ILLINOIS POWER CO - 10-Q Quarterly Report

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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, 2004

o 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: 1-3004

Illinois Power Company

(Exact name of registrant as specified in its charter)

Illinois	37-0344645
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

500 S. 27^th Street

Decatur, Illinois 62521-2200

(Address of principal executive offices)

(Zip Code)

(217) 424-6600

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has 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) has been subject to such filing requirements for the past 90 days.

YES ü NO ___

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

YES ___ NO ü

The number of shares outstanding of the registrant’s common stock as of November 14, 2004, was 23,000,000. (See Note 2 - Sale to Ameren - to our financial statements under Part I, Item 1 of this report for further information). Illinois Power Company is a subsidiary of Ameren Corporation. Ameren Corporation, in conjunction with its other registrant subsidiaries, made a separate filing of its quarterly report on Form 10-Q for the period ended September 30, 2004 (see Commission File No. 1-14756). Commencing with our Annual Report on Form 10-K for the fiscal year ended December 31, 2004, Illinois Power Company is expected to be included in the combined filing of Ameren Corporation and its other registrant subsidiaries.


	1

TABLE OF CONTENTS

	Page

Definitions	3

Forward-looking Statements	4

PART I. Financial Information

ITEM 1. Financial Statements (Unaudited)

Consolidated Statement of Income	5
Consolidated Balance Sheet	6
Consolidated Statement of Cash Flows	7
Notes to Consolidated Financial Statements	8

ITEM 2. Management’s Discussion and Analysis of Financial Condition and
Results of Operations	25

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk	40

ITEM 4. Controls and Procedures	41


PART II. Other Information

ITEM 1. Legal Proceedings	42

ITEM 6. Exhibits	42

SIGNATURES	43

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


	2

DEFINITIONS

When we use the words our, we or us, it indicates that such information relates to Illinois Power Company. As used in this Form 10-Q, the abbreviations listed below have the following meanings:

AFS

Ameren Energy Fuels and Services Company

Ameren

Ameren Corporation, parent company of IP as of September 30, 2004

Ameren Services

Ameren Services Company

AmerenIP

Illinois Power Company, doing business as AmerenIP

AmerGen

AmerGen Energy Company

ARB

Accounting Research Board

ARO

Asset Retirement Obligation

Bcf

Billion cubic feet

CILCO

Central Illinois Light Company, doing business as AmerenCILCO

CIPS

Central Illinois Public Service Company, doing business as AmerenCIPS

Clinton

Clinton Power Station

CWIP

Construction work in progress

DHI

Dynegy Holdings Inc.

DMG

Dynegy Midwest Generation, Inc.

DPM

Dynegy Power Marketing Inc.

Dynegy

Dynegy Inc.

EEI

Electric Energy, Inc.

EPA

U.S. Environmental Protection Agency

Exchange Act

Securities Exchange Act of 1934, as amended

FASB

Financial Accounting Standards Board

FCC

Federal Communications Commission

FERC

Federal Energy Regulatory Commission

FIN

FASB Interpretation

Fitch

Fitch Ratings

Form 10-K

Our Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 12, 2004

FSP

FASB Staff Position

GAAP

Generally accepted accounting principles in the United States of America

ICC

Illinois Commerce Commission

Illinova

Illinova Corporation, our former direct parent company and a wholly owned subsidiary of Dynegy

IP

Illinois Power Company

IPSPT

Illinois Power Special Purpose Trust

ISO Independent System Operator

kWh

Kilowatt-hour

LLC

Illinois Power Securitization Limited Liability Company

MGP

Manufactured Gas Plant

MISO

Midwest Independent Transmission System Operator, Inc.

Moody’s

Moody’s Investors Service, Inc.

MW

Megawatt

NOPR

Notice of Proposed Rulemaking

NOV

Notice of Violation

NSPS

New Source Performance Standard

OATT

Open Access Transmission Tariff

P.A. 90-561

Electric Service Customer Choice and Rate Relief Law of 1997

PGA

Purchase Gas Adjustment

PJM

PJM Interconnection LLC

PPA

Power Purchase Agreement

PSD

Prevention of Significant Deterioration

PUHCA

Public Utility Holding Company Act of 1935, as amended

RTO

Regional Transmission Organization

SEC

U.S. Securities and Exchange Commission

SFAS

Statement of Financial Accounting Standards

SPE

Special Purpose Entity

S&P

Standard and Poor’s Inc.

UE

Union Electric Company, doing business as AmerenUE

VIE

Variable Interest Entity


	3

FORWARD-LOOKING STATEMENTS

Statements made in this report, which are not based on historical facts, are "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 a nticipated. The following factors, in addition to those discussed elsewhere in this report and in past and subsequent filings with the SEC, could cause actual results to differ materially from our expectations as suggested by such "forward-looking" statements:

·	the impact of Ameren’s acquisition and integration of our operations with Ameren’s other businesses;

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

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

·	changes in laws and other governmental actions, including monetary, fiscal and regulatory 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 in Illinois when current power purchase agreements expire in 2006;

·	the effects of participation in the MISO;

·	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 any increased costs;

·	the use of financial and derivative instruments;

·	average rates for electricity in the Midwest;

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

·	disruptions of the capital markets or other events making our access to necessary capital more difficult or costly;

·	our substantial indebtedness and our ability to generate sufficient cash flows either from our operations or other liquidity initiatives to service principal and interest on such indebtedness;

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

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

·	weather conditions;

·	competition from alternate energy providers;

·	cost and availability of transmission and transportation capacity required to satisfy energy sales made by us;

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

·	legal and administrative proceedings.

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


	4

PART I. FINANCIAL INFORMAITON

ITEM 1. FINANCIAL STATEMENTS.

ILLINOIS POWER COMPANY

CONSOLIDATED STATEMENT OF INCOME

(Unaudited) (In millions)

	------Predecessor------ Three Months Ended September 30,				------Predecessor------ Nine Months Ended September 30,
	2004		2003		2004			2003

Operating Revenues:
Electric	$	327	$	352	$	832		$	860
Gas		52		49		328			330
Total operating revenues		379		401		1,160			1,190

Operating Expenses:
Purchased power		191		212		496			530
Gas purchased for resale		29		27		222			220
Other operations		30		47		102			110
Maintenance		14		15		41			43
Depreciation and amortization		21		19		61			59
Amortization of regulatory assets		11		11		32			32
Taxes other than income taxes		15		13		52			51
Total operating expenses		311		344		1,006			1,045
Operating Income		68		57		154			145

Other Income and (Deductions):
Interest income from former affiliates		43		43		128			128
Other income		4		1		16			3
Other expense		---		---		(1	)		(2	)
Total other income and (deductions)		47		44		143			129

Interest Charges		35		38		114			122

Income Before Income Taxes and Cumulative Effect of Change in Accounting Principle		80		63		183			152

Income Taxes		29		23		71			60

Income Before Cumulative Effect of Change in Accounting Principle		51		40		112			92

Cumulative Effect of Change in Accounting Principle, Net of Income Taxes		---		---		---			(2	)

Net Income		51		40		112			90
Preferred Stock Dividends		1		1		2			2
Net Income Applicable to Common Stockholder	$	50	$	39	$	110		$	88

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


	5

ILLINOIS POWER COMPANY

CONSOLIDATED BALANCE SHEET

(Unaudited) (In millions)

	-Successor- September 30, 2004		-Predecessor- December 31, 2003
ASSETS
Current Assets:
Cash and cash equivalents	$	51	$	17
Accounts receivables (less allowance for doubtful accounts of $6 million and $6 million, respectively)		114		109
Unbilled revenue		65		82
Miscellaneous accounts & notes receivable		11		82
Materials and supplies		86		84
Other current assets		48		39
Total current assets		375		413
Property and Plant, Net		1,969		1,949
Investments and Other Non-Current Assets:
Investment in IPSPT		4		4
Receivable from IPSPT		3		2
Goodwill		304		---
Other assets		64		212
Accumulated deferred income taxes		201		---
Total investments and other non-current assets		576		218
Note Receivable from Former Affiliate		---		2,271
Regulatory Assets		124		208
TOTAL ASSETS	$	3,044	$	5,059


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	70	$	71
Current maturities of long-term debt to IPSPT		71		74
Accounts and wages payable		66		57
Taxes accrued		2		50
Other current liabilities		155		115
Total current liabilities		364		367
Long-term Debt, Net		1,557		1,435
Long-term Debt to IPSPT		281		345
Deferred Credits and Other Non-Current Liabilities:
Accumulated deferred income taxes		---		1,011
Accumulated deferred investment tax credits		---		20
Regulatory liabilities		73		129
Accrued pension and other postretirement liabilities		239		39
Other deferred credits and other non-current liabilities		140		183
Total deferred credits and other non-current liabilities		452		1,382
Stockholders’ Equity:
Common stock, no par value, 100.0 shares authorized -
shares outstanding of 23.0 and 75.6, respectively		---		---
Other paid-in-capital		344		1,276
Preferred stock, not subject to mandatory redemption		46		46
Treasury stock		---		(287	)
Retained earnings		---		505
Accumulated other comprehensive loss		---		(10	)
Total stockholders’ equity		390		1,530
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,044	$	5,059

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


	6

ILLINOIS POWER COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited) (In millions)

	-------------Predecessor--------------
	Nine Months Ended
	September 30,
	2004			2003

Cash Flows From Operating Activities:
Net income	$	112		$	90
Adjustments to reconcile net income to net cash provided by
operating activities:
Cumulative effect of change in accounting principle		---			2
Depreciation and amortization		99			98
Deferred income taxes		(58	)		(10	)
Deferred investment tax credits		(1	)		(1	)
Changes in assets and liabilities:
Accounts receivable		6			1
Unbilled revenue		17			15
Materials and supplies		(13	)		(29	)
Accounts and wages payable		(2	)		(32	)
Other assets		13			(10	)
Other liabilities		(15	)		16
Net cash provided by operating activities		158			140


Cash Flows From Investing Activities:
Construction expenditures		(100	)		(100	)
Other investing activities		4			(2	)
Net cash used in investing activities		(96	)		(102	)


Cash Flows From Financing Activities:
Dividends on preferred stock		(2	)		(2	)
Prepaid interest on Note Receivable from Former Affiliate		43			85
Redemptions:
Short-term debt		---			(100	)
Long-term debt		(65	)		(254	)
Issuances:
Long-term debt		---			150
Increase in restricted cash		---			(3	)
Transitional funding trust notes overfunding		(4	)		---
Other financing activities		---			(8	)
Net cash used in financing activities		(28	)		(132	)

Net change in cash and cash equivalents		34			(94	)
Cash and cash equivalents at beginning of period		17			117
Cash and cash equivalents at end of period	$	51		$	23


Cash Paid During the Periods:
Interest	$	81		$	101
Income taxes	$	160		$	69

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


	7

ILLINOIS POWER COMPANY

Notes to Consolidated Financial Statements (Unaudited)

For the Interim Periods September 30, 2004 and 2003

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our Form 10-K.

The unaudited consolidated financial statements contained in this report include all material adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods. The results of operations for the interim periods presented in this Quarterly Report on Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, timing of maintenance and other expenditures and other factors. The preparation of the unaudited consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect our reported financial position and results of operations. These estimates and assumptions also impact the nature and extent of disclosure, if any, of our contingent liabilities. We review significant estimates affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Judgments and estimates are based on our beliefs and assumptions derived from information available at the time such estimates are made. Adjustments made with respect to the use of these estimates often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates are primarily used in (1) fair value determinations in purchase accounting, (2) recording revenue for services provided but not yet billed, (3) estimating the useful lives of our assets, (4) analyzing tangible and intangible assets for possible impairment, (5) projecting recovery of stranded costs, (6) estimating various factors used to value our pension assets, (7) assessing future tax ex posure and the realization of tax assets and (8) determining the amounts to accrue for contingencies. Actual results could differ materially from any such estimates.

We have reclassified certain amounts reported in this Quarterly Report on Form 10-Q from prior periods to conform to the 2004 financial statement presentation. These reclassifications had no impact on reported net income.

Our sale to Ameren was completed September 30, 2004. Therefore, information in our Consolidated Statement of Income and Consolidated Statement of Cash Flows relates to our ownership under our former ultimate parent company, Dynegy (predecessor). However, our Consolidated Balance Sheet as of September 30, 2004 does reflect the effects of the sale transaction with Ameren (successor), including the “push-down” of purchase accounting. Please read Note 2 - Sale to Ameren for additional information regarding the sale. All significant intercompany balances and transactions have been eliminated from the unaudited consolidated financial statements included in this report. All tabular dollar amounts are in millions, unless otherwise specified.

Property and Plant, Net The following tables present the details, by functional classification, of the items that comprise the balances related to Property and Plant, Net on our consolidated balance sheet.

Electric Plant ⁽¹⁾	September 30, 2004		December 31, 2003		Average Useful Life
					(in years)
Transmission	$	156	$	279		49.0
Distribution		1,022		1,625		36.0
General ⁽²⁾		263		249		31.3
Other ⁽²⁾		3		126		5.0 - 50.0
Construction Work-In-Progress		67		86
Total Electric Plant		1,511		2,365
Less: Accumulated Depreciation-Electric		---		870
	$	1,511	$	1,495

(1) 2003 amounts represent predecessor information.

(2) Joint function assets used in both electric and gas operations are included in the captions General and Other Electric Plant.


	8

ILLINOIS POWER COMPANY

Notes to Consolidated Financial Statements (Unaudited)

For the Interim Periods September 30, 2004 and 2003

Gas Plant ⁽¹⁾	September 30, 2004		December 31, 2003		Average Useful Life
					(in years)
Transmission	$	77	$	121		48.2
Distribution		286		530		36.3
General		10		21		20.7
Other		77		97		5.0 - 42.0
Construction Work-In-Progress		8		14
Total Gas Plant		458		783
Less: Accumulated Depreciation-Gas		---		329
	$	458	$	454

(1) 2003 amounts represent predecessor information.

Accounting Principles Adopted

SFAS No. 143 In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” We adopted SFAS No. 143, which provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, effective January 1, 2003. Under SFAS No. 143, an ARO is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset by an amount equal to the ARO. In each subsequent period, the liability is accreted towards the ultimate obligation amount and the capita lized ARO costs are depreciated over the useful life of the related asset.

At January 1, 2004, our ARO liability related to the Tilton site was approximately $1 million. This ARO related to the dismantling of the generation plant and remediation of the site. In July 2004, we sold the Tilton assets to DMG and reversed the related ARO liability as part of the accounting for that transaction. For additional information related to our Tilton ARO liability and remeasurement, please read Note 1 - Summary of Significant Accounting Policies - SFAS No. 143 beginning on page F-14 of our Form 10-K. There were no additional AROs recorded or settled during the three- and nine-month periods ended September 30, 2004. Please read Note 11 - Tilton for additional information regarding the Tilton facility.

We may have retirement obligations for the removal of asbestos and the dismantlement of our electric and gas transmission and distribution facilities and natural gas storage facilities. We intend to maintain these facilities in a manner such that the facilities will be operational indefinitely. We do not have sufficient information available to estimate a range of potential settlement dates for any known or unknown retirement obligations associated with these assets. We will recognize any such liability in accordance with SFAS No. 143 in the period in which sufficient information is available for us to make a reasonable estimate of the liability’s fair value.

In June 2004, the FASB issued an exposure draft on a proposed interpretation of SFAS No. 143. The FASB is expected to issue a final interpretation in the fourth quarter of 2004. Under the interpretation, a legal obligation to perform an asset retirement activity that is conditional on a future event is within the scope of SFAS No. 143. Accordingly, an entity would be required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability's fair value can be estimated reasonably. The exposure draft provides examples of conditional asset retirement obligations that may need to be recognized under the provisions of the interpretation, including asbestos removal. This proposed interpretation could require us to accrue additional liabilities and could result in increased expense, which, while not yet quantified, if not recoverable in rates could be material. This proposed interpretation would be effective for us no later than December 31, 2005.

SFAS No. 148 In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and provides alternative methods of transition (prospective, modified prospective or retroactive) for entities that voluntarily change to the fair-value based method of accounting for stock-based employee compensation in a fiscal year beginning before December 16, 2003. SFAS No. 148 requires prominent disclosure about the effects on reported net income of an entity& #146;s accounting policy decisions with respect to stock-based employee compensation. Although we do not grant stock-based compensation awards to our employees, our employees participated in the equity compensation plans of Dynegy, our former ultimate parent company. We transitioned to a


	9
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

fair value based method of accounting for stock-based compensation in the first quarter 2003 and are using the prospective method of transition as described under SFAS No. 148.

Under the prospective method of transition, all stock options granted since January 1, 2003 are accounted for on a fair value basis. We incurred compensation expense over the vesting period of the options in an amount equal to the fair value of the options. Options granted prior to January 1, 2003 continued to be accounted for using the intrinsic value method. Accordingly, for options granted prior to January 1, 2003, compensation expense was not reflected for employee stock options unless they were granted at an exercise price lower than market value on the grant date. Since the Dynegy-Illinova merger in February 2000, none of our employees have been granted in-the-money stock options.

Had compensation cost for all stock options granted prior to 2003 been determined on a fair value basis consistent with SFAS No. 123, our net income under predecessor Dynegy would have approximated the following pro forma amounts for the three- and nine-month periods ended September 30, 2004 and 2003, respectively.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003

Net income as reported	$	51	$	40	$	112	$	90
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects⁽¹⁾		---		---		---		---
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		1		1		3		3
Pro forma net income	$	50	$	39	$	109	$	87

(1) Compensation expense recorded for stock options granted after January 1, 2003 was negligible for the three- and nine-month periods ended September 30, 2004 and 2003.

On October 1, 2004, as a result of our sale to Ameren, all unvested stock options granted to our employees became null and void.

FIN No. 46R In the fourth quarter 2003, we adopted the initial provisions of FIN No. 46R, “Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51.” FIN No. 46R was effective on December 31, 2003 for entities considered SPEs. We adopted the remaining provisions of FIN No. 46R on March 31, 2004. These provisions require that we review the structure of non-SPE legal entities in which we have an investment and other legal entities with whom we transact business to determine whether such entities are VIEs, as defined by FIN No. 46R. While we did not enter into an y arrangements in 2003 that were subject to these initial provisions, two entities previously formed were impacted. As a result of our adoption of FIN No. 46R, we deconsolidated the IPSPT and the LLC. The deconsolidation occurred at December 31, 2003 and did not have any impact upon our results of operations. Please read Note 1 - Summary of Significant Accounting Policies - FIN No. 46 beginning on page F-16 of our Form 10-K for additional information regarding this deconsolidation.

We determined that we have no entities that were impacted by the adoption of these remaining provisions and, as such, our financial statements were not impacted by the adoption of these remaining provisions.

FSP SFAS 106-1 and 106-2 On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Prescription Drug Act) was enacted. The Prescription Drug Act introduced a prescription drug benefit to retirees under Medicare as well as a federal subsidy to sponsors of retiree healthcare benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. In January 2004, the FASB issued FSP SFAS No. 106-1 (FSP SFAS 106-1), “Accounting and Disclosure Requirements Related to the Medicare Pres cription Drug Improvement and Modernization Act of 2003,” which permitted a plan sponsor of a postretirement healthcare plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. We made this one-time election allowed by FSP SFAS 106-1.


	10
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

In May 2004, the FASB issued FSP SFAS No. 106-2 (FSP SFAS 106-2), which superceded FSP SFAS 106-1. FSP SFAS 106-2 provides guidance on accounting for the effects of the Prescription Drug Act by employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Our retiree drug benefit is not actuarially equivalent to the Medicare Part D drug benefit, and as such, our adoption of FSP SFAS 106-2 on July 1, 2004 had no financial impact.

NOTE 2 - SALE TO AMEREN

On September 30, 2004, Ameren completed the acquisition of all 23,000,000 outstanding shares of our common stock and 662,924 shares, or approximately 73%, of our preferred stock from Dynegy and its subsidiaries. There is no voting or non-voting common equity held by our non-affiliates. Ameren acquired us to complement its existing Illinois gas and electric operations. The purchase included our rate-regulated electric and natural gas transmission and distribution business serving approximately 600,000 electric and 415,000 gas customers in areas contiguous to Ameren’s existing Illinois utility service territories. As a result of the acquisition, we became an Ameren subsidiary operating as AmerenIP. The transaction also included Ameren’s acquisition of a 20% ownership interest in EEI from Dynegy and its subsidiaries. See Note 1 - Summary of Significant Accounting Policies for further information on our presentation of the effect of the transaction in our consolidated financial statements. For a discussion of the regulatory agency approvals granted in connection with the transaction, see Note 3 - Rate and Regulatory Matters.

The total transaction value was approximately $2.3 billion, including the assumption of approximately $1.8 billion of our debt and preferred stock and consideration, including transaction costs, of $451 million in cash, net of $51 million cash acquired, which, under the terms of the stock purchase agreement, is subject to a final working capital adjustment. The portion of the total transaction value attributable to Ameren’s acquisition of Dynegy’s 20% ownership interest in EEI was $125 million. Ameren placed $100 million of the cash portion of the purchase price in a six-year escrow pending resolution of certain IP and Dynegy affiliates’ contingent environmental obligations for which Ameren has been provided indemnification by Dynegy. See Note 8 - Commitments and Contingencies for information on a pending environmental matter to which the indemnification and escrow applies. In addition, this transaction included a fixed price capacity power purchase agreement for our annual purchase in 2005 and 2006 of 2,800 MWs of electricity from DPM, a subsidiary of Dynegy. The contract was marked to fair value at closing. This agreement is expected to supply about 70% of our electric customer requirements during those two years. We are currently in the final stages of soliciting bids to supply the remaining 30% of our power needs in 2005 and 2006. This solicitation is expected to be completed by the end of 2004. In the event that any of these suppliers are unable to supply the electricity required by the agreements, we will be forced to find alternative suppliers to meet our load requirements, thus exposing us to market price risk, which could have a material impact on our results of operations. Existing power purchase agreements expire on December 31, 2004.

Ameren’s financing plan for funding this acquisition included the issuance of new Ameren common stock. Ameren issued an aggregate of approximately 30 million common shares in February 2004 and July 2004, which together generated net proceeds of about $1.3 billion. Proceeds from these issuances were used to finance the cash portion of the purchase price and are being used to reduce our debt and to pay any related premiums. See Note 5 - Long-term Debt for information on redemptions and a tender offer instituted with respect to certain of our bonds after the acquisition.

The following table presents the estimated fair values of the assets acquired and liabilities assumed at the date of our acquisition by Ameren. Ameren is in the process of completing its valuations of the net assets and liabilities acquired, including the fixed price capacity power purchase agreement discussed above, and obtaining third party valuations of property and plant, intangible assets, acquired debt and pension and other postretirement benefit obligations. As a result, the allocation of the purchase price is preliminary and subject to further adjustment. The fair value of our power purchase agreements recorded at the acquisition date resulted in a $109 million liability, net. The excess of the purchase price for our common stock and 662,924 shares of preferred stock over tangible net assets acquired has been allo cated preliminarily to goodwill in the amount of $304 million, net of future tax benefits. For income tax purposes, we expect that a portion of the purchase price will be allocated to goodwill and that such portion will be deducted ratably over a 15-year period.


	11

ILLINOIS POWER COMPANY

Notes to Consolidated Financial Statements (Unaudited)

For the Interim Periods September 30, 2004 and 2003


Current assets	$ 375
Property and plant	1,969
Investments and other non-current assets	396
Goodwill	304
Total assets acquired	3,044
Current liabilities	223
Long-term debt, including current maturities	1,979
Other non-current liabilities	452
Total liabilities assumed	2,654
Preferred stock assumed	13
Net assets acquired	$ 377

Our Note Receivable from Former Affiliate of approximately $2.3 billion was eliminated as of September 30, 2004 and prior to the closing of Ameren’s acquisition of us to meet the conditions of the transaction. The steps to eliminate the Note were (i) the principal balance was reduced by offsetting certain payables owed by us to Illinova and other Dynegy entities; (ii) the principal balance was offset by the amount of interest that had been paid by Illinova to us but not yet earned; and (iii) a portion was eliminated in consideration of Illinova’s assumption of our net deferred tax obligation and our contemporaneous repurchase (and cancellation immediately thereafter) of a portion of our common stock. See Note 9 - Stockholders' Equity for more information on the changes in our common stock. Th e remaining principal balance of our Note Receivable from Former Affiliate was eliminated, as part of our overall recapitalization, with a corresponding reduction to our retained earnings. The elimination of our Note Receivable from Former Affiliate had no impact on our predecessor results of operations.

The intercompany payables consisted primarily of amounts due from us under the Services and Facilities Agreement. This included our share of income taxes, direct charges to us for specific services provided to us by Dynegy or its other entities and allocations of Dynegy administrative and general costs to us. See Note 7 - Related Party Transactions for further information regarding the Services and Facilities Agreement.

Ameren’s recapitalization plan for us includes the infusion of a substantial amount of new equity. In conjunction with obtaining approval of the acquisition, Ameren committed to the ICC that the recapitalization plan is expected to result in us achieving a common equity to total capitalization ratio of between 50% and 60% by December 31, 2006, the end of the mandatory transition period. In October 2004, Ameren made an equity contribution to us of $250 million, the proceeds of which were used in connection with the redemption of $192.5 million principal amount of our mortgage bonds 11.5% Series due 2010.

In November 2004, a voluntary separation opportunity was offered to certain groups (approximately 950) of our employees. The program is voluntary and offers an enhanced separation benefit and extended medical and dental benefits. Employees must make a decision by December 20, 2004, and will leave IP throughout 2005 based on business needs. The offering of this voluntary separation opportunity is consistent with Ameren’s plan for our integration and conditions in the ICC order for the realization of administrative synergies from the acquisition. Costs of the separation are expected to be deferred as a regulatory asset, which is also consistent with the ICC order.

NOTE 3 - RATE AND REGULATORY MATTERS

We are subject to regulation by various federal, state and local agencies, including extensive rules and regulations governing transportation, transmission and sale of electricity and natural gas, as well as those relating to environmental protection. Compliance with these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment, permitting, and remediation obligations. In addition, the United States Congress has before it a number of bills that could impact regulations or impose new regulation applicable to us. We cannot predict the outcome of these bills or other regulatory developments or the effects that they might have on our business.

Sale to Ameren The following regulatory agency approvals were granted in connection with our acquisition by Ameren on September 30, 2004.


	12
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

In April 2004, the FCC consented to the transfer of control of our FCC licenses to Ameren.

In April 2004, the initial 30 calendar day waiting period expired without a request by the Federal Trade Commission or Department of Justice for additional information or documents under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.

In July 2004, the FERC issued an order approving Ameren’s acquisition of us. The principal conditions of the FERC’s approval were that we join the MISO prior to closing the transaction and that 125 MW of EEI’s power be sold to a non-affiliate of Ameren. The Missouri Office of Public Counsel and a group of electric industrial customers of UE, both intervenors in the FERC proceeding, have requested the FERC to reconsider its order deferring to the Missouri Public Service Commission on the question of whether UE should be required to preserve its current entitlement to the output of EEI’s Joppa power plant facility. These appeals, which are pending, did not impede the completion of the acquisition on September 30, 2004. We joined the MISO on September 30, 2004.

On September 22, 2004, the ICC issued an order approving our acquisition by Ameren. The order contains several important provisions including the following:

The order requires us to submit quarterly reports in 2005 and 2006 on certain milestones regarding our progress in achieving an estimated $33 million in annual synergies by the beginning of 2007, and provides for adjustments in our next electric and gas rate cases if we fail to achieve those milestones.

·	After 2006, we will recover over four years, through rates, $67 million in reorganization costs related to our restructuring and integration into the Ameren system.

The order approves 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 us from a $20 million trust fund established by us and financed with contributions of $10 million each by Ameren and Dynegy; if cash expenditures are less than the amount in base rates, we 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 order provides us with the ability to declare and pay $80 million of dividends on our common stock in 2005 and $160 million of dividends on our common stock cumulatively through 2006, provided we have achieved an investment grade credit rating from S&P or Moody’s. If, however, our $550 million principal amount of mortgage bonds 11.5% Series due 2010 are not eliminated by December 31, 2006, we may not thereafter declare or pay common dividends without seeking authority from the ICC.

Ameren commits to cause an aggregate of at least $750 million principal amount of our long-term debt, including our $550 million principal amount of mortgage bonds 11.5% Series due 2010, to be redeemed, repurchased or retired on or before December 31, 2006. Ameren will contribute a substantial amount of common equity into us for this purpose and will cause our common equity to total capitalization ratio to range between 50% to 60% by December 31, 2006.

·	We will establish a dividend policy comparable to the dividend policy of Ameren’s other Illinois utilities consistent with achieving and maintaining a common equity to total capitalization ratio between 50% to 60%.

·	Ameren will commit us to make between $275 million and $325 million in energy infrastructure investments over its first two years of ownership.

·	Our employees, retirees and those retirees’ surviving dependents will remain in their current IP benefit plans or will be moved into appropriate Ameren benefit plans, and we will honor all existing labor agreements.

On September 27, 2004, the SEC issued an order under the PUHCA approving our acquisition by Ameren without material conditions.

Gas Rate Case In June 2004, we filed with the ICC seeking authority to raise our natural gas delivery rates by approximately $40 million annually. In August 2004, we filed supplemental testimony which revised the requested rate increase to approximately $36 million annually. We have operated under the same rate structure for 10 years. The requested increase will allow us to recover investments in our natural gas delivery system. In addition, the increase reflects the increase in our operating costs, including materials and labor, since 1994. The requested increase applies only to base rates and does not affect the cost of gas itself, which typically accounts for approximately two-thi rds of customers’ total gas bills and is recovered via the PGA process. As part of the regulatory process, which can be expected to take up to eleven months, the


	13
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

ICC will decide the amount of increase, if any, to provide recovery of costs from our customers. The ICC staff filed testimony on this matter in November 2004, which recommended an increase of approximately $16.8 million annually. Further, the Citizen’s Utility Board and the People of the State of Illinois recommended an increase of approximately $12.6 million annually. Hearings are scheduled to be held in January 2005. If approved by the ICC, the new rates are expected to go into effect in spring 2005. In the order approving our acquisition by Ameren, the ICC prohibits us from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond our pending request for a gas delivery rate increase.

P.A. 90-561 - ISO Participation See Note 5 - Commitments and Contingencies - Legal and Environmental Matters - P.A. 90-561 - ISO Participation, beginning on page F-22 of our Form 10-K, for more information regarding ISO participation. Participation in an ISO or RTO by utilities serving retail customers in Illinois was one of the requirements included in P.A. 90-561 and P.A. 92-12.

On September 30, 2004, prior to the completion of our acquisition by Ameren as required by the FERC’s order approving the acquisition, we transferred functional control, but not ownership, of our transmission system to the MISO. The transfer had no accounting impact because we continue to own the transmission system assets. Our participation in the MISO is expected to increase annual costs by approximately $3 million and could result in a decrease in annual revenues of between $2 million and $3 million based on MISO’s tariff structure. We may also be required to expand our transmission system according to decisions made by the MISO rather than through our internal planning process.

As a part of the transfer of functional control of our transmission system to the MISO, we received a refund of the exit fee we paid and expensed when we left the MISO in 2001, plus interest on the exit fee and the refund of our investment in the proposed Alliance RTO. These reimbursements resulted in after-tax gains of approximately $9 million during the quarter ended September 30, 2004 and were paid to Dynegy pursuant to the terms of the stock purchase agreement covering our acquisition by Ameren. The result of these reimbursements decreased operating expense by approximately $14 million and increased interest income by approximately $1 million.

Through orders issued during late 2003 and early 2004, the FERC had ordered the elimination of regional through-and-out rates assessed by the MISO on transmission service between the MISO and the PJM regions, to be effective May 1, 2004. However, in March 2004, the FERC accepted an agreement among affected transmission owners that retains the regional through-and-out rates until December 1, 2004, and provides for continued negotiations aimed at developing a long-term transmission pricing structure to eliminate seams between the PJM and the MISO regions based on specified pricing principles. On November 18, 2004, the FERC announced that it had approved the new pricing structure to eliminate the seam between MISO and PJM. The new rate structure will apply for a fixed period ending January 31, 2008 and will be based on the “license plate” rate design currently in place in both MISO and PJM. However, to avoid an abrupt cost shift as a result of the elimination of pancaked rates between MISO and PJM, the FERC also ordered the adoption of Seams Elimination Cost Adjustments (SECA). The FERC further ordered the parties to make a SECA filing by November 24, 2004. Until the SECA filing has been approved by the FERC, we cannot predict the ultimate impact that such rate structure will have on our costs and revenues.

In March 2004, the MISO tendered for filing at the FERC a proposed Open Access Transmission and Energy Markets Tariff (the “Energy Markets Tariff”), which is intended to supercede its existing OATT. The Energy Markets Tariff establishes rates, terms and conditions necessary for implementation of a centralized security-constrained economic dispatch platform supported by a day-ahead and real-time energy market design, including Locational Marginal-Cost Pricing and Financial Transmission Rights for transmission service within the MISO region. The Energy Markets Tariff also establishes market monitoring and mitigation procedures and codifies existing resource adequacy requirements placed on MISO members by their states or applicable Regional Reliability Organization. The MISO initially proposed t o make the Energy Markets Tariff effective on December 1, 2004, subject to its ability to implement the Energy Markets Tariff. However, implementation of the Energy Markets Tariff is now expected to be effective on March 1, 2005. On August 6, 2004, the FERC accepted the MISO’s Energy Markets Tariff subject to further compliance filings. On November 8, 2004, the FERC issued an order denying the requests for rehearing that were filed by a number of MISO stakeholders including Ameren. However, a final order from the FERC on the compliance filings made by the MISO in response to the FERC’s August 6 order is still pending. At this time, we are unable to determine the full impact that the Energy Markets Tariff will have until further information is available regarding the implementation of the Energy Markets Tariff.

Until we achieve some degree of operational experience participating in the MISO, we are unable to predict the ultimate impact that such participation or ongoing RTO developments at the FERC or other regulatory authorities will have on our financial position, results of operations or liquidity.


	14
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

NOTE 4 - SHORT-TERM BORROWINGS AND LIQUIDITY

At September 30, 2004, Ameren and certain of its subsidiaries had committed bank credit facilities totaling $1,164 million, all of which were available for use, subject to applicable regulatory short-term borrowing authorizations, by certain Ameren subsidiaries, including us, through a utility money pool arrangement. The utility money pool agreement with and among our affiliates coordinates and provides for certain short-term cash and working capital requirements. On September 30, 2004, the utility money pool agreement was amended to add us as a party. Also, on September 30, 2004, a unilateral borrowing agreement was entered into among Ameren, Ameren Services and us which enables us to make short-term borrowings directly from Ameren. The aggregate amount of short-term borrowings outstanding at any time by us, including external borrowings and borrowings under the unilateral borrowing agreement and the utility money pool agreement may not exceed $500 million pursuant to authorizations from the ICC and the SEC under the PUHCA. Ameren Services is responsible for operation and administration of the agreements. Access to the credit facilities for any of Ameren’s subsidiaries is subject to reduction based on use by affiliates.

For the near term, our debt maturities primarily consist of (i) quarterly payments of approximately $22 million on the IPSPT transitional funding trust notes, for which we receive a separate revenue stream from our customers, and (ii) the maturity of $70 million principal amount of mortgage bonds due March 2005.

Over the longer term, our liquidity and capital resources will be materially affected by our sale to Ameren. Ameren has committed to reduce our leverage, and consistent with that commitment, in October 2004, issued notices of redemption and a tender offer to redeem or repurchase certain of our outstanding mortgage bonds and our obligations with respect to certain tax-exempt pollution control bonds. See Note 5 - Long-term Debt for further information.

Indebtedness Provisions and Other Covenants

The bank credit agreements of Ameren and certain of its subsidiaries contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets and merge with other entities. Certain of these credit agreements also contain a provision that limits total indebtedness to 60% of total capitalization pursuant to a calculation defined in the related agreement. Our total indebtedness will also be limited by this provision from and after March 31, 2005. In addition, certain of these credit agreements contain indebtedness cross-default provisions and material adverse change clauses which could trigger a default under these agreements in the event that any of Ameren’s subsidiaries (as defined in the agreements), other than certain project finance subsidiaries, defaults in indebtedness in excess of $50 million. The credit agreements also require us to meet minimum ERISA funding rules.

None of these credit agreements contain credit rating triggers. At September 30, 2004, we were in compliance with all applicable provisions and covenants of these credit agreements. We do not have any bank credit agreements.

NOTE 5 - LONG-TERM DEBT

Upon our acquisition by Ameren, our total debt was increased to fair value by approximately $191 million which included early redemption premiums. The adjustment to the fair value of each debt series is being amortized over its remaining life, or to its expected redemption date, to interest expense.


	15
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

In October 2004, pursuant to an equity clawback provision of the related bond indenture, we unconditionally called for redemption on November 15, 2004, $192.5 million in principal amount of our mortgage bonds 11.5% Series due 2010 at a price equal to $1,115 per $1,000 principal amount, together with accrued and unpaid interest to, but not including, the redemption date. Ameren made an equity contribution of $250 million to us to provide funds for this purpose and to satisfy indenture provisions related to the equity clawback. Also, in October 2004, we made a cash tender offer for any and all of the remaining outstanding mortgage bonds 11.5% Series due 2010 ($357.5 million in aggregate principal amount). The purchase price was determined, as described in the offer to purchase, in accordance with standard m arket practice by reference to a yield of 50 basis points over the yield on the 2.625% U.S. Treasury Note due November 15, 2006, on November 18, 2004, the price determination date. The tender offer is scheduled to expire on November 22, 2004. This tender offer was also intended to satisfy our indenture obligation to offer to purchase the bonds resulting from the change of control upon our acquisition by Ameren. The bonds tendered will be purchased with cash contributed as equity to us by Ameren.

In addition, in October 2004, we called for redemption on December 1, 2004, the following indebtedness: (i) all $65.6 million principal amount of our outstanding 7.50% Series due 2025 mortgage bonds at a redemption price of 103.105% of the principal amount plus accrued interest and (ii) all $84.2 million principal amount of the Illinois Development Finance Authority’s Pollution Control Refunding Revenue Bonds, 1994 7.40% Series B due 2024 at a redemption price of 102% of the principal amount plus accrued interest. This indebtedness will be redeemed with cash contributed as equity to us by Ameren.

During each of the three- and nine-month periods ended September 30, 2004 and 2003, we paid the IPSPT approximately $22 million and $65 million, respectively, which the IPSPT used to pay down the transitional funding trust notes. We estimate that the IPSPT will continue to pay down such notes, approximately $22 million per quarter, through 2008. The LLC and the IPSPT, which are VIEs under FIN No. 46R, are separate legal entities from us. The assets of the VIEs are not available to our creditors and the transitional properties held by the VIEs are not assets of ours.

We make periodic interest payments related to our fixed-rate and variable rate debt obligations. Interest rates on these obligations ranged from 1.25% to 11.5% per annum during the nine months ended September 30, 2004. Interest expense for the three- and nine-month periods ended September 30, 2004 was approximately $35 million and $114 million, respectively. During the three- and nine-month periods ended September 30, 2003, interest expense was approximately $38 million and $122 million, respectively. The reduction in expense is due to the repayments to the IPSPT discussed above.

Indenture Provisions and Other Covenants Our indenture agreement and articles of incorporation include covenants and provisions related to the issuance of first mortgage bonds and preferred stock. For the issuance of additional first mortgage bonds based on available property, our indenture agreement requires earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued. For the twelve months ended September 30, 2004, we had a coverage ratio of 1.5 times the annual interest charges on the first mortgage bonds outstanding, which under our indenture agreement would not permit us to issue any additional first mortgage bonds based on available property. However, as of September 30, 2004, we had the ability under our indenture agreement to issue $569 million of bonds based upon retired bond capacity, for which no earnings coverage test is required. For the issuance of additional preferred stock, earnings coverage of at least 1.5 times the annual interest on outstanding debt and dividends on preferred stock outstanding and to be issued is required under our articles of incorporation. For the twelve months ended September 30, 2004, we had a coverage ratio of 1.1 times the annual interest on outstanding debt and dividend requirement on preferred stock outstanding, which would not permit us to issue any additional preferred stock. The ability to issue such securities in the future will depend on such tests at that time.

The indenture governing our mortgage bonds 11.5% Series due 2010, contain triggering event provisions that would give the holders of at least 25% in principal amount of these bonds then outstanding the right to require us to redeem the bonds if we take certain actions defined and/or described in the bond indenture as restricted payments, incurrence of indebtedness and issuance of preferred stock, dividend and other payment restrictions affecting subsidiaries, and repurchase at the option of bondholders due to asset sales. These triggering events have been suspended with the upgrade to an investment grade credit rating of our long-term debt on October 1, 2004, and will remain non-applicable as long as we maintain an investment grade bond status. Triggering events remain in effect on our ability t o incur liens, to merge, consolidate or sell assets, provide subsidiary guarantees, engage in sale and leaseback transactions and certain business activities as defined in the indenture.


	16
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

There are restrictions under the IPSPT Transitional Funding Trust Notes under which the LLC cannot make any loan, advance, or certain other investments to or in any other person. Also, as long as the Transitional Funding Trust Notes are outstanding, the Trust shall not, directly or indirectly, pay any dividend or make any distribution (by reduction of capital or otherwise) to any owner of a beneficial interest in the Trust.

Tilton Capital Lease In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, we terminated our lease with the original lessor and the related turbines were purchased from the original lessor by DMG for $81 million. This resulted in a reduction of debt of $78 million. Please read Note 8 - Commitments and Contingencies - Capital Leases and Note 11 - Tilton for additional information concerning our Tilton capital lease.

Off-Balance Sheet Arrangements At September 30, 2004, we had no off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. We do not expect to engage in any significant off-balance sheet financing arrangements in the near future.

Dividends See Note 3 - Rate and Regulatory Matters for restrictions on our ability to declare and pay common stock dividends imposed by the ICC order approving Ameren’s acquisition of us.

NOTE 6 - OTHER INCOME AND DEDUCTIONS

The following table presents the details of the items that comprise the balances related to Other Income and Deductions on our Consolidated Statement of Income while we were affiliated with predecessor Dynegy.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004			2003
Other income:
Interest income	$	3	$	1	$	11		$	2
Gain on disposition of property		---		---		1			---
Other		1		---		4			1
Total other income	$	4	$	1	$	16		$	3

Other expense:	$	---	$	---	$	(1	)	$	(2	)

NOTE 7 - RELATED PARTY TRANSACTIONS

Pre-sale to Ameren

At September 30, 2004, the $2.3 billion in principal outstanding under our Note Receivable from Former Affiliate was eliminated in connection with the sale of all of our common stock and approximately 73% of our preferred stock to Ameren. Please see Note 2 - Sale to Ameren for further discussion of the elimination of our Note Receivable from Former Affiliate. We recognized approximately $128 million of interest income from Illinova on the Note for each of the nine-month periods ended September 30, 2004 and 2003. During the nine-month period ended September 30, 2004, we received approximately $170 million of prepaid interest under our Note Receivable from Former Affiliate, however, at September 30, 2004, we carrie d $0 in prepaid interest on our Note Receivable from Former Affiliate, due to the prepaid interest elimination in conjunction with the elimination of the note. At September 30, 2003, we carried approximately $85 million in prepaid interest.

Prior to our sale to Ameren, we routinely conducted business with other subsidiaries of Dynegy. These transactions included the purchase or sale of electricity, natural gas and transmission services as well as certain other services. In conjunction with our sale to Ameren, we reclassified our accounts receivable from our former affiliates as third party receivables. Accounts payable to our former affiliates were netted against our Note Receivable from Former Affiliate. For additional information on the


	17

ILLINOIS POWER COMPANY

Notes to Consolidated Financial Statements (Unaudited)

For the Interim Periods September 30, 2004 and 2003

elimination of our Note Receivable from Former Affiliate, please read Note 2 - Sale to Ameren above. The following table presents aggregate amounts derived from transactions with our former affiliates:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003

Operating revenues	$	6	$	8	$	19	$	23

Power purchased	$	114	$	124	$	346	$	356
Other		3		15		17		56
Operating expenses	$	117	$	139	$	363	$	412

The reduction in operating expenses, excluding power purchased, resulted from making fewer gas purchases from our former affiliates during 2004.

We have a PPA with a former affiliate, DMG, that provides us the right to purchase power from DMG for a primary term extending through December 31, 2004. This right to purchase power qualifies under the normal purchase and sale exemption of SFAS No. 133 and, therefore, we have accounted for the PPA under the accrual method. The PPA defines the terms and conditions under which DMG provides power and energy to us using a tiered pricing structure. The agreement requires us to pay DMG approximately $311 million for capacity charges in 2004. Should power acquired under this agreement, when combined with our other power purchase agreements, be insufficient to meet our load requirements, we will have to buy power at current market prices. The PPA obligates DMG to provide power up to the reservation amount eve n if DMG has individual units unavailable at various times.

In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, we terminated our Tilton capital lease with the original lessor and the related turbines were purchased from the original lessor by DMG. Prior to the transaction, we recognized approximately $1 million and $8 million, respectively, of interest income from accretion of the receivable for the three- and nine-month periods ended September 30, 2004. The interest income from DMG was offset by the corresponding interest we paid to the original lessor. Please read Note 8 - Commitments and Contingencies - Capital Leases for further discussion of the Tilton lease and Note 11 - Tilton for further discussion of the July transactions related to Tilton.

Effective January 1, 2000, the Dynegy consolidated group, including us, began operating under a Services and Facilities Agreement which was approved by the ICC. Under this agreement, we shared facility space and exchanged services (such as financial, legal, information technology and human resources) with other Dynegy affiliates. Our services were exchanged at fully distributed costs and revenue was recorded under this agreement. This agreement was terminated in conjunction with our sale to Ameren. See Support Services Agreements below for a new agreement established with Ameren.

On October 23, 2002, the ICC issued an order approving a petition submitted by us to enter into an agreement with Dynegy and its affiliates that would allow for certain payments due to Dynegy under the Services and Facilities Agreement to be netted against certain payments due to us from Dynegy, should Dynegy or its affiliates fail to make payments due to us on or before their due dates. However, the PPA with DMG that expires on December 31, 2004 was specifically exempted from this agreement. The agreement also allowed Dynegy to net payments in the event we failed to make our required payments to Dynegy. No triggering events to necessitate such netting of transactions occurred under this agreement. Additionally, under the terms of this petition and the ICC’s approval, we could not pay any common d ividend to Dynegy or its affiliates until our first mortgage bonds were rated investment grade by Moody’s and S&P and specific approval was obtained from the ICC. This netting agreement was terminated in conjunction with our sale to Ameren.

Our financial statements include related-party transactions with the IPSPT, our wholly-owned unconsolidated subsidiary, which was deconsolidated in accordance with the adoption of FIN No. 46R effective on December 31, 2003. Please read Note 1 - Summary of Significant Accounting Policies - FIN No. 46 beginning on page F-16 in our Form 10-K for additional information regarding the deconsolidation of the IPSPT. The table below reflects our transactions with the IPSPT.


	18
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

	September 30,		December 31,
	2004		2003⁽¹⁾

Investment in IPSPT	$	4	$	4
Receivable from IPSPT (noncurrent)	$	3	$	2
Long-term debt to IPSPT (including maturing within one year)	$	352	$	420

⁽¹⁾2003 amounts represent predecessor information.

In addition to the transactions above, under predecessor Dynegy we recorded $5 million and $17 million, respectively, in net interest expense related to the IPSPT for the three- and nine-month periods ended September 30, 2004.

Post-Sale to Ameren

Utility Money Pool As part of the Ameren group, we now have the ability to borrow through a utility money pool agreement. Ameren Services administers the utility money pool and tracks the internal and external funds separately. Internal funds are surplus funds contributed to the utility money pool from participants. Through the utility money pool, the pool participants can access committed credit facilities at Ameren, UE, CIPS and CILCO, which totaled $1,164 million at September 30, 2004. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent the pool participants have surplus funds or other external sources are used to increase the available amounts. The average interest rate for borrowing under the utility money pool for the three months ended September 30, 2004 was 1.47% (2003 - 1.02%) and for the nine months ended September 30, 2004 and 2003 was 1.17%.

Additionally, on September 30, 2004 we entered into a unilateral borrowing agreement with Ameren and Ameren Services, another Ameren subsidiary, which enables us to make short-term borrowings directly from Ameren. The aggregate amount of short-term borrowings outstanding at any time by us, including external borrowings and borrowings under the unilateral borrowing agreement and the utility money pool agreement may not exceed $500 million pursuant to authorization from the ICC and the SEC under the PUHCA. Ameren Services is responsible for operation and administration of the agreement. For additional information on the availability of funds under the utility money pool arrangement and unilateral borrowing agreement, please read Note 4 - Short-term Borrowings and Liquidity above.

Interconnection Agreements

We, along with UE and CIPS, are parties to an interconnection agreement for the use of our respective transmission lines and other facilities for the distribution of power. In addition, we have a similar interconnection agreement with CILCO. Revenues or costs associated with these agreements were not material for the nine months ended September 30, 2004 and 2003. These agreements can be terminated by either party with three years notice.

Support Services Agreements

Costs of support services provided by Ameren Services and AFS to their affiliates, including wages, employee benefits, professional services and other expenses are based on, or are an allocation of, actual costs incurred. Effective September 30, 2004, we were added to the support services agreements with Ameren Services and AFS.

NOTE 8 - COMMITMENTS AND CONTINGENCIES

Commitments

Reference is made to Note 5 - Commitments and Contingencies beginning on page F-20 of our Form 10-K.

Legal and Environmental Matters

Set forth below is a description of our material legal proceedings. In addition to the matters set forth below, we are involved in legal or administrative proceedings before various courts and agencies with respect to matters occurring in the ordinary


	19
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

course of business. We have recorded reserves against some of these matters in amounts believed to be appropriate and expect that the final disposition of all such ordinary course proceedings will not have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

We record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated under SFAS No. 5, “Accounting for Contingencies.” For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Environmental reserves do not reflect our assessment of the insurance coverage that may be applicable to the matters at issue, whereas litigation reserves do reflect such potential coverage. We cannot make any assurances that the amount of any reserves or potential insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.

With respect to some of the items listed below, we have determined that a loss is not probable or that any such loss, to the extent probable, can not be reasonably estimated. In some cases, we are not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, we have assessed these matters based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Our judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

Asbestos-Related Litigation We have been named in a number of lawsuits, along with numerous other parties, which have been filed by certain plaintiffs claiming varying degrees of injury from asbestos exposure at generating plants formerly owned by us. A total of 109 lawsuits have been filed, with 26 of them settled and 44 of the lawsuits dismissed. As of September 30, 2004, 39 lawsuits were pending against us. Four of these pending asbestos lawsuits were served on us during the third quarter of 2004. Most of these pending lawsuits were filed in the Circuit Court of Madison County, Illinoi s. The number of total defendants named in each case is significant with as many as 130 parties named in a case to as few as five. The average number of parties is 70 in the pending lawsuits. Each lawsuit seeks unspecified damages in excess of $50,000, which, if proved, typically would be shared among the named defendants. We have recorded a reserve with respect to the pending lawsuits. We believe that the final dispositon of these proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. See Note 3 - Rate and Regulatory Matters - Sale to Ameren for information on the ICC’s approval of a tariff rider through which asbestos-related litigation claims will be allowed to be recovered from our electric customers, subject to certain terms, commencing in 2007.

Kemerer v. Illinois Power Company This case was brought in the Circuit Court of Mercer County, Illinois, by the wife of a man who died in 2000 when he backed his aluminum ladder into overhead power lines and was electrocuted. In the lawsuit, the plaintiff sought to recover on allegations of wrongful death (including lost wages and pain and suffering), negligent infliction of emotional distress (to the decedent’s wife) and punitive damages. The case was tried before a jury in January 2004, and the jury awarded the plaintiff approximately $1.6 million in actual damages and $3 million in punitive damages. In April 2004, we filed several post-trial motions, including a motion to set as ide the verdict based on our belief that insufficient supporting evidence was presented at trial. However, in August 2004, the judge awarded approximately $1.5 million in attorney’s fees to plaintiff’s counsel and denied our post-trial motions. We are vigorously pursuing all of these issues on appeal. Reserves have been established in connection with this lawsuit.

Sarah Lucash and Kyle Johnson v. Illinois Power Company Plaintiffs Lucash and Johnson were killed in an automobile accident in February 2001 when their car struck an IP guy wire and utility pole and caught fire. Plaintiffs’ families filed a lawsuit against us in the Circuit Court of Madison County, Illinois, which asserted wrongful death and survivorship causes of action alleging that we failed to properly maintain our electrical equipment and did not have authority for the location of the pole. The parties are currently engaged in discovery. The lawsuit seeks unspecified damages in excess of $50,000. Trial is scheduled to commence in early 2005. We cannot predict with any certaint y the extent to which we will incur any liability or to estimate the damages, if any, that might be incurred in connection with this lawsuit; however, we do not expect the outcome of this litigation to have a material adverse effect upon our financial position, results of operations or liquidity. We have established a reserve in connection with this litigation.

U.S. Environmental Protection Agency Complaint IP and DMG, a Dynegy subsidiary, are the subject of an NOV from the EPA and a complaint filed in 1999 by the United States in the U.S. District Court for the Southern District of Illinois


	20
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

(Court) alleging violations of the Clean Air Act and certain related federal and Illinois regulations. Similar notices and complaints were filed against other owners of coal-fired power plants in what we refer to as the Utility Enforcement Initiative. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at the three Baldwin Power Station generating units formerly owned by us constituted “major modifications” under the PSD, the NSPS regulations and the applicable Illinois regulations, and that the defendants failed to obtain required operating permits under the applicable Illinois regulations. When activities that are not otherwise exempt result in an increase in annual emissions that exceed the amount deemed significant under the PSD re gulations, those activities are considered “major modifications”. When activities meeting this definition occur, the Clean Air Act and related regulations generally subject those activities to PSD review and permit requirements and require that the generating facilities where the activities occur meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment.

DMG, the current owner of the Baldwin Power Station, acquired the generating facility as a result of Dynegy’s acquisition of us in 2000. With Ameren’s acquisition of us on September 30, 2004, we are no longer affiliated with DMG. DMG has significantly reduced emissions of sulphur dioxide and nitrogen oxides at the Baldwin Power Station since 1999 by converting from high to low sulfur coal and installing selective catalytic reduction equipment. However, the EPA may seek in the litigation to require the installation of the “best available control technology,” or the equivalent, at the Baldwin Power Station, which could require significant capital expenditures. The EPA also has the authority to seek civil penalties for the alleged violations at the rate of up to $27,500 per day for eac h violation.

In February 2003, the Court granted our and DMG’s joint motion for partial summary judgment based on the five-year statute of limitations. As a result, the EPA is not permitted to seek any monetary civil penalties for claims related to construction without a permit under the PSD regulations. The Court’s ruling also precludes monetary civil penalties for a portion of the claims under the NSPS regulations and the applicable Illinois regulations. We believe that we have meritorious defenses against the remaining claims. The trial to resolve claims of liability was conducted in June 2003 and closing arguments occurred in September 2003. We cannot predict when a decision will be rendered by the Court on the liability phase of the litigation. If the Court finds liability, a damages trial will then be conducted.

Pursuant to the terms of the stock purchase agreement covering Ameren’s acquisition of us from Dynegy, Dynegy agreed to fully indemnify Ameren and us in the event of an adverse ruling and in any settlement arising from or out of this litigation. To secure payment of the indemnification obligations of Dynegy, Ameren, pursuant to the terms of the stock purchase agreement, has deposited $100 million of the cash portion of the purchase price into an escrow account with the funds to be released to Dynegy on the sooner of (i) December 31, 2010, (ii) the date on which the senior unsecured debt of DHI, a Dynegy subsidiary, achieves an investment grade rating from S&P or Moody’s or (iii) the occurrence of specified events relating to contingent environmental liabilities associated with our former generating facilities, including the Baldwin Power Station. We cannot predict the ultimate outcome of this litigation or whether Dynegy will be able to satisfy its indemnification obligations under the stock purchase agreement in the event that we are found to be liable. We also cannot provide any assurance that the escrow arrangement will fully secure Dynegy’s indemnification obligations if such obligations are triggered.

In August 2003 two significant decisions were handed down in other cases that are part of the Utility Enforcement Initiative. The district court in United States v. Ohio Edison applied the EPA’s narrow interpretation of the “routine maintenance, repair and replacement” exclusion, which defines it with respect to what is routine for the specific unit where the projects occurred, while the court in United States v. Duke Energy Company rejected the EPA’s narrow interpretation, holding that the exclusion should be defined relative to what is routine for the particular industry. The Duke court also held that the hours and conditions of a unit’s operations must be held constant when measuring emissions increases. Under this rationale, an increase in maximum hourly emissions is required before activities would be considered “major modifications.” We are unable to predict the significance of these cases to the Baldwin Station litigation as they a re pending in other jurisdictions and are not binding authority.

The EPA previously requested information, which has been provided, concerning activities at DMG’s Vermilion, Wood River and Hennepin plants, all formerly owned by us. Although the EPA could eventually commence enforcement actions based on activities at these plants, we are unable to assess the likelihood of any such additional EPA enforcement actions. In the event enforcement actions are initiated against us as a result of our prior ownership of these plants, we and Ameren intend


	21
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

to rely on the indemnification provisions of the stock purchase agreement with Dynegy and the escrow agreement if it is in effect at the time.

Manufactured Gas Plants In the early 1900s, we operated 25 sites at which synthetic natural gas was manufactured from coal. Operation of these MGP sites was generally discontinued in the 1950s when natural gas became available from interstate gas transmission pipelines. Many of these MGP sites were contaminated with residues from the gas manufacturing process. The Illinois Environmental Protection Agency has issued No Further Remediation Letters for two of our MGP sites. Although we estimate our liability for MGP site remediation to be approximately $46 million for our remaining 23 MGP sites, because of the unknown and unique characteristics at each site, we cannot be certain of our ultimate liabilit y for remediation of the sites. In October 1995, we initiated litigation against a number of our insurance carriers. Settlement proceeds recovered from these carriers offset a portion of the estimated MGP remediation costs and are credited to customers through the tariff rider mechanism that the ICC previously approved. Cleanup costs in excess of insurance proceeds are considered probable of recovery from our electric and gas customers, based upon ICC Docket 91-0085.

Other

Operating Leases Minimum commitments in connection with operating leases have increased from $10 million, as reported in our Form 10-K, to $14 million at September 30, 2004. These operating lease payments primarily relate to our material distribution facility, which is a commercial property lease for our storage warehouse and the leases on various trucks and other vehicles. The increase is due to additional leases for various vehicles and other equipment. In July 2004, we terminated our Tilton lease with DMG in conjunction with the purchase by DMG of the Tilton assets. Additionally, we assigned our associated land lease on the Tilton site to DMG. See Capital Leases below for a description of the Tilton lease and Tilton assets.

Capital Leases An off-balance sheet operating lease for four gas turbines located in Tilton, Illinois was reclassified as a capital lease in September 2003, pursuant to the delivery of notice of an intent to exercise an option to purchase the assets when the lease expired in September 2004. The turbine assets were sublet to DMG and we became the capital sublessor. In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, we terminated our lease with the original lessor and the related turbines were purchased from the original lessor by DMG. As a result, we no longer have any off-balance sheet financing arrangements or capital lease agreements. Please read Note 11 - Tilton for additional information related to Tilton.

Please read Note 5 - Commitments and Contingencies beginning on page F-20 of our Form 10-K and Note 3 - Rate and Regulatory Matters for a discussion of the other material regulatory matters affecting us. No additional material developments affecting us have occurred with respect to such matters since the filing of our Form 10-K.

NOTE 9 - STOCKHOLDERS’ EQUITY

Additional Paid-In Capital

In October 2004, Ameren made an equity contribution of approximately $250 million to us. This equity contribution enabled us to call for redemption, pursuant to an indenture provision related to an equity clawback, $192.5 million in principal amount of our mortgage bonds 11.5% Series due 2010. We recorded the cash contribution as additional paid-in capital. Please read Note 5 - Long-term Debt for a discussion of the equity clawback.

Other Comprehensive Income

Comprehensive income includes net income as reported on the statement of income and all other changes in common stockholders’ equity, except those resulting from transactions with common shareholders. The balance in accumulated other comprehensive income was a loss of $10 million at December 31, 2003. In the first quarter of 2004, we recorded approximately $1 million in other comprehensive income related to the accumulated benefit obligation for our pension plan assets. At September 30, 2004, our entire accumulated other comprehensive income was eliminated as a result of our sale to Ameren.


	22
ILLINOIS POWER COMPANY Notes to Consolidated Financial Statements (Unaudited) For the Interim Periods September 30, 2004 and 2003

A reconciliation of net income to comprehensive income for the three- and nine-month periods ended September 30, 2004 is shown in the table below:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2004		2003		2004		2003

Net Income	$	51	$	40	$	112	$	90
Minimum pension liability adjustment		---		---		1		---
Total comprehensive income, net of taxes	$	51	$	40	$	113	$	90

Outstanding Shares of Common Stock

The elimination of our Note Receivable from Former Affiliate involved the repurchase and immediate cancellation of some of our shares of common stock. Please read Note 2 - Sale to Ameren for additional information on the elimination of our Note Receivable from Former Affiliate. The following table shows the activity related to this repurchase:

Balance at September 30, 2004 prior to repurchase:	Number of Shares
Common stock issued	75,643,937
Less: Treasury stock held and cancelled prior to September 30, 2004⁽¹⁾	12,751,724
Total shares prior to repurchase:	62,892,213
Less:
Shares repurchased and cancelled on September 30, 2004⁽²⁾	39,892,213
Balance of outstanding shares sold to Ameren:	23,000,000

⁽¹⁾	^{Treasury stock valued at $287 million.}

⁽²⁾	^{Treasury stock valued at $626 million.}

NOTE 10 - PENSION AND OTHER POSTRETIREMENT BENEFITS

Effective with our purchase by Ameren, our employees were transferred into the Ameren defined benefit and postretirement benefit plans. As such, Ameren has assumed obligations for pension and postretirement benefits, adjusted to fair value, and net of assets transferred to Ameren plans, of approximately $137 million and $102 million, respectively, as of September 30, 2004.

Please refer to Note 2 - Sale to Ameren for information regarding the voluntary separation opportunity offered in November 2004.

Components of Net Periodic Benefit Cost The components of net periodic benefit cost under our predecessor Dynegy were:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended September 30,
	2004			2003			2004			2003
Service cost benefits earned during period	$	3.9		$	3.4		$	1.2		$	1.0
Interest cost on projected benefit obligation		9.3			9.0			2.8			2.6
Expected return on plan assets		(11.6	)		(12.6	)		(1.6	)		(1.5	)
Amortization of net transition		(0.4	)		(0.4	)		0.5			0.5
Amortization of prior service cost		0.4			0.4			---			---
Amortization of net loss		0.8			---			1.2			1.2
Net periodic benefit cost (income)	$	2.4		$	(0.2	)	$	4.1		$	3.8


	23

ILLINOIS POWER COMPANY

Notes to Consolidated Financial Statements (Unaudited)

For the Interim Periods September 30, 2004 and 2003

	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended September 30,
	2004			2003			2004			2003
Service cost benefits earned during period	$	11.7		$	10.2		$	3.6		$	3.0
Interest cost on projected benefit obligation		27.9			27.0			8.4			7.8
Expected return on plan assets		(34.8	)		(37.8	)		(4.8	)		(4.5	)
Amortization of net transition		(1.2	)		(1.2	)		1.5			1.5
Amortization of prior service cost		1.2			1.2			---			---
Amortization of net loss		2.4			---			3.6			3.6
Net periodic benefit cost (income)	$	7.2		$	(0.6	)	$	12.3		$	11.4

Contributions In Note 12 - Employee Compensation, Savings and Pension Plans beginning on page F-35 of our Form 10-K, we reported that we expected to contribute approximately $2 million related to our pension plan liability in 2004. As a result of our acquisition by Ameren, we do not anticipate being required to make any pension contributions during the remainder of 2004.

FSP SFAS 106-2 provides guidance on accounting for the effects of the Prescription Drug Act by employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Our retiree drug benefit is not actuarially equivalent to the Medicare Part D drug benefit and as such, our adoption of FSP 106-2 on July 1, 2004 had no financial impact. See Note 1 - Summary of Significant Accounting Policies - FSP SFAS 106-1 and 106-2 for further information.

NOTE 11 - TILTON

In September 1999, we entered into an operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. We sublet the turbines to DMG in October 1999. For additional information relating to the Tilton capital lease and related ARO liability and remeasurement, please read Note 1 - Summary of Significant Accounting Policies - SFAS No. 143, beginning on page F-14 and Note 5 - Commitments and Contingencies - Other - Capital Leases, beginning on page F-23 of our Form 10-K.

In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, we terminated our lease with the original lessor. DMG then executed a transfer agreement under which the original lessor sold the turbine assets to DMG for the full contract price of approximately $81 million. Additionally, we assigned our associated land lease on the Tilton site to DMG.


	24

ILLINOIS POWER COMPANY

Management’s Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

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

OVERVIEW

Executive Summary

Operationally, residential and commercial electric sales volumes for the first nine months were very similar between 2004 and 2003. While experiencing extremely mild summer weather in 2004, this was partially offset by warmer spring weather. Residential and commercial gas sales volumes were negatively impacted by warmer than normal winter weather compared to 2003. We also saw a decline in industrial electric sales related to customers choosing alternate energy providers. Operating expenses in 2004 benefited from the reimbursement of the MISO exit fee and the RTO development costs and lower departmental spending, partially offset by higher employee benefit costs and costs associated with personal injury and other damage claims.

On September 30, 2004, our acquisition by Ameren was completed, which was the major effort in the third quarter. Another major effort was our gas rate case, which was filed in June 2004. In this case, we filed testimony with the ICC requesting an increase our natural gas delivery rates by approximately $36 million annually. The requested increase applies only to base rates. Upon approval by the ICC, the new rates will go into effect in spring 2005.

General

We are a regulated utility that serves approximately 600,000 electricity customers and nearly 415,000 natural gas customers in northern, central and southern Illinois. We also currently supply electric transmission service to numerous utilities, electric cooperatives, municipalities and power marketing entities in the State of Illinois.

Our results of operations and financial condition were affected by the consolidated financial and liquidity position of Dynegy, particularly because we were relying on interest payments under an unsecured $2.3 billion intercompany note receivable from Illinova, our former direct parent company and a wholly owned Dynegy subsidiary, which we refer to as our Note Receivable from Former Affiliate, for a significant portion of our net cash provided by operating activities. Through September 30, 2004, we were an indirect, wholly owned subsidiary of Dynegy.

On September 30, 2004, our acquisition by Ameren was completed. The total transaction value was approximately $2.3 billion, including the assumption of approximately $1.8 billion of our debt and preferred stock and consideration, including transaction costs, of $451 million in cash, net of $51 million cash acquired, which, under the terms of the stock purchase agreement, is subject to a final working capital adjustment. The portion of the total transaction value attributable to Ameren’s acquisition of Dynegy’s 20% ownership interest in EEI was $125 million. Ameren placed $100 million of the cash portion of t he purchase price in a six-year escrow pending resolution of certain IP and Dynegy affiliates’ contingent environmental obligations for which Ameren has been provided indemnification by Dynegy. See Note 8 - Commitments and Contingencies to our financial statements under Item I, Part 1 of this report for information on a pending environmental matter to which the indemnification and escrow applies. In addition, this transaction included a fixed price capacity power purchase agreement for the annual purchase in 2005 and 2006 of 2,800 MWs of electricity from DPM, a subsidiary of Dynegy. The contract was marked to fair value at closing. This agreement is expected to supply approximately 70% of our electric customer requirements during those two years. We are currently in the final stages of soliciting bids to supply the remaining 30% of our power needs in 2005 and 2006. This solicitation is expected to be completed by the end of 2004. In the event that any of these suppliers are unable to supply the electricity required by the agreements, we will be forced to find alternative suppliers to meet our load requirements thus exposing us to market price risk, which could have a material impact on our results of operations. Existing power purchase agreements expire on December 31, 2004.


	25

ILLINOIS POWER COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

I, Part 1 of this report for information on redemptions and a tender offer instituted with respect to certain of our indebtedness after the acquisition.

Our Note Receivable from Former Affiliate of approximately $2.3 billion was eliminated as of September 30, 2004 and prior to the closing of Ameren’s acquisition of us to meet the conditions of the transaction. The steps to eliminate the Note were (i) the principal balance was reduced by offsetting certain payables owed by us to Illinova and other Dynegy entities; (ii) the principal balance was offset by the amount of interest that had been paid by Illinova to us but not yet earned; and (iii) a portion was eliminated in consideration of Illinova’s assumption of our net deferred tax obligation and our contemporaneous repurchase (and cancellation immediately thereafter) of a portion of our common stock. (See Note 9 - Stockholders' Equity to our financial statements under Part I, Item 1 of this report for more information on the changes in our common stock.) The remaining principal balance of our Note Receivable from Former Affiliate was eliminated, as part of our overall recapitalization, with a corresponding reduction to our retained earnings. The elimination of our Note Receivable from Former Affiliate had no impact on predecessor results of operations.

The intercompany payables consisted primarily of amounts due from us under the Services and Facilities Agreement. This included our share of income taxes, direct charges to us for specific services provided to us by Dynegy or its other entities and allocations of Dynegy administrative and general costs to us. See Note 7 - Related Party Transactions to our financial statements under Part I, Item 1 of this report for information regarding the Services and Facilities Agreement.

Ameren’s recapitalization plans for us include the infusion of a substantial amount of new equity. Ameren has committed to the ICC in conjunction with obtaining approval of our acquisition that the recapitalization plan is expected to result in us achieving a common equity to total capitalization ratio of between 50% and 60% by December 31, 2006, the end of the mandatory transition period. In October 2004, Ameren made an equity contribution to us of $250 million, the proceeds of which were used in conjunction with the redemption of $192.5 million principal amount of our mortgage bonds 11.5% Series due 2010.

In November 2004, a voluntary separation opportunity was offered to certain groups (approximately 950) of our employees. The program is voluntary and offers an enhanced separation benefit and extended medical and dental benefits. Employees must make a decision by December 20, 2004 and will leave IP throughout 2005 based on business needs. The offering of this voluntary separation opportunity is consistent with Ameren’s plan for our integration and conditions in the ICC order for the realization of administrative synergies from the acquisition. Costs of the separation are expected to be deferred as a regulatory asset, which is also consistent with the ICC order.

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 impact the demand for our services. Our results are also affected by seasonal fluctuations caused by winter heating and summer cooling demand. The prices for commodities can fluctuate significantly due to the world economic and political environment, weather, supply and demand levels and many other factors. We do not have a purchased power cost recovery mechanism for our electric utility business, but we do have a purchased gas cost recovery mechanism for our gas delivery business. Our electric rates are set through the end of 2006 such that cost decreases or increases will not be immediately reflected in rates. Fluctuations in interest rates impact our cost of borrowing and pension and postretirement benefits. We employ various risk management strategies in order to try to reduce our exposure to commodity risks and other risks inherent in our business. The reliability of our transmission and distribution systems and the level of purchased power cost, operating and administrative costs and capital investment are key factors that we seek to control in order to optimize our results of operations, cash flows and financial position.

Our sale to Ameren was completed September 30, 2004. Therefore, information in our Consolidated Statement of Income and Consolidated Statement of Cash Flows relates to our ownership under our former ultimate parent company, Dynegy (predecessor). However, our Consolidated Balance Sheet as of September 30, 2004 does reflect the effects of the sale transaction with Ameren (successor), including the “push-down” of purchase accounting. Please read Note 2 - Sale to Ameren to our financial statements under Item I, Part 1 of this report for additional information regarding the sale.


	26

ILLINOIS POWER COMPANY

Management’s Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

Our net income was $51 million for the quarter ended September 30, 2004, compared to $40 million for the quarter ended September 30, 2003. Operationally, we were impacted by extremely mild summer weather in the third quarter of 2004, as compared to 2003, which resulted in lower residential electric sales volumes. Industrial electric sales were negatively affected by customers choosing alternate energy providers. Such switching is typically based on price. Residential and commercial gas sales were relatively flat. Lower overall operating costs were primarily due to the reimbursement of the MISO exit fee and the RTO development costs and lower departmental spending, partially offset by higher employee benefits costs.

Our net income was $112 million for the nine months ended September 30, 2004, compared to $90 million for the nine months ended September 30, 2003. Operationally, residential and commercial electric sales volumes were relatively flat in 2004 as compared to 2003, while industrial electrical sales were lower. These results were due to cooler summer weather partially offset by warmer spring weather. Residential and commercial gas sales volumes were negatively impacted by warmer than normal winter weather compared to 2003. Industrial electric sales were affected by customers choosing alternate energy providers. Operating expenses in 2004 benefited from the reimbursement of the MISO exit fee and the RTO development costs and lower departmental spending, partially offset by higher employee benefit costs and costs associated with personal injury and other damage claims.

Electric Operations

Provided below is an unaudited tabular presentation of our electric operating and financial statistics for the three-month periods ended September 30, 2004 and 2003, respectively.

	Three Months Ended September 30,
	2004		2003

Electric Sales Revenues -
Residential	$	136	$	149
Commercial		105		103
Commercial-distribution⁽¹⁾		---		---
Industrial		60		77
Industrial-distribution⁽¹⁾		2		1
Other		12		12
Revenues from ultimate consumers		315		342
Transmission/Wheeling		12		10
Total Electric Revenues	$	327	$	352

Electric Sales in kWh (Millions) -
Residential		1,592		1,766
Commercial		1,217		1,208
Commercial-distribution⁽¹⁾		3		1
Industrial		1,168		1,561
Industrial-distribution⁽¹⁾		972		641
Other		99		99
Sales to ultimate consumers		5,051		5,276
Interchange		---		6
Total Electric Sales		5,051		5,282

Cooling Degree Days ⁽²⁾ - Actual		559		773
Cooling Degree Days ⁽²⁾ - 10 year Rolling Average		862		850

⁽¹⁾Distribution of customer-owned energy

⁽²⁾A Cooling Degree Day (“CDD”) represents the number of degrees that the mean temperature for a particular day is above 65 degrees

Fahrenheit. The CDDs for a period of time are computed by adding the CDDs for each day during the period.


	27

ILLINOIS POWER COMPANY

Management’s Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

Provided below is an unaudited tabular presentation of our electric operating and financial statistics for the nine-month periods ended September 30, 2004 and 2003, respectively.

	Nine Months Ended September 30,
	2004		2003

Electric Sales Revenues -
Residential	$	326	$	328
Commercial		264		259
Commercial-distribution⁽¹⁾		---		---
Industrial		177		211
Industrial-distribution⁽¹⁾		4		4
Other		30		29
Revenues from ultimate consumers		801		831
Transmission/Wheeling		31		29
Total Electric Revenues	$	832	$	860

Electric Sales in kWh (Millions) -
Residential		4,182		4,197
Commercial		3,389		3,318
Commercial-distribution⁽¹⁾		6		3
Industrial		3,859		4,614
Industrial-distribution⁽¹⁾		2,401		1,789
Other		286		285
Sales to ultimate consumers		14,123		14,206
Interchange		1		7
Total Electric Sales		14,124		14,213

Cooling Degree Days ⁽²⁾ - Actual		932		971
Cooling Degree Days ⁽²⁾ - 10 year Rolling Average		1,236		1,214

^{⁽¹⁾Distribution of customer-owned energy}

^{⁽²⁾A Cooling Degree Day (“CDD”) represents the number of degrees that the mean temperature for a particular day is above 65 degrees}

Fahrenheit. The CDDs for a period of time are computed by adding the CDDs for each day during the period.

The following table presents the favorable (unfavorable) variations in electric margins, defined as electric revenues less purchased power, for the three-month and nine-month periods ended September 30, 2004, from the comparable periods in 2003. We consider electric margin to be a useful measure to analyze the change in profitability of our electric operations between periods and have included the below analysis as a complement to our financial information provided in accordance with GAAP. However, electric margin may not be a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP information we are providing.

	Three Months			Nine Months
Electric revenue change:
Effect of weather (estimate)	$	(20	)	$	(16	)
Customer choice and other (estimate)		(5	)		(12	)
Total	$	(25	)	$	(28	)

Purchased power change:
Purchased power		21			34
Total	$	21		$	34
Net change in electric margins	$	(4	)	$	6


	28

ILLINOIS POWER COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

Our electric margin decreased $4 million for the three months ended September 30, 2004, and increased $6 million for the nine months ended September 30, 2004, as compared to the same periods in 2003. The decrease in electric margin for the three months ended September 30, 2004 was due to lower residential revenues due to unfavorable weather and industrial sales affected by customers choosing alternative suppliers. While our purchased power costs decreased because of lower volumes, the average price per MW increased due to the mix of supply. The increase in electric margin for the nine months ended September 30, 2004 was due to lower power purchase costs due to decreased demand offset by lower revenues due to unfavorable weather and reduced revenues due to industrial customers choosing alternative suppliers.

Gas Operations

Provided below is an unaudited tabular presentation of our gas operating and financial statistics for the three-month periods ended September 30, 2004 and 2003, respectively.

	Three Months Ended September 30,
	2004		2003

Gas Sales Revenues -
Residential	$	30	$	26
Commercial		12		11
Industrial		8		8
Other		-		1
Revenues from ultimate consumers		50		46
Sales to former affiliates		2		3
Total Gas Revenues	$	52	$	49

Gas Sales in Therms (Millions) -
Residential		20		18
Commercial		11		10
Industrial		9		11
Sales to ultimate consumers		40		39
Transportation of customer-owned gas		46		48
Total gas sold and transported		86		87
Sales to former affiliates		2		5
Total Gas Delivered		88		92

Heating Degree Days ⁽¹⁾ - Actual		49		88
Heating Degree Days ⁽¹⁾ - 10 year Rolling Average		59		---

⁽¹⁾A Heating Degree Day (“HDD”) represents the number of degrees that the mean temperature for a particular day is below 65 degrees

Fahrenheit. The HDDs for a period of time are computed by adding the HDDs for each day during the period.


	29

ILLINOIS POWER COMPANY

Management’s Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

Provided below is an unaudited tabular presentation of our gas operating and financial statistics for the nine-month periods ended September 30, 2004 and 2003, respectively.

	Nine Months Ended September 30,
	2004			2003

Gas Sales Revenues -
Residential	$	217		$	212
Commercial		77			78
Industrial		28			31
Other		2			3
Revenues from ultimate consumers		324			324
Transportation of customer-owned gas		(1	)		(2	)
Sales to former affiliates		5			8
Total Gas Revenues	$	328		$	330

Gas Sales in Therms (Millions) -
Residential		214			238
Commercial		85			98
Industrial		32			46
Sales to ultimate consumers		331			382
Transportation of customer-owned gas		171			170
Total gas sold and transported		502			552
Sales to former affiliates		8			11
Total Gas Delivered		510			563

Heating Degree Days ⁽¹⁾ - Actual		3,145			3,492
Heating Degree Days ⁽¹⁾ - 10 year Rolling Average		3,190			3,018

⁽¹⁾A Heating Degree Day (“HDD”) represents the number of degrees that the mean temperature for a particular day is below 65 degrees

Fahrenheit. The HDDs for a period of time are computed by adding the HDDs for each day during the period.

We consider gas margin to be a useful measure to analyze the change in profitability of our gas operations between periods. However, gas margin may not be a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP information we are providing.

Our gas margins decreased $4 million during the nine months ended September 30, 2004, as compared to 2003 primarily due to milder winter weather conditions. The change in the gas margin for the third quarter 2004 as compared to the third quarter 2003 was relatively flat.


	30

ILLINOIS POWER COMPANY

Management’s Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

Operating Expenses and Other Statement of Income Items

The following table presents the favorable (unfavorable) variations in operating and other expenses for the three months and nine months ended September 30, 2004, from the comparable period in 2003:


	Three Months			Nine Months
Other operations	$	17		$	8
Maintenance		1			2
Depreciation and amortization		(2	)		(2	)
Taxes other than income taxes		(2	)		(1	)
Other income and deductions		3			14
Interest		3			8
Income taxes		(6	)		(11	)

Other Operations and Maintenance

Our other operations and maintenance expenses decreased $17 million and $1 million for the three-month periods ended September 30, 2004 and 2003, respectively, and $8 million and $2 million for the nine-month periods ended September 30, 2004 and 2003, respectively. The decrease in the three-month and nine-month periods ended September 30, 2004, primarily resulted from the reimbursement of the MISO exit fee and the RTO development costs and lower departmental spending, partially offset by higher employee benefit costs and costs associated with personal injury and other damage claims. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for further information regarding the MISO reimbursement.

Depreciation and Amortization

Depreciation and amortization expenses increased in the three-month and nine-month periods ended September 30, 2004, as compared to the same periods in 2003, primarily due to increases in our asset base.

Taxes Other Than Income Taxes

Our taxes other than income taxes were comparable in the third quarter and nine-month period ended September 30, 2004, as compared to the same periods in 2003.

Other Income and Deductions

Other income and deductions increased in the three-month and the nine-month periods ended September 30, 2004, as compared to the same periods in 2003, primarily due to the interest income on the Tilton lease. We transferred our interest in Tilton to DMG in July 2004. Please read Note 11 - Tilton to our financial statements under Part I, Item 1 of this report for further information.

Our Other Income and Deductions include interest income of $42 million and $128 million for the three-month and nine-month periods ended September 30, 2004 and 2003, respectively, under our Note Receivable from Former Affiliate. Due to the elimination of our Note Receivable from Former Affiliate, we will no longer receive interest income under the note.

Interest

Interest expense decreased in the third quarter and first nine months of 2004, as compared to the same periods of 2003, primarily due to the lower aggregate debt balances from period to period.

Income Taxes

Income tax expense increased in the third quarter and first nine months of 2004, as compared to the same periods in 2003, primarily due to higher pre-tax income.


	31

ILLINOIS POWER COMPANY

Management’s Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

LIQUIDITY AND CAPITAL RESOURCES

Our tariff-based gross margins continue to be the principal source of cash from operating activities for us. A diversified retail customer mix of primarily rate-regulated residential, commercial and industrial classes provides a reasonably predictable source of cash flows. In addition, we plan to utilize short-term borrowings from Ameren or the Ameren utility money pool to support our normal operations and other capital requirements.

The following table presents net cash provided by or used in operating, investing and financing activities for the nine months ended September 30, 2004 and 2003:


	2004		2003		Variance
Net Cash Provided By Operating Activities	$	158	$	140	$	18
Net Cash Used In Investing Activities		96		102		6
Net Cash Used In Financing Activities		28		132		104

The following cash flow discussions do not reflect the effects of purchase accounting.

Cash Flows from Operating Activities

Cash flows from operating activities totaled $158 million for the nine-month period ended September 30, 2004, compared to $140 million reported in the comparable 2003 period. Changes in operating cash flow reflect the operating results previously discussed herein and the following significant factors. Cash flows from operations in 2003 were negatively impacted by higher gas prices on volumes in leased storage and the payment of gas purchases accrued in 2002 and the prepayment of 2003 gas purchases. Gas prices remained high in 2004 and we continue to prepay for gas purchases. Cash flows from operations in 2004 were negatively affected by the timing of our income tax payments to Dynegy and the effect of the sale on tax payments to Dynegy.

Cash Flows from Investing Activities

Cash flows from investing activities for the nine months ended September 30, 2004 were approximately $96 million compared to $102 million for the same period in 2003. Capital expenditures consisted of numerous projects to upgrade and maintain the reliability of our electric and gas transmission and distribution systems, add new customers to the system and prepare for a competitive environment.

In conjunction with our acquisition by Ameren on September 30, 2004, we expect to incur $275 million to $325 million in energy infrastructure improvements over the next two years through 2006. This commitment was made to the ICC in the proceeding involving our sale to Ameren.

Cash Flows from Financing Activities

Cash flows used in financing activities were $28 million in 2004, compared to $132 million in 2003. Cash flows used in financing activities were lower in 2004 due to lower debt maturities in 2004, as compared to 2003. In 2003, cash used for debt maturities was partially offset by the receipt of the remaining $150 million in proceeds from our December 2002 $550 million bond issuance and three months of additional prepaid interest on our Note Receivable from Former Affiliate. In May 2003, we repaid the remaining $100 million then outstanding on our $300 million term loan.

Short-term Borrowings and Liquidity

As stated above, prior to our sale to Ameren, we were an indirect, wholly owned subsidiary of Dynegy. We were susceptible to developments at Dynegy because we were relying on our Note Receivable from Former Affiliate for a substantial portion of our net cash provided by operating activities. Due to our non-investment grade credit ratings and other factors, our access to the commercial paper and capital markets was limited and we had no short-term borrowings for the nine-month period ended September 30, 2004.

Our Note Receivable from Former Affiliate, which had $2.3 billion in principal outstanding at December 31, 2003, had no balance at September 30, 2004, due to its elimination in conjunction with our sale to Ameren. The note was scheduled to mature


	32

ILLINOIS POWER COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

on September 30, 2009 and bore interest at an annual rate of 7.5%, due semiannually in April and October. Because our operating cash flows, cash on hand and other capital resources were insufficient to satisfy our 2003 debt maturities and other capital resource requirements, Dynegy prepaid approximately $128 million of interest on our Note Receivable from Former Affiliate in 2003. During the nine months ended September 30, 2004, we received an additional $170 million of prepaid interest under our Note Receivable from Former Affiliate. At September 30, 2004, we carried no prepaid interest on our Note Receivable from Former Affiliate, due to the prepaid interest elimination in conjunction with our sale to Ameren. At September 30, 2003, we carried approximately $85 million in prepaid interest.

As part of the Ameren group, we now have the ability to borrow through a utility money pool agreement. Ameren Services administers the utility money pool and tracks the internal and external funds separately. Internal funds are surplus funds contributed to the utility money pool from participants. The primary source of external funds is the UE commercial paper program. Through the utility money pool, the pool participants can access committed credit facilities at Ameren, UE, CIPS and CILCO, which totaled $1,164 million at September 30, 2004. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent the pool participants have surplus funds or other external sources are use d to increase the available amounts. The availability of funds is also determined by funding requirement limits established by the SEC under the PUHCA. We expect to rely on the utility money pool to coordinate and provide for certain short-term cash and working capital requirements. Borrowers receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends upon the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the three months ended September 30, 2004 was 1.47% (2003 - 1.02%) and for the nine months ended September 30, 2004 and 2003 was 1.17%.

Additionally, on September 30, 2004 we entered into a unilateral borrowing agreement with Ameren and Ameren Services which enables us to make short-term borrowings directly from Ameren. The aggregate amount of short-term borrowings outstanding at any time by us, including external borrowings and borrowings under the unilateral borrowing agreement and the utility money pool agreement may not exceed $500 million pursuant to authorizations from the ICC and the SEC under the PUHCA. Ameren Services is responsible for operation and administration of the agreement.

Long-term Debt and Equity

On September 30, 2004, Ameren assumed approximately $1.8 billion of our debt and preferred stock. The assumed debt and preferred stock included $936 million of mortgage bonds, $509 million of pollution control indebtedness supported by mortgage bonds, $352 million in Transitional Funding Trust Notes payable to the IPSPT and $13 million of preferred stock, net of shares acquired by Ameren. In conjunction with Ameren’s acquisition of us, our debt was adjusted to fair value by approximately $191 million, which included early debt redemption premiums. The adjustment to the fair value of each debt series is being amortized over its remaining life, or to its expected redemption date, to interest expense.

Subsequent to the acquisition of us by Ameren and pursuant to an equity clawback provision, we unconditionally called for redemption on November 15, 2004, $192.5 million in principal amount of our mortgage bonds 11.5% Series due 2010 at a price equal to $1,115 per $1,000 principal amount, together with accrued and unpaid interest to the redemption date. Ameren made an equity contribution of $250 million to us to provide funds for this purpose and to satisfy indenture provisions related to the equity clawback. We also made a cash tender offer for any remaining mortgage bonds 11.5% Series due 2010 ($357.5 million in aggregate principal amount). The purchase price was determined, as described in the offer to purchase, in accordance with standard market practice by reference to a yield of 50 basis points over the yield on the 2.625% U.S. Treasury Note due November 15, 2006, on November 18, 2004, the price determination date. The tender offer is scheduled to expire on November 22, 2004. This tender offer was also intended to satisfy our indenture obligation to offer to purchase the bonds resulting from the change of control in conjunction with our acquisition by Ameren. The bonds will be repurchased with cash contributed as equity to us by Ameren. See Note 5 - Long-term Debt to our financial statements under Part I, Item 1 of this report for further information.


	33

ILLINOIS POWER COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

the principal amount plus accrued interest. This indebtedness will be redeemed with cash contributed as equity to us by Ameren.

The following table presents the issuances, redemptions and maturities of long-term debt for the nine-month periods ended September 30, 2004 and 2003:


	Month Issued, Redeemed,	Nine Months Ended September 30,
	Repurchased or Matured	2004	2003
Issuances
11.5% Mortgage Bonds Due 2010	January	$ ---	$ 150

Redemptions, Repurchases and Maturities
6 1/2% Mortgage Bonds Due 2003	August	---	100
6% Mortgage Bonds Due 2003	September	---	90
IPSPT Transitional Funding Trust Notes	March	22	22
IPSPT Transitional Funding Trust Notes	June	21	21
IPSPT Transitional Funding Trust Notes	September	22	21

Total Redemptions		$ 65	$ 254

In each of the three- and nine-month periods ended September 30, 2004 and 2003, we paid approximately $22 million and $65 million, respectively, on the IPSPT transitional funding trust notes. For the near term, our debt maturities primarily comprise (i) similar quarterly payments on the IPSPT transitional funding trust notes, for which we receive a separate revenue stream from our customers; and (ii) maturity of $70 million principal amount of mortgage bonds due March 2005.

Indebtedness Provisions, Other Covenants and Off Balance Sheet Arrangements

See Note 4 - Short-term Borrowings and Liquidity to our financial statements under Part I, Item 1 of this report for a discussion of the indebtedness provisions contained in certain of our debt instruments.

An off-balance sheet operating lease for four gas turbines located in Tilton, Illinois was reclassified as a capital lease in September 2003, pursuant to the delivery of notice of an intent to exercise an option to purchase the assets when the lease expired in September 2004. The turbine assets were sublet to DMG and we became the capital sublessor. In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, we terminated our lease with the original lessor and the related turbines were purchased from the original lessor by DMG. As a result, we no longer have a ny off-balance sheet financing arrangements or capital lease agreements. Please read Note 11 - Tilton to our financial statements under Part I, Item 1 of this report for additional information related to Tilton.

Dividends

Under our articles of incorporation, we may pay dividends on our common stock, all of which is now owned by Ameren, subject to the preferential rights of the holders of our preferred stock, of which Ameren now owns approximately 73%. However, we are limited in our ability to pay dividends by the Illinois Public Utilities Act and the Federal Power Act, which require retained earnings equal to or greater than the amount of any proposed dividend. We are also limited in our ability to pay common dividends by the conditions of the ICC order approving our sale to Ameren.

In its approval of our acquisition by Ameren, the ICC issued an order which restricts the payment of dividends on our common stock to $80 million in 2005 and $160 million cumulatively through 2006, provided we have achieved an investment grade credit rating from S&P or Moody’s. If our mortgage bonds 11.5% Series due 2010 are not eliminated by December 31, 2006, we may not thereafter declare or pay common dividends without seeking authority from the ICC. In addition, in accordance with the order issued by the ICC, we will establish a common dividend policy comparable to the dividend policy of Ameren’s other Illinois utilities consistent with achieving and maintaining a common equity to total capitalization ratio between 50% and 60%.


	34

ILLINOIS POWER COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

During each of the nine-month periods ended September 30, 2004 and 2003, we paid preferred stock dividends of approximately $2 million. We paid no common stock dividends in the first nine months of 2004 or 2003.

Contractual Obligations and Contingent Financial Commitments

We have entered into various financial obligations and commitments in the course of our ongoing operations and financing strategies. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Financial Obligations and Commercial Commitments” beginning on page 20 of our Form 10-K for a complete listing of our obligati ons and commitments.

Subsequent to December 31, 2003, obligations associated with contracts for firm transportation and storage services for natural gas that have varying expiration dates ranging from 2004 to 2012, increased from $66 million, as reported in our Form 10-K, to approximately $73 million at September 30, 2004. The increase was the result of the renewal of three contracts under different terms and the signing of an additional contract. Gas purchase commitments have increased from approximately $38.7 million, as reported in our Form 10-K, to approximately $70 million at September 30, 2004. We began entering into fixed-price forward contracts during April 2004 and continued through October 2004. Typically, these obligations range in duration from one to twelve months and require us to compensate the provider for capacity charges.

As part of the terms of our sale to Ameren, we have entered into a PPA with a Dynegy affiliate that will be effective for 2005 and 2006. As a result of this agreement, our obligations for purchased power have increased $287 million over our estimate at December 31, 2003 of $324 million.

Subsequent to December 31, 2003, obligations associated with our operating leases have increased from $10 million to $14 million. The increase is a result of additional leases for various trucks and other vehicles.

We make periodic interest payments related to our fixed-rate and variable-rate debt obligations. Interest rates on these obligations ranged from 1.25% to 11.5% per annum during the nine months ended September 30, 2004.

As a result of our acquisition by Ameren and the merger of our pension plans with the Ameren plan, cash funding requirements have been revised and funding is no longer required until 2008 and 2009. Please see Note 10 - Pension and Other Postretirement Benefits to our financial statements under Item I, Part 1 of this report for further information.

Credit Ratings

As a result of our acquisition by Ameren, our senior secured debt ratings have been upgraded to investment grade by Moody’s, S&P and Fitch. As of October 1, 2004, our credit ratings as assessed by the three rating agencies were:

	Moody’s	S&P	Fitch
Senior Secured Debt	Baa3	A-	BBB
Preferred Stock	Ba3	BBB	BB+
Outlook	Stable	Negative	Positive

A credit rating is not a recommendation to buy, sell or hold securities and should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the assigning rating organization.


	35

ILLINOIS POWER COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

OUTLOOK

We expect the following industry-wide trends and company-specific issues to impact earnings in 2004 and beyond:

·	Economic conditions, which principally impact native load demand, particularly from our industrial customers, were weak for the past few years.

·	We have historically achieved weather-adjusted growth in our native electric residential and commercial load of approximately 2% per year and expect this trend to continue for at least the next few years.

·	Electric rates in our service territory are legislatively fixed through January 1, 2007.

The ICC conducted workshops in 2004 seeking input from interested parties on the framework for retail rate determination and the framework for generation procurement by customers after the current Illinois rate freeze ends in 2006. Ameren actively participated in these workshops and supported a framework that would have all regulated Illinois electric transmission and distribution companies bid out their native load requirements for generation through an auction process. Ameren has also supported a structure that provides for recovery from customers of the generation costs resulting from that auction. Many others participating in these workshops were supportive of the framework proposed by Ameren. We expect the ICC to issue a report on the workshop process later this year, but we do not believe the ICC will make decisions on the final regulatory structure until sometime in 2005, after Ameren and other co mpanies submit filings detailing their post-2006 plans.

·	Power prices in the Midwest impact the cost of power we purchase in the interchange markets. There continues to be overcapacity in peaking generation in the Midwest. However, power prices increased in 2004 and 2003 relative to 2002, due in part to higher prices for natural gas.

·	Increased expenses associated with rising employee benefit costs.

We have filed with the ICC for a $36 million gas rate increase. The ICC must make a decision by May 2005. In the order approving Ameren’s acquisition of us, the ICC prohibits us from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond our pending request for a gas delivery rate increase.

·	We will incur higher ongoing operational costs and may lose some revenue as a result of participating in the MISO. See Note 3 - Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for additional information.

In the ordinary course of business, we evaluate strategies to enhance our financial position, results of operations and liquidity. These strategies may include potential acquisitions, divestitures, and opportunities to reduce costs or increase revenues, and other strategic initiatives in order to increase shareholder value. We are unable to predict which, if any, of these initiatives will be executed, as well as the impact these initiatives may have on our future financial position, results of operations or liquidity; however, the impact could be material.

RISK FACTORS

We may not be able to successfully integrate into Ameren’s other businesses or achieve the benefits anticipated from the acquisition by Ameren.

We cannot assure you that we will be able to successfully integrate with Ameren’s other businesses. Our integration with Ameren’s other businesses will present significant challenges and, as a result, Ameren may not be able to operate the combined company as effectively as expected. Ameren may also fail to achieve the anticipated benefits of the acquisition as quickly or as cost effectively as anticipated or may not be able to achieve those benefits at all.

The electric rates that we are allowed to charge in Illinois are largely set through 2006. This “rate freeze,” along with other actions of regulators, can significantly affect our earnings, liquidity and business activities and are largely outside our control.

The rates that we are allowed to charge for our services are the single most important item influencing our financial position, results of operations and liquidity. We are highly regulated and the regulation of the rates that we charge our customers is determined, in large part, outside of our control by governmental organizations, including the ICC and the FERC. Decisions made by these regulators could have a material impact on our financial position, results of operations and liquidity.

As a provision of the Illinois legislation related to the restructuring of the electric industry, a rate freeze is in effect until January 1, 2007. This legislation also contains a provision requiring that earnings in excess of certain levels be shared equally with our customers through 2006. The ICC conducted workshops in 2004 seeking input from interested parties on the framework for retail rate determination and the framework for generation procurement by customers after the current rate freeze ends in 2006. We believe the ICC will make a decision on these matters in 2005.


	36

ILLINOIS POWER COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

Also, in the order approving our acquisition by Ameren, the ICC prohibits us from filing for any proposed increase in gas delivery rates to be effective prior to January 1, 2007, beyond our pending request for a gas delivery rate increase.

Ameren committed us to make between $275 million and $325 million in energy infrastructure investments over its first two years of ownership in conjunction with the ICC’s approval of our acquisition by Ameren. Our rate freeze will result in the capital expenditures related to our electric business not becoming recoverable in rates, or earning a return before January 1, 2007. Therefore, our undertakings with respect to making energy infrastructure investments and funding new programs, coupled with the rate moratoriums described above, could result in increased financing requirements for us and thus have a material impact on our liquidity.

We do not have the benefit of a purchased power adjustment clause for our electric operations that would allow us to recover increased power costs from customers. Therefore, to the extent that we have not hedged our power costs, we are exposed to changes in power prices to the extent power must be purchased on the open market in order for us to serve our customers.

Steps taken and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation. At the federal level, the FERC has been mandating changes in the regulatory framework in which transmission-owning public utilities, such as ourselves, operate. In Illinois, the Illinois Customer Choice Law provides for electric utility restructuring and retail direct access. Retail direct access, which allows customers to choose their electric generation supplier, was first offered to residential customers on May 1, 2002. Although retail direct access has not had a negative effect on our revenues or liquidity, we expect competitive forces in the electric supply segment of our business to continue to increase.

The potential negative consequences associated with further electric industry restructuring in our service territory, if it occurs, could be significant and could include the impairment and writedown of certain assets, including net regulatory assets, lower revenues, reduced profit margins and increased costs of capital and operations expenses.

We are not able to predict what rate treatment we will receive following the expiration of the rate moratorium in Illinois. Some of the factors which influence rates are largely outside our control. In response to competitive, economic, political, legislative and/or regulatory pressures, we may have to agree to further rate moratoriums, rate refunds or rate reductions, any or all of which could have a significant adverse affect on our earnings, liquidity and business activities.

Our participation in a RTO could increase costs, reduce revenues and reduce our control over our transmission assets.

In December 1999, the FERC issued Order 2000 requiring all utilities subject to the FERC jurisdiction to state their intentions for joining a RTO. On September 30, 2004, prior to the completion of Ameren’s acquisition of our business as required by the FERC order approving the acquisition, we transferred functional control of our transmission system to the MISO. Our participation in the MISO is expected to increase our annual costs by approximately $3 million in the aggregate and could result in a decrease in annual revenues of between $2 million and $3 million in the aggregate. We may also be required to expand our transmission system according to decisions made by a RTO rather than our internal planning process. In addition, we are unable to determine the full impact of the MISO’s Energy Ma rkets Tariff accepted by the FERC in August 2004 (discussed in Note 3 - Rate and Regulatory Matters to our financial statements in Part I, Item 1 of this report) until further information is available regarding the implementation of the Energy Markets Tariff.

The substance and implementation of standard market design rules by the FERC is uncertain and may adversely affect the cost and reliability of transmission service required to supply electricity to our retail customers.

On July 31, 2002, the FERC issued its standard market design NOPR. The NOPR proposes a number of changes to the way the current wholesale transmission service and energy markets are operated. Specifically, the NOPR proposes that all


	37

ILLINOIS POWER COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

jurisdictional transmission facilities be placed under the control of an independent transmission provider (similar to a RTO), proposes a new transmission service tariff that provides a single form of transmission service for all users of the transmission system including bundled retail load, and proposes a new energy market and congestion management system that uses locational marginal pricing as its basis. In Ameren’s filings with the FERC, it has expressed concern with the potential impact of the proposed rules in their current form on the cost and reliability of service to retail customers. Ameren also proposed that certain modifications be made to the proposed rules in order to protect transmission owners from the possibility of trapped transmission costs that might not be recoverable from ratepayers as a result of inconsistent regulatory policies.

In April 2003, the FERC issued a “white paper” reflecting comments received in response to the NOPR. More specifically, the white paper indicated that the FERC will not assert jurisdiction over the transmission rate component of bundled retail service and will insure that existing bundled retail customers retain their existing transmission rights and retain rights for future load growth in its final rule. Moreover, the white paper acknowledged that the final rule will provide the states with input on resource adequacy requirements, allocation of firm transmission rights, and transmission planning. The FERC also requested input on the flexibility and timing of the final rule’s implementation.

Although issuance of the final rule is uncertain and its implementation schedule is still unknown, the MISO is in the process of implementing a separate market design similar to the proposed market design in the NOPR. In July 2003, the MISO filed with the FERC a revised OATT codifying the terms and conditions under which it will implement the new market design. Thereafter, on October 17, 2003, the MISO filed a motion to withdraw its revised OATT. On October 29, 2003, the FERC issued a series of orders granting the motion for withdrawal of the revised OATT and providing guidance to be followed by the MISO in developing a new energy market design in the future. In March 2004, the MISO tendered for filing at the FERC a proposed Energy Markets Tariff, which is intended to supercede its existing OATT (see N ote 3 - Rate and Regulatory Matters to our financial statements under Item I, Part 1 of this report). In August 2004, the FERC accepted the MISO’s Energy Market Tariff subject to further compliance filings. On November 8, 2004, the FERC issued an order denying the requests for rehearing that were filed by a number of MISO stakeholders including Ameren. However, a final order from the FERC on the compliance filings made by the MISO in response to the FERC’s August 6 order is still pending. Until the FERC issues a final rule and the MISO finalizes its new market design, we are unable to predict the ultimate impact of the NOPR or the MISO new market design on our future financial position, results of operations or liquidity.

Increasing costs associated with our defined benefit retirement plan, healthcare plan and other employee related benefits may adversely affect our results of operations, liquidity and financial position.

Due to our acquisition by Ameren, no contributions to our defined benefit retirement plan are expected to be necessary through 2007. Future required contributions are now estimated to be $27 million in 2008 and $42 million in 2009. These amounts are estimates and may change based on actual stock market performance, changes in interest rates, and any pertinent changes in government regulations, each of which could also result in a requirement to record an additional minimum pension liability.

In addition to the costs of our retirement plan, the costs to us of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to the healthcare plan for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plan, healthcare plans and other employee benefits may adversely affect our results of operations, liquidity or financial position.

Our energy risk management strategies may not be effective in managing electricity pricing risks, which could result in unanticipated liabilities to us or increased volatility of our earnings.

We are exposed to changes in market prices for electricity. Prices for electricity may fluctuate substantially over relatively short periods of time and expose us to commodity price risk. We attempt to manage our exposure from these activities through enforcement of established risk limits and risk management procedures. We cannot assure you that these strategies will be successful in managing our pricing risk, or that they will not result in net liabilities to us as a result of future volatility in these markets.


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ILLINOIS POWER COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

Our business is dependent on our ability to successfully access the capital markets. We may not have access to sufficient capital in the amounts and at the times needed.

We rely on access to short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied by our operating cash flows. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively impact our ability to maintain and grow our business. Based on our current credit ratings, we believe that we will have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets such that our cost of capital would increase or our ability to access the capital markets would be adversely affected.

Our counterparties may not meet their obligations to us.

We are exposed to risk that counterparties which owe us money, energy or other commodities or services will not be able to perform their obligations. The possibility that certain counterparties may fail to perform their obligations has increased due to financial difficulties, in some cases brought on by improper or illegal accounting and business practices, affecting some participants in the industry. Should the counterparties to these arrangements (which include an agreement pursuant to which a subsidiary of Dynegy is obligated to supply electricity to us during 2005 and 2006) fail to perform, we might be forced to obtain replacement power at then-current market prices. In such event we might incur losses in addition to amounts, if any, already paid to the counterparties.

REGULATORY MATTERS

See Note 3 - Rate and Regulatory Matters, Note 7 - Related Party Transactions and Note 8 - Commitments and Contingencies to our financial statements under Part I, Item 1 of this report.


	39

ILLINOIS POWER COMPANY

Management’s Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Commodity Price Risk

We are exposed to changes in market prices for natural gas and electricity to the extent they cannot be recovered through rates.

Electricity Our operating results may be impacted by commodity price fluctuations for electricity used in supplying service to our customers. We have contracted with AmerGen and DMG to supply power via PPAs that expire at the end of 2004. Should power acquired under these agreements be insufficient to meet our load requirements, we will have to buy power at current market prices. The PPA with DMG obligates DMG to provide power up to the reservation amount, and at the same prices, even if DMG has individual units unavailable at various times. The PPA with AmerGen does not obligate AmerGen to acquire replacement power for us in the event of a curtailment or shutdown at its Clinton Power S tation. Under a Clinton shutdown scenario, to the extent we exceed our capacity reservation with DMG, we will have to buy power at current market prices. Such purchases would expose us to commodity price risk. As discussed in our Form 10-K, P.A. 90-561 was amended to extend the retail electric rate freeze for two additional years, through 2006.

As part of our acquisition by Ameren, we entered into a fixed price PPA with DPM for our annual purchase in 2005 and 2006 of 2,800 MWs of electricity. This agreement is expected to supply 70% of our electric customer requirements during those two years. Additionally, we are in the final stages of soliciting bids to supply the remaining 30% of our power needs for 2005 and 2006. This solicitation is expected to be completed by the end of 2004. If we are unable to sufficiently contract for all of our power and energy needs, or if any of the parties to these agreements are unable to satisfy their obligations thereunder for any reason, either to purchase or deliver power, we could be required to satisfy our needs through open market purchases thus exposing us to commodity price risk. Any additional costs co uld not be passed on to ratepayers until at least the end of the rate freeze in Illinois.

Gas The ICC determines rates that we may charge for retail gas service. As with the rates that we are allowed to charge for retail electric service, these rates are designed to recover our cost of service and to allow our shareholders the opportunity to earn a reasonable rate of return. Our rate schedules contain PGA provisions for passing through to our customers any increases or decreases in the cost of natural gas, subject to an annual prudency review by the ICC. Rates for gas distribution services are set by the ICC in rate proceedings and are based on the underlying costs. Future natural gas sales will continue to be affected by an increasingly competitive marketplace, changes in t he regulatory environment, transmission access, weather conditions, gas cost recoveries, customer conservation efforts and the overall economy. Price risk associated with our gas operations is mitigated through contractual terms applicable to the business, as allowed by the ICC. We apply prudent risk management practices in order to minimize these market risks. However, such risk management practices may not fully mitigate these exposures.

In June 2004, we filed with the ICC seeking authority to raise our natural gas delivery rates by approximately $40 million annually, which we revised in August to approximately $36 million annually. The requested increase will allow us to recover investments in our natural gas delivery system. The requested increase applies only to base rates and does not affect the cost of gas itself, which typically accounts for approximately two-thirds of customers’ total gas bills and is recovered via the PGA process. As part of the regulatory process, which can be expected to take up to eleven months, the ICC will decide the amount of increase, if any, to provide recovery of costs from our customers. Upon approval, the new rates will go into effect in spring 2005. See Note 3 - Rate and Regulatory Matters to o ur financial statements under Part I, Item 1 of this report for further information on this pending rate proceeding.

Interest Rate Risk We are exposed to fluctuating interest rates related to variable rate financial obligations. As of September 30, 2004, approximately 19% of our total debt instruments were variable rate instruments. Based upon sensitivity analysis of the variable rate financial obligations in our debt portfolio as of September 30, 2004, it is estimated that a one percentage point interest rate increase or decrease in the average market interest rates during the twelve month period ending September 30, 2005 would result in a change of approximately $3 million in interest expense.


	40

ILLINOIS POWER COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations

For the Interim Periods September 30, 2004 and 2003

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of Disclosure Controls and Procedures

As of September 30, 2004, the principal executive officer and principal financial officer of the Registrant have evaluated the effectiveness of the design and operation of the Registrant’s disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act). Based upon that evaluation, the principal executive officer and principal financial officer of the Registrant have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to the Registrant, which is required to be included in the Registrant’s reports filed or submitted with the SEC under the Exchange Act.

(b) Change in Internal Controls

There has been no change to the Registrant’s internal control over financial reporting that occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting. Subsequent to Ameren’s acquisition of us on September 30, 2004, certain of our internal controls over financial reporting were modified to make such internal controls consistent with the internal controls of Ameren and its subsidiaries. The internal controls over financial reporting adopted from Ameren and its subsidiaries were used in connection with the preparation of this report.


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ILLINOIS POWER COMPANY

PART II. OTHER INFORMATION

ITEM 1 - LEGAL PROCEEDINGS.

Note 3 - Rate and Regulatory Matters, Note 7 - Related Party Transactions and Note 8 - Commitments and Contingencies to our financial statements under Part I, Item 1, of this report contain information on legal and administrative proceedings which are incorporated by reference under this item.

ITEM 6 - EXHIBITS.

(a)	The following documents are included as exhibits to this Form 10-Q:

*10.1 Amendment No. 2, dated as of April 30, 2004, to Stock Purchase Agreement, dated as of February 2, 2004, by and between Dynegy and certain of its subsidiaries and Ameren (incorporated by reference to Exhibit 2.1 to the Form 10-Q for the quarterly period ended June 30, 2004 of Ameren, File No. 1-14756).

*10.2 Amendment No. 3, dated as of May 31, 2004, to Stock Purchase Agreement, dated as of February 2, 2004, by and between Dynegy and certain of its subsidiaries and Ameren (incorporated by reference to Exhibit 2.2 to the Form 10-Q for the quarterly period ended June 30, 2004 of Ameren, File No. 1-14756).

*10.3 Amendment No. 4, dated as of September 24, 2004, to Stock Purchase Agreement, dated as of February 2, 2004, by and between Dynegy and certain of its subsidiaries and Ameren (incorporated by reference to Exhibit 2.1 to the Form 10-Q for the quarterly period ended September 30, 2004 of Ameren, File No. 1-14756).

*10.4 Escrow Agreement among Illinova, Ameren and JPMorgan Chase Bank, as escrow agent, dated as of September 30, 2004, (incorporated by reference to Exhibit 10.1 to the Form 10-Q for the quarterly period ended September 30, 2004 of Ameren, File No. 1-14756).

†31.1 Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Illinois Power.

†31.2 Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Illinois Power.

†32.1 Section 1350 Certification of Principal Executive Officer of Illinois Power.

†32.2 Section 1350 Certification of Principal Financial Officer of Illinois Power.

† Filed herewith.

*Incoporated herein by reference.


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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	ILLINOIS POWER COMPANY

Date: November 19, 2004	By:	/s/ Martin J. Lyons
		Martin J. Lyons
		Vice President and Controller
		(Principal Accounting Officer)

AFS	Ameren Energy Fuels and Services Company
Ameren	Ameren Corporation, parent company of IP as of September 30, 2004
Ameren Services	Ameren Services Company
AmerenIP	Illinois Power Company, doing business as AmerenIP
AmerGen	AmerGen Energy Company
ARB	Accounting Research Board
ARO	Asset Retirement Obligation
Bcf	Billion cubic feet
CILCO	Central Illinois Light Company, doing business as AmerenCILCO
CIPS	Central Illinois Public Service Company, doing business as AmerenCIPS
Clinton	Clinton Power Station
CWIP	Construction work in progress
DHI	Dynegy Holdings Inc.
DMG	Dynegy Midwest Generation, Inc.
DPM	Dynegy Power Marketing Inc.
Dynegy	Dynegy Inc.
EEI	Electric Energy, Inc.
EPA	U.S. Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FCC	Federal Communications Commission
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
Fitch	Fitch Ratings
Form 10-K	Our Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 12, 2004
FSP	FASB Staff Position
GAAP	Generally accepted accounting principles in the United States of America
ICC	Illinois Commerce Commission
Illinova	Illinova Corporation, our former direct parent company and a wholly owned subsidiary of Dynegy
IP	Illinois Power Company
IPSPT	Illinois Power Special Purpose Trust
ISO	Independent System Operator
kWh	Kilowatt-hour
LLC	Illinois Power Securitization Limited Liability Company
MGP	Manufactured Gas Plant
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatt
NOPR	Notice of Proposed Rulemaking
NOV	Notice of Violation
NSPS	New Source Performance Standard
OATT	Open Access Transmission Tariff
P.A. 90-561	Electric Service Customer Choice and Rate Relief Law of 1997
PGA	Purchase Gas Adjustment
PJM	PJM Interconnection LLC
PPA	Power Purchase Agreement
PSD	Prevention of Significant Deterioration
PUHCA	Public Utility Holding Company Act of 1935, as amended
RTO	Regional Transmission Organization
SEC	U.S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SPE	Special Purpose Entity
S&P	Standard and Poor’s Inc.
UE	Union Electric Company, doing business as AmerenUE
VIE	Variable Interest Entity