benefit obligations		5			9
Net cash provided by operating activities		48			127

Cash Flows From Investing Activities:
Capital expenditures		(183	)		(75	)
Proceeds from sale of noncore properties		-			11
Changes in money pool advances		42			-
Purchases of emission allowances		-			(12	)
Sales of emission allowances		-			1
Net cash used in investing activities		(141	)		(75	)

Cash Flows From Financing Activities:
Dividends on common stock		-			(65	)
Dividends on preferred stock		(1	)		(1	)
Capital issuance costs		-			(2	)
Short-term debt, net		200			-
Changes in money pool borrowings		-			(99	)
Borrowings from credit facility		-			40
Redemptions, repurchases, and maturities:
Long-term debt		(50	)		(20	)
Preferred stock		(1	)		(1	)
Issuances of long-term debt		-			96
Capital contribution from parent		14			-
Net cash provided by (used in) financing activities		162			(52	)
Net change in cash and cash equivalents		69			-
Cash and cash equivalents at beginning of year		3			2
Cash and cash equivalents at end of period	$	72		$	2

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

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Operating Revenues:
Electric	$	307		$	375		$	859		$	888
Gas		49			59			375			381
Other		-			1			2			2
Total operating revenues		356			435			1,236			1,271

Operating Expenses:
Purchased power		211			213			573			561
Gas purchased for resale		26			35			267			272
Other operations and maintenance		74			68			197			188
Depreciation and amortization		20			20			60			57
Amortization of regulatory assets		4			-			12			-
Taxes other than income taxes		13			14			50			52
Total operating expenses		348			350			1,159			1,130

Operating Income		8			85			77			141

Other Income and Expenses:
Miscellaneous income		4			2			9			4
Miscellaneous expense		(2	)		(1	)		(3	)		(3	)
Total other income		2			1			6			1

Interest Charges		19			13			55			37

Income (Loss) Before Income Taxes (Benefit)		(9	)		73			28			105

Income Taxes (Benefit)		(5	)		30			10			42

Net Income (Loss)		(4	)		43			18			63

Preferred Stock Dividends		1			1			2			2

Net Income (Loss) Available to Common Stockholder	$	(5	)	$	42		$	16		$	61

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

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

	September 30,		December 31,
	2007		2006
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	-
Accounts receivable - trade (less allowance for doubtful
accounts of $10 and $3, respectively)		125		105
Unbilled revenue		71		101
Accounts receivable – affiliates		61		1
Materials and supplies		156		122
Other current assets		52		27
Total current assets		465		356
Property and Plant, Net		2,190		2,134
Investments and Other Assets:
Investment in IP SPT		9		8
Goodwill		214		214
Other assets		52		62
Regulatory assets		353		401
Total investments and other assets		628		685
TOTAL ASSETS	$	3,283	$	3,175

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt payable to IP SPT	$	51	$	51
Short-term debt		200		75
Borrowings from money pool		95		43
Accounts and wages payable		82		119
Accounts payable – affiliates		41		67
Taxes accrued		6		7
Other current liabilities		117		72
Total current liabilities		592		434
Long-term Debt, Net		766		772
Long-term Debt Payable to IP SPT		24		92
Deferred Credits and Other Liabilities:
Regulatory liabilities		93		110
Accrued pension and other postretirement benefits		217		230
Accumulated deferred income taxes		135		138
Other deferred credits and other noncurrent liabilities		94		53
Total deferred credits and other liabilities		539		531
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		1,194
Preferred stock not subject to mandatory redemption		46		46
Retained earnings		117		101
Accumulated other comprehensive income		5		5
Total stockholders’ equity		1,362		1,346
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,283	$	3,175

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

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

	Nine Months Ended
	September 30,
	2007			2006
Cash Flows From Operating Activities:
Net income	$	18		$	63
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization		63			18
Amortization of debt issuance costs and premium/discounts		6			3
Deferred income taxes		8			58
Other		(1	)		-
Changes in assets and liabilities:
Receivables		(50	)		60
Materials and supplies		(34	)		(34	)
Accounts and wages payable		(45	)		(62	)
Assets, other		(16	)		(1	)
Liabilities, other		54			(5	)
Pension and other postretirement benefit obligations		20			8
Net cash provided by operating activities		23			108

Cash Flows From Investing Activities:
Capital expenditures		(132	)		(128	)
Other		(1	)		(1	)
Net cash used in investing activities		(133	)		(129	)

Cash Flows From Financing Activities:
Dividends on preferred stock		(2	)		(2	)
Capital issuance costs		-			(1	)
Short-term debt, net		125			-
Changes in money pool borrowings, net		52			35
IP SPT maturities		(65	)		(69	)
Issuance of long-term debt		-			75
Overfunding of TFNs		-			(17	)
Net cash provided by financing activities		110			21
Net change in cash and cash equivalents		-			-
Cash and cash equivalents at beginning of year		-			-
Cash and cash equivalents at end of period	$	-		$	-

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

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY (Consolidated)

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

AMEREN ENERGY GENERATING COMPANY (Consolidated)

CILCORP INC. (Consolidated)

CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)

ILLINOIS POWER COMPANY (Consolidated)

COMBINED NOTES TO FINANCIAL STATEMENTS

(Unaudited)

September 30, 2007

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries, 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. 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 and natural gas transmission and distribution business and a non-rate-regulated electric generation business (through its subsidiary, AERG), all in Illinois.

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

Ameren has various other subsidiaries responsible for the short-term 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 its interest in EEI under the equity method. The following table presents summarized financial information of EEI for the three and nine months ended September 30, 2007 and 2006.

	Three Months				Nine Months
	2007		2006		2007		2006
Operating revenues	$	117	$	105	$	324	$	290
Operating income		53		93		158		191
Net income		34		56		99		117

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. 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 that may be expected for a full year. Certain reclassifications have been made to the prior year’s financial statements to conform to our 2007 reporting presentation. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three and nine months ended September 30, 2007 and 2006, due to an immaterial number of stock options, restricted stock and performance share units outstanding.

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

A summary of nonvested shares as of September 30, 2007, and changes during the nine-month period ended September 30, 2007, under the Long-term Incentive Plan of 1998, as amended, and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

	Performance Share Units					Restricted Shares
	Shares			Weighted-average Fair Value Per Unit		Shares		Weighted-average Fair Value Per Share
Nonvested at January 1, 2007		338,516		$	56.07		377,776		$	45.79
Granted^(a)		357,573			59.60		-			-
Dividends		-			-		11,567			50.62
Forfeitures		(13,711	)		56.64		(5,841	)		46.47
Vested^(b)		(12,975	)		59.14		(70,391	)		43.84
Nonvested at September 30, 2007		669,403		$	57.88		313,111		$	46.23

(a)	Includes performance share units (share units) granted to certain executive and non-executive officers and other eligible employees in February 2007 under the 2006 Plan.

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

The fair value of each share unit awarded in February 2007 under the 2006 Plan was determined to be $59.60 based on Ameren’s closing common share price of $53.99 per share at the grant date and lattice simulations used to estimate expected share payout based on Ameren’s attainment of certain financial measures relative to the designated peer group. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 4.735%, dividend yields of 2.3% to 5.2% for the peer group, volatility of 12.91% to 18.33% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend over the performance period.

Ameren recorded compensation expense of $4 million and $3 million for the quarters ended September 30, 2007 and 2006, respectively, and a related tax benefit of $2 million and $1 million for the quarters ended September 30, 2007 and 2006, respectively. Ameren recorded compensation expense of $13 million and $8 million for the nine-month periods ended September 30, 2007 and 2006, respectively, and a related tax benefit of $5 million and $3 million for the nine-month periods ended September 30, 2007 and 2006, respectively. As of September 30, 2007, total compensation cost of $25 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of three years.

Accounting Changes and Other Matters

FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of SFAS No. 109 (FIN 48)

FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, Ameren may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition of income tax assets and liabilities, classification of current and deferred income tax assets and liabilities, accounting for interest and penalties on income taxes, accounting for income taxes in interim periods, and requires expanded disclosures.

The Ameren Companies adopted the provisions of FIN 48 on January 1, 2007. The amount of unrecognized tax benefits as of January 1, 2007, was $155 million, $58 million,

$15 million, $36 million, $18 million, $18 million and $12 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. Of these unrecognized tax benefits on January 1, 2007, $20 million, $6 million, less than $1 million, less than $1 million, and less than $1 million for Ameren, UE, CIPS, Genco, and CILCORP, respectively, would impact the respective company’s effective tax rate, if recognized.

As of January 1, 2007, the Ameren Companies adopted a policy of recognizing interest and penalties accrued on tax liabilities on a gross basis as interest expense or penalty expense in the statements of income. Prior to January 1, 2007, the Ameren Companies recognized such items in the provision for taxes on a net-of-tax basis. As of January 1, 2007, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP had recorded a liability of $12 million, $5 million, less than $1 million, $4 million, $1 million, less than $1 million, and less than

$1 million, respectively, for the payment of interest with respect to unrecognized tax benefits and no amount for penalties with respect to unrecognized tax benefits.

All of the Ameren Companies’ federal income tax returns are closed through 2001. The Ameren Companies are currently under federal income tax return examination for years 2002 through 2005. State income tax returns are generally subject to examination for a period of three years

after filing of the respective returns. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. The Ameren Companies do not have state income tax returns in the process of examination. The Ameren Companies also do not have material state income tax issues in the process of administrative appeals or litigation.

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

SFAS No. 157, Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and expands required disclosures about fair value measurements. 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 as of the beginning of our 2008 fiscal year. We are still 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 to be material.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of SFAS No. 115

In February 2007, the FASB issued SFAS No. 159, which permits companies to choose to measure many financial instruments and certain assets and liabilities at fair value that are not currently required to be measured at fair value on an instrument-by-instrument basis. Entities electing the fair value option will be required to recognize changes in fair value in earnings and to expense upfront cost and fees associated with the item for which the fair value option is elected. SFAS No. 159 is effective as of the beginning of our 2008 fiscal year. At this time, we do not expect to elect the fair value option for any of our eligible financial instruments or other items.

FSP FIN 39-1, Amendment of FASB Interpretation No. 39

In April 2007, the FASB issued FSP FIN 39-1, effective for us as of the beginning of our 2008 fiscal year. FSP FIN 39-1 permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. We are currently evaluating whether we will elect to apply the accounting policies permitted under this pronouncement. The adoption of FSP FIN 39-1 will have no impact on net income, and we do not expect the impact to be material to our financial position.

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. We evaluate goodwill for impairment in the fourth quarter of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Ameren’s and IP’s goodwill relates to the acquisitions of IP and an additional 20% ownership interest in EEI in 2004, and Ameren’s and CILCORP’s goodwill relates to the acquisitions of CILCORP and Medina Valley in 2003. For the period from January 1, 2007 to September 30, 2007, there were no changes in the carrying amount of goodwill.

Intangible Assets. At September 30, 2007, intangible assets consisted of emission allowances of $197 million at Ameren, $60 million at UE, $57 million at Genco, $42 million at CILCORP and $1 million at CILCO. Emission allowances consist of various individual emission allowance certificates and do not have expiration dates. Emission allowances are charged to fuel expense as they are used in operations.

The following table presents the net book value of emission allowances consumed or (sold) for Ameren, UE, Genco, CILCORP and CILCO during the three and nine months ended September 30, 2007 and 2006.

	Three Months						Nine Months
	2007			2006			2007			2006
Ameren^(a)	$	7		$	(7	)	$	27		$	18
UE		(2	)		-			(5	)		(2	)
Genco		8			9			23			24
CILCORP^(b)		3			7			6			18
CILCO		-			2			-			8

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

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

Excise Taxes

Excise taxes reflected on Missouri electric, Missouri gas, and Illinois gas customer bills are imposed on us. They are recorded on a gross basis in Operating Revenues and Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued. The following table presents excise taxes recorded in Operating Revenues and Taxes Other than Income Taxes for the three and nine months ended September 30, 2007 and 2006:

	Three Months				Nine Months
	2007		2006		2007		2006
Ameren	$	46	$	43	$	128	$	129
UE		38		35		88		87
CIPS		2		2		11		11
CILCORP		2		2		8		8
CILCO		2		2		8		8
IP		4		4		21		23

Asset Retirement Obligations

AROs at Ameren and UE increased compared to December 31, 2006, to reflect the accretion of obligations to their fair values.

Prior Period Adjustment

During the third quarter of 2007, we identified a misallocation of first quarter 2007 purchased power expense among Ameren subsidiaries. The error resulted in an understatement of UE and Genco purchased power expense of approximately $7 million and $2 million, respectively, and an overstatement of CIPS, CILCORP, CILCO and IP purchased power expense of approximately $4 million, $1 million, $1 million, and $4 million, respectively, during both the three months ended March 31, 2007, and the six months ended June 30, 2007. The error resulted in an overstatement of UE and Genco net income of $5 million and $1 million, respectively, and an understatement of CIPS, CILCORP, CILCO and IP net income of approximately $3 million, $1 million, $1 million, and $3 million, respectively, during both the three months ended March 31, 2007, and the six months ended June 30, 2007. The error did not have a significant impact on previously reported subsidiary balance sheets or statements of cash flows, and the error had no impact on Ameren’s previously reported consolidated financial position or results of operations or cash flows.

All UE, CIPS, Genco, CILCORP, CILCO and IP financial information as of and for the nine months ended September 30, 2007, included in this quarterly report reflects the correction of the error. Previously-issued quarterly financial statements have not been restated, as management does not believe that the impact of these errors is material to the financial statements of UE, CIPS, Genco, CILCORP, CILCO and IP as of and for the quarter ended March 31, 2007, and as of and for the six months ended June 30, 2007.

NOTE 2 – RATE AND REGULATORY MATTERS

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

Missouri

Electric

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 a proposed average increase in electric rates of 17.7%, or $361 million, based on a requested return on equity of 12.0%. This rate increase filing was based on a test year ended June 30, 2006, and was updated for known and measurable items through January 1, 2007. In May 2007, the MoPSC issued an order, as clarified, granting UE a $43 million increase in base rates for electric service based on a return on equity of 10.2% and a capital structure of 52% common equity. New electric rates became effective June 4, 2007. The MoPSC order also included the following significant provisions:

·	Acceptance without rate adjustment of the expiration of UE’s cost-based power supply contract with EEI, which expired in December 2005.

·	Allowance of the full cost of certain CTs purchased or built in the past few years to be included in UE’s rate base.

Establishment of a regulatory tracking mechanism, through the use of a regulatory liability account, for gains on sales of SO₂emission allowances, net of SO₂ premiums incurred under the terms of coal procurement contracts, plus any SO₂discounts received under such contracts. These deferred amounts will be addressed as part of UE’s next rate case. The MoPSC allowed an annual base level of SO₂ emission allowance sales of up to $5 million, which UE can recognize in its statement of income.

·	Approval of a regulatory tracking mechanism for pension and postretirement benefit costs.

·	Change of income tax method associated with the cost of property removal, net of salvage, to the normalization method of accounting, which reduced income tax expense in the calculation of UE’s electric rates and for financial reporting purposes.

·	Establishment of off-system sales base level of $230 million used in determining UE’s revenue requirement.

·	Extension of UE’s Callaway nuclear plant and fossil generation plant lives used in calculating depreciation expense for electric rates and financial reporting purposes.

·	MoPSC staff directed to review a possible loss in capacity sales as a result of the breach of the upper reservoir of the Taum Sauk pumped-storage hydroelectric facility.

·	Establishment of a requirement to fund low-income energy assistance and energy conservation programs; half of such funding will be recoverable through rates to customers.

·	Denial of UE’s request to implement a fuel and purchased power cost recovery mechanism.

In June 2007, the MoPSC denied UE’s and other intervenors’ applications for rehearing with respect to certain aspects of the MoPSC rate order. In July 2007, UE appealed certain aspects of the MoPSC decision, principally the 10.2% return on equity granted by the MoPSC, to the Circuit Court of Cole County in Jefferson City, Missouri. The Office of Public Counsel and the Missouri attorney general, who were both intervenors in the electric rate case, also appealed certain aspects of the MoPSC decision to the Circuit Court of Cole County.

Taum Sauk

In June 2007, the MoPSC opened an investigation of the breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility in December 2005. In October 2007, the MoPSC staff issued its report on the Taum Sauk incident, and in November 2007 UE provided its response to the report. The MoPSC is expected to issue an order on the investigation by the end of 2007. See Note 8 – Commitments and Contingencies for additional information.

January 2007 Ice Storm Cost Recovery

UE submitted a filing to the MoPSC in November 2007 requesting operations and maintenance expenses that UE incurred as a result of a severe ice storm in January 2007 be deferred as a regulatory asset and, if approved, be amortized over five years beginning with the effective date of electric rates approved in UE's next rate proceeding. UE incurred approximately $25 million of operations and maintenance expenses in the first quarter of 2007 as a result of the January storm.

Illinois

Electric

New electric rates for CIPS, CILCO and IP went into effect on January 2, 2007, reflecting delivery service tariffs approved by the ICC in November 2006 and full cost recovery of power purchased on behalf of Ameren Illinois Utilities’ customers in the September 2006 auction in accordance with a January 2006 ICC order. As a result of these new electric rates going into effect, the estimated average annual residential rate overall increase in 2007 was expected to be 40% to 55% over 2006 rates. The estimated average annual residential rate overall increase for electric heat customers was expected to be 60% to 80% over 2006 rates.

Due to the magnitude of these rate increases, various legislators supported legislation that would have reduced and frozen the electric rates of CIPS, CILCO and IP to the rates that were in effect prior to January 2, 2007, and would have imposed a tax on electric generation in Illinois to help fund customer assistance programs. The Illinois governor also supported rate rollback and freeze legislation. In July 2007, an agreement was reached among key stakeholders in Illinois designed to avoid such legislation and address the increase in electric rates and the future power procurement process in Illinois. The terms of the agreement, which includes a comprehensive rate relief and customer assistance program, were set forth in a letter dated July 24, 2007, to the leaders of the Illinois General Assembly and the Illinois attorney general, in a release and settlement agreement with the Illinois attorney general, in funding agreements among the parties contributing to the rate relief and assistance programs and in legislation, which became effective on August 28, 2007. The following is a discussion of this agreement, including its impact on future power procurement for the Ameren Illinois Utilities, and outstanding significant regulatory and related legal matters affecting our Illinois electric operations.

Electric Settlement Agreement

The settlement agreement was the result of many months of negotiations among leaders of the House of Representatives and Senate in Illinois, the office of the Illinois attorney general, Ameren, on behalf of its affiliates, including Marketing Company, Genco and AERG, the Ameren Illinois Utilities, Exelon Corporation (Exelon), on behalf of Exelon Generation Company LLC, Commonwealth Edison Company, Exelon’s Illinois electric utility subsidiary, Dynegy Holdings Inc., Midwest Generation, LLC, and MidAmerican Energy Company. The comprehensive program provides approximately $1 billion of funding for rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Pursuant to the comprehensive program, the Ameren Illinois Utilities, Genco and AERG, have agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and

$28 million from AERG. Below is a summary of the total customer relief and assistance to be provided to the customers of the Ameren Illinois Utilities, the Ameren Illinois Utilities’, Genco’s and AERG’s portion of the funding

that is expected to be disbursed, and the expected charges to earnings as a result of the program and agreement.

	Total Relief/Assistance to Ameren Illinois Customers		Ameren Subsidiaries’ Funding^(a)		Estimated Ameren Earnings Per Share Impact^(b)
2007	$	253,000,000	$	86,000,000	$	0.26
2008		132,000,000		37,000,000		0.11
2009		97,000,000		25,000,000		0.07
2010		6,000,000		2,000,000		0.01
Total	$	488,000,000	$	150,000,000	$	0.45

(a)	Includes a $4.5 million contribution in 2007 towards funding of a newly-created IPA.

(b)	Includes estimated cost of proposed forgiveness of outstanding customer late payment fees.

The Ameren Illinois Utilities, Genco and AERG will recognize in their financial statements the costs of their respective rate relief contributions and program funding in a manner corresponding with the timing of the funding included in the above table. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, of $59 million, $8 million, $5 million, $11 million, $24 million and $11 million, respectively, under the terms of the settlement agreement during the quarter ended September 30, 2007. At September 30, 2007, Ameren, CIPS, CILCO and IP (Illinois Regulated) had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $108 million, $37 million, $21 million and $50 million, respectively.

Other electric generators and utilities in Illinois have agreed to contribute $851 million to the comprehensive rate relief and customer assistance program. Contributions by the other electric generators (the Generators) and utilities to the comprehensive program are subject to funding agreements. Under these agreements, at the end of each month, the Ameren Illinois Utilities will bill the Generators and utilities for their proportionate share of that month’s rate relief and assistance, which will be due in 30 days. If any escrow funds have been provided by the Generators, these funds will be drawn prior to seeking reimbursement from the Generators.

The settlement agreement preserves existing rates and rate structures, and the Ameren Illinois Utilities retain the right to file new electric delivery service rate cases with the ICC at the respective utility’s discretion. See Electric Delivery Service Rate Cases below for information on electric delivery service rate increase requests recently filed by the Ameren Illinois Utilities. The settlement agreement provides that if legislation is enacted in Illinois before August 1, 2011, freezing or reducing retail electric rates, or imposing or authorizing a new tax, special assessment or fee on the generation of electricity, then the remaining commitments under this agreement would expire, and any funds set aside in support of the commitments would be refunded to the utilities and Generators.

As part of the settlement agreement, the current reverse auction used for power procurement in Illinois was discontinued and replaced with a new power procurement process. In 2008, Illinois utilities will contract for their necessary baseload, intermediate and peaking power requirements through a request-for-proposal process, subject to ICC review and approval. Also as part of the agreement, existing supply contracts from the September 2006 reverse auction remain in place. In October 2007, CIPS, CILCO and IP filed a proposal with the ICC to formalize the structure of the power procurement process and related products for the period June 1, 2008 through May 31, 2009.

As part of the settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock-in energy prices for 400 to 1,000 megawatts annually of their around-the-clock power requirements during the period June 1, 2008 to December 31, 2012, at relevant market prices. These financial contracts do not include capacity, are not load-following products and do not involve the physical delivery of energy. These financial contracts became effective on August 28, 2007, when legislation in connection with the settlement agreement became law. Below are the contracted volumes and prices per megawatthour.

Period	Volume	Price per Megawatthour
June 1, 2008 – December 31, 2008	400 MW	$47.45
January 1, 2009 – May 31, 2009	400 MW	49.47
June 1, 2009 – December 31, 2009	800 MW	49.47
January 1, 2010 – May 31, 2010	800 MW	51.09
June 1, 2010 – December 31, 2010	1,000 MW	51.09
January 1, 2011 – December 31, 2011	1,000 MW	52.06
January 1, 2012 – December 31, 2012	1,000 MW	53.08

The financial contracts provide that if any one of the following events occurs during their term, the Ameren Illinois Utilities and Marketing Company will meet as soon as practicable, but no later than 30 days after the date such event occurs, to identify and discuss its effect on the terms and conditions of, and prices under the financial contracts: a) a state tax on electric generation; b) a state or federal tax on and/or regulation of greenhouse gas emissions (e.g., a carbon tax); or c) if the state of Illinois enacts a law that eliminates retail electric supplier choice for the residential and small commercial customers of the Ameren Illinois Utilities. The financial contracts also provide that if any one of these events occurs, the parties to the financial contracts will negotiate to determine in a commercially reasonable manner whether the affected terms, conditions and prices can be revised so as to preserve the economic benefits of the financial contracts for all parties and to revise the financial contracts accordingly. In the event the parties to the financial contracts are not able to agree on such revisions, Marketing Company may terminate the financial contracts by written notice no earlier than 60 days and no later than 90 days after such event occurs, with the termination being effective when

notice is given. Under the terms of the settlement agreement and the legislation, these financial contracts are deemed prudent, and the Ameren Illinois Utilities are permitted full recovery of their costs in rates.

Beginning in June 2009 and thereafter, power procurement will be accomplished through competitive requests for proposals to supply the separate baseload, intermediate and peaking power needs of the utility instead of the full requirements, load-following supply contracts previously procured through the reverse auction. The power procurement process that is expected to be implemented would require the IPA to develop an annual Procurement Plan (Plan) for the Ameren Illinois Utilities and Commonwealth Edison. Each Plan would govern a utility’s procurement of power to meet the expected load requirements that are not met by pre-existing contracts or generation facilities. Subject to ICC approval, the Ameren Illinois Utilities would be allowed to lease, or invest in, generation facilities. The objective of each Plan would be to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability for the utilities’ eligible retail customers. The power procurement process provides that each Plan be submitted to the ICC for initial approval; if approved, the final design and implementation of a Plan would be overseen by an independent procurement administrator selected by the IPA and a procurement monitor selected by the ICC. The IPA has broad authority to assist in the procurement of electric power for residential and nonresidential customers beginning in June 2009. Winning proposals will be selected on the basis of price, compared for reasonableness to benchmarks developed by the procurement administrator and procurement monitor, and approved by the ICC.

The power procurement process provides for the subject electric utility in Illinois to file proposed tariffs with the ICC, which will be designed to pass-through to customers the costs of procuring electric power supply with no mark-up on the price paid by the utility, plus any reasonable costs that the utility incurred in arranging and providing for the supply of electric power. All such procurement costs will be deemed to have been prudently incurred and recoverable through rates.

The settlement agreement and the legislation provide that the Ameren Illinois Utilities have a right to maintain membership in a FERC-approved regional transmission organization of their choice for a period of at least 15 years.

The settlement agreement and the legislation also include a commitment to energy conservation programs designed to reduce energy consumption through increased energy efficiency and demand response. In addition, 2% of the Illinois utilities’ electricity is to be procured from renewable sources beginning June 1, 2008, with that percentage increasing in subsequent years, subject to limits on customer rate impacts. The provision for full and timely recovery of the cost of these commitments is also included in the settlement agreement and the legislation.

Pursuant to the settlement agreement, all previously pending litigation and regulatory actions by the office of the Illinois attorney general relating to the reverse auction procurement process, which was used to determine market-based rates effective January 1, 2007, and the electric space heating marketing practices of the Ameren Illinois Utilities have been withdrawn with prejudice. The litigation and regulatory actions included those filed by the office of the attorney general with the FERC, the ICC, the United States Court of Appeals for the District of Columbia Circuit and the Circuit Court of the First Judicial Circuit Jackson County, Illinois and the Appellate Court of Illinois, Second Judicial Circuit.

Finally, the settlement agreement establishes the authority to obtain accelerated review by the ICC of a merger or combination of the three Ameren Illinois Utilities, if requested in the future.

Appeals of 2006 ICC Procurement Order

The Illinois attorney general, CUB, and ELPC, appealed to Illinois district appellate courts the ICC’s denial of rehearing requests with respect to its January 2006 order, which approved the power procurement auction and related tariffs. In August 2006, the Supreme Court of Illinois ordered that the appeals be consolidated in the appellate court for the Second Judicial Circuit in Illinois. The Illinois attorney general’s appeal at the Second Judicial Circuit appellate court was withdrawn as part of the agreement discussed above. CUB’s and ELPC’s appeals at the Second Judicial Circuit appellate court are still pending. The Ameren Illinois Utilities filed a motion to dismiss the appeals in September 2007.

Power Procurement Auction Lawsuits

Ameren, CIPS, CILCO, IP, Commonwealth Edison Company and its parent company, Exelon, and 15 electricity suppliers, including Marketing Company, which are selling power to the Illinois utilities pursuant to contracts entered into as a result of the September 2006 power procurement auction, were named as defendants in two similar lawsuits seeking class action status filed in the Circuit Court of Cook County, Illinois in March 2007. The classes have yet to be certified. The asserted class seeks to represent all customers who purchased electric service from Commonwealth Edison Company or the Ameren Illinois Utilities. Both lawsuits allege, among other things, that the Illinois utilities and the power suppliers illegally manipulated prices in the September 2006 power procurement auction. The relief sought in both lawsuits is actual damages to be determined at trial and legal costs,

including attorneys’ fees. One of the lawsuits also seeks punitive damages and recovery of illegal profits and excludes the Ameren Illinois Utilities from the requests for relief. In April 2007, the defendants in these lawsuits filed notices removing these cases to the U.S. District Court for the Northern District of Illinois. The defendants have pending motions to dismiss. These two lawsuits are not affected by the settlement agreement discussed above.

Redesigned Rates

In October 2007, the ICC issued an order authorizing redesigned electric rates for CIPS, CILCO and IP to be implemented December 1, 2007. These rates were designed to reduce seasonal fluctuations for residential customers who use large amounts of electricity while allowing utilities to fully recover costs. The ICC subsequently issued a rehearing order in late October 2007, granting CIPS’, CILCO’s and IP’s rehearing request to change the implementation date of the rate redesign for certain customers to January 1, 2008. The ICC granted the change in effective date to ensure the implementation of redesigned rates was revenue neutral to the Ameren Illinois Utilities in 2007 and subsequent calendar years.

Electric and Natural Gas Delivery Service Rate Cases

CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million and IP - $139 million). The Ameren Illinois Utilities pledged earlier this year to keep the overall residential electric bill increases to less than 10% per year for each utility in their next rate filings. These filings are consistent with that pledge. Accordingly, the requested rate increase for IP residential customers is proposed to be capped in the first year of the increase if the amount of the final authorized rate increase exceeds the first year capped rate level. This rate increase limit could result in approximately $30 million of the requested increase not being phased in until the second year. The amount of CIPS' and CILCO's requested increases did not require inclusion of similar limits as they were within the scope of the pledge. The electric rate increase requests are based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion, and a test year ended December 31, 2006, with certain prosective updates.

CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS -

$15 million increase, CILCO - $4 million decrease and IP - $56 million increase). The natural gas rate change requests are based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion and a test year ended December 31, 2006, with certain prospective updates.

In their filings, the Ameren Illinois Utilities have also requested ICC approval to implement mechanisms that would permit the reconciliation and adjustment of actual bad debt expenses to those established in rates by the ICC for electric and gas customers and the more timely recovery of investments in existing electric distribution plant. Since general rate adjustment proceedings require up to 11 months in Illinois, these mechanisms would allow current revenues to better match current costs. In addition, the Ameren Illlinois Utilities are seeking approval of a revenue decoupling rate adjustment mechanism as a part of their natural gas delivery service rate change requests. This mechanism would separate each utility's fixed cost recovery from the volume of gas it sells by providing a periodic true-up of revenues. The periodic true-up would result in adjustments to a utility's ICC-approved tariffs based on increases or decreases in demand for natural gas.

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

Federal

FERC Order – MISO Charges

In May 2007, Ameren Services, on behalf of UE, CIPS, CILCO and IP, filed with the United States Court of Appeals for the District of Columbia Circuit, an appeal of the FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants, retroactive to 2005. In August 2007, the court granted the FERC’s motion to hold the appeal in abeyance pending completion of the underlying proceedings at the FERC. Other MISO participants also filed appeals. On November 5, 2007, the FERC issued orders relative to these allocation matters. We are evaluating the impact of these orders and cannot determine their ultimate impact at this time.

UE Power Purchase Agreement with Entergy Arkansas, Inc.

In July 2007, as a consequence of a series of orders issued by the FERC addressing a complaint filed by the Louisiana Public Service Commission against Entergy

Arkansas, Inc. (Entergy) and certain of its affiliates, which alleged unjust and unreasonable cost allocations, Entergy commenced billing UE for additional charges under a 165-megawatt power purchase agreement. These additional charges to UE are expected to approximate $13 million for 2007 and additional amounts during the term of the power purchase agreement, which terminates effective August 25, 2009. Although UE was not a party to the FERC proceedings that gave rise to these additional charges, UE intervened in August 2007 in a related FERC proceeding for the purpose of challenging the additional charges. UE is unable to predict whether the FERC will grant any relief.

NOTE 3 – CREDIT FACILITIES AND LIQUIDITY

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

The following table summarizes the borrowing activity and relevant interest rates as of September 30, 2007, under the $1.15 billion credit facility and the 2007 and 2006

$500 million credit facilities:

$1.15 Billion Credit Facility^(a)	Ameren (Parent)			UE			Genco			Ameren Total
September 30, 2007:
Average daily borrowings outstanding during 2007	$	164		$	350		$	6		$	520
Outstanding short-term debt at period end		250			92			75			417
Weighted-average interest rate during 2007		5.90	%		5.70	%		5.26	%		5.76	%
Peak short-term borrowings during 2007	$	350		$	506		$	75		$	856
Peak interest rate during 2007		8.25	%		8.25	%		5.75	%		8.25	%

(a)	Includes issuances under commercial paper programs at Ameren and UE supported by this credit facility.

2007 $500 Million Credit Facility	CIPS			CILCORP (Parent)			CILCO (Parent)			IP			AERG			Total
September 30, 2007:
Average daily borrowings outstanding during 2007	$	-		$	98		$	23		$	120		$	73		$	314
Outstanding short-term debt at period end		-			125			75			200			100			500
Weighted-average interest rate during 2007		-			6.87	%		6.31	%		6.53	%		6.84	%		6.69	%
Peak short-term borrowings during 2007	$	-		$	125		$	75		$	200		$	100		$	500
Peak interest rate during 2007		-			8.63	%		6.47	%		6.64	%		7.02	%		8.63	%
2006 $500 Million Credit Facility
September 30, 2007:
Average daily borrowings outstanding during 2007	$	92		$	48		$	62		$	79		$	95		$	376
Outstanding short-term debt at period end		135			50			75			-			115			375
Weighted-average interest rate during 2007		6.52	%		6.82	%		6.28	%		6.59	%		6.89	%		6.62	%
Peak short-term borrowings during 2007	$	135		$	50		$	75		$	125		$	115		$	500
Peak interest rate during 2007		8.25	%		7.04	%		6.47	%		6.64	%		8.25	%		8.25	%

At September 30, 2007, Ameren and certain of its subsidiaries had $2.15 billion of committed credit facilities, consisting of the three facilities shown above, in the amounts of

$1.15 billion, $500 million and $500 million maturing in July 2010, January 2010 and January 2010, respectively.

Effective July 12, 2007, the termination date for UE’s and Genco’s direct borrowing sublimits under the $1.15 billion credit facility was extended to July 10, 2008, pursuant to the annual 364-day renewal provisions of the facility. The $1.15 billion credit facility will terminate on July 14, 2010, with respect to Ameren.

The $1.15 billion credit facility was used to support the commercial paper programs that included $92 million of outstanding commercial paper of UE as of September 30, 2007.

The 2007 $500 million credit facility was entered into in February 2007, by CIPS, CILCORP, CILCO, IP and AERG.

The obligations of IP under the 2007 $500 million credit facility were secured by the issuance of mortgage bonds in the amount of $200 million. CIPS and CILCO cannot utilize any amount of their borrowing authority under the 2007 $500 million credit facility until they reduce their borrowing authority by an equal amount under the 2006 $500 million credit facility. If CIPS or CILCO elect to transfer borrowing authority from the 2006 $500 million credit facility to the 2007 $500 million credit facility, that company must retire an appropriate amount of first mortgage bonds issued with respect to the 2006 $500 million credit facility and issue new bonds in an equal amount to secure its obligations under the 2007 $500 million credit facility. In July 2007, CILCO permanently reduced its $150 million of borrowing authority under the 2006 $500 million credit facility by $75 million and shifted that amount of capacity to the 2007 $500 million credit

facility. CILCO is now considered a borrower under both credit facilities and is subject to the covenants of both.

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

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.

Utility

CIPS, CILCO and IP borrow from each other through the utility money pool agreement subject to applicable regulatory short-term borrowing authorizations. AERG may make loans to, but may not borrow from, the utility money pool. Although UE and Ameren Services are parties to the utility money pool agreement, they are not currently borrowing or lending under the agreement. The average interest rate for borrowing under the utility money pool for the three and nine months ended September 30, 2007, was 5.4% and 5.7%, respectively (2006 – 5.4% and 5.0%, respectively).

Non-state-regulated Subsidiaries

Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS, Ameren Energy and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access funding from Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool agreement. At September 30, 2007, $728 million was available through the non-state-regulated subsidiary money pool, excluding additional funds available through excess cash balances. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three and nine months ended September 30, 2007, was 5.6% and 5.1%, respectively (2006 – 4.8% and 4.6%, respectively).

See Note 7 – Related Party Transactions for the amount of interest income (expense) from the money pool arrangements recorded by the Ameren Companies for the three and nine months ended September 30, 2007 and 2006.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ and AERG’s compliance with indebtedness provisions and other covenants. See Note 5 – Credit Facilities and Liquidity in the Form 10-K, for a detailed description of those provisions.

The Ameren Companies’ bank credit facilities contain provisions that, among other things, place restrictions on the ability to incur liens, sell assets, and merge with other entities. The $1.15 billion credit facility contains provisions that limit total indebtedness of each of Ameren, UE and Genco to 65% of total consolidated capitalization pursuant to a calculation defined in the facility. Exceeding these debt levels would result in a default under the $1.15 billion credit facility.

The $1.15 billion credit facility also contains default provisions, 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 facility are several and not joint, and except under limited circumstances, the obligations of UE and Genco are not guaranteed by Ameren or any other subsidiary. CIPS, CILCORP, CILCO, AERG and IP are not considered subsidiaries for purposes of the cross-default or other provisions.

Under the $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 in the facility.

Both the 2007 $500 million credit facility and the 2006 $500 million credit facility entered into by CIPS, CILCORP, CILCO, IP and AERG, discussed above, limit the indebtedness of each borrower to 65% of consolidated total capitalization pursuant to a calculation set forth in the facilities. Events of default under these facilities apply separately to each borrower (and, except in the case of CILCORP, to their subsidiaries), and an event of default under these facilities does not constitute an event of default under the $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 dividend payment limitation. A similar restriction does not apply to AERG, which is currently not rated by Moody’s or S&P, if its debt-to-operating cash flow ratio, as set forth in these facilities, is less than or equal to a 3.0 to 1.0 ratio. As of September 30, 2007, AERG was in compliance with this test in the 2007 $500 million credit facility and the 2006 $500 million credit facility. CIPS, CILCO and IP are not currently limited in their dividend payments by this provision of the 2007 $500 million or 2006 $500 million credit facilities. Ameren’s access to dividends from CILCO and AERG is limited by dividend restrictions at CILCORP.

The 2007 $500 million credit facility and the 2006 $500 million credit facility also limit the amount of other secured indebtedness issuable by each borrower thereunder. 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 $425 million (including the principal amount of CILCORP’s outstanding senior notes and senior bonds) under the 2007 $500 million credit facility and $550 million (including the principal amount of CILCORP’s outstanding senior notes and senior bonds as well as amounts drawn under the 2007 $500 million credit facility) under the 2006 $500 million credit facility, secured in each case by the pledge of CILCO common stock. For AERG, other secured debt is limited to $100 million under the 2007 $500 million credit facility and $200 million under the 2006 $500 million credit facility secured on an equal basis with its obligations under the facilities. The limitations on other secured debt at CILCORP and AERG in the 2007 $500 million credit facility are subject to adjustment based on the borrowing sublimits of these entities under this facility or under the 2006 $500 million credit facility. In addition, the 2007 $500 million credit facility and the 2006 $500 million credit facility prohibit CILCO from issuing any preferred stock if, after giving effect to such issuance, the aggregate liquidation value of all CILCO preferred stock issued after February 9, 2007 and July 14, 2006, respectively, would exceed $50 million.

The 2007 $500 million credit 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 (subject to, in the case of CIPS and CILCO, their then current borrowing sublimits under the facility and similar provisions in the 2006 facility): 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, but prior to December 31, 2009 - $150 million, on and after December 31, 2009 - $200 million; CILCO, prior to December 31, 2007 - $25 million, on and after December 31, 2007, but prior to December 31, 2008 - $50 million, on and after December 31, 2008, but prior to December 31, 2009 - $75 million, on and after December 31, 2009 - $150 million; and IP, prior to December 31, 2008 - $100 million, on and after December 31, 2008, but prior to December 31, 2009 - $200 million, on and after December 31, 2009 - $350 million.

The 2006 $500 million credit facility provides that CIPS, CILCO and IP will agree to reserve future bonding capacity under their respective mortgage indentures 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.

As of September 30, 2007, the ratio of total indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the $1.15 billion credit facility for Ameren, UE and Genco was 50%, 50% and 48%, respectively. The ratios for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the provisions of the 2007 $500 million credit facility and 2006 $500 million credit facility, were 53%, 59%, 46%, 46% and 39%, 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, 2007, 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 0.5 million new shares of common stock valued at $23 million and 1.4 million new shares valued at $71 million in the three and nine months ended September 30, 2007, respectively.

In February 2007, $100 million of Ameren’s 2002 5.70% notes matured and were retired.

In May 2007, $250 million of Ameren’s senior notes related to its 2002 equity security units matured and were retired.

In June 2007, UE issued, pursuant to an effective SEC Form S-3 shelf registration statement, $425 million of 6.40% senior secured notes due June 15, 2017, with interest payable semi-annually on June 15 and December 15 of each year,

beginning in December 2007. UE received net proceeds of $422 million, which were used to repay short-term debt.

In connection with UE’s June 2007 issuance of $425 million of senior secured notes, UE agreed, for so long as those senior secured notes are outstanding, that it would not, prior to June 15, 2012, optionally redeem, purchase or otherwise retire in full its outstanding first mortgage bonds not subject to release provisions thus causing a first mortgage bond release date to occur. Such release date is the date at which the security provided by the pledge under UE’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness ranking equally with any other outstanding senior unsecured indebtedness of UE. UE further agreed that the interest rate for these $425 million of senior secured notes will be subject to an increase of up to a maximum of 2.00% if such release date occurs between June 15, 2012 and June 15, 2017 (the maturity date of the $425 million senior secured notes) and Moody's or S&P downgrades the rating assigned to these senior secured notes below investment grade as a result of the occurrence of the release within 30 days of such release date (subject to extension if and for so long as the rating for such senior secured notes is under consideration for possible downgrade). Any interest rate increase on these senior secured notes will take effect on the first day of the interest period during which such rating downgrade requires an increase in the interest rate.

CIPS

See Note 5 – Credit Facilities and Liquidity in the Form 10-K regarding CIPS’ agreement under the 2007 $500 million credit facility and the 2006 $500 million credit facility to reserve future bonding capacity under its mortgage indenture.

CILCORP

In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was recorded at fair value. Amortization related to these fair value adjustments was $1 million (2006 -$1 million) and $4 million (2006 - $4 million) for the three and nine months ended September 30, 2007, respectively, and was included as a reduction to interest expense in the Consolidated Statements of Income of Ameren and CILCORP. See Note 5 – Credit Facilities and Liquidity in the Form 10-K regarding CILCORP’s pledge of the common stock of CILCO as security for CILCORP’s obligations under the 2007 $500 million credit facility and the 2006 $500 million credit facility.

CILCO

In January 2007, $50 million of CILCO’s 7.50% first mortgage bonds matured and were retired.

See Note 5 – Credit Facilities and Liquidity in the Form 10-K regarding CILCO’s agreement under the 2007 $500 million credit facility and the 2006 $500 million credit facility to reserve future bonding capacity under its mortgage indenture.

In July 2007, 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 2007.

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

(2006 - $3 million) and $9 million (2006 - $10 million) for the three and nine months ended September 30, 2007, respectively, and was included as a reduction to interest expense in the Consolidated Statements of Income of Ameren and IP.

See Note 5 – Credit Facilities and Liquidity in the Form 10-K regarding IP’s agreement under the 2007 $500 million credit facility and the 2006 $500 million credit facility to reserve future bonding capacity under its mortgage indenture.

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 Form 10-K, for a detailed description of those provisions.

UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable based on the 12 months ended September 30, 2007, 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	4.2	$ 2,232	≥2.5	49.2	1,584
CIPS	≥2.0	1.8	-	≥1.5	1.3	-
CILCO	≥2.0^(f)	11.0	84	≥2.5	32.1	319^(g)
IP	≥2.0	1.8	-	≥1.5	1.1	-

(a)	Coverage required on the annual interest charges on 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, whichever is more restrictive. In addition to these tests, UE, CIPS, CILCO and IP have the ability to issue bonds based upon retired bond capacity of $16 million, $3 million, $175 million, and $914 million, respectively, for which no earnings coverage test is required.

(d)	Amounts are net of future bonding capacity restrictions agreed to by CIPS, CILCO and IP under the 2007 $500 million credit facility and the 2006 $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 and nine months ended September 30, 2007, CILCO had earnings equivalent to at least 38% 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 2007 $500 million credit facility and the 2006 $500 million credit facility.

UE’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of 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, 2007.

Genco’s and CILCORP’s indentures include provisions that require the companies to maintain certain debt service coverage and debt-to-capital ratios in order for the companies to pay dividends, to make certain principal or interest payments, to make certain loans to affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended September 30, 2007:

	Required Interest Coverage Ratio	Actual Interest Coverage Ratio	Required Debt–to- Capital Ratio	Actual Debt–to- Capital Ratio
Genco^(a)	≥1.75^(b)	6.3	≤60%	44%
CILCORP^(c)	≥2.2	3.0	≤67%	27%

(a)

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

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

Genco’s ratio restrictions under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness. In the event CILCORP is not in compliance with these restrictions, CILCORP may make payments of dividends or intercompany loans if its senior long-term debt rating is at least BB+ from S&P, Baa2 from Moody’s, and BBB from Fitch. At September 30, 2007, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were B+, Ba2, and BB+, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior notes and bonds and credit facility obligations.

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, 2007, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

NOTE 5 – OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three and nine months ended September 30, 2007 and 2006:

	Three Months						Nine Months
	2007			2006			2007			2006
Ameren:^(a)
Miscellaneous income:
Interest and dividend income	$	16		$	9		$	41		$	21
Allowance for equity funds used during construction		2			1			2			2
Other		2			2			11			6
Total miscellaneous income	$	20		$	12		$	54		$	29
Miscellaneous expense:
Other	$	(6	)	$	(3	)	$	(10	)	$	(4	)
Total miscellaneous expense	$	(6	)	$	(3	)	$	(10	)	$	(4	)
UE:
Miscellaneous income:
Interest and dividend income	$	8		$	7		$	24		$	18
Allowance for equity funds used during construction		1			1			1			1
Other		-			1			3			3
Total miscellaneous income	$	9		$	9		$	28		$	22
Miscellaneous expense:
Other	$	(5	)	$	(3	)	$	(9	)	$	(7	)
Total miscellaneous expense	$	(5	)	$	(3	)	$	(9	)	$	(7	)
CIPS:
Miscellaneous income:
Interest and dividend income	$	4		$	4		$	12		$	12
Other		1			-			1			1
Total miscellaneous income	$	5		$	4		$	13		$	13
Miscellaneous expense:
Other	$	(1	)	$	-		$	(2	)	$	(1	)
Total miscellaneous expense	$	(1	)	$	-		$	(2	)	$	(1	)
Genco:
Miscellaneous income:
Other	$	-		$	-		$	1		$	-
Total miscellaneous income	$	-		$	-		$	1		$	-
CILCORP:
Miscellaneous income:
Interest and dividend income	$	1		$	-		$	3		$	1
Other		1			-			1			-
Total miscellaneous income	$	2		$	-		$	4		$	1
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(5	)	$	(4	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(5	)	$	(4	)

CILCO:
Miscellaneous income:
Interest and dividend income	$	1		$	-		$	3		$	-
Other		1			-			1			-
Total miscellaneous income	$	2		$	-		$	4		$	-
Miscellaneous expense:
Other	$	(2	)	$	(2	)	$	(5	)	$	(4	)
Total miscellaneous expense	$	(2	)	$	(2	)	$	(5	)	$	(4	)
IP:
Miscellaneous income:
Interest and dividend income	$	2		$	1		$	5		$	2
Other		2			1			4			2
Total miscellaneous income	$	4		$	2		$	9		$	4
Miscellaneous expense:
Other	$	(2	)	$	(1	)	$	(3	)	$	(3	)
Total miscellaneous expense	$	(2	)	$	(1	)	$	(3	)	$	(3	)

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

NOTE 6 – DERIVATIVE FINANCIAL INSTRUMENTS

The following table presents the pretax net gain (loss) for the three and nine months ended September 30, 2007 and 2006, of power hedges included in Operating Revenues – Electric. This pretax net gain (loss) represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI due to transactions being delivered or settled:

	Three Months					Nine Months
Gains (Losses)	2007		2006			2007		2006
Ameren	$	22	$	2		$	35	$	-
UE		2		2			-		5
Genco		-		1			-		2
IP		-		(1	)		-		(7	)

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, 2007:

	Ameren^(a)			UE		CIPS		Genco			CILCORP/ CILCO		IP
Derivative instruments carrying value:
Other current assets	$	52		$	11	$	1	$	-		$	3	$	1
Other assets		24			-		2		-			3		3
Other current liabilities		9			2		1		2			1		1
Regulatory liabilities		25			-		6		-			5		19
Other deferred credits and liabilities		4			-		-		-			-		-
Gains (losses) deferred in Accumulated OCI:
Power forwards^(b)		54			12		-		-			-		-
Interest rate swaps^(c)		3			-		-		3			-		-
Gas swaps and futures contracts^(d)		1			-		-		-			2		-
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 $43 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.

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

Other Derivatives

The following table presents the net change in market value for the three and nine months ended September 30, 2007 and 2006, of option and swap transactions used to manage our positions in SO₂ allowances, coal, heating oil, and nonhedge power and gas trading activity. Certain of these transactions are treated as nonhedge transactions under

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. The net change in the market value of SO₂, coal and heating oil options and swaps is recorded as Operating Expenses – Fuel. The nonhedge power and gas swaps are recorded in Operating Revenues – Electric and Operating Revenues – Gas.

	Three Months						Nine Months
Gains (Losses)	2007			2006			2007			2006
SO₂ options and swaps:
Ameren	$	-		$	1		$	6		$	(2	)
UE		-			1			5			3
Genco		-			1			1			(4	)
Coal options:
Ameren		-			(1	)		2			(2	)
UE		-			(1	)		2			(2	)
Heating oil options:
Ameren		-			(2	)		3			(2	)
Nonhedge power swaps and forwards:
Ameren		3			-			(2	)		-
UE		2			1			(2	)		1
Nonhedge gas futures:
Ameren		(2	)		-			-			-
UE		(2	)		-			-			-

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 13 – Related Party Transactions under Part II, Item 8 of the Form 10-K. Below are updates to several of these related party agreements.

Electric Rate Settlement

See Note 2 – Rate and Regulatory Matters and Note 8 – Commitments and Contingencies for information on an electric settlement agreement reached in July 2007 among key stakeholders in Illinois and reflected in legislation, enacted on August 28, 2007, that addresses electric rate increases and the future power procurement process in Illinois. As part of the electric settlement agreement in Illinois, the Ameren Illinois Utilities, Genco and AERG agreed to make contributions of $150 million as part of a comprehensive program providing approximately $1 billion of funding for rate relief to certain Illinois electric customers, including customers of the Ameren Illinois Utilities. At September 30, 2007, CIPS, CILCO and IP had receivable balances from Genco for reimbursement of customer rate relief of $7 million, $4 million and $10 million, respectively. Also at September 30, 2007, CIPS and IP had receivable balances from AERG for reimbursement of customer rate relief of $3 million and $4 million, respectively. In addition, as part of the electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company to lock-in energy prices for a portion of their around-the-clock power requirements from 2008 to 2012 at relevant market prices. These financial contracts became effective on August 28, 2007, when the legislation in connection with the agreement became law.

Electric Power Supply Agreements

The following table presents the amount of gigawatthour sales under related party electric power supply agreements for the three and nine months ended September 30, 2007 and 2006:

	Three Months				Nine Months
	2007		2006		2007		2006
Genco sales to Marketing Company^(a)		-		5,820		-		16,707
Marketing Company sales to CIPS^(a)		-		3,424		-		9,500
Genco sales to Marketing Company^(b)		4,754		-		12,711		-
AERG sales to Marketing Company⁽^b⁾		1,270		-		3,912		-
Marketing Company sales to CIPS⁽^c⁾		671		-		1,852		-
Marketing Company sales to CILCO⁽^c⁾		349		-		922		-
Marketing Company sales to IP⁽^c⁾		1,016		-		2,716		-

(a)	These agreements expired or terminated on December 31, 2006.

(b)

In December 2006, Genco and Marketing Company, and AERG and Marketing Company, entered into new power supply agreements whereby Genco and AERG sell and Marketing Company purchases all the capacity available from Genco’s and AERG’s generation fleets and such amount of associated energy commencing on January 1, 2007.

(c)

In accordance with the January 2006 ICC order, discussed in Note 2 – Rate and Regulatory Matters, an auction was held in September 2006 to procure power for CIPS, CILCO and IP after their previous power supply contracts expired on December 31, 2006. Through the auction, Marketing Company contracted with CIPS, CILCO and IP to provide power for their customers. See also Note 3 – Rate and Regulatory Matters under Part II, Item 8 of the Form 10-K for further details of the power procurement auction in Illinois. See Note 2 – Rate and Regulatory Matters for a discussion of future changes in the Illinois power procurement process as a result of the electric settlement agreement reached among key stakeholders in July 2007 and the related legislation enacted into law in August 2007.

Joint Dispatch Agreement

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. The termination of the JDA was accepted by FERC in September 2006.

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

	Three Months	Nine Months
UE sales to Genco	2,073	7,507
Genco sales to UE	898	2,615

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

	Three Months		Nine Months
UE	$	15	$	73
Genco		5		22
Total	$	20	$	95

Money Pools

See Note 3 - Credit Facilities and Liquidity for a discussion of affiliate borrowing arrangements.

Intercompany Promissory Notes

Genco’s subordinated note payable to CIPS associated with the transfer in 2000 of CIPS’ electric generating assets and related liabilities to Genco matures on May 1, 2010. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $2 million (2006 - $3 million) and $7 million (2006 - $10 million) for the three and nine months ended September 30, 2007 and 2006, respectively.

CILCORP had no outstanding borrowings directly from Ameren at September 30, 2007. CILCORP had $156 million of outstanding borrowings from Ameren at September 30, 2006, with average interest rates of 4.8% and 4.5% for the three and nine months ended September 30, 2006, respectively. CILCORP recorded interest expense of less than $1 million

(2006 - $2 million) and less than $1 million (2006 - $6 million) for these borrowings for the three and nine months ended September 30, 2007, respectively.

The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the three and nine months ended September 30, 2007 and 2006. The table is based primarily on the agreements discussed above and in Note 13 – Related Party Transactions under Part II, Item 8 of the Form 10-K, 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:
Genco and AERG power supply	2007	$	(b	)	$	(b	)	$	222		$	73		$	(b	)	$	(b	)	$	(b	)	$	615		$	207		$	(b	)
agreements with Marketing Company
Ancillary service agreement	2007		5		(b		)	(b		)	(b		)	(b		)		13		(b		)	(b		)	(b		)	(b		)
with CIPS, CILCO and IP
Power supply agreement with Marketing Company – expired	2006	(b		)	(b		)		216		(c		)	(b		)	(b		)	(b		)		605			5		(b		)
December 31, 2006
UE and Genco gas	2007	(c		)	(b		)	(b		)	(b		)	(b		)	(c		)	(b		)	(b		)	(b		)	(b		)
transportation agreement	2006	(c		)	(b		)	(b		)	(b		)	(b		)	(c		)	(b		)	(b		)	(b		)	(b		)
JDA – terminated December 31, 2006	2006		35		(b		)		23		(b		)	(b		)		156		(b		)		69		(b		)	(b		)
Total Operating Revenues	2007	$	5		$	(b	)	$	222		$	73		$	(b	)	$	13		$	(b	)	$	615		$	207		$	(b	)
	2006		35		(b		)		239		(c		)	(b		)		156		(b		)		674			5		(b		)
Fuel and Purchased Power:
CIPS, CILCO and IP agreements	2007	$	(b	)	$	42		$	(b	)	$	22		$	64		$	(b	)	$	120		$	(b	)	$	60		$	176
with Marketing Company(auction)
Ancillary service agreement with UE	2007	(b		)		2		(b		)		1			2		(b		)		5		(b		)		2			6
Ancillary service agreement with Marketing Company	2007	(b		)		1		(b		)		-			2		(b		)		3		(b		)		1			4
JDA – terminated December 31, 2006	2006		23		(b		)		35		(b		)	(b		)		69		(b		)		156		(b		)	(b		)
Power supply agreement with Marketing Company – expired	2006	(b		)		118		(b		)		1		(b		)	(b		)		337		(b		)		1		(b		)
December 31, 2006
Executory tolling agreement	2007	(b		)	(b		)	(b		)		8		(b		)	(b		)	(b		)	(b		)		28		(b		)
with Medina Valley	2006	(b		)	(b		)	(b		)		9		(b		)	(b		)	(b		)	(b		)		29		(b		)
UE and Genco gas	2007	(b		)	(b		)	(c		)	(b		)	(b		)	(b		)	(b		)	(c		)	(b		)	(b		)
transportation agreement	2006	(b		)	(b		)	(c		)	(b		)	(b		)	(b		)	(b		)	(c		)	(b		)	(b		)
Total Fuel and Purchased	2007	$	(b	)	$	45		$	(c	)	$	31		$	68		$	(b	)	$	128		$	(c	)	$	91		$	186
Power	2006		23			118			35			10		(b		)		69			337			156			30		(b		)

		Three Months																	Nine Months
Agreement				UE			CIPS			Genco		CILCORP^(a)				IP			UE			CIPS			Genco		CILCORP ^(a)				IP
Other Operating Expense:
Ameren Services support	2007		$	34		$	12		$	6		$	12		$	18		$	102		$	35		$	18		$	37		$	54
services agreement	2006			34			12			7			12			18			103			36			18			37			54
Ameren Energy support	2007			2		(b		)	(c		)	(b		)	(b		)		7		(b		)	(c		)	(b		)	(b		)
services agreement	2006			2		(b		)		1		(b		)	(b		)		6		(b		)		2		(b		)	(b		)
AFS support services	2007			2			-			1			1			-			5			1			2			2			1
agreement	2006			1		(c		)	(c		)	(c		)		1			3			1			1			1			2
Insurance premiums^(d)	2007			7		(b		)		1			-		(b		)		16		(b		)		3			1		(b		)
Total Other Operating	2007		$	45		$	12		$	8		$	13		$	18		$	130		$	36		$	23		$	40		$	55
Expenses	2006			37			12			8			12			19			112			37			21			38			56
Interest expense (income) from	2007		$	-		$	(c	)	$	3		$	(c	)	$	(c	)	$	-		$	(c	)	$	7		$	(c	)	$	(c	)
money pool borrowings(advances)	2006		(c		)		(1	)		3			1			1		(c		)		(2	)		8			4			2

(a)	Amounts represent CILCORP and CILCO activity.

(b)	Not applicable.

(c)	Amount less than $1 million.

(d)	Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.

NOTE 8 – COMMITMENTS AND CONTINGENCIES

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

Reference is made to Note 1 – Summary of Significant Accounting Policies, Note 3 – Rate and Regulatory Matters, Note 13 – Related Party Transactions, and Note 14 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters and Note 7 – Related Party Transactions in this report.

Callaway Nuclear Plant

The following table presents insurance coverage at UE’s Callaway nuclear plant at September 30, 2007. The property coverage and the nuclear liability coverage were renewed on October 1, 2007 and January 1, 2007, respectively.

Type and Source of Coverage	Maximum Coverages	Maximum Assessments for Single Incidents
Public liability:
American Nuclear Insurers	$ 300	$ -
Pool participation	10,461^(a)	101^(b)
	$ 10,761^(c)	$ 101
Nuclear worker liability:
American Nuclear Insurers	$ 300^(d)	$ 4
Property damage:
Nuclear Electric Insurance Ltd.	$ 2,750^(e)	$ 24
Replacement power:
Nuclear Electric Insurance Ltd.	$ 490^(f)	$ 9
Energy Risk Assurance Company	$ 64^(g)	$ -

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

(b)

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

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

(d)

Industry limit for potential liability for worker tort claims filed for bodily injury caused by a nuclear energy accident. Effective January 1, 1998, this program was modified to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations.

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

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

(g)

Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. The coverage is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 7 – Related Party Transactions for more information on this affiliate transaction.

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. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

Subsequent to the terrorist attacks on September 11, 2001, both American Nuclear Insurers and Nuclear Electric Insurance Ltd. confirmed that losses resulting from terrorist attacks would be covered under their policies, subject to applicable policy limits. Both companies, however, revised their policy terms to include an industry aggregate for all “non-certified” terrorist acts as defined by the Terrorism Risk Insurance Act of 2002, which was renewed in 2005. The non-certified American Nuclear Insurers nuclear liability cap is a $300 million shared industry aggregate for all facilities licensed in the United States during the policy period. The aggregate for all Nuclear Electric Insurance Ltd. policies, which apply to non-certified property claims within a 12-month period, is $3.2 billion, plus any amounts available through reinsurance or indemnity from an outside source.

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

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. In addition, we have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 14 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

As of September 30, 2007, our commitments for the procurement of coal and related transportation have changed from amounts previously disclosed as of December 31, 2006. The following table presents our total estimated coal and related transportation purchase commitments at September 30, 2007:

	2007		2008		2009		2010		2011
Ameren^(a⁾	$	145	$	552	$	380	$	186	$	121
UE		78		294		256		142		103
Genco		43		143		66		20		8
CILCORP/CILCO		9		37		21		8		4

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

As of September 30, 2007, our commitments for the procurement of natural gas have materially changed from amounts previously disclosed as of December 31, 2006. The following table presents our total estimated natural gas purchase commitments at September 30, 2007:

	2007		2008		2009		2010		2011		Thereafter^(a)
Ameren^(b)	$	173	$	591	$	369	$	263	$	213	$	1,964
UE		20		85		58		37		27		56
CIPS		29		111		81		64		42		73
Genco		9		30		8		8		8		13
CILCORP/CILCO		53		162		97		59		58		838	^(c)
IP		57		192		123		95		77		983	^(c)

(a)	Commitments for natural gas are until 2031.

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

(c)	Commitments for natural gas purchases for CILCO and IP include projected natural gas purchases pursuant to a 20-year supply contract beginning in April 2011. Purchases under this contract will be passed through to utility customers under the PGA.

As of September 30, 2007, the commitments for the procurement of nuclear fuel have materially changed from amounts previously disclosed as of December 31, 2006. The following table presents the total estimated nuclear fuel purchase commitments at September 30, 2007:

		2007				2008				2009				2010				2011				Thereafter^(a)
Ameren/UE		$	52			$	71			$	63			$	74			$	51			$	292

(a)	Commitments for nuclear fuel are until 2020.

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 that would use coal or nuclear fuel. During the second quarter of 2007, UE entered into a commitment to purchase heavy forgings needed to construct a nuclear plant. This commitment does not mean a decision has been made to build a nuclear plant. The purpose of entering into the forgings purchase commitment was to secure access to heavy forgings, which are long lead-time materials, in the event that UE decides to build a nuclear plant. As of September 30, 2007, UE’s commitments to purchase heavy forgings totaled $88 million through 2010 ($3.5 million in 2007, $6.5 million in 2008, $7.5 million in 2009 and $70.5 million in 2010).

As part of the electric settlement agreement in Illinois, the Ameren Illinois Utilities, Genco and AERG, committed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and $28 million from AERG. Also as part of the electric settlement agreement in Illinois, the Ameren Illinois Utilities entered into financial contracts with Marketing Company to lock-in energy prices for 400 to 1,000 megawatts annually of their around-the-clock power requirements from 2008 to 2012. See Note 2 – Rate and Regulatory Matters for additional information regarding the electric settlement agreement in Illinois.

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, natural gas storage plants, and natural gas transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, and impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological and historical resources), and chemical and waste handling. Our activities often require complex and lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires 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. These rules require significant reductions in these emissions from UE, Genco, AERG 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. Although the federal rules mandate a specific 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 has finalized rules to implement the federal Clean Air Interstate Rule program that will reduce the number of NO_x allowances automatically allocated to Genco’s, AERG’s and EEI’s plants. As a result of the Illinois rules, Genco, AERG and EEI will need to procure allowances and install pollution control equipment in order to continue to operate. We currently plan to install scrubbers at our large coal-fired plants in Illinois.

Missouri rules, which substantially follow the federal regulations and became effective in April 2007, are expected to reduce mercury emissions 81% by 2018 and reduce NO_x emissions 30% and SO₂ emissions 75% by 2015.

Illinois has adopted rules for mercury emissions that are significantly stricter than the federal regulations. In 2006, Genco, CILCO, EEI, and the Illinois EPA entered into an agreement that was incorporated into Illinois’ mercury emission regulations. Under the regulations, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NO_x and SO₂ controls. In 2009, Genco, AERG and EEI will begin putting into service equipment designed to reduce mercury emissions. These rules, when fully implemented, are expected to reduce mercury emissions 90%, NO_x emissions 50% and SO₂ emissions 70% by 2015 in Illinois.

The table below presents estimated capital costs based on current technology to comply with both the federal Clean Air Interstate Rule and Clean Air MercuryRule through 2016 and related state implementation plans. The estimates described below could change depending upon additional federal or state requirements, new technology, variations in costs of material or labor, or alternative compliance strategies, among other reasons. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with the proposed rules, thereby deferring capital investment.

	2007	2008 - 2011	2012 - 2016	Total
UE^(a)	$ 110	$ 630- 830	$ 910- 1,180	$ 1,650- 2,120
Genco	110	820- 1,060	180- 260	1,110- 1,430
CILCO (AERG)	100	185- 240	95- 140	380- 480
EEI	10	185- 240	165- 220	360- 470
Ameren	$ 330	$ 1,820- 2,370	$ 1,350- 1,800	$ 3,500- 4,500

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

Illinois and Missouri must also develop attainment plans to meet the federal eight-hour ozone ambient standard, the federal fine particulate ambient standard and the Clean Air Visibility rule. Both states have filed ozone attainment plans for the St. Louis area. The state attainment plans for fine particulate must be submitted to the EPA by April 2008, and the plans for the Clean Air Visibility rule must be submitted to the EPA by December 2007. The costs in the table above assume that emission controls required for the Clean Air Interstate Rule regulations will be sufficient to meet these new standards in the St. Louis region. Should Missouri develop an alternative plan to comply with these standards, the cost impact could be material to UE, but we would expect these costs to be recoverable from ratepayers. 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 such state actions would have on our results of operations, financial position, or liquidity.

Emission Allowances

Both federal and state laws require significant reductions in SO₂ and NO_x emissions that result from burning fossil fuels. The Clean Air Act 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 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 was applied 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 SO₂ and NO_x emission allowances held and the related SO₂ and NO_x emission allowance book values that are carried as intangible assets as of September 30, 2007.

	SO₂^(a)	NO_x^(b)	Book Value
UE	1.591	15,948	$ 60
Genco	0.624	11,841	57
CILCO (AERG)	0.300	2,147	1
EEI	0.293	3,397	9
Ameren	2.808	33,333	197^(c)

(a)	Vintages are from 2007 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 2007 to 2008. Units are in NO_x allowances (one allowance equals one ton emitted). NO_x allowances for 2009 and beyond have not yet been allocated by the EPA; however, UE, Genco, AERG and EEI expect to be allocated allowances in future years.

(c)	Includes value assigned to AERG and EEI allowances as a result of purchase accounting of $70 million.

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 increasing the ratio of Acid Rain Program allowances surrendered. The current Acid Rain Program requires the surrender of one SO₂ allowance for every ton of SO₂ that is emitted. 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. In order to accommodate this change in surrender ratio and to comply with the federal and state regulations, UE, Genco, AERG and EEI expect to install control technology designed to further reduce SO₂ emissions, as discussed above.

Global Climate

Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities. Coal-fired power plants, however, are significant sources of carbon dioxide, a principal greenhouse gas. Six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the TVA, signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% to 5% voluntary decrease in carbon intensity by the utility sector between 2002 and 2012. Currently, Ameren is considering various initiatives to comply with the MOU, including increased generation at nuclear and hydroelectric power plants, increased efficiency

measures at our coal-fired units, and investments in renewable energy and carbon sequestration projects.

In April 2007, the U.S. Supreme Court issued a decision that determined that the EPA has authority to regulate carbon dioxide and other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. The Supreme Court sent the case back to the EPA, which must conduct a rulemaking to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” Unless the U.S. Congress enacts legislation directing otherwise, the EPA could begin to regulate such emissions.

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

Ameren is preparing a report to address the environmental planning process and actions of Ameren relative to the climate change issue. The report is expected to be issued in mid-December 2007.

New Source Review

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

In April 2007, the U.S. Supreme Court in Environmental Defense v. Duke Energy Corp., issued a decision that effectively reduced the statutory defenses available to NSR and Prevention of Significant Deterioration (PSD) claims. The key issue before the Supreme Court was whether EPA requirements to obtain permits under the NSR and PSD programs are triggered when a “modification” at an industrial facility results in an increase in an hourly emissions rate, as upheld by the U.S. Court of Appeals for the Fourth Circuit, or in total annual emissions, as asserted by environmental groups. The U.S. Supreme Court found that the NSR and PSD regulations can be triggered by either an hourly or annual increase in the emissions. The Supreme Court decision did not address other potential defenses or potential exceptions under the NSR and PSD programs.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. We are currently in discussions with the EPA and the state of Illinois regarding resolution of these matters, but we are unable to predict the outcome of these discussions. Resolution of these matters could have a material adverse impact on the future results of operations, financial position or liquidity of Ameren, Genco, AERG and EEI. A resolution could result in increased capital expenditures, increased operations and maintenance expenses, and fines or penalties. We believe that any potential resolution would likely require the installation of control technology, some of which is already planned for compliance with other regulatory requirements such as the Clean Air Interstate Rule and the Illinois mercury rules.

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 have contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of September 30, 2007, 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, 2007, CIPS, CILCO and IP had recorded liabilities of $25 million, $5 million and $76 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 in effect in Missouri a rate rider mechanism that permits remediation costs associated with MGP sites to be recovered from utility customers. UE does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs. 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, 2007, UE had recorded $5 million to represent its estimated minimum obligation for its 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, 2007, UE had recorded $4 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, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2. UE currently owns a parcel of property that was used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other potentially responsible parties (PRPs) to evaluate the extent of potential contamination with respect to Sauget Area 2.

Sauget Area 2 investigation activities under the oversight of the EPA are largely completed, and the results of such activities will be submitted to the EPA by the end of 2007. Following this submission, the EPA will ultimately select a remedy alternative and begin negotiations with various PRPs to implement the selected alternative. Over the last several years, numerous other parties have joined the PRP group and presumably will participate in the funding of any required remediation. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities of Solutia related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection.

In December 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $3.9 million at September 30, 2007, 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 actions may have on our results of operations, financial position, or liquidity.

Polychlorinated Biphernals Information Request

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

We cannot predict whether any further actions will be required on the part of the Ameren Illinois Utilities regarding this matter or what the ultimate outcome of this matter will be.

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. At the FERC’s direction, outside experts were hired by UE to review the cause of the incident. Their reports and reports by FERC staff indicated 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. FERC agreed with this conclusion and rejected repair as an option.

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, (1) to pay a civil penalty of $10 million, (2) to pay $5 million into an interest-bearing escrow account to fund project enhancements at or near the Taum Sauk facility, and (3) to implement and comply

with a new dam safety program developed in connection with the settlement.

In February 2007, UE submitted plans and an environmental report to FERC to rebuild the upper reservoir at its Taum Sauk plant, assuming successful resolution of outstanding issues with authorities of the state of Missouri. UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant in August 2007 and hired a contractor in November 2007. Should the Taum Sauk plant be rebuilt, UE would expect it to be out of service through at least the fall of 2009, if not longer.

UE has accepted responsibility for the effects of the incident. At this time, UE believes that substantially all damages and liabilities (but not penalties) caused by the breach, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. UE expects the total cost for clean up, damage and liabilities, excluding costs to rebuild the facility, resulting from the Taum Sauk incident to range from $188 million to $208 million. As of September 30, 2007, UE had paid $89 million and accrued a $99 million liability, including costs resulting from the FERC-approved stipulation and consent agreement discussed above, while expensing $31 million and recording a $157 million receivable due from insurance companies. As of September 30, 2007, UE has received $35 million from insurance companies, which has reduced the insurance receivable balance to $122 million as of such date. As of September 30, 2007, UE had a $57 million receivable due from insurance companies related to rebuilding the facility. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.

In December 2006, the state of Missouri, through its attorney general, and 10 business owners filed separate lawsuits regarding the Taum Sauk breach that are currently pending in the Circuit Court of Reynolds County, Missouri. The attorney general’s suit alleges negligence, violations of the Missouri Clean Water Act and various other statutory and common law claims. The business owners’ suit contains similar allegations and seeks damages relating to business losses and lost profit. Both suits seek unspecified punitive damages. In May 2007, the Missouri Department of Natural Resources’ petition to intervene as a plaintiff in the attorney general’s lawsuit was denied. UE is currently in discussions with authorities of the state of Missouri to resolve outstanding issues associated with this incident.

See Note 2 – Rate and Regulatory Matters for information on the MoPSC’s Taum Sauk investigation.

Until the reviews conducted by state authorities have concluded, litigation has been resolved, the insurance review is completed, and future regulatory treatment for the facility 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 189 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, 2007, the average number of parties was 71.

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

From July 1, 2007, through September 30, 2007, nine additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois. Four lawsuits were settled. The following table presents the status as of September 30, 2007, 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	343	31	188	145	2	49	164
Settled	116	-	59	51	-	18	60
Dismissed	151	27	99	51	2	10	70
Pending	76	4	30	43	-	21	34

(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, 2007, eight asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

IP has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms. Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will be recovered by IP from a $20 million trust fund established by IP 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.

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

NOTE 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 2006, 2005 and 2004. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. The latest study was filed in 2005. Minor tritium contamination was discovered on the Callaway nuclear plant site in the summer of 2006. Existing facts and regulatory requirements indicate that this discovery will not cause any significant increase in a decommissioning cost estimate when the next study is conducted. 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 and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to a regulatory asset.

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 and nine months ended September 30, 2007 and 2006, is shown below for the Ameren Companies:

	Three Months						Nine Months
	2007			2006			2007			2006
Ameren:^(a)
Net income	$	244		$	293		$	510		$	486
Unrealized gain on derivative hedging instruments, net of taxes of $8, $6, $6 and $1, respectively		15			14			10			5
Reclassification adjustments for (gain) included in net income, net of taxes of $9, $1, $19 and $3, respectively		(17	)		(1	)		(33	)		(4	)

		Three Months				Nine Months
		2007		2006		2007		2006
Adjustment to pension and benefit obligation, net of taxes (benefit) of $1, $-, $(2) and $-, respectively		1		-		2		-
Total comprehensive income, net of taxes	$	243	$	306	$	489	$	487

UE:
Net income	$	193		$	166		$	307		$	309
Unrealized gain on derivative hedging instruments, net of taxes of $3, $5, $3 and $2, respectively		5			8			4			4
Reclassification adjustments for (gain) included in net income, net of taxes of $1, $3, $2 and $3, respectively		(1	)		(5	)		(3	)		(4	)
Total comprehensive income, net of taxes	$	197		$	169		$	308		$	309
CIPS:
Net income	$	1		$	29		$	19		$	43
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $-, $- and $(3), respectively		-			(1	)		-			(5	)
Reclassification adjustments for (gain) included in net income, net of taxes of $-, $-, $1 and $1, respectively		(1	)		-			(1	)		(1	)
Total comprehensive income, net of taxes	$	-		$	28		$	18		$	37
Genco:
Net income	$	25		$	19		$	84		$	27
Unrealized gain (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $2, $(1) and $2, respectively		-			3			(2	)		3
Reclassification adjustments for (gain) included in net income, net of taxes of $-, $2, $- and $1, respectively		-			(2	)		-			(1	)
Adjustment to pension and benefit obligation, net of taxes (benefit) of $1, $-, $(1) and $-, respectively		1			-			(1	)		-
Total comprehensive income, net of taxes	$	26		$	20		$	81		$	29
CILCORP:
Net income	$	1		$	13		$	34		$	22
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $(1), $(3), $- and $(13), respectively		(1	)		(4	)		(1	)		(19	)
Reclassification adjustments for (gain) included in net income, net of taxes of $-, $-, $1 and $-, respectively		-			-			(2	)		(1	)
Adjustment to pension and benefit obligation, net of taxes of $-, $-, $- and $-, respectively		-			-			1			-
Total comprehensive income, net of taxes	$	-		$	9		$	32		$	2
CILCO:
Net income	$	10		$	19		$	58		$	44
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $(3), $- and $(13), respectively		-			(4	)		-			(19	)
Reclassification adjustments for (gain) included in net income, net of taxes of $-, $-, $1 and $-, respectively		-			-			(2	)		-
Total comprehensive income, net of taxes	$	10		$	15		$	56		$	25
IP:
Net income (loss)	$	(4	)	$	43		$	18		$	63
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit) of $-, $(4), $- and $(1), respectively		-			(6	)		-			(2	)
Reclassification adjustments for loss included in net income, net of taxes (benefit) of $-, $(4), $- and $(1), respectively		-			6			-			2
Total comprehensive income (loss), net of taxes	$	(4	)	$	43		$	18		$	63

(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. We previously did not expect future contributions to be required until 2009, at which time we had expected a required contribution of $75 million to $125 million, to maintain minimum funding levels for Ameren’s pension plans. In May 2007, the MoPSC issued an electric rate order for UE that allows UE to recover through customer rates pension expense incurred under GAAP. Consequently, Ameren expects to fund its pension plans at a level equal to the pension expense. Based on Ameren's assumptions at December 31, 2006, and reflecting this pension funding policy, Ameren now expects annual voluntary contributions of $45 million to $70 million in each of the next five years. These amounts are estimates and may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions.

Ameren made a contribution to its postretirement benefit plan of $26 million during the nine months ended September 30, 2007 as compared to $37 million during the nine months ended September 30, 2006.

The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three and nine months ended September 30, 2007 and 2006:

	Pension Benefits^(a)												Postretirement Benefits^(a)
	Three Months						Nine Months						Three Months						Nine Months
	2007			2006			2007			2006			2007			2006			2007			2006
Service cost	$	16		$	16		$	47		$	47		$	5		$	5		$	15		$	16
Interest cost		45			43			135			129			18			18			54			51
Expected return on plan assets		(51	)		(49	)		(154	)		(147	)		(13	)		(12	)		(39	)		(35	)
Amortization of:
Transition obligation		-			-			-			-			1			-			2			1
Prior service cost (benefit)		3			3			9			8			(2	)		(2	)		(6	)		(5	)
Actuarial loss		5			10			16			31			6			9			18			26
Net periodic benefit cost	$	18		$	23		$	53		$	68		$	15		$	18		$	44		$	54

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

UE, CIPS, Genco, CILCORP, CILCO, IP and EEI are participants in Ameren’s plans and are responsible for their proportional share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and nine months ended September 30, 2007 and 2006:

	Pension Costs								Postretirement Costs
	Three Months				Nine Months				Three Months				Nine Months
	2007		2006		2007		2006		2007		2006		2007		2006
Ameren	$	18	$	23	$	53	$	68	$	15	$	18	$	44	$	54
UE		10		13		30		39		7		9		22		28
CIPS		2		3		6		9		2		2		5		6
Genco		2		2		4		6		1		1		3		3
CILCORP		2		3		7		8		2		3		5		7
IP		1		2		4		6		2		3		8		10
EEI		1		-		2		-		1		-		1		-

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

As discussed above and in Note 2 – Rate and Regulatory Matters, the MoPSC issued an order that included approval of a regulatory tracking mechanism for pension and postretirement benefit costs. The difference between the level of pension and postretirement benefit costs incurred by UE under GAAP and the level of such costs built into rates effective June 4, 2007, will be tracked by means of a regulatory asset or liability, as applicable. The resulting regulatory asset or liability will be included in rate base for purposes of setting new rates in UE’s next electric rate case and amortized over five years beginning with the effective date of electric rates approved in UE’s next rate case. As of September 30, 2007, the regulatory liability was $6 million.

NOTE 12 – SEGMENT INFORMATION

Ameren has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 – Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI and other non-rate regulated activities, which are included in Other. 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 parent company, AERG, EEI, and Marketing Company. Other primarily includes Ameren parent company activities and the leasing activities of CILCORP, AERG, Resources Company, and CIPSCO Investment Company.

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

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

The following table presents information about the reported revenues and net income of Ameren for the three and nine months ended September 30, 2007 and 2006, and total assets as of September 30, 2007 and December 31, 2006.

Three Months	Missouri Regulated		Illinois Regulated			Non-rate-regulated Generation		Other			Intersegment Eliminations			Consolidated
2007:
External revenues	$	934	$	702		$	372	$	(11	)	$	-		$	1,997
Intersegment revenues		11		21			122		10			(164	)		-
Net income (loss)^(a)		179		(9	)		73		1			-			244
2006:
External revenues	$	811	$	836		$	256	$	7		$	-		$	1,910
Intersegment revenues		46		4			212		(1	)		(261	)		-
Net income^(a)		142		83			62		6			-			293
Nine Months
2007:
External revenues	$	2,258	$	2,503		$	980	$	(2	)	$	-		$	5,739
Intersegment revenues		34		34			379		30			(477	)		-
Net income^(a)		264		45			197		4			-			510
2006:
External revenues	$	2,021	$	2,501		$	703	$	35		$	-		$	5,260
Intersegment revenues		182		12			594		17			(805	)		-
Net income^(a)		255		125			102		4			-			486
As of September 30, 2007:
Total assets	$	10,611	$	6,487		$	3,938	$	1,131		$	(1,762	)	$	20,405
As of December 31, 2006:
Total assets	$	10,251	$	6,226		$	3,612	$	1,161		$	(1,672	)	$	19,578

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

The following table presents information about the reported revenues and net income of UE for the three and nine months ended September 30, 2007 and 2006, and total assets as of September 30, 2007 and December 31, 2006.

Three Months	Missouri Regulated			Other ^(a)		Consolidated UE
2007:
Revenues		$	945	$	-	$	945
Net income^(b)			179		13		192
2006:
Revenues		$	857	$	-	$	857
Net income^(b)			142		23		165
Nine Months
2007:
Revenues		$	2,292	$	-	$	2,292
Net income^(b)			264		39		303
2006:
Revenues		$	2,203	$	-	$	2,203
Net income^(b)			255		50		305
As of September 30, 2007:
Total assets		$	10,611	$	52	$	10,663
As of December 31, 2006:
Total assets		$	10,251	$	36	$	10,287

(a)	Includes 40% interest in EEI.

(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 and nine months ended September 30, 2007 and 2006, and total assets as of September 30, 2007 and December 31, 2006.

Three Months	Illinois Regulated			Non-rate-regulated Generation		CILCORP Other		Intersegment Eliminations			Consolidated CILCORP
2007:
External revenues	$	142		$	64	$	-	$	-		$	206
Intersegment revenues		-			1		-		(1	)		-
Net income (loss)^(a)		(4	)		5		-		-			1

Three Months	Illinois Regulated		Non-rate-regulated Generation		CILCORP Other			Intersegment Eliminations			Consolidated CILCORP
2006:
External revenues	$	153	$	5	$	-		$	-		$	158
Intersegment revenues		-		54		-			(54	)		-
Net income (loss)^(a)		12		2		(1	)		-			13
Nine Months
2007:
External revenues	$	537	$	202	$	-		$	-		$	739
Intersegment revenues		-		3		-			(3	)		-
Net income^(a)		11		23		-			-			34
2006:
External revenues	$	523	$	23	$	-		$	-		$	546
Intersegment revenues		-		139		-			(139	)		-
Net income (loss)^(a)		23		3		(4	)		-			22
As of September 30, 2007:
Total assets^(b)	$	1,253	$	1,390	$	4		$	(194	)	$	2,453
As of December 31, 2006:
Total assets^(b)	$	1,208	$	1,246	$	4		$	(217	)	$	2,241

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

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

The following table presents information about the reported revenues and net income of CILCO for the three and nine months ended September 30, 2007 and 2006, and total assets as of September 30, 2007 and December 31, 2006.

Three Months	Illinois Regulated			Non-rate-regulated Generation		CILCO Other			Intersegment Eliminations			Consolidated CILCO
2007:
External revenues	$	142		$	64	$	-		$	-		$	206
Intersegment revenues		-			1		-			(1	)		-
Net income (loss)^(a)		(4	)		14		-			-			10
2006:
External revenues	$	153		$	5	$	(1	)	$	-		$	157
Intersegment revenues		-			54		-			(54	)		-
Net income (loss)^(a)		12			8		(1	)		-			19
Nine Months
2007:
External revenues	$	537		$	202	$	-		$	-		$	739
Intersegment revenues		-			3		-			(3	)		-
Net income^(a)		11			46		-			-			57
2006:
External revenues	$	523		$	23	$	-		$	-		$	546
Intersegment revenues		-			139		-			(139	)		-
Net income (loss)^(a)		23			24		(4	)		-			43
As of September 30, 2007:
Total assets	$	1,063		$	785	$	1		$	(1	)	$	1,848
As of December 31, 2006:
Total assets	$	1,020		$	642	$	1		$	(22	)	$	1,641

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

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

OVERVIEW

Ameren Executive Summary

Ameren’s earnings in the third quarter of 2007 and the first nine months of 2007 were reduced by the costs associated with the Illinois electric settlement agreement, which is discussed below, changes in the Ameren Illinois Utilities’ electric rate structure and the rising costs of operating and investing in our Missouri and Illinois rate-regulated segments, including increased reliability expenditures. During the third quarter of 2007, these factors more than offset higher margin in the Missouri and Illinois rate-regulated business segments from warmer

summer weather, the implementation of the June 2007 Missouri electric rate order and higher electric margin in Non-rate-regulated Generation due to the replacement of below-market power sales contracts that expired in 2006.

Ameren’s earnings in the first nine months of 2007 were reduced by $19 million (after taxes), or 9 cents per share, as a result of the cost of restoration efforts associated with a severe ice storm January 2007. Storm-related costs in the first nine months of 2006 reduced net income by an estimated $25 million (after taxes), or 13 cents per share. In addition, costs related to participation in the MISO Day Two Energy Market were $10 million (after taxes), or 5 cents per share, higher in the first nine months of 2007 over the same period in 2006 because of a March 2007 FERC order that resettled such costs among market participants retroactive to 2005. Ameren’s net income in the first quarter of 2007 benefited from the reversal of a $10 million charge (after taxes), or 5 cents per share, originally recorded in 2006 related to funding for low-income energy assistance and energy efficiency programs in Illinois. These commitments were terminated in the first quarter of 2007 as a result of credit rating downgrades resulting from Illinois legislative actions during that period.

In late August 2007, the Illinois governor signed into law the enabling legislation for the Illinois electric settlement agreement that was reached among key stakeholders in Illinois deigned to address the increase in electric rates that occurred after the state’s electric rate freeze ended on January 1, 2007, and to address the future power procurement process in Illinois. As part of the Illinois settlement agreement, the electric customers of the Ameren Illinois Utilities will receive $488 million in bill credits and refunds and other relief through 2010 as part of an approximately $1 billion state-wide relief package. The Ameren Illinois Utilities, Genco and AERG will be funding $150 million, in the aggregate, of this program over a four-year period. The total impact to Ameren’s earnings per share is expected to be about 45 cents per share spread across four years, including 26 cents per share in 2007. The Ameren Illinois Utilities began sending checks and providing bill credits to customers in September 2007. Ameren recorded 18 cents per share of these costs in the third quarter of 2007. Other key aspects of the settlement agreement are currently being implemented including those related to power procurement in the future.

Ameren’s Illinois Regulated business segment experienced a significant earnings decline during the third quarter and first nine months of 2007 compared with 2006 due to, among other things, its current levels of electric and gas delivery service rates being insufficient to recover its current costs of providing service to its customers. In early November 2007, the Ameren Illinois Utilities filed requests with the ICC for a combined $247 million increase in electric and gas rates. As the Illinois Regulated business segment’s recent earnings results indicate, these rate increase requests are clearly needed by the Ameren Illinois Utilities and are consistent with the Ameren Illinois Utilities’ need to recover their costs of providing safe and reliable service to their customers and earning a reasonable return on their investments. Earlier this year, the Ameren Illinois Utilities pledged to keep the overall annual residential electric bill increases in Illinois to less than 10 percent per year for each utility in their next rate filings. These Illinois rate filings are consistent with that pledge. This self-imposed rate increase limit could result in approximately $30 million of the increase request not being phased-in until the second year of implementation if the full request is granted by the ICC. The Ameren Illinois Utilities’ also requested rate mechanisms for bad debt expenses, electric infrastructure investments and the decoupling of natural gas revenues from volumes. The ICC has eleven months to make a decision on these filings. With rising costs, including fuel and related transportation, purchased power, labor and material costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, Ameren, UE, CIPS, CILCO and IP expect to experience regulatory lag until requests to increase rates to recover such costs are granted by state regulators. As a result, Ameren, UE, CIPS, CILCO and IP expect to be entering a period where more frequent rate cases will be necessary.

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries, 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 are dependent on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.

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

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

·	Genco operates a non-rate-regulated electric generation business.

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

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

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

RESULTS OF OPERATIONS

Earnings Summary

Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. About 90% of Ameren’s 2006 revenues were directly subject to state or 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. 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 for our electric utility business. We do have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses and purchased power cost recovery mechanisms for our Illinois electric delivery businesses. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, for a discussion of pending and recently-decided rate cases and the electric settlement agreement in Illinois. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Ameren’s net income decreased to $244 million, or $1.18 per share, in the third quarter of 2007 from $293 million, or $1.42 per share, in the third quarter of 2006. Net income in the Missouri Regulated and Non-rate-regulated Generation segments in the three months ended September 30, 2007, increased by $37 million and $11 million, respectively, from the prior-year period, while net earnings in the Illinois Regulated segment declined by $92 million.

Ameren’s net income increased to $510 million, or $2.46 per share, in the first nine months of 2007 from $486 million, or $2.37 per share, in the first nine months of 2006. Net income increased in the Missouri Regulated and Non-rate-regulated Generation segments by $9 million and $95 million, respectively, in the first nine months of 2007 compared to the prior-year period, while net income in the Illinois Regulated segment decreased by $80 million.

Earnings were favorably impacted in the third quarter and first nine months of 2007 as compared with the same periods in 2006 by:

·	higher margins in the Non-rate-regulated Generation segment due to the replacement of below-market power sales contracts, which expired in 2006, with higher-priced contracts;

·	favorable weather conditions;

·	the absence of costs in the current-year periods that were incurred in the prior-year periods related to the reservoir breach at UE’s Taum Sauk plant (4 cents per share and 9 cents per share, respectively);

·	higher electric rates, lower depreciation expense and decreased income tax expense in the Missouri Regulated segment pursuant to the MoPSC rate order for UE issued in May 2007 (9 cents per share and 11 cents per share, respectively); and

·	the absence of costs associated with outages caused by severe storms in the current year periods that were incurred in the prior-year periods (10 cents per share and 13 cents per share, respectively).

Earnings were negatively impacted in the third quarter and first nine months of 2007 as compared with the same periods in 2006 by:

·	electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities’ electric customers under the Illinois settlement agreement (18 cents per share) described in Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report;

·	the elimination of bundled tariffs and the rate redesign in Illinois;

·	higher fuel and related transportation prices (9 cents per share and 23 cents per share, respectively);

·	higher labor and employee benefit costs (4 cents per share and 12 cents per share, respectively);

·	increased depreciation and amortization expense (4 cents per share and 11 cents per share, respectively);

·	higher financing costs (5 cents per share and 13 cents per share, respectively); and

·	lower emission allowance sales (4 cents per share and 5 cents per share, respectively).

In addition to the above items affecting both periods, earnings were impacted in the first nine months of 2007 as compared with the first nine months of 2006 by the following items:

Earnings were favorably impacted by:

the reversal of an accrual originally recorded in 2006 in the Illinois Regulated segment for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan (5 cents per share). The commitment to make these contributions was terminated in 2007 as a result of credit rating agency downgrades resulting from Illinois legislative actions; and

·	the lack of FERC fees related to UE’s Osage hydroelectric plant in the current-year period that were incurred in the prior-year period and the capitalization of fees, pursuant to a May 2007 MoPSC order, in the current-year period (2 cents per share).

Earnings were negatively impacted by:

·	costs associated with electric outages caused by a severe ice storm in January 2007 (9 cents per share);

·	a FERC order in March 2007 that reallocated costs related to participation in the MISO Day Two Energy Market among market participants retroactive to 2005 (5 cents per share); and

·	the cost of UE’s Callaway nuclear plant refueling and maintenance outage in the second quarter of 2007 exceeding the cost of the unplanned outage at the Callaway plant in the second quarter of 2006 (9 cents per share).

An increase in the number of common shares outstanding reduced Ameren’s earnings per share in the 2007 periods compared with the 2006 periods. Per share information presented above is based on average shares outstanding in 2006.

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 and nine months ended September 30, 2007 and 2006:

	Three Months					Nine Months
	2007			2006		2007		2006
Net income (loss):
UE^(a)	$	192		$	165	$	303	$	305
CIPS		-			28		17		41
Genco		25			19		84		27
CILCORP		1			13		34		22
IP		(5	)		42		16		61
Other⁽^b⁾		31			26		56		30
Ameren net income	$	244		$	293	$	510	$	486

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

(b)	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.

Below is a table of income statement components by segment for the three and nine months ended September 30, 2007 and 2006:

	Missouri Regulated			Illinois Regulated			Non-rate- regulated Generation			Other / Intersegment Eliminations			Total
Three Months 2007:
Electric margin	$	677		$	185		$	267		$	(14	)	$	1,115
Gas margin		9			48			-			-			57
Other revenues		2			2			-			(4	)		-
Other operations and maintenance		(222	)		(142	)		(79	)		16			(427	)

	Missouri Regulated			Illinois Regulated			Non-rate-regulated Generation			Other / Intersegment Eliminations			Total
Three Months 2007:
Depreciation and amortization		(82	)		(54	)		(26	)		(7	)		(169	)
Taxes other than income taxes		(69	)		(23	)		(6	)		1			(97	)
Other income and (expenses)		8			5			1			-			14
Interest expense		(49	)		(36	)		(28	)		3			(110	)
Income taxes		(94	)		8			(49	)		5			(130	)
Minority interest and preferred dividends		(1	)		(2	)		(7	)		1			(9	)
Net income (loss)	$	179		$	(9	)	$	73		$	1		$	244
Three Months 2006:
Electric margin	$	622		$	319		$	221		$	(18	)	$	1,144
Gas margin		10			52			-			(3	)		59
Other revenues		1			2			1			(4	)		-
Other operations and maintenance		(214	)		(133	)		(65	)		17			(395	)
Depreciation and amortization		(82	)		(49	)		(26	)		(5	)		(162	)
Taxes other than income taxes		(66	)		(29	)		(5	)		1			(99	)
Other income and (expenses)		7			3			-			(1	)		9
Interest expense		(43	)		(25	)		(26	)		5			(89	)
Income taxes		(93	)		(55	)		(27	)		14			(161	)
Minority interest and preferred dividends		-			(2	)		(11	)		-			(13	)
Net income	$	142		$	83		$	62		$	6		$	293
Nine Months 2007:
Electric margin	$	1,579		$	573		$	766		$	(44	)	$	2,874
Gas margin		50			227			-			(4	)		273
Other revenues		2			3			-			(5	)		-
Other operations and maintenance		(668	)		(398	)		(239	)		56			(1,249	)
Depreciation and amortization		(253	)		(162	)		(80	)		(19	)		(514	)
Taxes other than income taxes		(186	)		(89	)		(20	)		-			(295	)
Other income and (expenses)		25			15			3			1			44
Interest expense		(146	)		(97	)		(81	)		8			(316	)
Income taxes		(135	)		(22	)		(132	)		10			(279	)
Minority interest and preferred dividends		(4	)		(5	)		(20	)		1			(28	)
Net income	$	264		$	45		$	197		$	4		$	510
Nine Months 2006:
Electric margin	$	1,492		$	668		$	570		$	(46	)	$	2,684
Gas margin		45			222			-			(4	)		263
Other revenues		2			1			1			(4	)		-
Other operations and maintenance		(581	)		(381	)		(216	)		37			(1,141	)
Depreciation and amortization		(243	)		(144	)		(79	)		(19	)		(485	)
Taxes other than income taxes		(184	)		(99	)		(19	)		-			(302	)
Other income and (expenses)		16			9			1			(1	)		25
Interest expense		(123	)		(70	)		(77	)		16			(254	)
Income taxes		(165	)		(76	)		(56	)		24			(273	)
Minority interest and preferred dividends		(4	)		(5	)		(23	)		1			(31	)
Net income	$	255		$	125		$	102		$	4		$	486

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins for the three and nine months ended September 30, 2007, compared with the same periods in 2006. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined as gas revenues less gas purchased for resale. We consider electric, interchange and gas margins useful measures to analyze the change in profitability of our electric and gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

Three Months	Ameren^(a)		UE			CIPS		Genco			CILCORP		CILCO		IP
Electric revenue change:
Effect of weather on native load (estimate)	$	59	$	46		$	3	$	-		$	2	$	2	$	8
UE electric rate increase		15		15			-		-			-		-		-
Storm-related outages		3		2			2		(2	)		-		-		1
JDA- terminated December 31, 2006		-		(35	)		-		(23	)		-		-		-
Interchange revenues		36		36			-		-			-		-		-

Three Months	Ameren^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Elimination of CILCO/AERG intra-company
power supply agreement		30			-			-			-			30			30			-
Illinois settlement agreement-net of
reimbursement		(53	)		-			(8	)		(20	)		(14	)		(14	)		(11	)
Illinois rate redesign, generation repricing, growth and other		15			27			(24	)		7			33			33			(66	)
Total	$	105		$	91		$	(27	)	$	(38	)	$	51		$	51		$	(68	)
Fuel and purchased power change:
Fuel:
Generation and other	$	(21	)	$	(9	)	$	-		$	(17	)	$	2		$	2		$	-
Emission allowance sales (costs)		(16	)		5			-			-			4			3			-
Mark-to-market gains (losses)		4			(1	)		-			-			-			-			-
Price		(30	)		(25	)		-			-			(1	)		(1	)		-
JDA-terminated December 31, 2006		-			23			-			35			-			-			-
Purchased power		(35	)		(22	)		(17	)		48			(27	)		(27	)		2
Power purchase agreement - Entergy Arkansas, Inc.		(8	)		(8	)		-			-			-			-			-
Elimination of CILCO/AERG intra-
company power supply agreement		(30	)		-			-			-			(30	)		(30	)		-
Storm-related energy costs		2			1			-			1			-			-			-
Total fuel and purchased power change	$	(134	)	$	(36	)	$	(17	)	$	67		$	(52	)	$	(53	)	$	2
Net change in electric margins	$	(29	)	$	55		$	(44	)	$	29		$	(1	)	$	(2	)	$	(66	)
Net change in gas margins	$	(2	)	$	(1	)	$	(2	)	$	-		$	1		$	1		$	(1	)
Nine Months
Electric revenue change:
Effect of weather on native load (estimate)	$	105		$	67		$	14		$	-		$	8		$	8		$	16
UE electric rate increase		20			20			-			-			-			-			-
Storm-related outages		9			8			2			(2	)		-			-			1
JDA - terminated December 31, 2006		-			(156	)		-			(69	)		-			-			-
Interchange revenues		128			128			-			-			-			-			-
Elimination of CILCO/AERG intra-company
power supply agreement		83			-			-			-			83			83			-
Illinois settlement agreement - net of
reimbursement		(53	)		-			(8	)		(20	)		(14	)		(14	)		(11	)
FERC-ordered MISO resettlements -
March 2007		16			-			-			12			3			3			-
Illinois rate redesign, generation repricing, growth and other		180			11			28			(16	)		118			118			(35	)
Total	$	488		$	78		$	36		$	(95	)	$	198		$	198		$	(29	)
Fuel and purchased power change:
Fuel:
Generation and other	$	(16	)	$	12		$	-		$	(45	)	$	15		$	16		$	-
Emission allowance sales (costs)		(10	)		3			-			-			12			8			-
Mark-to-market gains (losses)		11			(1	)		-			5			1			1			-
Price		(72	)		(60	)		-			(2	)		(7	)		(7	)		-
JDA - terminated December 31, 2006		-			69			-			156			-			-			-
Purchased power		(77	)		14			(53	)		90			(94	)		(94	)		2
Power purchase agreement - Entergy Arkansas, Inc.		(12	)		(12	)		-			-			-			-			-
Elimination of CILCO/AERG intra-company
power supply agreement		(83	)		-			-			-			(83	)		(83	)		-
FERC-ordered MISO resettlements -
March 2007		(38	)		(12	)		(8	)		-			(4	)		(4	)		(14	)
Storm-related energy costs		(1	)		(2	)		-			1			-			-			-
Total fuel and purchased power change	$	(298	)	$	11		$	(61	)	$	205		$	(160	)	$	(163	)	$	(12	)
Net change in electric margins	$	190		$	89		$	(25	)	$	110		$	38		$	35		$	(41	)
Net change in gas margins	$	10		$	5		$	1		$	-		$	4		$	4		$	(1	)

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

Ameren

Ameren’s electric margin decreased by $29 million for the three months and increased by $190 million for the nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·	Non-rate-regulated Generation selling more power at market-based prices in the third quarter and first nine months of 2007 compared with sales at below-market prices pursuant to cost-based power supply agreements, which expired on December 31, 2006;

·	favorable weather conditions increased native load electric margin by an estimated $33 million and $54 million for the three and nine months ended September 30, 2007, respectively;

·	UE’s electric rate increase that went into effect June 4, 2007, which increased electric margin by an estimated, $15 million and $20 million for the three and nine months ended September 30, 2007, respectively;

an increase in margin on interchange sales primarily because of the termination of the JDA on December 31, 2006. This termination of the JDA provided UE with the ability to sell its excess power, originally obligated to Genco under the JDA at cost, in the spot market at higher purchased power prices. This increase was partially offset by higher purchased power costs of $8 million and $12 million for the three and nine months ended September 30, 2007, respectively, associated with Entergy Arkansas, Inc. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report, for more information on the UE power purchase agreement with Entergy Arkansas, Inc. In addition, increased native load demand, because of warmer weather, reduced excess power available for sale;

·	increased revenues as a result of lower than expected line losses at UE;

·	increased hydroelectric generation, which favorably impacted purchased power cost;

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

·	unrealized mark-to-market net gains on fuel and energy contracts not yet settled increased electric margin by $4 million and $11 million for the three and nine months ended September 30, 2007, respectively; and

decreased fuel costs due to the lack of $4 million in fees levied by the FERC in the nine months ended September 30, 2006, upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant, and the May 2007 MoPSC rate order, which directed UE to transfer $4 million of the total fees to an asset account, which is being amortized over 25 years.

The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·	the combined effect of the elimination of the Ameren Illinois Utilities’ bundled tariffs, implementation of new delivery service tariffs including changes in seasonal rates effective January 2, 2007, and the expiration of power supply contracts;

·	a 15% and 12% increase in coal and related transportation prices for the three and nine months ended September 30, 2007, respectively;

rate relief and customer assistance programs under the Illinois electric settlement agreement reduced electric margin by $53 million. Illinois customer refund payments and credits, including the forgiveness of late payment charges, provided to certain Ameren Illinois Utilities’ electric customers of $159 million for the three and nine months ended

September 30, 2007, decreased electric revenue. As part of the settlement agreement, Ameren expects to receive reimbursements from non-affiliated generators in Illinois totaling $106 million for the three and nine months ended September 30, 2007;

MISO purchased power costs were $18 million and $29 million higher for the three and nine months ended September 30, 2007, respectively. Costs related to participation in the MISO Day Two Energy Market were higher for the year because of a March 2007 FERC order that resettled costs among market participants retroactive to 2005; and

·	decreased emission allowance sales of $20 million and $22 million offset by lower emission allowance costs of $4 million and $12 million for the three and nine months ended September 30, 2007, respectively.

Ameren’s gas margin was comparable in the three months ended September 30, 2007, with the same period in 2006. Ameren’s gas margin increased by $10 million, or 4%, for the nine months ended September 30, 2007, compared with the same period in 2006 primarily because of favorable weather conditions as evidenced by a 14% increase in heating degree-days for the nine months ended September 30, 2007.

Missouri Regulated

UE’s electric margin increased $55 million and $89 million for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The following items had a favorable impact on electric margin

for the third quarter and first nine months of 2007 as compared to the year-ago periods:

an increase in margin on interchange sales primarily because of the termination of the JDA on December 31, 2006. This termination of the JDA provided UE with the ability to sell its excess power, originally obligated to Genco under the JDA at cost, in the spot market at higher market prices. This increase was partially offset by increased purchased power costs of $8 million and $12 million for the three and nine months ended September 30, 2007, respectively, associated with an agreement with Entergy Arkansas, Inc. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report, for more information on the UE power purchase agreement with Entergy Arkansas, Inc. In addition, increased native load demand, because of warmer weather, reduced excess power available for sale;

·	favorable weather conditions increased native load electric margin by an estimated $31 million and $44 million for the three and nine months ended September 30, 2007, respectively;

·	the electric rate increase that went into effect June 4, 2007, which increased electric margin by an estimated $15 million and $20 million for the three and nine months ended September 30, 2007, respectively;

·	increased revenues as a result of lower than expected line losses;

·	increased hydroelectric generation, which favorably impacted purchased power costs;

·	severe storm-related outages in 2006, which reduced electric margin by $3 million and $6 million for the three and nine months ended September 30, 2006, respectively; and

Factors that had an unfavorable impact on electric margin for the three and nine months ended September 30, 2007, as compared to the same periods in the prior year, were as follows:

·	a 24% and 17% increase in coal and related transportation prices for the three- and nine-month periods ended September 30, 2007, respectively;

·	MISO costs were $12 million higher for the nine months ended September 30, 2007, compared to the same period in 2006, due to the March 2007 FERC order;

·	other MISO purchased power costs, excluding the effect of the March 2007 FERC order, were $18 million higher for the third quarter of 2007 and $9 million higher for the nine months ended September 30, 2007, compared to the same periods in 2006; and

·	reduced power plant availability because of planned maintenance activities.

UE’s gas margin was comparable in the three months ended September 30, 2007, with the same period in 2006. UE’s gas margin increased by $5 million, or 11%, for the nine months ended September 30, 2007, compared with the same period in 2006 primarily because of favorable weather conditions as evidenced by a 15% increase in heating degree-days for the nine months ended September 30, 2007.

Illinois Regulated

Illinois Regulated’s electric margin declined by $134 million, or 42%, and $95 million, or 14%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. Illinois Regulated’s gas margin decreased by $4 million in the third quarter of 2007 and increased by $5 million, or 2%, for the nine months ended September 30, 2007, compared with the same periods in 2006.

CIPS

CIPS’ electric margin decreased by $44 million, or 43%, and $25 million, or 12%, for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·	the combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs, including changes in seasonal rates effective January 2, 2007, and the expiration of power supply contracts;

the Illinois settlement agreement reduced electric margin by $8 million. Customer refund payments and credits, including the forgiveness of late payment charges, totaled $54 million for the three and nine months ended September 30, 2007, which were reduced by expected reimbursements of $36 million due from non-affiliated generators and $10 million due from affiliated generators in Illinois; and

·	MISO costs increased $8 million for the nine months ended September 30, 2007, compared to the same period in 2006, because of a March 2007 FERC order that resettled costs among market participants retroactive to 2005.

The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·	MISO purchased power costs, excluding the effect of the March 2007 FERC order discussed above, were $4 million and $16 million lower for the three and nine months ended September 2007, respectively, compared to the same periods in 2006;

·	severe storm-related outages in 2006, which reduced electric margin by $2 million for the three and nine months ended September 30, 2006; and

·	favorable weather conditions, which increased electric margin by an estimated $5 million for the nine months ended September 30, 2007.

CIPS’ gas margin decreased by $2 million for the three months ended September 30, 2007, compared with the same period in 2006 primarily because of reduced transportation service revenues. CIPS’ gas margin increased by $1 million, or 2%, for the nine months ended September 30, 2007, primarily because of favorable weather conditions as evidenced by a 15% inrease in heating degree-days for the nine months ended September 30, 2007.

CILCO (Illinois Regulated)

The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for the three and nine months ended September 30, 2007, as compared with the same periods in 2006:

	Three Months			Nine Months
CILCO (Illinois Regulated)	$	(24	)	$	(29	)
CILCO (AERG)		22			64
Total change in electric margin	$	(2	)	$	35

CILCO’s (Illinois Regulated) electric margin decreased by $24 million, or 45%, and $29 million, or 23%, for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·	the combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs, including changes in seasonal rates effective January 2, 2007, and the expiration of power supply contracts;

the Illinois settlement agreement reduced electric margin by $5 million. Customer refund payments and credits, including the forgiveness of late payment charges, totaled $32 million for the three and nine months ended September 30, 2007, which were reduced by expected reimbursements of $21 million from non-affiliated generators and by $6 million from affiliated generators in Illinois; and

·	MISO costs increased $4 million for the nine months ended September 30, 2007, because of the March 2007 FERC order noted above.

The decrease in electric margin was reduced by favorable weather conditions, which increased electric margin by an estimated $2 million for the nine months ended September 30, 2007.

See Non-rate-regulated Generation below for an explanation of CILCO’s (AERG) change in electric margin for the three and nine months ended September 30, 2007, as compared with the same periods in 2006.

CILCO’s (Illinois Regulated) gas margin was comparable for the three months ended September 30, 2007, with the same period in 2006. CILCO’s (Illinois Regulated) gas margin increased by $4 million, or 7%, for the nine months ended September 30, 2007, compared with the same period in 2006 primarily because of favorable weather conditions as evidenced by a 12% increase in heating degree-days in the first nine months of 2007 and growth in the industrial sector.

IP’s electric margin decreased by $66 million, or 41%, and $41 million, or 13%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·	the combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs, including changes in seasonal rates effective January 2, 2007, and the expiration of power supply contracts;

the Illinois settlement agreement reduced electric margin by $11 million. Customer refund payments and credits, including the forgiveness of late payment charges, totaled $73 million for the three and nine months ended September 30, 2007, which were reduced by expected reimbursements of $49 million from non-affiliated generators and by $13 million from affiliated generators in Illinois; and

·	the March 2007 FERC order, referenced above, reduced IP’s electric margin by $14 million for the nine months ended September 30, 2007, compared to the same period a year ago.

The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·	favorable weather conditions, which increased electric margin by an estimated $2 million and $4 million for the three and nine months ended September 30, 2007, respectively; and

·	severe storm-related outages in 2006, which reduced electric margin by $1 million for the three and nine months ended September 30, 2006.

IP’s gas margin was comparable for the three and nine months ended September 30, 2007, compared with the same periods in 2006, primarily because of reduced transportation service revenues, partially offset by favorable weather conditions as evidenced by a 13% increase in heating degree-days for the nine months ended September 30, 2007.

Non-rate-regulated Generation

Non-rate-regulated Generation’s electric margin increased by $46 million, or 21%, and $196 million, or 34%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.

Genco

Genco’s electric margin increased by $29 million, or 33%, and $110 million, or 42%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

selling power at market-based prices for the three and nine months ended September 30, 2007, compared with selling power at below-market prices pursuant to a cost-based power supply agreement, which expired on December 31, 2006. This was offset, in part, by the loss of margin on sales supplied with power acquired through the JDA;

·	reduced purchased power costs due to the expiration of the JDA;

·	increased power plant availability due to fewer planned outages this year reduced purchased power costs;

·	a reduction of mark-to-market losses on fuel contracts in 2007, which amounted to $5 million for the nine months ended September 30, 2006; and

·	MISO costs were $12 million lower for the nine months ended September 30, 2007, compared with the same period in 2006, as a result of the March 2007 FERC order.

The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·	costs of $20 million for the three and nine months ended September 30, 2007, pursuant to the Illinois electric settlement agreement discussed above; and

·	a 3% increase in coal and related transportation prices for the three and nine months ended September 30, 2007, respectively.

CILCO (AERG)

For the three and nine months ended September 30, 2007, AERG’s electric margin increased by $22 million, or 82%, and $64 million, or 72%, respectively, compared with the same periods in 2006. The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·	increased revenues due to selling power at market-based prices in the third quarter of 2007 compared with sales at below-market prices in 2006 pursuant to a cost-based power supply agreement, which expired on December 31, 2006; and

·	reduced emission costs of $3 million and $8 million for the three and nine months ended September 30, 2007, respectively, compared with the same prior-year periods.

The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared with the year-ago periods:

·	costs of $9 million for the three and nine months ended September 30, 2007, pursuant to the Illinois electric settlement agreement discussed above;

·	revenues and fuel costs decreased due to reduced plant availability because of an extended plant outage; and

·	a 12% increase in coal and related transportation prices for the nine months ended September 30, 2007.

EEI

EEI’s electric margin decreased by $36 million, or 35%, and $28 million, or 12%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·	the lack of emissions allowance sales in 2007, which increased the electric margin by $30 million for the three and nine months ended September 30, 2006;

·	a 5% increase in coal and related transportation prices for the three and nine months ended September 30, 2007; and

·	revenues and fuel costs decreased due to reduced plant availability due to increased unit outages in the three and nine months ended September 30, 2007.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren

Three months – Other operations and maintenance expenses increased $32 million in the third quarter of 2007 compared with the third quarter of 2006 primarily because of higher plant maintenance expenditures of $12 million due to outages at coal-fired plants, increased distribution system reliability and maintenance expenditures, higher labor and employee benefits costs, and increased injuries and damages expenses. Additionally, as part of the Illinois electric settlement agreement, we paid $4 million to the IPA in the third quarter of 2007. The amount of the increase in expenses in the third quarter of 2007 over 2006 was lower than it otherwise would have been because in the third quarter of 2006, we experienced severe storms in our service territory resulting in expenses of $23 million, while there were no major storms in our service territory during the third quarter ended September 30, 2007. Additionally, in the third quarter of 2006, Ameren recorded $7 million of costs related to the December 2005 reservoir breach at UE’s Taum Sauk plant with no similar costs recorded in the third quarter of 2007.

Nine months - Other operations and maintenance expenses increased $108 million in the first nine months of 2007 compared with the first nine months of 2006. Maintenance and labor costs associated with the Callaway refueling and maintenance outage in the second quarter of 2007 added $35 million to other operations and maintenance expenses in the period. Higher non-Callaway labor costs, bad debt reserves, maintenance at coal-fired plants, the IPA payment described above, and distribution system reliability expenditures also increased other operations and maintenance expenses in the first nine months of 2007 compared to the year-ago period. Reducing the effect of these items was the reversal of an accrual of $15 million established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan. Additionally, in the prior-year period, we recognized costs related to the Taum Sauk reservoir breach of $17 million and noncore property sale losses of $7 million at a subsidiary of AERG, items which did not recur in 2007. Increased other operations and maintenance expenses resulting from a severe ice storm in January 2007 in UE’s and CIPS’ service territories were offset by the absence in 2007 of severe summer storms such as those that occurred in the summer of the prior year.

Variations in other operations and maintenance expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:

Missouri Regulated

Three months – Other operations and maintenance expenses were comparable in the third quarter of 2007 with the third quarter of 2006. Increased plant maintenance at coal-fired plants from scheduled outages, increased distribution system reliability and maintenance expenditures, and insurance premiums paid to an affiliate for replacement power coverage in the current year third quarter were offset by the absence of costs related to the Taum Sauk reservoir breach. In addition, there were no severe summer storms in 2007, which resulted in expenses of $16 million in the third quarter of 2006.

Nine months - Other operations and maintenance expenses increased $86 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of ice storm repair expenditures of approximately $25 million and costs associated with the Callaway refueling and maintenance outage of $35 million. Increased plant maintenance at coal-fired plants, increased distribution system reliability and maintenance expenditures, higher labor costs, and insurance premiums for replacement power coverage of $14 million paid to an affiliate also increased other operations and maintenance expenses in the first nine months of 2007 compared with the prior year period. Reducing the effect of these items was the absence in the current year period of costs related to the Taum Sauk reservoir breach and the absence of severe summer storms in 2007 such as those that occurred in the prior year period.

Illinois Regulated

Other operations and maintenance expenses increased $9 million and $17 million in the Illinois Regulated segment in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.

CIPS

Three months – Other operations and maintenance expenses were comparable between periods as the absence of severe summer storms in 2007, such as those that occurred in the summer of the prior year, was offset by increased distribution system reliability and maintenance expenditures and by higher injuries and damages expenses.

Nine months - Other operations and maintenance expenses increased $7 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of increased bad debt reserves as a result of the transition to higher electric rates in Illinois, and increased distribution system reliability expenditures. The reversal in 2007 of the customer assistance program accrual of $4 million,

established in 2006 as noted above, reduced the effect of these increases. The impact of a severe ice storm in January 2007 was offset by the absence in 2007 of severe summer storms such as those that occurred in the summer of the prior year.

CILCO (Illinois Regulated)

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

Nine months – Other operations and maintenance expenses were comparable between periods as an increase in bad debt reserves was offset by the reversal of the customer assistance program accrual of $3 million established in 2006 as noted above.

Three months – Other operations and maintenance expenses increased $6 million in the third quarter of 2007 compared with the third quarter of 2006 primarily because of higher employee benefit costs and increased injuries and damages expenses. Reducing the unfavorable impact of these items was the absence of severe summer storms in 2007 such as those that occurred in the summer of 2006.

Nine months - Other operations and maintenance expenses increased $9 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of higher employee benefit costs and increased bad debt reserves. Reducing the effect of these items was the reversal of the customer assistance program accrual of $8 million, established in 2006 as noted above, and the absence of severe summer storms in 2007 such as those that occurred in the summer of the prior year.

Non-rate-regulated Generation

Other operations and maintenance expenses increased $14 million and $23 million in the Non-rate-regulated Generation segment in the three and nine months ended
September 30, 2007, respectively, compared with the same periods in 2006.

Genco

Three months – Other operations and maintenance expenses increased $5 million in the third quarter of 2007 compared with the third quarter of 2006 primarily because of higher plant maintenance costs due to scheduled outages. Additionally, as part of the Illinois electric settlement agreement, Genco paid $3 million to the IPA in the third quarter of 2007.

CILCORP (Parent Company Only)

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

Nine months - Other operations and maintenance expenses were comparable between periods as increased employee benefit costs in the current year period were offset by the absence of a write-off in 2007, as occurred in the prior year period, of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.

CILCO (AERG)

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

Nine months - Other operations and maintenance expenses increased $7 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of higher plant maintenance costs due to an extended plant outage.

EEI

Three and nine months - Other operations and maintenance expenses increased $2 million and $5 million in the three and nine months ended September 30, 2007, respectively, compared to the prior year periods primarily because of higher plant maintenance costs.

Depreciation and Amortization

Ameren

Three and nine months – Ameren’s depreciation and amortization expenses increased $7 million and $29 million in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The increases were primarily because of capital additions in 2006 and the start of amortization of a regulatory asset in 2007 associated with acquisition integration costs at IP, as required by an ICC order.

Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:

Missouri Regulated

Three months - Depreciation and amortization expenses were comparable between periods as increased depreciation expenses from capital additions were offset by decreased expenses resulting from the extension of UE’s plants’ useful lives in connection with a MoPSC electric rate order issued in May 2007. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information on UE’s electric rate order.

Nine months – Depreciation and amortization expenses increased $9 million in the nine months ended September 30, 2007, primarily because of capital additions in 2006 and early 2007, including CTs purchased in the second quarter of 2006, and storm-related expenditures in 2006.

Illinois Regulated

Depreciation and amortization expenses increased $5 million and $18 million in the Illinois Regulated segment in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.

CIPS & CILCO (Illinois Regulated)

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

Three and nine months – Depreciation and amortization expenses increased $4 million and $15 million in the three and nine months ended September 30, 2007, respectively, primarily because of amortization in 2007 of $4 million and $12 million for the three and nine months ended September 30, 2007, respectively, of a regulatory asset associated with acquisition integration costs, as required by an ICC order.

Non-rate-regulated Generation

Three and nine months - Depreciation and amortization expenses were comparable in the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three and nine months ended September 30, 2007, with the same periods in 2006.

Taxes Other Than Income Taxes

Ameren

Three months – Ameren’s taxes other than income taxes were comparable between periods.

Nine months - Ameren’s taxes other than income taxes decreased $7 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of lower gross receipts and lower property tax expenses.

Variations in taxes other than income taxes in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:

Missouri Regulated

Three and nine months – Taxes other than income taxes increased $4 million and $3 million in the third quarter and first nine months of 2007 compared with the same periods in the prior year primarily because of increased gross receipts taxes.

Illinois Regulated

Taxes other than income taxes in the Illinois Regulated segment decreased $6 million and $10 million for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.

CIPS

Three and nine months – Taxes other than income taxes decreased $3 million and $6 million for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006, primarily because of lower property tax expenses. The nine-month period was also impacted by lower gross receipts taxes in 2007.

CILCO (Illinois Regulated) & IP

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

Non-rate-regulated Generation

Three and nine months - Taxes other than income taxes were comparable in the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three and nine months ended September 30, 2007, with the same periods in 2006.

Other Income and Expenses

Ameren

Three and nine months – Miscellaneous income increased $8 million and $25 million in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006, primarily because of increased

interest income. Miscellaneous income in each period includes interest income on industrial development revenue bonds acquired by UE in conjunction with its purchase of CTs. These amounts are offset by an equivalent amount of interest expense associated with capital leases for the CTs recorded in interest charges on Ameren’s and UE’s statements of income. Miscellaneous expense increased $3 million and $6 million in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006, primarily as a result of contributions made to our charitable trust.

Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:

Missouri Regulated

Three and nine months – Miscellaneous income was comparable between the third quarter of 2007 and the third quarter of 2006. Miscellaneous income increased $6 million for the nine months ended September 30, 2007, compared with the same period in 2006, primarily as a result of increased interest income. As discussed above, miscellaneous income includes interest income related to industrial development revenue bonds that is offset in interest charges on UE’s statement of income. These interest amounts were $7 million for the third quarter in both 2007 and 2006 and $22 million and $16 million for the nine months ended September 30, 2007 and 2006, respectively. Miscellaneous expense was comparable for the three and nine months ended September 30, 2007, with the same periods in 2006.

Illinois Regulated

Miscellaneous income increased $3 million and $7 million in the Illinois Regulated segment in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. Miscellaneous expense was comparable for the three- and nine-month periods in 2007 compared with the same periods in 2006.

CILCO (Illinois Regulated) & IP

Three months – Miscellaneous income was comparable at CILCO (Illinois Regulated) in the third quarter of 2007 with the same period in the prior year. Miscellaneous income increased $2 million at IP in the three months ended September 30, 2007, compared with the same period in 2006 primarily because of increased interest income. Miscellaneous expense was comparable in the third quarter of 2007 with the same period in 2006.

Nine months - Miscellaneous income increased $2 million and $5 million at CILCO (Illinois Regulated) and IP in the nine months ended September 30, 2007, respectively, compared with the same period in 2006 primarily because of increased interest income. Miscellaneous expense was comparable at CILCO (Illinois Regulated) and IP between periods.

CIPS

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

Non-rate-regulated Generation

Other income and expenses were comparable in the Non-rate-regulated Generation segment and at Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three and nine months ended September 30, 2007, with the same periods in 2006.

Interest

Ameren

Three and nine months - Interest expense increased $21 million and $62 million in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings and other items noted below. Interest expense recognized on UE’s capital leases associated with the purchase of CTs is offset by an equivalent amount of interest income recorded in other income and expenses on Ameren’s and UE’s statement of income. With the adoption of FIN 48, we also began to record interest associated with uncertain tax positions as interest expense rather than income tax expense. These interest charges were $2 million and $9 million for the three and nine months ended September 30, 2007, respectively.

Variations in interest expense in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006, were as follows:

Missouri Regulated

Three and nine months – Interest expense increased $7 million and $23 million for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The increase in the third quarter was due primarily to increased interest expense related to the issuance

of $425 million senior secured notes in June 2007. Interest expense increased in the nine-month period primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings and because of increased interest expense related to the June 2007 debt issuance. As discussed above, interest charges include interest expense related to capital leases that is offset in other income and expenses on UE’s statement of income. Interest expense recorded in conjunction with the adoption of FIN 48 was $3 million for the nine months ended September 30, 2007.

Illinois Regulated

Interest expense increased $11 million and $27 million in the Illinois Regulated segment in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.

CIPS

Three months – Interest expense was comparable between periods.

Nine months – Interest expense increased $5 million for the nine months ended September 30, 2007, compared with the same period in 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings.

CILCO (Illinois Regulated)

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

Three months – Interest expense increased $6 million for the third quarter of 2007, compared with the same period in 2006, primarily because of increased short-term borrowings and higher interest rates resulting from reduced credit ratings.

Nine months – Interest expense increased $18 million for the nine months ended September 30, 2007, compared with the same period in 2006, primarily because of the issuance of $75 million senior secured notes in June 2006 and because of increased short-term borrowings and higher interest rates due to reduced credit ratings.

Non-rate-regulated Generation

Interest expense was comparable in the Non-rate-regulated Generation segment in the third quarter of 2007 with the same period in 2006. Interest expense increased $4 million in the nine months ended September 30, 2007, compared with the same period in 2006.

CILCORP (Parent Company Only) & CILCO (AERG)

Three months – Interest expense was comparable between periods.

Nine months - Interest expense increased $2 million and $4 million at CILCORP (Parent Company Only) and CILCO (AERG) for the nine months ended September 30, 2007, respectively, compared with the same period in 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings.

Genco & EEI

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

Income Taxes

Ameren

Three and nine months - Ameren’s effective tax rate decreased between 2007 and 2006.

Variations in effective tax rates in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:

Missouri Regulated

Three months – The effective tax rate decreased in 2007 from 2006 primarily because of an increase in reserves for uncertain tax positions in 2006 for tax returns filed in previous years, along with an increase in expenses deductible for tax purposes, which were not expensed for book purposes in 2007. These decreases were offset by lower favorable tax return-to-accrual adjustments in 2007 compared to the same period in 2006.

Nine months – The effective tax rate decreased in 2007 from 2006, primarily because of the items detailed above, along with the implementation of changes ordered by the MoPSC in UE’s 2007 electric rate order. The effective tax rate for the nine-month period in 2006 was increased by the effect of higher non-deductible expenses than the same period in 2007.

Illinois Regulated

The effective tax rate increased in the Illinois Regulated segment in the three months ended September 30, 2007, and decreased in the nine months ended September 30, 2007,

compared with the same periods in 2006, due to items detailed below.

CIPS

Three and nine months – The effective tax rate increased primarily because of unfavorable tax return-to-accrual adjustments in 2007 compared to favorable tax return-to-accrual adjustments in 2006.

CILCO (Illinois Regulated)

Three months – The effective tax rate increased primarily because of an increase in expenses deductible for tax purposes that were not expensed for book purposes on a pre-tax loss in 2007, along with a decrease in reserves for uncertain tax positions in 2006 for returns filed in previous years as compared to no change in reserves in 2007.

Nine months – The effective tax rate decreased primarily because of an increase in expenses deductible for tax, which were not expensed for book purposes, along with favorable tax return-to-accrual adjustments in 2007 compared with unfavorable tax return-to-accrual adjustments in 2006.

Three months – The effective tax rate increased primarily because of favorable tax return-to-accrual adjustments on a pre-tax book loss in 2007 compared with unfavorable tax

return-to-accrual adjustments in 2006.

Nine months – The effective tax rate decreased primarily because of favorable tax return-to-accrual adjustments in 2007 compared with unfavorable tax return-to-accrual adjustments in 2006.

Non-rate-regulated Generation

The effective tax rate increased in the Non-rate-regulated Generation segment in the three and nine months ended September 30, 2007, compared with the same periods in 2006, due to items detailed below.

Genco

Three and nine months – The effective tax rate increased primarily because of lower reserves for uncertain tax positions in 2006 for tax returns filed in previous years as compared to 2007, a decrease in 2007 of expenses deductible for tax purposes but not expensed for book purposes when compared to 2006, and unfavorable tax return-to-accrual adjustments in 2007 compared with favorable tax return-to-accrual adjustments in 2006.

CILCO (AERG)

Three and nine months – The effective tax rate increased primarily because of lower reserves for uncertain tax positions in 2006 for tax returns filed in prior years, a decrease in expenses in 2007 that were deductible for tax purposes but not expensed for book purposes, and unfavorable tax return-to-accrual adjustments in 2007 compared to favorable tax return-to-accrual adjustments in 2006.

CILCORP (Parent Company Only)

Three and nine months – The effective tax rate decreased primarily because of lower favorable tax return-to-accrual adjustments in 2007 as compared to 2006.

EEI

Three and nine months – The effective tax rate decreased primarily because of an increase in expenses deductible for tax purposes, which were not expensed for book purposes.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO (Illinois Regulated) and IP) continue to be the principal source of cash from operating activities for Ameren and its rate-regulated subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows for Ameren, UE, CIPS, CILCO (Illinois Regulated) and IP. For operating cash flows, Genco and AERG principally rely on power sales to Marketing Company, which sold power through the Illinois power procurement auction in September 2006, and is selling power through other primarily market-based contracts with wholesale and retail customers. In addition to cash flows from operating activities, the Ameren Companies use available cash, money pool or other short-term borrowings from affiliates, commercial paper, or 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, 2007, 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 and in the case of Ameren subsidiaries, equity infusions from

Ameren. The Ameren Companies will incur significant capital expenditures over the next five years for compliance with environmental regulations or to make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Expenditures are expected to be funded with debt. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a discussion of the Illinois electric settlement agreement that among other things, will change the process for power procurement in Illinois in the future and will impact future cash flows of the Ameren Companies, except UE. The settlement resulted in customer refunds and credits during the third quarter of 2007, and will result in further monthly credits to customers through 2010. The Ameren Illinois Utilities will receive reimbursement for a majority of these refunds and credits from Illinois power generators, including Genco and CILCO (AERG).

The following table presents net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2007 and 2006:

	Net Cash Provided By Operating Activities							Net Cash Used In Investing Activities									Net Cash Provided By (Used In) Financing Activities
	2007		2006		Variance			2007			2006			Variance			2007			2006			Variance
Ameren^(a)	$	920	$	1,069	$	(149	)	$	(1,093	)	$	(1,044	)	$	(49	)	$	206		$	(87	)	$	293
UE		519		620		(101	)		(535	)		(611	)		76			15			(27	)		42
CIPS		11		127		(116	)		(115	)		(47	)		(68	)		99			(80	)		179
Genco		153		49		104			(137	)		(83	)		(54	)		(15	)		36			(51	)
CILCORP		20		104		(84	)		(141	)		(33	)		(108	)		201			(71	)		272
CILCO		48		127		(79	)		(141	)		(75	)		(66	)		162			(52	)		214
IP		23		108		(85	)		(133	)		(129	)		(4	)		110			21			89

(a)

Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

Cash Flows from Operating Activities

Ameren’s cash from operating activities decreased in the first nine months of 2007, as compared with the first nine months of 2006. The Illinois electric settlement agreement resulted in $45 million of customer refunds and program funding. Under the terms of the settlement agreement, the Ameren Illinois Utilities will receive reimbursements from Illinois electricity generators in future months for a majority of these expenditures. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from Illinois electric customers lagged payments for power purchases. A decrease in income taxes paid (net of refunds) of $59 million benefited cash flows from operations in the first nine months of 2007. Increases in electric and gas margins also benefited operating cash flows, but were reduced by higher operations and maintenance expenses as discussed in Results of Operations, primarily as a result of the Callaway nuclear plant refueling and maintenance outage and storm-related outage repairs.

At UE, cash from operating activities decreased in the first nine months of 2007, compared with the first nine months of 2006. Increased storm repair costs and increased other operations and maintenance expenses as a result of the Callaway nuclear plant refueling and maintenance outage were only partially offset by increased electric and gas margins, as discussed in Results of Operations. In addition, there was an increase in accounts receivable, primarily because of higher prices for interchange power sales and warmer summer weather. Compared to the prior-year period, decreases in cash paid for Taum Sauk-related costs (net of insurance recoveries) of $24 million, and a decrease in income tax payments (net of refunds) of $97 million benefited cash flows from operations.

At CIPS, cash from operating activities decreased in the first nine months of 2007, compared with the first nine months of 2006. Operating cash flows were lower, primarily because of $15 million of customer refunds and program funding related to the Illinois electric settlement agreement, and increased other operations and maintenance expenses. Under the terms of the settlement agreement, CIPS will receive reimbursements from Illinois electricity generators in future months for a portion of these expenditures. See Note 2 – Rate and Regulatory Matters for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, and past due customer accounts increased due to higher rates and uncertainty about future rate relief programs. Income tax payments (net of refunds) decreased $26 million, benefiting cash flows from operations.

Genco’s cash from operating activities increased in the first nine months of 2007 compared to the 2006 period, primarily because of an increase in electric margins, as discussed in Results of Operations, and a reduction in cash spent for fuel inventory due to large cash outlays made in 2006 to replenish coal inventory after disruptions in rail deliveries caused by train derailments. Reducing these increases in cash from operating activities was an increase in income tax payments (net of refunds) of $23 million.

Cash from operating activities decreased for CILCORP and CILCO in the nine months ended September 30, 2007,

compared with the same period of 2006. The positive cash effect of increased electric margins discussed in Results of Operations was more than offset by $9 million of customer refunds and program funding related to the Illinois electric settlement agreement. Under the terms of the settlement agreement, CILCO will receive reimbursements from Illinois electricity generators in future months for a portion of these expenditures. See Note 2 – Rate and Regulatory Matters for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, and past due customer accounts increased due to higher rates and uncertainty about future rate relief programs. In addition, Income tax payments (net of refunds) increased $21 million and $18 million for CILCORP and CILCO, respectively.

IP’s cash from operating activities decreased in the nine months ended September 30, 2007, compared with the same period in 2006. The Illinois electric settlement agreement resulted in $21 million of customer refunds and program funding. Under the terms of the settlement agreement, IP will receive reimbursements from Illinois electricity generators in future months for a portion of these expenditures. See Note 2 – Rate and Regulatory Matters for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, and past due customer accounts increased due to higher rates and uncertainty about future rate relief programs. Storm repair costs increased $11 million compared to the prior year, and income tax payments (net of refunds) increased by $32 million, further reducing cash flows from operations.

Cash Flows from Investing Activities

Ameren had an increase in cash used in investing activities in the first nine months of 2007 compared to the first nine months of 2006. Net cash used for capital expenditures increased in 2007 as a result of increased storm repair costs, power plant scrubber projects and upgrades at various power plants. These expenditures were offset by the lack of CT acquisitions in 2007 as occurred in 2006. The absence in 2007 of $11 million of proceeds from sales of non-core properties received in 2006 also contributed to the increase in cash used in investing activities. A decrease in purchases of emission allowances was partially offset by fewer sales of emission allowances resulting in a $19 million net benefit to investing cash flows.

UE’s cash used in investing activities decreased in the first nine months of 2007, compared to the same period in 2006, principally because of the $292 million expended for CT purchases in 2006, partially offset by a $152 million increase in capital expenditures in the first nine months of 2007 as compared with the first nine months of 2006. The increased capital expenditures in 2007 were related to storm repair costs, a power plant scrubber project, and other power plant upgrades. In the 2006 period, UE received proceeds of $67 million from an intercompany note related to the transfer of UE’s Illinois territory to CIPS, which had reduced cash used in investing activities in the same period in 2006.

CIPS had an increase in its net use of cash from investing activities during 2007 as compared to the same period in 2006. The net $68 million increase was primarily due to an increase in money pool advances. In the 2007 period, CIPS made net advances of $94 million compared to $18 million in the 2006 period. Reducing this increase in net use of cash from investing activities, capital expenditures decreased by $5 million compared to the prior year.

Genco’s cash used in investing activities increased in the first nine months of 2007 compared with the 2006 period. Capital expenditures increased $73 million, principally due to a scrubber project at one of its power plants and various plant upgrades, while emission allowance purchases decreased by $19 million.

CILCORP’s and CILCO’s cash used in investing activities increased in the nine months ended September 30, 2007, compared with the same period in 2006. Cash flow used in investing activities increased as a result of a $108 million increase in capital expenditures, primarily due to a power plant scrubber project and plant upgrades at AERG. The absence in 2007 of $11 million of proceeds received in 2006 from the sale of leveraged leases, and (for CILCORP only) the absence in 2007 of a 2006 note receivable payment from Resources Company in the amount of $42 million related to the 2005 transfer of leveraged leases from CILCORP to Resources Company also resulted in an increase in cash used in investing activities. The receipt of a $42 million repayment of prior-year money pool advances and a $12 million reduction of emission allowance purchases reduced cash flows used in investing activities in the 2007 period compared to 2006.

IP’s cash used in investing activities increased in the first nine months of 2007 compared to the same period in 2006 as a result of increased capital expenditures.

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

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

may be purchased, among other things. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.

Cash Flows from Financing Activities

Cash provided by financing activities increased for Ameren in the first nine months of 2007 from the year-ago period. Cash from financing activities increased as a result of a

$425 million debt issuance in June 2007 by UE, which was larger than the prior year’s issuances that totaled $232 million. The proceeds of the $425 million offering were used to reduce short-tem debt at UE. Overall, short-term debt increased $432 million year-over-year at Ameren. The increased short-term debt was used to pay maturing long-term notes and to fund working capital requirements at Ameren’s subsidiaries. Cash was reduced by a $7 million decrease in common stock issuances and a $327 million increase in long-term debt redemptions, repurchases and maturities, including the maturity of $350 million in notes at Ameren Corporation in the first nine months of 2007.

UE had a net source of cash from financing activities in the first nine months of 2007, compared to a net use of cash in the same period of the prior year. Contributing to the increase was the issuance of $425 million in long-term debt in June 2007. The proceeds were used to reduce short-term debt. Overall, short-term debt decreased $142 million in 2007 compared to an increase of $128 million in 2006. Short-term borrowings were used in 2007 to fund working capital requirements and increased capital expenditures, and in 2006 principally to fund the acquisition of CTs. A $92 million increase in dividend payments and $20 million of net repayments on an intercompany borrowing arrangement with Ameren reduced cash provided by financing activities in the first nine months of 2007 compared to the same period in 2006.

CIPS had a net source of cash from financing activities for the nine months ended September 30, 2007, compared to a net use of cash for the first nine months of 2006. Cash from financing activities increased as a result of a $100 million net increase in short-tem debt, a $50 million decrease in dividends paid, a $20 million reduction in long-term debt maturities, and the absence in 2007 of a 2006 intercompany note payment to UE in the amount of $67 million. Reducing these positive effects was the absence in 2007 of $61 million in proceeds from long-term debt issuances in 2006.

Genco had a net use of cash from financing activities for the nine months ended September 30, 2007, compared to a net source of cash for the first nine months of 2006. The increase in cash used in financing activities in 2007 was a result of a $20 million increase in dividend payments and a $75 million capital contribution received in 2007 compared to $150 million received in 2006. Reducing the net cash used in financing activities was a net increase in short-term debt of $75 million in the first nine months of 2007 compared to the same period in 2006.

CILCORP and CILCO had a net source of cash from financing activities for the nine months ended September 30, 2007, compared to a net use of cash for the first nine months of 2006. Short-term debt increased year-over-year by $325 million for CILCORP and $200 million for CILCO. Dividends were not paid by either company in 2007, compared to $50 million and $65 million paid in 2006 by CILCORP and CILCO, respectively. Also benefiting cash in 2007 compared to 2006 was the absence of money pool repayments in 2007, compared to 2006 repayments of $92 million at CILCORP and $99 million at CILCO. In addition, there was a $14 million capital contribution received by CILCO in 2007 from CILCORP. Cash flows from financing activities were reduced by a $43 million increase in CILCORP note repayments, a $96 million reduction in long-term debt proceeds at both CILCORP and CILCO, and increased redemptions, repurchases, and maturities of long-term debt of $18 million and $30 million at CILCORP and CILCO, respectively.

IP had a net increase in cash from financing activities in the first nine months of 2007, compared to the same period of the prior year. Cash benefited by $125 million of short-term debt borrowings in 2007 compared to none in 2006, a $17 million net increase in money pool borrowings, and by the lack of $17 million in TFN overfunding. These benefits to cash were reduced by the lack of long-term debt proceeds in 2007, compared to $75 million in 2006.

Short-term Borrowings and Liquidity

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

The following table presents the various committed bank credit facilities of the Ameren Companies and AERG and their availability as of September 30, 2007:

Credit Facility	Expiration	Amount Committed		Amount Available
Ameren, UE and Genco:
Multiyear revolving^(a)	July 2010	$	1,150	$	728
CIPS, CILCORP, CILCO, IP and AERG:
2007 Multiyear revolving⁽^b⁾	January 2010		500		-
2006 Multiyear revolving^(c)	January 2010		500		125

(a)	Ameren Companies may access this credit facility through intercompany borrowing arrangements. The maximum amount directly available to Ameren, UE and Genco under the facility is $1.15 billion, $500 million and $150 million, respectively.

(b)

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

(c)

The maximum amount available to each borrower at September 30, 2007, including for issuance of letters of credit, was limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $150 million, IP - $150 million and AERG - $200 million. In July 2007, CILCO shifted $75 million of its capacity under this facility to the 2007 $500 million credit facility. Accordingly, as of October 31, 2007, CILCO had a sublimit of $75 million under this facility and a $75 million sublimit under the 2007 credit facility.

In addition to committed credit facilities, a further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 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. The authorization was effective as of April 1, 2006, and terminates on March 31, 2008. IP has unlimited short-term debt authorization from FERC.

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

With the repeal of PUHCA 1935, the issuance of short-term unsecured 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.

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

Long-term Debt and Equity

The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt (net of any issuance discounts and including any redemption premiums) and preferred stock for the nine months ended September 30, 2007 and 2006, for the Ameren Companies. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 4 – Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report.

		Nine Months
	Month Issued, Redeemed, Repurchased or Matured	2007		2006
Issuances
Long-term debt
UE:
6.40% Senior secured notes due 2017	June	$	425	$	-
CIPS:
6.70% Senior secured notes due 2036	June		-		61
CILCO:
6.20% Senior secured notes due 2016	June		-		54
6.70% Senior secured notes due 2036	June		-		42
IP:
6.25% Senior secured notes due 2016	June		-		75
Total Ameren long-term debt issuances		$	425	$	232


		Nine Months
	Month Issued, Redeemed, Repurchased or Matured	2007		2006
Common stock
Ameren:
DRPlus and 401(k)	Various	$	71	$	78
Total common stock issuances		$	71	$	78
Total Ameren long-term debt and common stock issuances		$	496	$	310
Redemptions, Repurchases and Maturities
Long-term debt
Ameren:
2002 5.70% notes due 2007	February	$	100	$	-
Senior notes due 2007	May		250		-
CIPS:
7.05% First mortgage bonds due 2006	June		-		20
CILCORP:
9.375% Senior notes due 2029	March/April		-		12
CILCO:
7.73% First Mortgage bonds due 2025	July		-		20
7.50% First mortgage bonds due 2007	January		50		-
IP:
Note payable to IP SPT:
5.65% Series due 2008	Various		65		-
5.54% Series due 2007	Various		-		86
Preferred Stock
CILCO:
5.85% Series	July		1		1
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities		$	466	$	139

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, 2007:

	Effective Date	Authorized Amount		Issued		Available
Ameren	June 2004	$	2,000	$	459	$	1,541
UE	October 2005		1,000		685		315
CIPS	May 2001		250		211		39

In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus.

Ameren is also currently selling newly issued shares of its common stock under certain of its 401(k) plans pursuant to effective SEC Form S-8 registration statements. Under DRPlus and its 401(k) plans, Ameren issued a total of 1.4 million new shares of common stock valued at $71 million in the nine months ended September 30, 2007.

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

Indebtedness Provisions and Other Covenants

See Note 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, 2007, 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. Inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets or make our access to the capital markets uncertain or limited. Such events would increase our cost of

capital and adversely affect our ability to access the capital markets.

Dividends

The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The board of directors has not set specific targets or payout parameters when declaring common stock dividends. However, the board considers various issues, including Ameren’s historical earnings and cash flow, projected earnings, projected cash flow and potential cash flow requirements, dividend payout rates at other utilities, return on investments with similar risk characteristics, impacts of regulatory orders or legislation and overall business considerations.

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 and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At September 30, 2007, except as discussed below with respect to the 2007 $500 million credit facility and the 2006 $500 million credit facility, none of these circumstances existed at the Ameren Companies and, as a result, they were allowed to pay dividends.

The 2007 $500 million credit facility and 2006 $500 million credit facility limit CIPS, CILCORP, CILCO and IP to common and preferred stock dividend payments of $10 million per year each if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below investment-grade credit rating from either Moody’s or S&P. With respect to AERG, which currently is not rated by Moody’s or S&P, the common and preferred stock dividend restriction will not apply if its ratio of consolidated total debt to consolidated operating cash flow, pursuant to a calculation defined in the facilities, is less than or equal to 3.0 to 1. 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, 2007, AERG was in compliance with the debt-to-operating cash flow ratio test in the 2007 and 2006 $500 million credit facilities. The other borrowers thereunder are not currently limited in their dividend payments by this provision of the 2007 or 2006 $500 million credit facilities.

The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the nine months ended September 30, 2007 and 2006.

	Nine Months
	2007		2006
UE	$	246	$	154
CIPS		-		50
Genco		113		93
CILCORP^(a)		-		50
Nonregistrants		36		44
Dividends paid by Ameren	$	395	$	391

(a)	CILCO paid to CILCORP dividends of $50 million for the nine months ended September 30, 2006.

Contractual Obligations

For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 14 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K, 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. See also Note 1 – Summary of Significant Accounting Policies to our financial statements under Part I, Item 1, of this report for the unrecognized tax benefits under the provisions of FIN 48.

Subsequent to December 31, 2006, obligations related to the procurement of coal and related transportation, natural gas and nuclear fuel materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $5,560 million, $1,759 million, $400 million, $356 million, $1,346 million, $1,346 million and $1,527 million, respectively, as of September 30, 2007. The Ameren Companies adopted the provisions of FIN 48 on January 1, 2007. The amount of unrecognized tax benefits under the provisions of FIN 48 are $155 million, $58 million, $15 million, $36 million, $18 million, $18 million and $12 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. UE also entered into a commitment to purchase heavy forgings during 2007. As of September 30, 2007, UE’s commitment to purchase heavy forgings totaled $88 million. Total obligations at September 30, 2007, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $6,415 million, $2,301 million, $445 million, $392 million, $1,409 million, $1,409 million and $1,680 million, respectively.

As a result of the Illinois electric settlement agreement reached in July 2007 and the enactment of related legislation into law, which occurred on August 28, 2007, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million

from Genco and $28 million from AERG. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco and CILCO (AERG) incurred charges to earnings of $59 million, $8 million, $5 million,

$11 million, $24 million and $11 million, respectively, under the terms of the settlement agreement during the quarter ended September 30, 2007. At September 30, 2007, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $108 million, $37 million, $21 million and $50 million, respectively. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for additional information regarding the Illinois electric settlement agreement.

Credit Ratings

The following table presents the principal credit ratings of the Ameren Companies by Moody’s, S&P and Fitch effective on the date of this report:

	Moody’s	S&P	Fitch
Ameren:
Issuer/corporate credit rating	Baa2	BBB-	BBB+
Unsecured debt	Baa2	BB+	BBB+
Commercial paper	P-2	A-3	F2
UE:
Issuer/corporate credit rating	Baa1	BBB-	A-
Secured debt	A3	BBB	A+
Commercial paper	P-2	A-3	F2
CIPS:
Issuer/corporate credit rating	Ba1	BB	BB+
Secured debt	Baa3	BBB	BBB
Genco:
Issuer/corporate credit rating	-	BBB-	BBB+
Unsecured debt	Baa2	BBB-	BBB+
CILCORP:
Issuer/corporate credit rating	-	BB	BB+
Unsecured debt	Ba2	B+	BB+
CILCO:
Issuer/corporate credit rating	Ba1	BB	BB+
Secured debt	Baa2	BBB	BBB
IP:
Issuer/corporate credit rating	Ba1	BB	BB+
Secured debt	Baa3	BBB-	BBB

During March and April of 2007, Moody’s, S&P, and Fitch downgraded various credit ratings of certain of the Ameren Companies. Depending on the specific credit rating agency action and the specific legal entities affected, the downgrade of these credit ratings was a result of the actions of various Illinois state legislators, including passage of forms of legislation that would have rolled back and frozen the electric rates of CIPS, CILCO and IP, and in the case of UE was prompted by higher costs, lower financial metrics and a continued challenging regulatory environment in Missouri.

On August 1, 2007, Fitch changed the rating outlook at Ameren to stable. In addition, Fitch revised the rating watch on CIPS, CILCORP, CILCO and IP to positive. The positive watch followed the announcement of the Illinois electric settlement agreement. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for further discussion of the Illinois settlement agreement.

On August 29, 2007, Moody’s changed the rating outlook at Ameren and Genco to stable. The rating outlook of CIPS, CILCORP, CILCO, and IP was upgraded to positive. These actions were prompted by the Illinois electric settlement agreement. Moody’s stated that “the settlement significantly reduces the likelihood of a rate freeze being enacted in Illinois and provides the foundation for a potentially improving political and regulatory environment for investor-owned-utilities in the state.”

On August 29, 2007, S&P issued a research update in response to the Illinois settlement agreement, as discussed above. The outlook on the ratings of Ameren, UE and Genco was changed to stable. The outlook on the ratings of CIPS, CILCORP, CILCO, and IP was upgraded to positive. On September 6, 2007, S&P upgraded its senior secured debt ratings of UE, CIPS, and CILCO from “BBB-” to “BBB” as a result of changes in its first mortgage bond rating methodology.

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made as of the end of the third quarter of 2007 were $76 million, $4 million, $8 million, $27 million, $27 million, and $33 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively, resulting from our reduced corporate and issuer credit ratings. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at September 30, 2007, could have resulted in Ameren, UE, CIPS, CILCORP, CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to $160 million, $43 million, $16 million, $20 million, $22 million, $22 million, and $39 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease depending upon the credit ratings of the borrower. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

OUTLOOK

Below are some key events and trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2007 and beyond.

Revenues

The earnings of UE, CIPS, CILCO and IP are largely determined by the regulation of their rates by state agencies. With rising costs, including fuel and related transportation, purchased power, labor and material costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, Ameren, UE, CIPS, CILCO and IP expect to experience regulatory lag until requests to increase rates to recover such costs are granted by state regulators. As a result, Ameren, UE, CIPS, CILCO and IP expect to be entering into a period where more frequent rate cases will be necessary. The Ameren Illinois Utilities filed delivery service rate cases with the ICC in November 2007 due to inadequate recovery of costs and low returns on equity being experienced in 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million and IP - $139 million). The electric rate increase requests were based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion and a test year ended December 31, 2006, with certain prospective updates. In addition, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - $15 million increase, CILCO - $4 million decrease and IP - $56 million increase). The natural gas rate change requests were based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion and a test year ended December 31, 2006, with certain prospective updates. The ICC has until October 2008 to render a decision in these rate cases. UE is actively considering the timing of its next electric rate case filing in Missouri.

In current and future rate cases, UE, CIPS, CILCO and IP will also seek cost recovery mechanisms from their state regulators to reduce regulatory lag. In their electric and natural gas delivery service rate cases filed in November 2007, the Ameren Illinois Utilities requested ICC approval to implement rate adjustment mechanisms for bad debt expenses, electric infrastructure investments and the decoupling of natural gas revenues from sales volumes. In July 2005, a law was enacted that enables the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri’s utilities. Rules for the fuel and purchased power cost recovery mechanism were approved by the MoPSC in September 2006. Detailed rules for the environmental cost recovery mechanism are being developed and expected to be effective in the first half of 2008.

Average residential electric rates for CIPS, CILCO and IP increased significantly following the expiration of a rate freeze at the end of 2006. Electric rates rose because of the increased cost of power purchased on behalf of the Ameren Illinois Utilities’ customers and an increase in electric delivery service rates. Due to the magnitude of these increases, a comprehensive settlement agreement was reached with key stakeholders in Illinois that provides approximately $1 billion of funding for rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Pursuant to the settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and $28 million from AERG. To fund these contributions, the Ameren Illinois Utilities, Genco and AERG will need to increase their respective borrowings.

As part of the Illinois electric settlement agreement and related legislation, the reverse auction used for power procurement in Illinois was discontinued and replaced with a new power procurement process led by the IPA, beginning in 2009. In 2008, utilities will contract for necessary baseload, intermediate and peaking power requirements through a request-for-proposal process, subject to ICC review and approval. Existing supply contracts from the September 2006 reverse auction will remain in place. The impact of the new procurement process in Illinois is uncertain.

The MoPSC issued an order, as clarified, granting UE a $43 million increase in base rates for electric service with new electric rates effective June 4, 2007. This order included provisions to extend UE's Callaway nuclear plant and fossil generation plant lives and to change the income tax method associated with cost of property removal. Such provisions are expected to decrease Ameren's and UE's expenses by $58 million annually. The MoPSC also approved a stipulation and agreement authorizing an increase in UE’s annual natural gas delivery revenues of $6 million, effective April 1, 2007. UE agreed not to file a natural gas delivery rate case before March 15, 2010.

·	See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a further discussion of Illinois and Missouri rate matters.

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

·	The availability and performance of UE’s, Genco’s, AERG’s and EEI’s electric generation fleet can materially impact their revenues. UE, Genco and CILCO are seeking to raise the equivalent availability and capacity

factors of their power plants through greater investments and a process improvement program.

All but 5 million megawatthours of Genco and AERG’s pre-2006 wholesale and retail electric power supply agreements expired during 2006. In 2007, 1 million megawatthours of these agreements will expire and another 2 million contracted megawatthours will expire in 2008. These agreements had an average embedded selling price of $36 per megawatthour. These agreements are being replaced with market-based sales. The Non-rate-regulated Generation segment expects to generate 31 million megawatthours of power in 2007 (Genco – 17 million, AERG – 6 million, EEI – 8 million).

The marketing strategy for Non-rate-regulated Generation is to optimize generation output in a low risk manner to minimize earnings and cash flow volatility, while capitalizing on its low-cost generation fleet to provide for solid, sustainable returns. Through a mix of physical and financial sales contracts, including contracts resulting from the Illinois 2006 power procurement auction and the Illinois electric settlement agreement, the Non-rate-regulated Generation segment has sold approximately 90% of its expected 2007 generation output at an average price of $51 per megawatthour (fiscal year 2008 - 75%, or 24 million megawatthours; fiscal year 2009 - 55%, or 18 million megawatthours). Expected sales in 2007 include an estimated 7.6 million megawatthours of power sold through the 2006 Illinois power procurement auction at about $65 per megawatthour (2008 - 6.8 million, 2009 - 4.3 million).

The future development of ancillary services and capacity markets in MISO could increase the electric margins of UE, Genco, AERG and EEI. Ancillary services are services necessary to support the transmission of energy from generation resources to loads while maintaining reliable operation of the transmission provider's transmission system. A capacity market allows participants to purchase or sell capacity products that meet reliability requirements. MISO is currently in the process of developing a centralized regional wholesale ancillary services market, which is expected to begin during 2008. In September 2007, MISO filed a new proposed ancillary services market tariff with the FERC subject to normal FERC procedural review. We expect MISO will begin development of a capacity market once its ancillary services market is in place.

We expect continued economic growth in our service territory to benefit energy demand in 2007 and beyond, but higher energy prices could result in reduced demand from customers, especially in Illinois. Future energy efficiency programs developed by UE, CIPS, CILCO and IP could also result in reduced demand for our electric generation and our electric and gas transmission and distribution services.

Fuel and Purchased Power

In 2006, 85% of Ameren’s electric generation (UE - 77%, Genco - 97%, CILCO - 99%, EEI – 100%) was supplied by its coal-fired power plants. About 93% of the coal used by these plants (UE - 97%, Genco - 87%, CILCO - 69%, EEI - 100%) was delivered by railroads from the Powder River Basin in Wyoming. In the past, deliveries from the Powder River Basin have been restricted because of rail maintenance, weather and derailments. As of September 30, 2007, coal inventories for UE, Genco, AERG and EEI were adequate, and consistent with historical levels. Disruptions in coal deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.

Ameren’s coal and related transportation costs are expected to increase 15% to 20% in 2007 over 2006 and 5% to 10% in 2008. Further increases are expected beyond 2008. Ameren’s nuclear fuel costs are also expected to rise over the next few years. 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 in Part I of this report for information about the percentage of fuel and transportation requirements that are price-hedged for 2007 through 2011.

·	In 2007, Ameren and IP will experience higher year-over-year purchased power expenses as the amortization of certain favorable purchase accounting adjustments associated with the IP acquisition was completed in 2006.

·	In 2007, Ameren expects to reduce levels of emission allowance sales in order to retain remaining allowances for future environmental 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. In February 2007, UE submitted plans and an environmental report to FERC to rebuild the upper reservoir at its Taum Sauk plant, assuming successful resolution of outstanding issues with authorities of the state of Missouri. UE received approval from FERC to rebuild the upper reservoir in August 2007 and hired a contractor in November 2007. Should the Taum Sauk plant be rebuilt, UE would expect it to be out of service through at least the fall of 2009, 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 (but not penalties or lost electric margins)

caused by the breach, including rebuilding the plant, will be covered by insurance. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. As a result of this breach, UE is engaged in litigation initiated by certain private parties and by authorities in the state of Missouri. UE is currently in discussions with state authorities to resolve outstanding issues associated with this incident. The Taum Sauk incident is also under investigation at the MoPSC. 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. 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 further discussion of Taum Sauk matters.

·	UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in the fall of 2008 and is expected to last 30 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 at 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 and gas rates.

·	Genco expects its annual depreciation expense will decrease by $12 million annually based on a depreciation study completed in September 2007.

·	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 2007 and 2016, Ameren expects that certain Ameren Companies will be required to invest between $3.5 billion and $4.5 billion to retrofit their power plants with pollution control equipment. Costs for these types of projects continue to escalate. These investments will also result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 50% of this investment will be in Ameren’s regulated UE operations, and it is therefore 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.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. The costs to comply with future legislation or regulations could be so expensive that Ameren and other similarly-situated electric power generators may be forced to close some coal-fired facilities. Ameren will provide a report on how it is responding to rising regulatory, competitive, and public pressure to significantly reduce carbon dioxide and other emissions from current and proposed power plant operations. The report will include Ameren’s climate change strategy and activities, current greenhouse gas emissions, and analysis with respect to plausible future greenhouse gas scenarios. Ameren will issue this report in mid-December 2007. Investments to control carbon emissions at Ameren’s coal-fired plants would significantly increase future capital expenditures and operations and maintenance expenses.

UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. At this time, UE does not expect to require new baseload generation capacity until 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 that would use coal or nuclear fuel. In 2007, UE signed an agreement with UniStar Nuclear to assist UE in the preparation of a combined construction and operating license application (COLA) for filing with the NRC. A COLA describes how a nuclear plant would be designed, constructed and operated. In addition, UE has also signed contracts for certain long lead-time equipment. Preparing a COLA and entering into these contracts does not mean a decision has been made to build a nuclear plant. They are only the first steps in the regulatory licensing and procurement process. UE and UniStar Nuclear must submit the COLA to the NRC in 2008 to be eligible for incentives available under provisions of the 2005 Energy Policy Act.

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

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

Affiliate Transactions

As a result of the termination of the JDA on December 31, 2006, UE and Genco no longer have the obligation to provide power to each other. UE is able to sell any excess power it has at market prices, which we believe will most likely be higher than the prices paid to it by Genco. Genco will no longer receive the margins on sales that it made, which were fulfilled with power from UE. The electric rate order issued in May 2007 by the MoPSC incorporated the net decrease in UE’s revenue requirement from increased margins expected to result from the termination of the JDA. See Note 7 - Related Party Transactions to our financial statements under Part I, Item 1, of this report for a discussion of the effects of terminating the JDA.

Other

In 2006, Ameren realized gains on sales of noncore properties, including leveraged leases. The net benefit of these sales to Ameren in 2006 was 16 cents per share. Ameren continues to pursue the sale of its interests in its remaining three leveraged lease assets. Ameren does not expect to achieve similar sales levels of noncore properties in 2007.

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

REGULATORY MATTERS

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

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

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

Interest Rate Risk

We are exposed to market risk through changes in interest rates. The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable-rate debt outstanding at September 30, 2007:

	Interest Expense		Net Income^(a)
Ameren	$	20	$	(13	)
UE		6		(4	)
CIPS		2		(1	)
Genco		1		(1	)
CILCORP		5		(3	)
CILCO		4		(2	)
IP		6		(4	)

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

The estimated changes above do not consider potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably act to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure.

Credit Risk

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

Our physical and financial instruments are subject to credit risk consisting of trade accounts receivable and executory contracts with market risk exposures. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At September 30, 2007, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales or delivery of electricity and natural gas to customers in Missouri and Illinois. UE, CIPS, Genco, CILCO, AERG, IP, AFS and Marketing Company may have credit exposure associated with power purchase and sale activity with nonaffiliated companies. These companies also have credit exposure to affiliates. At September 30, 2007, UE’s, CIPS’, Genco’s, CILCO’s, AERG’s, IP’s, AFS’ and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading purchases and sales was each less than $1 million, net of collateral (2006 – less than $1 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program that involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged leases. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $32 million at September 30, 2007 (2006 - $35 million).

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

Equity Price Risk

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

Commodity Price Risk

We are exposed to changes in market prices for electricity, fuel, and natural gas. UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are partially hedged through sales agreements. Genco, AERG and EEI also seek to sell power forward to wholesale, municipal and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through structured risk management programs and policies, which include structured forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of UE, Genco, AERG and EEI is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.

The following table shows how our earnings might decrease if power prices were to decrease by 1% on unhedged economic generation for the remainder of 2007 through 2010:

	Net Income^(a)
Ameren	$	(23	)
UE		(9	)
Genco		(7	)
CILCO (AERG)		(2	)
EEI		(6	)

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

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

Similar techniques are used to manage risks associated with fuel exposures for generation. Most UE, Genco, AERG and EEI fuel supply contracts are physical forward contracts. UE, Genco, AERG and EEI do not have a provision similar to the PGA clause for electric operations, so UE, Genco, AERG and EEI have entered into long-term contracts with various suppliers to purchase coal and nuclear fuel to manage their

exposure to fuel prices. The coal hedging strategy is intended to secure a reliable coal supply while reducing exposure to commodity price volatility. Price and volumetric risk mitigation is accomplished primarily through periodic bid procedures, whereby the amount of coal purchased is determined by the current market prices and the minimum and maximum coal purchase guidelines for the given year. We generally purchase coal up to five years in advance, but we may purchase coal beyond five years to take advantage of favorable deals or market conditions. The strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions.

Transportation costs for coal and natural gas can be a significant portion of fuel costs. We typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. The natural gas transportation expenses for the distribution utility companies and the gas-fired generation units are controlled by FERC via published tariffs with rights to extend the contracts from year to year. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariffs for our requirements.

The following table presents the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of CIPS, CILCO and IP, which own no generation, that are price-hedged over the remainder of 2007 through 2011:

	2007			2008			2009 – 2011
Ameren:
Coal		100	%		98	%	51	%
Coal transportation		100			96		44
Nuclear fuel		100			100		73
Natural gas for generation		100			19		-
Natural gas for distribution	(a)				26		12
Purchased power for Illinois Regulated^(b)		100			91		60
UE:
Coal		100	%		99	%	54	%
Coal transportation		100			97		62
Nuclear fuel		100			100		73
Natural gas for generation		100			14		-
Natural gas for distribution	(a)				58		9
CIPS:
Natural gas for distribution	(a)				23	%	14	%
Purchased power^(b)		100	%		91		60
Genco:
Coal		100	%		100	%	47	%
Coal transportation		100			98		32
Natural gas for generation		100			17		-
CILCORP/CILCO:
Coal (AERG)		100	%		83	%	41	%
Coal transportation (AERG)		100			79		24
Natural gas for distribution	(a)				20		10
Purchased power^(b)		100			91		60
IP:
Natural gas for distribution	(a)				23	%	13	%
Purchased power^(b)		100	%		91		60
EEI:
Coal		100	%		100	%	55	%
Coal transportation		100			100		-

(a)	The year 2007 is non-applicable for this table. The year 2008 represents November 2007 through March 2008. This continues each successive year through March 2011.

(b)

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

The following table shows how our 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 five-year period 2007 through 2011:

	Coal					Transportation
	Fuel Expense		Net Income^(a)			Fuel Expense		Net Income^(a)
Ameren^(b)	$	11	$	(7	)	$	15	$	(10	)
UE		4		(3	)		6		(4	)
Genco		4		(2	)		3		(2	)
CILCORP		2		(1	)		2		(1	)
CILCO (AERG)		2		(1	)		2		(1	)
EEI		1		(1	)		4		(3	)

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

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

In the event of a significant change in coal and coal transportation prices, UE, Genco, AERG and EEI would probably take actions to further mitigate their exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure or fuel sources.

See Note 8 – Commitments and Contingencies to our financial statements under Part I, Item 1, of this report for further information regarding the long-term commitments for the procurement of coal, natural gas and nuclear fuel.

Fair Value of Contracts

Most of our commodity contracts qualify for treatment as normal purchases and sales. We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission allowances. The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the three and nine months ended September 30, 2007. 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^(b)			CILCORP/ CILCO			IP
Three Months
Fair value of contracts at beginning of period, net	$	52		$	5		$	-		$	(2	)	$	3		$	(15	)
Contracts realized or otherwise settled during the period		(25	)		(1	)		2			-			4			18
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		7			11			-			(1	)		(1	)		-
Other changes in fair value		4			(6	)		(6	)		1			(6	)		(19	)
Fair value of contracts outstanding at end of period, net	$	38		$	9		$	(4	)	$	(2	)	$	-		$	(16	)
Nine Months
Fair value of contracts at beginning of period, net	$	41		$	9		$	(7	)	$	(1	)	$	(3	)	$	(34	)
Contracts realized or otherwise settled during the period		(16	)		(4	)		5			-			7			36
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		15			6			-			(1	)		(4	)		(7	)
Other changes in fair value		(2	)		(2	)		(2	)		-			-			(11	)
Fair value of contracts outstanding at end of period, net	$	38		$	9		$	(4	)	$	(2	)	$	-		$	(16	)

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

(b)	In conjunction with the new power supply agreement between Marketing Company and Genco that went into effect January 1, 2007, the mark-to-market value of hedges entered into during 2006 for Genco was transferred from Genco to Marketing Company.

The following table presents maturities of derivative contracts as of September 30, 2007:

Sources of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years		Maturity in Excess of 5 Years		Total Fair Value
Ameren:
Prices actively quoted	$	8		$	(1	)	$	-	$	-	$	7
Prices provided by other external sources^(a)		(23	)		(1	)		-		-		(24	)
Prices based on models and other valuation methods^(b)		39			16			-		-		55
Total	$	24		$	14		$	-	$	-	$	38
UE:
Prices actively quoted	$	-		$	-		$	-	$	-	$	-
Prices provided by other external sources^(a)		(1	)		-			-		-		(1	)
Prices based on models and other valuation methods^(b)		8			2			-		-		10
Total	$	7		$	2		$	-	$	-	$	9

Sources of Fair Value

Maturity

Less than

1 Year

Maturity

1-3 Years

Maturity

4-5 Years

Maturity in

Excess of

5 Years

Total

Fair Value

CIPS:
Prices actively quoted	$	-		$	-		$	-		$	-	$	-
Prices provided by other external sources^(a)		(2	)		(1	)		(1	)		-		(4	)
Prices based on models and other valuation methods^(b)		-			-			-			-		-
Total	$	(2	)	$	(1	)	$	(1	)	$	-	$	(4	)
Genco:
Prices actively quoted	$	(1	)	$	-		$	-		$	-	$	(1	)
Prices provided by other external sources^(a)		(1	)		-			-			-		(1	)
Prices based on models and other valuation methods^(b)		-			-			-			-		-
Total	$	(2	)	$	-		$	-		$	-	$	(2	)
CILCORP/CILCO:
Prices actively quoted	$	1		$	-		$	-		$	-	$	1
Prices provided by other external sources^(a)		(1	)		-			-			-		(1	)
Prices based on models and other valuation methods^(b)		-			-			-			-		-
Total	$	-		$	-		$	-		$	-	$	-

IP:
Prices actively quoted	$	-		$	-	$	-	$	-	$	-
Prices provided by other external sources^(a)		(17	)		1		-		-		(16	)
Prices based on models and other valuation methods^(b)		-			-		-		-		-
Total	$	(17	)	$	1	$	-	$	-	$	(16	)

(a)	Principally fixed price for floating over-the-counter power swaps, power forwards and fixed price for floating over-the-counter natural gas swaps.

(b)	Principally coal and SO₂ option values based on a Black-Scholes model that includes information from external sources and our estimates. Also includes interruptible power forward and option contract values based on our estimates.

ITEM 4. CONTROLS AND PROCEDURES.

(a)	Evaluation of Disclosure Controls and Procedures

As of September 30, 2007, evaluations were performed, under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.

(b)	Change in Internal Controls

There has been no change in 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 substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses.

For additional information on legal and administrative proceedings, see Note 2 – Rate and Regulatory Matters, Note 7 – Related Party Transactions and Note 8 – Commitments and Contingencies to our financial statements under Part I, Item 1, and Item 1A, Risk Factors, below of this report.

ITEM 1A. RISK FACTORS.

The Form 10-K includes a detailed discussion of our risk factors. The information presented below updates and should be read in conjunction with the risk factors and information disclosed in the Form 10-K.

The electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are determined through regulatory proceedings and are subject to legislative actions which are largely outside of our control. Where these events result in the inability of UE, CIPS, CILCO or IP to recover their respective costs and earn an appropriate return on investment, it could have a material adverse effect on our future results of operations, financial position or liquidity.

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, and liquidity of the Ameren Companies. The electric and gas utility 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. With rising costs, including fuel and related transportation, purchased power, labor and material costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, Ameren, UE, CIPS, CILCO and IP expect to experience regulatory lag until rate relief is granted from state regulators. As a result, Ameren, UE, CIPS, CILCO and IP expect to be entering a period where more frequent rate cases will be necessary. Ameren remains subject to competitive, economic, political, legislative and regulatory pressures that could have a material adverse effect on our results of operations, financial position, or liquidity.

Illinois

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 requesting a modification of their electric delivery service rates effective January 2, 2007. In November 2006, the ICC issued an order that approved an aggregate revenue increase of $97 million effective January 2, 2007 (CIPS - an $8 million decrease, CILCO - a $21 million increase and IP - an $84 million increase) based on an allowed return on equity of 10%. In May 2007, the ICC issued an order disallowing the recovery of certain administrative and general expenses totaling $50 million. Because of the ICC’s cost disallowances and regulatory lag, the Ameren Illinois Utilities are not expected to earn their allowed return on equity of 10% in 2007. Most customers were taking service under a frozen bundled electric rate in 2006, which included the cost of power, so these delivery service revenue changes do not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery service rates that became effective January 2, 2007.

Due to inadequate recovery of costs and low returns on equity being experienced in 2007, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million and IP - $139 million). The electric rate increase requests were based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion and a test year ended December 31, 2006, with certain prospective updates. In addition, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - $15 million increase, CILCO - $4 million decrease and IP - $56 million increase). The natural gas rate change requests were based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion and a test year ended December 31, 2006, with certain prospective updates. The ICC has until October 2008 to render a decision in these rate cases and could materially reduce the amount of the increase requested, or even reduce rates.

Electric Settlement Agreement

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 expired 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 through an auction. It also approved the related tariffs to collect these costs from customers for the period commencing January 2, 2007. In accordance with the January 2006 ICC order, a power procurement auction was held in September 2006. New electric rates for CIPS, CILCO and IP went into effect on January 2, 2007, reflecting delivery service tariffs approved by the ICC in November 2006 and full cost recovery of power purchased

on behalf of Ameren Illinois Utilities’ customers in the September 2006 auction.

Due to the magnitude of these rate increases, various legislators supported legislation that would have reduced and frozen the electric rates of CIPS, CILCO and IP at the rates that were in effect prior to January 2, 2007, and would have imposed a tax on electric generation in Illinois to help fund customer assistance programs. The Illinois governor also supported rate rollback and freeze legislation. The rate rollback and freeze legislation would have prevented the Ameren Illinois Utilities from recovering from retail customers substantial portions of the cost of electric energy the Ameren Illinois Utilities are purchasing under wholesale contracts entered into as a result of the September 2006 auction, and would have caused the Ameren Illinois Utilities to under-recover their delivery service costs until the ICC could approve higher delivery service rates.

As a result of these concerns, in July 2007, an agreement was reached among key stakeholders in Illinois that addresses the increase in electric rates and the future power procurement process. The settlement agreement was subject to enactment of legislation into law, which occurred on August 28, 2007. Ameren, on behalf of Marketing Company, Genco and AERG, the Ameren Illinois Utilities, Exelon, on behalf of Exelon Generation Company LLC, Commonwealth Edison Company, Exelon’s Illinois electric utility subsidiary, Dynegy Holdings, Inc., Midwest Generation, LLC, and MidAmerican Energy Company agreed to contribute an aggregate of approximately $1 billion over four years to fund both rate relief programs and the IPA. The agreement provides that if legislation is enacted in Illinois before August 1, 2011 freezing or reducing retail electric rates or imposing or authorizing a new tax, special assessment or fee on generation of electricity, then the remaining funding commitments will expire and any funds set aside in support of those commitments will be refunded to the utilities and electric generators. Also pursuant to the agreement, all pending litigation and regulatory actions by the Illinois attorney general relating to the reverse auction procurement process, which was used to determine market-based rates effective January 1, 2007, and the electric space heating marketing practices of the Ameren Illinois utilities were withdrawn with prejudice.

Although we cannot fully predict the effect of the implementation of the settlement agreement and related comprehensive rate relief program on Ameren, the Ameren Illinois Utilities, Genco or AERG, we believe the settlement agreement significantly reduces the risk that legislation will be enacted into law that reduces and freezes electric rates of CIPS, CILCO and IP to rates that were in effect prior to January 2, 2007, or that imposes a tax on electric generation in Illinois. The following factors resulting from implementation of the Illinois electric settlement agreement could have a material adverse effect on the results of operations, financial position or liquidity of Ameren, the Ameren Illinois Utilities, Genco or AERG:

·	uncertainty as to the implementation of the new power procurement process in Illinois for 2008 and 2009, including ICC review and approval requirements, the role of the IPA, and the ability of the Ameren Illinois Utilities to lease, or invest in, generation facilities;

·	the increase in short-term or long-term borrowings by the Ameren Illinois Utilities, Genco and AERG to fund contributions under the settlement agreement;

the failure by the electric generators that are party to the settlement agreement to perform in a timely manner under their respective funding agreements, which permit the Ameren Illinois Utilities to seek reimbursement for a portion of the rate relief that will be provided to certain of their electric customers; and

·	the extent to which Genco and AERG will be successful in making future sales to supply a portion of Illinois’ total electric demand through the revised power procurement mechanism.

If, notwithstanding the Illinois settlement agreement, any decision is made or action occurs 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, and such decision or action is not promptly enjoined, it could result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP.

Missouri

With the expiration of multiyear electric and gas rate moratoriums, effective July 1, 2006, UE filed requests with the MoPSC in July 2006 for an electric rate increase of $361 million and for a natural gas delivery rate increase of $11 million. In March 2007, a stipulation and agreement was approved by the MoPSC authorizing an increase in annual natural gas delivery revenues of $6 million, effective April 1, 2007. As part of this stipulation and agreement, UE agreed not to file a natural gas delivery rate case before March 15, 2010. This agreement does not prevent UE from filing to recover infrastructure costs through a statutory infrastructure system replacement surcharge (ISRS) during this three-year rate moratorium. The return on equity to be used by UE for purposes of any future ISRS tariff filing is 10.0%.

In May 2007, the MoPSC issued an order authorizing a $43 million increase in UE’s base rates for electric service based on a return on equity of 10.2%. The MoPSC denied UE’s and other intervenors’ applications for rehearing with respect to certain aspects of the MoPSC

rate order. In July 2007, UE appealed certain aspects of the MoPSC decision, principally the 10.2% return on equity granted by the MoPSC, to the Circuit Court of Cole County in Jefferson City, Missouri. The Office of Public Counsel and the Missouri attorney general, who were both intervenors in the electric rate case, also appealed certain aspects of the MoPSC decision to the Circuit Court of Cole County. We cannot predict the outcome of these appeals of the MoPSC rate order. Any change in electric or gas rates may not directly correspond to a change in UE’s earnings.

Increased federal and state environmental regulation will cause UE, Genco, CILCO (through AERG) and EEI to incur large capital expenditures and to incur increased operating costs. Future limits on greenhouse gas emissions would likely require UE, Genco, CILCO (through AERG) and EEI to incur significant additional increases in capital expenditures and operating costs and could result in the closures of coal-fired generating plants.

About 61% of Ameren’s generating capacity is coal-fired and about 85% of its electric generation was produced by its coal-fired plants in 2006. The remaining electric generation comes from nuclear, gas-fired, hydroelectric, and oil-fired power plants. In May 2005, the EPA issued final regulations with respect to SO₂, NO_x, and mercury emissions from coal-fired power plants. These regulations require significant additional reductions in the emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. Preliminary estimates of aggregate capital compliance expenditures for UE, Genco, and EEI range from $3.5 billion to $4.5 billion by 2016.

Illinois has adopted rules for mercury emissions that are significantly stricter than the federal regulations. In 2006, Genco, CILCO, EEI, and the Illinois EPA entered into an agreement that was incorporated into Illinois’ mercury emission regulations. Under the regulations, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NO_x and SO₂ controls. Genco, AERG and EEI will begin putting into service equipment designed to reduce mercury emissions in 2009. When fully implemented, it is estimated that these rules will reduce mercury emissions 90%, NO_x emissions 50% and SO₂ emissions 70% by 2015 in Illinois.

The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review 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 made.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. We are currently in discussions with the EPA and the state of Illinois regarding resolution of these matters, but we are unable to predict the outcome of these discussions. Resolution of the matters could have a material adverse impact on the future results of operations, financial position, or liquidity of Ameren, Genco, AERG and EEI. A resolution could result in increased capital expenditures, increased operations and maintenance expenses, and fines or penalties. We believe that any potential resolution would likely require the installation of control technology, some of which is already

planned for compliance with other regulatory requirements such as the Clean Air Interstate Rule and the Illinois mercury emission rules.

New environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, increased financing requirements, penalties and closure of power plants for UE, Genco, CILCO (through AERG) and EEI. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs by Genco, AERG or EEI in Illinois. We are unable to predict the ultimate impact of these matters on our results of operations, financial position or liquidity.

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

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

Period	(a) Total Number of Shares (or Units) Purchased^(a)		(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
July 1 – July 31, 2007		2,950	$	49.11		-		-
August 1 – August 31, 2007		-		-		-		-
September 1 – September 30, 2007		4,625		53.58		-		-
Total		7,575	$	51.84		-		-

(a)

These shares of Ameren common stock were purchased by Ameren 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, as amended. 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, 2007		11,000	$	100.00		-		-
August 1 – August 31, 2007		-		-		-		-
September 1 – September 30, 2007		-		-		-		-
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 2007. 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, 2007 period.

ITEM 6. EXHIBITS.

The documents listed below are being filed on behalf of the Ameren Companies as indicated.

Exhibit Designation	Registrant(s)	Nature of Exhibit
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

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	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE
31.4	UE	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE
31.5	CIPS	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CIPS
31.6	CIPS	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CIPS

31.7	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco
31.8	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco
31.9	CILCORP	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCORP
31.10	CILCORP	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCORP
31.11	CILCO	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCO
31.12	CILCO	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCO
31.13	IP	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of IP
31.14	IP	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of IP
Section 1350 Certifications
32.1	Ameren	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren
32.2	UE	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of UE
32.3	CIPS	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CIPS
32.4	Genco	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco
32.5	CILCORP	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCORP
32.6	CILCO	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCO
32.7	IP	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of IP

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

Principal Accounting Officer

(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)

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, 2007