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, 2003 

¨ 

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 

(I.R.S. Employer 

incorporation or organization) 

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 x NO o

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

YES o NO x

Illinova Corporation is the sole holder of all 62,892,213 outstanding shares of the common stock and owns approximately 73% of the preferred stock of Illinois Power Company. There is no voting or non-voting common equity held by non-affiliates of Illinois Power Company. Illinois Power Company is an indirect wholly owned subsidiary of Dynegy Inc.


	1

ILLINOIS POWER COMPANY 

TABLE OF CONTENTS 

			Page

PART I.	FINANCIAL INFORMATION

	Definitions		3


	Item 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED):

	Condensed Consolidated Balance Sheets:
		September 30, 2003 and December 31, 2002	4

	Condensed Consolidated Statements of Income and Comprehensive Income:
		For the three and nine months ended September 30, 2003 and 2002	5

	Condensed Consolidated Statements of Cash Flows:
		For the nine months ended September 30, 2003 and 2002	6

	Notes to Condensed Consolidated Financial Statements		7


	Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	17

	Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	30

	Item 4.	CONTROLS AND PROCEDURES	30

PART II.	OTHER INFORMATION

	Item 1.	LEGAL PROCEEDINGS	31

	Item 6.	EXHIBITS AND REPORTS ON FORM 8-K	31



	2

PART I 

Definitions 

As used in this Form 10-Q, the terms listed below are defined as follows: 

AmerGen	AmerGen Energy Company
ARB	Accounting Research Board
ARO	Asset Retirement Obligation
Clinton	Clinton Power Station
ComEd	Commonwealth Edison Company
DMG	Dynegy Midwest Generation, Inc.
Dynegy	Dynegy Inc.
EITF	Emerging Issues Task Force of the Financial Accounting Standards Board
EPA	Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
Exelon	Exelon Corporation
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation Number
GAAP	Generally Accepted Accounting Principles
ICC	Illinois Commerce Commission
Illinova	Illinova Corporation, our direct parent company and a wholly owned subsidiary of Dynegy
kWh	Kilowatt-Hour
MGP	Manufactured-Gas Plant
MISO	Midwest Independent Transmission System Operator, Inc.
MW	Megawatts
NOV	Notice of Violation
P.A. 90-561	Electric Service Customer Choice and Rate Relief Law of 1997
PPA	Power Purchase Agreement
PUHCA	The Public Utility Holding Company Act of 1935, as amended
RTO	Regional Transmission Organization
SEC	United States Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
Trans-Elect	Trans-Elect Inc.



	3

ILLINOIS POWER COMPANY 

CONDENSED CONSOLIDATED BALANCE SHEETS (in millions, except share data) (unaudited) 


	September 30, 2003			December 31, 2002

ASSETS
Utility Plant:
Electric (includes construction work in progress of $91 million and $98 million, respectively)	$	2,484		$	2,410
Gas (includes construction work in progress of $18 million and $18 million, respectively)		781			770

		3,265			3,180
Less -- accumulated depreciation		1,261			1,219

		2,004			1,961


Investments and Other Assets		10			9


Current Assets:
Cash and cash equivalents		23			117
Restricted cash		20			17
Accounts receivable, net		120			104
Accounts receivable, affiliates		71			22
Accrued unbilled revenue		63			78
Inventories, at average cost		64			44
Prepayments and other		42			20

		403			402


Note Receivable from Affiliate		2,271			2,271


Deferred Debits:
Transition period cost recovery		126			155
Other		134			143

		260			298

	$	4,948		$	4,941


CAPITAL AND LIABILITIES
Capitalization:
Common stock -- no par value, 100,000,000 shares authorized: 75,643,937 shares issued, stated at	$	1,274		$	1,274
Additional paid-in capital		9			9
Retained earnings - accumulated since 1/1/99		478			390
Accumulated other comprehensive income (loss), net of tax		(13	)		(13	)
Less -- Capital stock expense		7			7
Less -- 12,751,724 shares of common stock in treasury, at cost		287			287

		1,454			1,366

Preferred stock		46			46
Long-term debt		1,801			1,719

		3,301			3,131


Current Liabilities:
Accounts payable		41			66
Accounts payable, affiliates		11			18
Notes payable and current portion of long-term debt		86			376
Accrued liabilities		240			145

		378			605


Deferred Credits:
Accumulated deferred income taxes		1,003			1,038
Accumulated deferred investment tax credits		20			21
Other		246			146

		1,269			1,205

	$	4,948		$	4,941

See notes to condensed consolidated financial statements. 


	4

ILLINOIS POWER COMPANY 

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (in millions) (unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,

		2003			2002			2003			2002


Operating Revenues:
Electric	$	352		$	365		$	860		$	896
Gas		49			41			330			247

Total		401			406			1,190			1,143


Operating Expenses and Taxes:
Power purchased		212			210			530			521
Gas purchased for resale		27			19			220			147
Other operating expenses		47			38			110			107
Maintenance		15			16			43			41
Depreciation and amortization		19			20			59			61
Amortization of regulatory assets		11			12			32			38
General taxes		13			9			51			45
Income taxes		10			25			15			45

Total		354			349			1,060			1,005

Operating income		47			57			130			138


Other Income and Deductions – Net:
Interest income from affiliates		43			43			128			128
Miscellaneous - net		(12	)		(16	)		(44	)		(45	)

Total		31			27			84			83

Income before interest charges		78			84			214			221


Interest Charges:
Interest expense		38			27			122			83
Allowance for borrowed funds used during construction		---			---			---			---

Total		38			27			122			83


Earnings before cumulative effect of change in accounting principle		40			57			92			138
Cumulative effect of change in accounting principle, net of tax (Note 1)		---			---			(2	)		---


Net income		40			57			90			138
Less - Preferred dividend requirements		1			1			2			2

Net income applicable to common shareholder	$	39		$	56		$	88		$	136



Net income	$	40		$	57		$	90		$	138
Other comprehensive income (loss), net of tax		---			---			---			---

Comprehensive income	$	40		$	57		$	90		$	138

See notes to condensed consolidated financial statements. 


	5

ILLINOIS POWER COMPANY 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) (unaudited) 


	Nine Months Ended September 30,

		2003			2002


CASH FLOWS FROM OPERATING ACTIVITIES:

Net income	$	90		$	138
Items not affecting cash flows from operating activities:
Depreciation and amortization		98			105
Deferred income taxes		(11	)		(2	)
Cumulative effect of change in accounting principle (Note 1)		2			---

Changes in assets and liabilities resulting from operating activities:
Accounts receivable		1			(5	)
Unbilled revenue		15			14
Inventories		(20	)		4
Prepayments		(23	)		(4	)
Accounts payable		(32	)		(11	)
Other deferred credits		(25	)		(9	)
Interest accrued and other, net		45			(11	)


Net cash provided by operating activities		140			219


CASH FLOWS FROM INVESTING ACTIVITIES:

Capital expenditures		(100	)		(102	)
Other investing activities		(2	)		4


Net cash used in investing activities		(102	)		(98	)


CASH FLOWS FROM FINANCING ACTIVITIES:

Dividends on common and preferred stock		(2	)		(2	)
Prepaid interest from affiliate		85			---
Redemptions:
Short-term debt		(100	)		(38	)
Long-term debt		(254	)		(161	)
Issuances:
Short-term debt		---			60
Long-term debt		150			---
Increase in restricted cash		(3	)		(6	)
Other financing activities		(8	)		(3	)


Net cash used in financing activities		(132	)		(150	)


Net change in cash and cash equivalents		(94	)		(29	)
Cash and cash equivalents at beginning of period		117			41


Cash and cash equivalents at end of period	$	23		$	12

See notes to condensed consolidated financial statements . 


	6

ILLINOIS POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the Interim Periods Ended September 30, 2003 and 2002

Note 1 - Summary of Significant Accounting Policies 

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. These interim financial statements should be read together with the audited consolidated financial statements and notes thereto included in Illinois Power Company’s ("IP," "we," "us" and "our" ) Annual Report on Form 10-K for the year ended December 31, 2002, which we refer to in this report as the Form 10-K. 

The unaudited condensed consolidated financial statements contained in this quarterly report include all material adjustments that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. Interim period results are not necessarily indicative of the results for the full year. The preparation of the condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to develop estimates and make assumptions that affect reported financial position and results of operations and that impact the nature and extent of disclosure, if any, of contingent assets and 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 judgments and 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) recording revenue for services provided but not yet billed, (2) estimating the useful lives of our assets, (3) analyzing tangible and intangible assets for impairment, (4) projecting recovery of stranded costs, (5) estimating various factors impacting the valuation of our pension assets, (6) assessing future tax exposure and the realization of tax assets and (7) determining the amounts to accrue related to contingencies. Actual results could differ materially from any such estimates. Certain reclass
ifications have been made to prior period amounts in order to conform to current year presentation. 

All significant intercompany balances and transactions have been eliminated from the unaudited condensed consolidated financial statements included in this quarterly report. All nonutility operating transactions are included in the line titled "Miscellaneous - net" in our Condensed Consolidated Statements of Income and Comprehensive Income. 

Accounting Principles Adopted 

SFAS No. 143 In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." We adopted this statement effective January 1, 2003. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. Under SFAS No. 143, the 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. In each subsequent period the liability is accreted to its fair value and the capitalized cost is depreciated over the useful life of the related asset. The cumulative effect of applying SFAS No. 143 has been recognized as a change in accounting principle in the unaudited condensed consolidated statements of income and comprehensive income. Upon adoption, the cumulative effect, net of the associated income taxes, was approximately $2 million related to our lease agreement for four gas t urbines and a separate land lease agreement in Tilton, Illinois and the ARO liability for the asset receivable and the land lease was approximately $6 million. Amortization and accretion expense for 2003 is expected to be approximately $1 million. There were no additional AROs recorded or settled during the three-and nine-month periods ending September 30, 2003.

In addition to this liability, we also have potential retirement obligations for the dismantlement of our electric and gas transmission and distribution facilities and natural gas storage facilities. It is our intent to maintain these facilities in a manner such that the facilities will be operational indefinitely. As such, we cannot estimate any potential retirement obligations associated with these assets. At the time we are able to estimate any new asset retirement obligations, liabilities will be recorded in accordance with SFAS No. 143.

Had SFAS No. 143 been applied retroactively in the three months and nine months ended September 30, 2002, our net income would have been reduced by approximately $0.2 million and $0.6 million, respectively. 


	7

ILLINOIS POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the Interim Periods Ended September 30, 2003 and 2002

SFAS No. 146   In July 2002, the FASB issued SFAS No. 146, "Accounting for Exit or Disposal Activities." SFAS No. 146 addresses issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that were previously accounted for pursuant to the guidance in EITF Issue 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002.  The adoption of SFAS
 No. 146 did not have any impact on our financial statements. 

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 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’s accounting policy decisions with respect to stock-based employee compensation. We transitioned to a 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. As a result, a charge of approximately $0.2 million will be reflected in 2003 other operating expense in the unaudited condensed consolidated statements of income and comprehensive income. 

Under the prospective method of transition, all stock options granted since January 1, 2003 will be accounted for on a fair value basis. As of September 30, 2003, the fair value based expense which we have recorded for options granted in 2003 is $0.1 million. Options granted prior to January 1, 2003 continue to be accounted for using the intrinsic value method. Had compensation cost for options granted before January 1, 2003 been determined on a fair value basis consistent with SFAS No. 123, our net income would have approximated the following pro forma amounts for the three- and nine-months ended September 30, 2003 and 2002, respectively (in millions). 

	Three Months Ended				Nine Months Ended
	September 30,				September 30,

		2003		2002		2003		2002

Net income as reported	$	40	$	57	$	90	$	138
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		---		---		---		---

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	$	39	$	56	$	87	$	135

FIN 45   In November 2002, the FASB issued FIN 45, "Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." As required by FIN 45, we adopted the disclosure requirements on December 31, 2002. On January 1, 2003, we adopted the initial recognition and measurement provisions for guarantees issued or modified after December 31, 2002. The adoption of the recognition and measurement provisions did not have any impact on our financial statements. 

Accounting Principles Not Yet Adopted

FIN 46   In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities—an Interpretation of ARB No. 51." In summary, this interpretation increases the level of risk that must be assumed by equity investors in special purpose entities. FIN 46 requires that the equity investor have significant equity at risk (a minimum of 10 percent with few exceptions, which is an increase from 3 percent under previous guidance) and hold a controlling interest, evidenced by voting rights, risk of loss and the benefit of residual returns. If the equity investor is unable to evidence these characteristics, the entity that retains these
 ownership characteristics will be required to consolidate the variable interest entity. While we have not entered into any arrangements in 2003 that would be subject to FIN 46, we are analyzing the structures of entities previously formed to determine whether we have any arrangements that are impacted. FIN 46 was applicable immediately to variable interest entities created or obtained after January 31, 2003. For variable interest entities created or obtained before February 1, 2003, FIN 46 was applicable as of July 1, 2003. In October 2003, the FASB deferred the implementation date of FIN 46 until the fourth quarter 2003. The impact of adopting FIN 46 will be reflected as a cumulative effect of a change in accounting principle in the fourth quarter 2003. 


	8

ILLINOIS POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the Interim Periods Ended September 30, 2003 and 2002

Note 2 - Agreed Sale to Exelon

On October 31, 2003, we and Dynegy Inc., our ultimate parent company, among others, entered into a purchase agreement under which a newly formed subsidiary of Exelon Corporation, which we refer to as New IP Company, will acquire substantially all of our assets and liabilities, excluding, among other things, the $2.3 billion note receivable from Illinova and deferred taxes from the previous transfer of our fossil generating assets to DMG, for $2.225 billion. The purchase price includes:

		•	the assumption by Exelon of all of our debt, estimated to be approximately $1.8 billion at closing;

		•	a $150 million promissory note; and

		•	approximately $275 million of cash, subject to working capital adjustments

Proceeds from the transaction would be used to reduce Dynegy Inc.’s consolidated indebtedness.

The consummation of the sale is conditioned upon, among other things, the elimination of the obligation to us under the $2.3 billion intercompany note receivable from Illinova. The sale is also conditioned on the receipt of all regulatory and other consents and approvals as specified in the purchase agreement, including approvals from the ICC, FERC, the SEC and other governmental and regulatory agencies. The passage of legislation recently introduced in the Illinois General Assembly during its November veto session, which ends on November 20, 2003, is critical to the consummation of the transaction. This legislation would authorize the ICC to consider the sale transaction and a proposed rate plan in a single proceeding and render a decision on both issues in a nine-month review process. The proposed rate plan contemplates a rate increase beginning in 2007.

The proposed legislation provides for an immediate effective date, which requires passage by vote of at least three-fifths of each house of the General Assembly. If the legislation passes by a three-fifths super-majority vote in the November veto session and is promptly signed into law by the Governor, then it would become effective in late November. If the legislation becomes effective, a petition would be filed with the ICC in December, which would start the nine-month review with a decision expected in September 2004. Filings with the FERC and the SEC are expected to be made around the same time as the filing of the petition with the ICC. Rulings by the FERC and the SEC are currently anticipated within a few months following the ICC’s decision. Pending these state and federal approvals, the sale is expected to close in the fourth quarter of 2004. Approval of the legislation by less than a three-fifths super-majority would delay its effective date, as well as the filings with the ICC, the FERC and the SEC, until July 2004, and delay the decision by the ICC until early 2005.

Since the submission of the proposed legislation, various consumer groups and others in Illinois have voiced their opposition. As a result, the language contained in the proposed legislation has changed and may continue to change throughout the approval process. Additionally, on November 3, 2003, the People of the State of Illinois, by and through Lisa Madigan, Attorney General of the State of Illinois, the Cook County State’s Attorney Office, the Citizens Utility Board and others, filed a petition at the ICC seeking an investigation by the ICC into Illinois Power’s financial condition. The stated purpose of the request is to assist the General Assembly in determining whether to pass the proposed legislation. An initial hearing in this matter before an Administrative Law Judge has been set for November 14, 2003. It is not possible to determine the outcome of this proceeding or when it w ill be decided. Moreover, we cannot assure you that the proposed legislation will be approved by the General Assembly.

The purchase agreement may be terminated upon the occurrence of certain events, including:

	•	if the closing shall not have occurred on or before December 31, 2004; or

	•	if the above-described Illinois legislation does not become effective within 60 days of the end of the legislative session of the Illinois General Assembly scheduled to begin in January 2004.

In a related agreement that is conditioned upon the closing of the transaction, Dynegy has contracted to sell 3,100 MW of generating capacity and 2,900 MW of generating capacity and energy to an Exelon subsidiary, which in turn would contract to sell power to New IP Company, for six years beginning in January 2005. It is anticipated that this agreement will be in place concurrently with the termination of our power purchase agreement with DMG, which expires in December 2004, and the closing of the sale to Exelon.


	9

ILLINOIS POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the Interim Periods Ended September 30, 2003 and 2002

Note 3 - Related Parties 

At September 30, 2003, principal outstanding under our note receivable from Illinova approximated $2.3 billion.  We refer to this note as our Note Receivable from Affiliate.  Due to the July and September 2003 prepayments described below, we had no accrued interest at September 30, 2003. At December 31, 2002, principal outstanding under our Note Receivable from Affiliate approximated $2.3 billion with accrued interest of approximately $14 million. We recognized approximately $43 million of interest income under our Note Receivable from Affiliate for the three months ended September 30, 2003 and September 30, 2002 and approximately $128 million of interest income for the nine months ended September 30, 2003 and September 30, 2002. In July 2003, Dynegy made an interest pa
yment of approximately $100 million on its $2.3 billion intercompany note payable to Illinova, which in turn made an interest payment of approximately $100 million to us under our Note Receivable from Affiliate. In September and October 2003, Dynegy paid to Illinova, which in turn paid us, additional interest payments of approximately $71 million and approximately $28 million, respectively. These notes contain substantially similar interest payment provisions pursuant to which semi-annual interest payments of approximately $86 million are due to us under our Note Receivable from Affiliate on April 1 and October 1 of each year. The amounts paid to us in July, September and October 2003 represent accrued interest on the notes for the months of April – September 2003 and prepaid interest for the months of October 2003 – May 2004. We have classified six months of prepaid interest, received as of September 30, 2003, as cash flows from financing activities on our condensed consolidated statemen
t of cash flows. As the interest is earned, it will be reclassified as cash flows from operating activities in the condensed consolidated cash flow statement. For further discussion of our liquidity position and support commitment from Dynegy, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations – Credit Capacity, Liquidity and Debt Maturities – Sources of Liquidity" beginning on page 18. 

We have reviewed the collectibility of our Note Receivable from Affiliate to assess whether it has become impaired under the criteria of SFAS No. 114, “Accounting by Creditors for Impairment of a Loan.”  Under this standard, a loan is impaired when, based on current information and events, it is “probable” that a creditor will be unable to collect all amounts due according to the contractual terms of the loan agreement.  Please see Note 1, “Summary of Significant Accounting Policies,” in the Form 10-K for further discussion as to applicable GAAP requirements regarding impairment of this note.  While we believe that our Note Receivable from Affiliate is not impaired and is fully collectible, we continue to review the collectibility of the note on a quarterly basis.  Principal payments on our Note Receivable from Af
filiate are not required until 2009 when it is due in full; as a result, future events may affect our view as to the collectibility of the remaining principal owed us under the note.  In our fourth quarter review, we will consider the impact, if any, of the proposed transaction with Exelon on the collectibility of our Note Receivable from Affiliate.  It is possible that if negative events affect Dynegy or if we do not receive timely interest payments on our Note Receivable from Affiliate, such matters could cause us to believe it necessary to impair our Note Receivable from Affiliate on our condensed consolidated balance sheet and such action could have a material adverse effect on our liquidity, financial condition and results of operations.  For example, a significant impairment could impact our ability to comply with the financial covenants contained in our Tilton lease agreement and to stay within the utility earnings cap contained in the Illinois Customer Choice Law.

We routinely conduct business with other subsidiaries of Dynegy. These transactions include the purchase or sale of electricity, natural gas and transmission services as well as certain other services. Operating revenue derived from transactions with affiliates approximated $8 million and $23 million for the three- and nine-months ended September 30, 2003. For the three- and nine-months ended September 30, 2002, approximately $10 million and $26 million in operating revenue was derived from affiliate transactions. Aggregate operating expenses charged by affiliates during the quarter ended September 30, 2003 approximated $139 million, including $124 million for power purchased. Approximately $412 million in aggregate operating expenses, including $356 million for power purchased, was 
charged by affiliates during the nine-months ended September 30, 2003. Aggregate operating expenses charged by affiliates approximated $148 million and $403 million for the three- and nine-months ended September 30, 2002, including $132 million and $369 million, respectively, for power purchased. The change in operating expenses, excluding power purchased, resulted from additional purchases of gas from an affiliate. We believe that these related party transactions have been conducted at prices and terms similar to those available to and transacted with unrelated parties. 


	10

ILLINOIS POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the Interim Periods Ended September 30, 2003 and 2002

Note 4 - Commitments and Contingencies 

Commitments 

Please see Note 6, "Commitments and Contingencies," to the Form 10-K for a description of the material commitments affecting us. No material developments affecting us have occurred with respect to such matters since our filing of the Form 10-K, except as described herein. 

Legal and Environmental Matters 

Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In the opinion of management, the disposition of these ordinary course matters will not have a material adverse effect on our 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 is reasonably estimable in accordance with SFAS No. 5, "Accounting for Contingencies." For environmental matters, we record liabilities when environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Please see Note 1, "Summary of Significant Accounting Policies," beginning on page F-8 of the Form 10-K for further discussion. 

 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, is not reasonably estimable. Notwithstanding the foregoing, management has assessed these matters based on currently available information and made an informed judgment concerning the potential outcome of such matters, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s 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. 

Trans-Elect Litigation   As previously announced, in October 2002 we entered into an asset purchase and sale agreement to sell our 1,672 circuit mile electric transmission system to Trans-Elect, an independent transmission company, conditioned on several matters, including the receipt of the required approvals from the SEC under the PUHCA, the Federal Trade Commission, the ICC and the FERC. On February 20, 2003, the FERC voted to defer approval of the transaction and ordered a hearing to establish the allowable transmission rates for Trans-Elect. Under the agreement, if the transaction did not close on or before July 7, 2003, either party could
 terminate the agreement. As of July 7, 2003, the agreement had not been approved by, among other Entities, the FERC and, as a result, we terminated the agreement in accordance with its terms on July 8, 2003. 

 In October 2003, Trans-Elect, Inc. and Illinois Electric Transmission Company, LLC filed suit against us in the Northern District of Illinois requesting specific performance and estoppel, and claiming damages as a result of breach of contract and lost profits. These causes of action allegedly arise from our termination of the agreement described above. Trans-Elect claims that that we breached the agreement by not using our "best efforts" to obtain the required approvals and/or to negotiate an alternate agreement that could be approved.  We have until November 17, 2003 to respond to the 
plaintiffs' complaints.

We deny these claims, in that we believe we complied with the terms of the agreement, and intend to defend against them vigorously. It is not possible to predict with any certainty whether 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 believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition or results of operations. 

U.S. Environmental Protection Agency Complaint   IP and DMG, collectively referred to in this section as the Defendants, are currently the subject of a NOV from the EPA and a complaint filed by the EPA and the Department of Justice alleging violations of the Clean Air Act, the regulations promulgated thereunder and certain Illinois regulations adopted pursuant to the Clean Air Act. Eight 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 Defendan
ts’ three Baldwin Station generating units constituted "major 


	11

ILLINOIS POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the Interim Periods Ended September 30, 2003 and 2002

modifications" under the Prevention of Significant Deterioration ("PSD"), the New Source Performance Standard ("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 meet the definition of "major modifications" occur and are not otherwise exempt, the Clean Air Act and related regulations generally require that the generating facilities at which such activities occur meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment. 

DMG has undertaken activities to reduce significantly emissions at the Baldwin Station since the complaint was filed in 1999. In 2000, the Baldwin Station was converted from high to low sulfur coal, resulting in sulfur dioxide emission reductions of over 90% from 1999 levels. Furthermore, selective catalytic reduction equipment has been installed at two of the three units at Baldwin Station, resulting in significant emission reductions of nitrogen oxides. However, the EPA may seek to require the installation of the "best available control technology," or the equivalent, at the Baldwin Station. Current estimates indicate that capital expenditures of up to $410 million could be incurred if the installation of best available control technology were required. The EPA also has the authori
ty to seek penalties for the alleged violations at the rate of up to $27,500 per day for each violation. 

In February 2003, the Court granted our 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 and vigorously defended against them at trial. The trial to address these remaining issues began in June 2003 and closing arguments occurred in September 2003. The parties also participated in a mandatory settlement conference with the judge but did not reach a settlement. Shortly b
efore closing argument, motions to intervene were filed on behalf of the State of Illinois and on behalf of Bottom Conservancy, Health and Environmental Justice – St. Louis, Inc., Illinois Stewardship Alliance and Prairie Rivers Alliance. The motions were granted by order on October 23, 2003 as to all intervenors. The order specifically limits the participation of the intervenors to filing briefs in support of arguments they believe the United States has ceased to pursue. The judge has indicated he intends to enter judgment in this matter before the end of 2003. Dynegy has recorded a reserve for potential penalties that could be imposed if the EPA were to prosecute successfully these remaining claims for penalties. 

In August 2003 two significant decisions were handed down in other cases that are part of the Utility Enforcement Initiative. In one case, United States v. Ohio Edison, the Court found the defendant liable for violations of the Clean Air Act. In reaching this decision, the Court adopted the EPA’s interpretation of the "routine maintenance, repair and replacement" exclusion, applying it narrowly at each unit where the projects occurred. The Court held that the projects at issue were not routine and thus the exclusion did not apply. In the second case, United States v. Duke Energy Company, the Court rejected the EPA’s interpretation of the routine maintenance, repair and replacement exclusion holding that the exclusion should be defined relative to what is routine for the par
ticular industry, not what is routine for the particular unit at issue. The Duke case also held that the government bears the burden of proof on the issue of whether a project at issue is routine. 

Also in August 2003, the EPA issued a new rule, the "Equipment Replacement Provision of the Routine Maintenance, Repair and Replacement Exclusion," which became final in October. This rule specifies that the replacement of components of a process unit with identical components (or their functional equivalents) will fall within the scope of the routine maintenance, repair and replacement exclusion if (i) the replacement costs is less than 20% of the total cost of replacing the unit, (ii) the replacement does not alter the unit’s basic design and (iii) the unit will continue to comply within applicable emission and operational standards. 

None of the Defendants’ other facilities are covered in the complaint and NOV, but the EPA has officially requested information, which has been provided, concerning activities at the Defendants’ Vermilion, Wood River and Hennepin plants. The EPA could eventually commence enforcement actions based on activities at these plants. However, the likelihood of additional enforcement actions is uncertain in light of the August 2003 public statement by the Acting Administrator of the EPA indicating that additional enforcement actions under the Utility Enforcement Initiative are unlikely and the November 2003 public statement by lawyers for the EPA that investigations into several power plants for past Clean Air Act violations would likely be dropped and that future cases would be ju
dged under the new rule. 


	12

ILLINOIS POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the Interim Periods Ended September 30, 2003 and 2002

Manufactured-Gas Plants   In the early 1900’s, we operated two dozen sites at which 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 EPA has issued No Further Remediation Letters for two of our MGP sites. Although we estimate our liability for MGP site remediation to be approximately $48 million for our remaining 22 MGP sites, because of the unknown and unique characteristics at each site, we cannot b
e certain of our ultimate liability 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. 

Asbestos Litigation   We have lawsuits pending against us for illnesses based on alleged exposure to asbestos at generation facilities previously owned by us. As of September 30, 2003, thirty–five lawsuits were pending, thirteen of which were served during the third quarter of 2003. We intend to defend against the pending lawsuits vigorously. We have recorded a reserve for these matters and do not believe that any liability we might incur as a result of these matters would have a material adverse effect on our financial condition or result of operations. 

Regulatory Matters 

P.A. 90-561 – 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. 

 In January 1998, we, in conjunction with eight other transmission-owning entities, filed with the FERC for all approvals necessary to create and to implement the MISO. On May 8, 2001, the FERC issued an order approving a settlement that allowed Illinois Power to withdraw from the MISO. 

 On November 1, 2001, we and seven of the transmission owners proposing to form the Alliance RTO filed definitive agreements with the FERC for approval whereby National Grid would serve as the Alliance RTO’s managing member. In an order issued on December 20, 2001, the FERC stated that it could not approve the Alliance RTO, and the FERC directed the Alliance companies to file a statement of their plans to join an RTO, including the timeframe, within 60 days of December 20, 2001. 

On May 28, 2002, we submitted a letter to the FERC indicating that we would join PJM either as an individual transmission owner or as part of an independent transmission company. On July 31, 2002, the FERC issued an order approving our proposal to join PJM, subject to certain conditions. These conditions include requirements, among others, that (i) the parties negotiate and implement a rate design that will eliminate rate pancaking between PJM and the MISO, (ii) the North American Electric Reliability Council oversee the reliability plans for the MISO and PJM, and (iii) PJM and MISO develop a joint operation agreement to deal with seams issues. In addition, the FERC initiated an investigation under Federal Power Act section 206 of the MISO, PJM West and PJM’s transmission rates 
for through and out service and revenue distribution. Subsequent to the July 31 order, the parties were unable to negotiate a rate design that would eliminate rate pancaking between PJM and the MISO and the FERC ordered a hearing on this matter. The hearing has concluded and an order from the FERC is expected before the end of the year. Although we are not currently charging rates or collecting revenues through these entities, once we begin operating under PJM, our transmission rates and revenues could be impacted by the outcome of this proceeding. 

On July 23, 2003, the FERC initiated an investigation under Federal Power Act section 206 of the transmission rates for through and out service of several former Alliance RTO participants including us. On November 13, 2003, the FERC announced the issuance of an order relating to this investigation, although it has neither described nor disclosed the content of this order. Until the content of this order is made publicly available, we will be unable to determine its impact, if any, on the investigation. Further action in this proceeding is expected before the end of 2003.
 
We recently suspended our efforts to join an RTO in light of the potential sales transaction with Exelon. Our agreement with Exelon requires that we take certain steps designed to ensure our membership in PJM upon closing of the transaction, which we currently expect will occur, subject to the regulatory and other approvals described above, in the fourth quarter of 2004. 


	13

ILLINOIS POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the Interim Periods Ended September 30, 2003 and 2002

Please see Note 6, "Commitments and Contingencies," to the Form 10-K for a description of the other material regulatory matters affecting us. No additional material developments affecting us have occurred with respect to such matters since our filing of the Form 10-K. 

Note 5 – Debt 

On December 20, 2002, we closed a private offering of $550 million of our 11 1/2% Mortgage bonds due 2010. Of the $550 million in aggregate principal amount of our Mortgage bonds, we issued $400 million in December 2002, with $150 million issued on a delayed delivery basis subject to ICC approval, which we received in January 2003. The mortgage bonds were sold at a discounted price of $97.48 to yield an effective interest rate of 12%. We realized net cash proceeds from this offering of approximately $380 million in December 2002 and approximately $142 million in January 2003. We used a portion of the proceeds from the offering to replenish the liquidity used to repay our $96 million 6.25% Mortgage bonds, which matured on July 15, 2002. Also, we used $200 million in Dece
mber 2002 and $100 million on May 2, 2003 to pay off our one-year term loan due May 2003. We have used the remaining proceeds, together with the interest income described in Note 3 above and other available cash, to repay our $190 million in aggregate August and September 2003 mortgage bond maturities. 

Exchange Offer   On July 11, 2003, we commenced an exchange offer, pursuant to which we offered to exchange up to $550 million of our outstanding 11 1/2% Mortgage Bonds due 2010, or Outstanding Bonds, for a new series of our 11 1/2% Mortgage Bonds due 2010, or New Bonds, with substantially the same terms as the Outstanding Bonds, including the same principal amount, interest rate, redemption terms and payment and maturity dates, and which were registered under the Securities Act. The exchange offer, which was initially scheduled to expire on August 11, 2003, was extended until August 25, 2003 and was completed on August 28, 2003. For 
a complete discussion of the terms and conditions of our exchange offer, please read the prospectus relating to the exchange offer, which we filed with the SEC on July 11, 2003. 

Please see Note 9, "Long-Term Debt," to the Form 10-K for further discussion of our 11 1/2% Mortgage bonds due 2010. 

The following table provides a summary of our debt payments for the fourth quarter of 2003, the next four years and thereafter (millions of dollars). 


Payments Due by Period

Cash Obligations		Total		2003		2004		2005		2006		2007		Thereafter

Long-Term Debt ⁽¹⁾	$	1,445	$	---	$	---	$	70	$	---	$	---	$	1,375
Transitional Funding Trust Notes ⁽¹⁾		452		22		86		86		86		86		86
Tilton Capital Lease ⁽²⁾		81		---		81		---		---		---		---

Total Cash Obligations	$	1,978	$	22	$	167	$	156	$	86	$	86	$	1,461

(1)  Does not include the associated debt discount or fair market value adjustment. 

(2)  Please read the section "Tilton Capital Lease" below for additional information. 

Term Loan   In May 2003, we used a portion of the proceeds from our above described sale of $550 million in 11 1/2% Mortgage bonds due 2010 to pay down the $100 million then outstanding under our one-year term loan. 

Mortgage Bond Maturities   We used the remaining proceeds from our December 2002 Mortgage bond offering together with prepaid interest payments from Illinova on our Note Receivable from Affiliate to pay an aggregate of $190 million in mortgage bond maturities in August and September 2003. 

Tilton Capital Lease   In September 1999, we entered into an $81 million operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. These facilities consist of peaking units totaling 176 MW of capacity. We sublet the turbines to DMG in October 1999. In September 2003, we delivered notice of our intent to exercise 


	14

ILLINOIS POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the Interim Periods Ended September 30, 2003 and 2002

our option to purchase the turbines upon the expiration of the operating lease in September 2004. As a result of this action, the operating lease was reclassified as a capital lease and we are now the capital sublessor. Based upon an independent appraisal, we recorded a receivable from DMG at the fair market value of $66 million, which is offset by a corresponding liability to the original lessor. The receivable from DMG and payable to the original lessor will be accreted to the $81 million lease payment over the next 12 months using the straight line method. The accretion to be recorded for 2003 will be approximately $4 million and will be recorded as interest income offset by the same amount of interest expense. The accretion to be recorded in 2004 will be approximately $11 million.
 The net effect on our income statement will be zero. This lease obligation was previously disclosed as a lease obligation in the footnotes to our financial statements and the Commercial Financial Obligations and Contingent Financial Commitments tables in our Form 10-K. 

Note 6 – Liquidity 

We have a significant amount of leverage, including quarterly payments of approximately $22 million due on our transitional funding trust notes. We are required to make these same quarterly payments of approximately $22 million on our transitional funding trust notes through 2008. 

Due to our non-investment grade credit ratings and other factors, we do not have access to the commercial paper markets, and our access to the capital markets is limited. These factors, along with the level of our indebtedness and the fact that we do not currently have a revolving credit facility, will have several important effects on our future operations. First, a significant portion of our cash flows will be dedicated to the payment of principal and interest on our outstanding indebtedness, including the transitional funding trust notes, and will not be available for other purposes. Second, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes is limited. 

Because we have no revolving credit facility and no access to the commercial paper markets, we rely on cash on hand, cash flows from operations, including interest payments under our $2.3 billion Note Receivable from Affiliate, and liquidity support which has been committed by Dynegy, to satisfy our debt obligations and to otherwise operate our business. Please see Note 5, "Related Parties," to the Form 10-K and Note 3, "Related Parties," in this Form 10-Q for further discussion related to the potential impairment of our Note Receivable from Affiliate. 

For the near term, we will continue to rely on a support commitment by Dynegy in order to satisfy our obligations. As part of our long-term plan, we will consider one or more liquidity initiatives including, among other things, a revolving credit facility or additional debt issuances. We believe our liquidity and capital resources, including our support commitment from Dynegy, are sufficient to satisfy our obligations over the next twelve months. Please read Note 2, "Agreed Sale to Exelon," for additional information affecting our long-term plan. 

Our ability to execute one or more liquidity initiatives successfully is subject to a number of risks. These risks include, among others, the ability to obtain new bank or other borrowings and the financial effects of our relationship with Dynegy. We encourage you to read Dynegy’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003 for additional information regarding Dynegy and its current liquidity position. 

Note 7 – Regulatory Issues 

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. 


	15

ILLINOIS POWER COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) For the Interim Periods Ended September 30, 2003 and 2002

Note 8 – Pension Plan Assets 

As a result of general declines in interest rates, projected plan obligations at year-end are expected to be greater than the market value of pension plan assets. If IP’s pension plan, which is included in the Dynegy pension plans, is underfunded at year-end 2003 by a greater amount than at year-end 2002, we have two alternatives. The first alternative is to contribute cash to the plan in an amount equal to the underfunded amount. The second alternative is to establish a liability equal to the underfunded amount with the offset being an after-tax reduction in stockholder’s equity. Determination of any underfunded amount will be made at year-end 2003 and will be dependent on the actual return on pension assets for 2003, the discount rate assumptions, which depend on year-end 
interest rates, and actual participant numbers. 


	16

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

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

The following discussion should be read together with the unaudited condensed consolidated financial statements and the notes thereto included in this report and with our Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the SEC. 

General – Company Profile 

We are engaged in the transmission, distribution and sale of electric energy and the distribution, transportation and sale of natural gas in the State of Illinois. We provide electric and natural gas service to residential, commercial and industrial customers in substantial portions of 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. 

We are an indirect, wholly owned subsidiary of Dynegy Inc. Dynegy acquired our direct parent company, Illinova, and its subsidiaries, including us, in February 2000. Our operations comprise one of Dynegy’s three operating divisions. Our results of operations and financial condition are affected by the consolidated financial and liquidity position of Dynegy. 

We recently entered into an agreement to sell substantially all of our assets and liabilities, excluding, among other things, the Note Receivable from Affiliate and deferred taxes from the previous transfer of our fossil generating assets to DMG, to Exelon for $2.225 billion. Please read Note 2,"Agreed Sale to Exelon," for further discussion. 

Liquidity and Capital Resources 

Overview 

Our cash balance as of November 5, 2003 was approximately $49 million, including restricted cash of approximately $31million. Because of our significant debt obligations, including higher interest expense resulting from our December 2002 Mortgage bond offering, we remain reliant on cash on hand, cash flows from operations and liquidity support committed by Dynegy to satisfy our obligations. Please see "Conclusion" below for further discussion. 

Our Relationship with Dynegy 

We are an indirect, wholly owned subsidiary of Dynegy Inc. Due to our relationship with Dynegy, adverse developments or announcements concerning Dynegy have affected our ability to access the capital markets and to otherwise conduct our business. We are particularly susceptible to developments at Dynegy because we rely upon an unsecured Note Receivable from Affiliate for a substantial portion of our cash flows. Our Note Receivable from Affiliate relates to the transfer of our former fossil-fueled generating assets. The note matures on September 30, 2009 and bears interest at an annual rate of 7.5%, due semiannually in April and October. At September 30, 2003 and December 31, 2002, principal outstanding under the note approximated $2.3 billion. We had no accrued interest at Septem
ber 30, 2003 due to prepayments of approximately $100 million and $71 million on our Note Receivable from Affiliate in July 2003 and September 2003, respectively, as further discussed in Note 3, "Related Parties" above, while at December 31, 2002 accrued interest approximated $14 million. An additional interest prepayment of approximately $28 million was received in October 2003. As of October 31, 2003, seven months of interest on our Note Receivable from Affiliate had been prepaid. 

We have reviewed the collectibility of this note to assess whether it has become impaired under the criteria of SFAS No. 114, "Accounting by Creditors for Impairment of a Loan." Under this standard, a loan is impaired when, based on current information and events, it is "probable" that a creditor will be unable to collect all amounts due according to the contractual terms of the loan agreement. Please see "Critical Accounting Policies" in the Form 10-K for further discussion as to applicable GAAP requirements regarding impairment of the loan. While we believe that the note is not impaired, we continue to review the collectibility of the note on a quarterly basis. Principal payments on the note are not required until 2009 when it is due in full; as a result, future events may affect o
ur view as to the collectibility of the remaining principal owed to us under the note. On our fourth quarter review, we will consider the impact, if any, of the proposed transaction with Exelon on the collectibility of our Note Receivable from Affiliate.  It is possible that if negative events affect Dynegy or if we do not receive timely interest payments on our Note Receivable from Affiliate, such matters could cause us to believe it necessary to impair our Note Receivable from Affiliate on our condensed consolidated balance sheet and such action could have a material adverse effect on our liquidity, financial condition and results of operations. For example, a significant impairment could impact our ability to comply with the financial covenants contained in our Tilton lease agreement and to stay within the utility earnings cap contained in the Illinois Customer Choice Law. 


	17

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

On October 31, 2003, we entered into an agreement to sell substantially all of our assets and liabilities, excluding, among other things, the Note Receivable from Affiliate and deferred taxes from the previous transfer of our fossil generating assets to DMG, to Exelon.  The sale is conditioned on, among other things, the receipt of approvals from the ICC, the FERC, the SEC and other governmental and regulatory agencies.  In addition, the passage of legislation recently introduced in the Illinois General Assembly is critical to the consummation of the transaction.  Pending these approvals, the transaction is expected to close in the fourth quarter 2004.  Please read Note 2, “Agreed Sale to Exelon,” for further discussion.

Credit Capacity, Liquidity and Debt Maturities 

Sources of Liquidity   We are currently satisfying our capital requirements primarily with cash from operations, cash on hand, interest payments under our $2.3 billion Note Receivable from Affiliate and liquidity support which has been committed by Dynegy. 

Without the additional support from Dynegy through its prepayments of interest on the Note Receivable from Affiliate, our cash flows are insufficient to satisfy our debt service obligations and other capital resource requirements. We used the remaining proceeds from our December 2002 Mortgage bond offering, together with a portion of the prepaid interest payments received in July 2003 and September 2003, respectively, under our Note Receivable from Affiliate, to pay our August and September 2003 mortgage bond maturities of $190 million in aggregate. An additional interest prepayment of approximately $28 million was received in October 2003 and is being used for payment of general operating expenses. In the near term, we will continue to rely on a support commitment from Dynegy i
n order to satisfy our obligations. Although Dynegy’s restructured credit facility, which expires in February 2005, prohibits it from prepaying more than $200 million in principal under our Note Receivable from Affiliate during the term of the credit agreement, it does not limit Dynegy’s ability to prepay interest under our Note Receivable from Affiliate. In addition, the indenture governing Dynegy Holdings Inc.’s recently issued second priority senior secured notes permits payments of principal on the intercompany note receivable up to $450 million or to the extent that a fixed charge coverage ratio of 2:1 is satisfied. The indenture also permits the prepayment of interest on the intercompany note receivable up to twelve months at any one time. 

As part of our long-term plan, we will consider one or more liquidity initiatives including, among other things, a revolving credit facility or additional debt issuances. Please read Note 2, "Agreed Sale to Exelon," for further discussion. Please also read "Conclusion" below. 

Uses of Liquidity   On May 17, 2002, we exercised the "term-out" provision contained in our $300 million 364-day revolving credit facility, which was scheduled to mature on May 20, 2002. In connection with this conversion, we borrowed the remaining $60 million available under this facility. The exercise of the "term-out" provision converted the facility to a one-year term loan that matured in May 2003. In December 2002, we used a portion of the proceeds from our $550 million Mortgage bond offering to repay $200 million on this loan. On May 2, 2003 we made the final $100 million payment on this loan. 

Our $100 million and $90 million Mortgage bonds, which matured on August 1, 2003 and September 15, 2003, respectively, were redeemed using prepaid interest under our Note Receivable from Affiliate as further discussed above, and the remaining proceeds from our December 2002 Mortgage bond offering. Our December 2002 Mortgage bond offering has also resulted, and is expected to continue to result, in additional interest expense. Please read "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Three-Month Periods Ended September 30, 2003 and 2002" for a discussion of this additional interest expense. 

In addition, we have made quarterly payments of approximately $22 million on our transitional funding trust notes. These payments are made from our restricted cash, which is reserved for use in paying off the transitional funding trust notes issued under the provisions of the Electric Service Customer Choice and Rate Relief Law of 1997 ("P.A. 90-561"). We will continue to make these quarterly payments through 2008. 


	18

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

Collateral   As discussed in our Form 10-K, we have been requested to provide letters of credit to support certain business transactions, including our purchase of natural gas and natural gas transportation. As of September 30, 2003, Dynegy had posted approximately $20 million in collateral in support of these transactions, down from $28 million at December 31, 2002. 

Debt Payments   The following table provides a summary of our debt payments for the fourth quarter of 2003, the next four years and thereafter (millions of dollars). 

Payments Due by Period

Cash Obligations	Total		2003		2004		2005		2006		2007		Thereafter

Long-Term Debt ⁽¹⁾	$	1,445	$	---	$	---	$	70	$	---	$	---	$	1,375
Transitional Funding Trust Notes ⁽¹⁾		452		22		86		86		86		86		86
Tilton Capital Lease ⁽²⁾		81		---		81		---		---		---		---

Total Cash Obligations	$	1,978	$	22	$	167	$	156	$	86	$	86	$	1,461

(1) Does not include the associated debt discount or fair market value adjustment. 

(2) Please read the section "Tilton Capital Lease" below for additional information. 

Financial Obligations and Commercial Commitments   We have entered into various financial obligations and commitments in the course of our ongoing operations and financing strategies. Financial obligations are considered to represent known future cash payments that we are required to make under existing contractual arrangements, such as debt and lease agreements. These obligations may result from general financing activities, as well as from commercial arrangements that are directly supported by related revenue-producing activities. Financial commitments represent contingent obligations that become payable only if certain pre-defined events wer
e to occur, such as funding financial guarantees. Please see "Liquidity and Capital Resources—Financial Obligations and Commercial Commitments" in our Form 10-K for a complete listing of our obligations and commitments. We enter into obligations on an ongoing basis for the reservation of natural gas supply. These obligations generally range in duration from one to twelve months and require us to compensate the provider for capacity charges. The cost of the agreements through 2003 is $76 million compared to $28 million reported in the Form 10-Q for June 30, 2003. The increase is due to increased natural gas prices. 

Tilton Capital Lease   In September 1999, we entered into an $81 million operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. These facilities consist of peaking units totaling 176 MW of capacity.  We sublet the turbines to DMG in October 1999 pursuant to a sublease that requires DMG to pay all amounts owed by us under the operating lease.  In September 2003, we delivered notice of our intent to exercise our option to purchase the turbines upon the expiration of the operating lease in September 2004.  As a result of this action, the operating lease was reclassified as a capital lease and we are now the capital sublessor.  Based upon an independent appraisal, we recorded a receivable from DMG at the fair market value of $66 million, which is offset by a correspo
nding liability to the original lessor.  The receivable from DMG and payable to the original lessor will be accreted up to the $81 million lease payment over the next 12 months using the straight line method.  The accretion to be recorded for 2003 will be approximately $4 million and will be recorded as interest income offset by the same amount of interest expense.  The accretion to be recorded in 2004 will be approximately $11 million.  The net effect on our income statement will be zero.  This lease obligation was previously disclosed as a lease obligation in the footnotes to our financial statements and the Commercial Financial Obligations and Contingent Financial Commitments tables in our Form 10-K.

Dividends   There are restrictions on our ability to pay cash dividends, including any dividends that we might pay indirectly to Dynegy. Under our Restated Articles of Incorporation, we may pay dividends on our common stock, all of which is owned by Illinova, subject to the preferential rights of the holders of our preferred stock, of which Illinova owns approximately 73%. We also 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. Additionally, the ICC’s October 23, 2002 order relating to a netting agree
ment between us and Dynegy prohibits us from declaring and paying any dividends on our common stock until such time as our mortgage bonds are rated investment grade by both Moody’s and Standard & Poor’s, and further requires that we first obtain approval for any such payment from the ICC. 


	19

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

During the nine months ended September 30, 2003, we paid preferred stock dividends of approximately $2 million. During the nine months ended September 30, 2002, we paid common stock dividends of $0.5 million to Illinova and preferred stock dividends of approximately $2 million. 

Capital Expenditures   Capital expenditures for the nine months ended September 30, 2003 were approximately $100 million. We estimate that we will spend approximately $25 million on construction for the remainder of 2003. Capital expenditures for the nine months ended September 30, 2002 were approximately $102 million, and for the year ended December 31, 2002 were $144 million. Capital expenditures consist 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. 

Conclusion   We have a significant amount of leverage, including quarterly payments of approximately $22 million due on our transitional funding trust notes. We are required to make these same quarterly payments of approximately $22 million on our transitional funding trust notes through 2008. 

Due to our non-investment grade credit ratings and other factors, we do not have access to the commercial paper markets, and our access to the capital markets is limited. These factors, along with the level of our indebtedness and the fact that we do not currently have a revolving credit facility, will have several important effects on our future operations. First, a significant portion of our cash flows will be dedicated to the payment of principal and interest on our outstanding indebtedness, including the transitional funding trust notes, and will not be available for other purposes. Second, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes is limited. 

Because we have no revolving credit facility and no access to the commercial paper markets, we rely on cash on hand, cash flows from operations, including interest payments under our $2.3 billion Note Receivable from Affiliate, and liquidity support which has been committed by Dynegy, to satisfy our debt obligations and to otherwise operate our business. Please see Note 5, "Related Parties," to the Form 10-K and Note 3, "Related Parties," in this Form 10-Q for further discussion related to the potential impairment of our Note Receivable from Affiliate. 

For the near term, we will continue to rely on a support commitment by Dynegy in order to satisfy our obligations. As part of our long-term plan, we will consider one or more liquidity initiatives including, among other things, a revolving credit facility or additional debt issuances. We believe our liquidity and capital resources, including our support commitment from Dynegy, are sufficient to satisfy our obligations over the next twelve months. Please read Note 2, "Agreed Sale to Exelon," for additional information affecting our long-term plan. 

Our ability to execute one or more liquidity initiatives successfully is subject to a number of risks. These risks include, among others, our ability to obtain new bank or other borrowings and the financial effects of our relationship with Dynegy. We encourage you to read Dynegy’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003 for additional information regarding Dynegy and its current liquidity position. 

Factors Affecting Future Operating Results 

Our financial condition and results of operations in the fourth quarter of 2003 and beyond may be affected significantly by a number of factors, including: 

Ø	the effects of the agreed sale of substantially all of our assets and liabilities, excluding, among other things, the Note Receivable from Affiliate and deferred taxes from the previous transfer of our fossil generating assests to DMG, to Exelon;

Ø	our ability to address our significant leverage and increased interest expense in light of, among other things, our non-investment grade status and lack of borrowing capacity;

Ø	our ability to receive proceeds from one or more potential liquidity initiatives, including new bank borrowings or additional debt issuances;

Ø	our ability to execute our business strategy of delivering reliable transmission and distribution services in a cost-effective manner;


	20

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

Ø	our ability to receive interest payments under our Note Receivable from Affiliate and to otherwise receive liquidity support from, and continued performance under our arrangements with, Dynegy;

Ø	the effects of past or future regulatory actions, including Illinois power market deregulation and, specifically, "direct access," on our electric business;

Ø	our ability to maintain or improve our credit ratings;

Ø	the effects of weather on our electric and gas business;

Ø	our ability to secure power and natural gas for our electric and gas customers;

Ø	the effects of general economic conditions; and

Ø	the effects of customer choice in Illinois.

Additionally, as further discussed in Note 1 to the unaudited condensed consolidated financial statements, new accounting pronouncements have impacted our results of operations and will continue to do so in the future. Please read the section "Uncertainty of Forward-Looking Statements and Information" below for additional factors that could impact our future operating results. 

Critical Accounting Policies 

Please see our Form 10-K for a complete explanation of our critical accounting policies, with respect to which there have been no material changes since the filing of the Form 10-K. 


	21

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

Results of Operations 

Provided below is an unaudited tabular presentation of certain operating and financial statistics for the three-month periods ended September 30, 2003 and 2002, respectively. 

	Three Months Ended September 30,

	2003		2002

	($ in millions)
Electric Sales Revenues -
Residential	$	149	$	154
Commercial		103		105
Commercial-distribution ⁽¹⁾		---		---
Industrial		77		83
Industrial-distribution ⁽¹⁾		1		1
Other		12		11

Revenues from ultimate consumers		342		354
Interchange		---		---
Transmission/Wheeling		10		11

Total Electric Revenues	$	352	$	365


Electric Sales in kWh (Millions) -
Residential		1,766		1,832
Commercial		1,208		1,231
Commercial-distribution ⁽¹⁾		1		1
Industrial		1,561		1,667
Industrial-distribution ⁽¹⁾		641		621
Other		99		98

Sales to ultimate consumers		5,276		5,450
Interchange		6		---

Total Electric Sales		5,282		5,450


Cooling Degree Days ⁽²⁾ – Actual		773		1,006
Cooling Degree Days ⁽²⁾ – 10 Year Rolling Average		850		860

⁽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.


	22

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

	Three Months Ended September 30,

	2003		2002

	($ in millions)
Gas Sales Revenues -
Residential	$	26	$	22
Commercial		11		9
Industrial		8		5
Other		1		---

Revenues from ultimate consumers		46		36
Transportation of customer-owned gas		---		---
Sales to affiliates		3		5

Total Gas Revenues	$	49	$	41


Gas Sales in Therms (Millions) -
Residential		18		18
Commercial		10		11
Industrial		11		11

Sales to ultimate consumers		39		40
Transportation of customer-owned gas		48		47

Total gas sold and transported		87		87
Sales to affiliates		5		13

Total Gas Delivered		92		100


Heating Degree Days ⁽¹⁾ – Actual		88		29
Heating Degree Days ⁽¹⁾ – 10 Year Rolling Average		---		---

(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. 


	23

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

Three-Month Periods Ended September 30, 2003 and 2002 

For the quarter ended September 30, 2003, we reported net income of $40 million, compared with third quarter 2002 net income of $57 million. 

Operating revenues in 2003 decreased $5 million period over period primarily due to unfavorable weather impacting residential and commercial electric usage partially offset by increased gas prices. Residential and commercial electric sales revenues decreased because of lower usage due to cooler than normal summer weather. Industrial electric sales revenues decreased due to customers choosing alternative electric suppliers coupled with a downturn in general economic conditions. Gas revenues increased in 2003 due to slightly higher gas prices. 

Operating expenses, exclusive of income taxes discussed below, increased $20 million in 2003 compared to 2002 due primarily to higher market prices for natural gas purchases coupled with an increase in general and administrative expenses due to higher insurance related claims expense and an increase in legal reserves as a result of additional activity during the quarter partially offset by operating efficiency gains. Lower regulatory asset amortization in 2003 resulted from the additional regulatory asset amortization that was recorded late in 2002. 

Other income in 2003 and 2002 includes interest income associated with our Note Receivable from Affiliate of $43 million. 

Interest expense period-to-period increased $11 million reflecting higher outstanding debt balances and higher interest rates. Interest expense for the remainder of 2003 will continue to reflect higher costs from our December 2002 and January 2003 issuances of mortgage bonds totaling $550 million, which were issued at a 12% effective interest rate compared to our average 2002 mortgage bond interest rate of 5.81%. 

We reported total income tax provision, included in income taxes and miscellaneous - net, of $22 million and $41 million for the three-month periods ended September 30, 2003 and 2002, respectively. The effective tax rates approximated 36% and 42% in 2003 and 2002, respectively. The 2003 effective tax rate was positively affected by the reversal of a contingent liability previously recorded in relation to the open audit periods of 1998 and 1999.


	24

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

Provided below is an unaudited tabular presentation of certain operating and financial statistics for the nine-month periods ended September 30, 2003 and 2002, respectively. 

	Nine Months Ended September 30,

	2003		2002

	($ in millions)
Electric Sales Revenues -
Residential	$	328	$	348
Commercial		259		261
Commercial-distribution ⁽¹⁾		---		---
Industrial		211		217
Industrial-distribution ⁽¹⁾		4		4
Other		29		29

Revenues from ultimate consumers		831		859
Interchange		---		7
Transmission/Wheeling		29		30

Total Electric Revenues	$	860	$	896


Electric Sales in kWh (Millions) -
Residential		4,197		4,342
Commercial		3,318		3,334
Commercial-distribution ⁽¹⁾		3		2
Industrial		4,614		4,719
Industrial-distribution ⁽¹⁾		1,789		1,921
Other		285		282

Sales to ultimate consumers		14,206		14,600
Interchange		7		1

Total Electric Sales		14,213		14,601



Cooling Degree Days ⁽²⁾ – Actual		971		1,432
Cooling Degree Days ⁽²⁾ – 10 Year Rolling Average		1,214		1,246

(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. 


	25

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

	Nine Months Ended September 30,

		2003			2002

	($ in millions)
Gas Sales Revenues -
Residential	$	212		$	161
Commercial		78			58
Industrial		31			18
Other		3			2

Revenues from ultimate consumers		324			239
Transportation of customer-owned gas		(2	)		---
Sales to affiliates		8			8

Total Gas Revenues	$	330		$	247


Gas Sales in Therms (Millions) -
Residential		238			214
Commercial		98			90
Industrial		46			41

Sales to ultimate consumers		382			345
Transportation of customer-owned gas		170			180

Total gas sold and transported		552			525
Sales to affiliates		11			20

Total Gas Delivered		563			545


Heating Degree Days ⁽¹⁾ – Actual		3,492			3,024
Heating Degree Days ⁽¹⁾ – 10 Year Rolling Average		3,018			3,054

⁽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.


	26

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

Nine-Month Periods Ended September 30, 2003 and 2002 

For the nine months ended September 30, 2003, we reported net income of $90 million, compared with net income of $138 million for the same period in 2002. 

Operating revenues in 2003 increased $47 million primarily due to higher gas prices coupled with colder than normal winter weather which caused increased residential and commercial demand for gas, partially offset by cooler than normal spring and summer weather which decreased residential and commercial electric demand. In addition, 2003 revenues attributable to the sale of electricity to residential customers were negatively impacted by a five percent rate reduction effective May 1, 2002. In 2002, revenues from the sale of electricity were positively affected by the reversal of a contingent liability related to the resolution of a billing dispute with a large wholesale electric customer. 

Operating expenses, excluding income taxes, increased $85 million in 2003 compared to 2002 primarily due to higher market prices for natural gas purchases, an increase in the average price of power purchased, higher insurance related claims expense and an increase in legal reserves as a result of additional activity. These are partially offset by lower regulatory asset amortization resulting from the additional regulatory asset amortization recorded in December 2002 and operating efficiency gains. 

Other income in 2003 and 2002 included interest income associated with our Note Receivable from Affiliate of $128 million. 

Interest expense period-to-period increased $39 million reflecting higher outstanding debt balances and higher interest rates. Interest expense for the remainder of 2003 will continue to reflect higher costs from our December 2002 and January 2003 issuances of mortgage bonds totaling $550 million, which were issued at a 12% effective interest rate compared to our average 2002 mortgage bond interest rate of 5.81%. 

In the first quarter 2003, we adopted SFAS No. 143, resulting in a charge of approximately $2 million, net of tax. 

We reported an income tax provision, included in income taxes and miscellaneous – net, of $58 million, which includes the tax benefits from the adoption of SFAS No. 143, and $97 million for the nine-month periods ended September 30, 2003 and 2002, respectively. The effective tax rates approximated 39% and 41% in 2003 and 2002, respectively. 

Operating Cash Flow 

Cash flow from operating activities totaled $140 million for the nine-month period ended September 30, 2003, compared to $219 million reported in the 2002 period. Changes in operating cash flow reflect the operating results previously discussed herein. Additional factors decreasing cash flow were higher priced gas inventories and higher prepayments due to increased collateral requirements on natural gas purchases. Accounts payable negatively impacted cash flow due to the decrease in natural gas payables caused by increased prepayments of natural gas purchases. For the nine-month period ended September 2003, we have classified $85 million, or six months, of prepaid interest under our Note Receivable from Affiliate as cash flows from financing activities on our condensed consolidated statement of cash flows due to our lack of access to the capital markets. As the interest is earned, it will be reclassified as cash flows from operating activities in th e condensed consolidated cash flow statement. For additional discussion on this prepaid interest, please read Note 3, “Related Parties” beginning on page 10 and “Managements Discussion and Analysis of Financial Condition and Results of Operations–Credit Capacity, Liquidity and Debt Maturities– Sources of Liquidity,” beginning on page 18.

Outlook

Our future results of operations may be affected, either positively or negatively, by regulatory actions (with respect to rates or otherwise), general economic conditions, weather, overall economic growth, the demand for power and natural gas in our service area, utilization of competitive alternate service providers by our customers and financing costs. Our results of operations will also be impacted by the agreed sale of substantially all of our assets and liabilities, excluding, among other things, the Note Receivable from Affiliate and deferred taxes from the previous transfer of our fossil generating assets to DMG, to Exelon, with respect to which we entered into an agreement on October 31, 2003. Please read Note 2, "Agreed Sale to Exelon" above for additional information.


	27

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

Uncertainty of Forward-Looking Statements and Information   This quarterly report includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events. These statements are intended as "forward-looking statements" under the Private Securities Litigation Reform Act of 1995. All statements included or incorporated by reference in this quarterly report, other than statements of historical fact, that address activities, events or developments that we or our management expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment on t
he future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. Important factors that could cause a material difference in the actual results from the forward-looking statements are set forth elsewhere in this quarterly report. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as "anticipate," "estimate," "project," "forecast," "may," "should," "expect," "will" and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following: 

Ø	projected operating or financial results;

Ø	our ability to consummate the agreed sale transaction with Exelon;

Ø	expectations regarding capital expenditures, preferred dividends and other matters;

Ø	beliefs about the financial impact of deregulation;

Ø	assumptions regarding the outcomes of legal and administrative proceedings;

Ø	projections as to the carrying value of our Note Receivable from Affiliate;

Ø	estimations relating to the potential impact of new accounting standards;

Ø	intentions with respect to future energy supplies;

Ø	our ability to obtain required funding from Dynegy in the short-term and to consummate one or more liquidity initiatives in the long-term; and

Ø	anticipated costs associated with legal and regulatory compliance.

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties, including the following: 

Ø	the effects of the agreed sale transaction with Exelon;

Ø	our substantial indebtedness and our ability to generate sufficient cash flows either from our operations or other liquidity initiatives, or to obtain required funding from Dynegy, to service principal and interest on such indebtedness;

Ø	the timing and extent of changes in commodity prices for natural gas and electricity;

Ø	the effects of deregulation in Illinois and nationally and the rules and regulations adopted in connection therewith;

Ø	competition from alternate retail electric providers;

Ø	general economic and capital market conditions, including overall economic growth, demand for power and natural gas, and interest rates;

Ø	our ability to execute one or more long-term liquidity initiatives, including a new revolving credit facility or additional debt issuances;

Ø	the effects of our relationship with Dynegy Inc., our indirect parent company, including the ultimate impact of the legal and administrative proceedings to which it is currently subject;

Ø	Dynegy’s financial condition, including its ability to continue to support payment to us of principal and interest on our $2.3 billion intercompany note receivable from Illinova;

Ø	the cost of borrowing, access to capital and other factors affecting our financing activities;

Ø	operational factors affecting the ongoing commercial operations of our transmission, transportation and distribution facilities, including catastrophic weather-related damage, unscheduled repairs or workforce issues;

Ø	the cost and other effects of legal and administrative proceedings, settlements, investigations, or claims, including environmental liabilities that may not be covered by indemnity or insurance; and

Ø	other regulatory or legislative developments that affect the energy industry in general and our operations in particular.


	28

ILLINOIS POWER COMPANY MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For the Interim Periods Ended September 30, 2003 and 2002

In addition, there may be other factors that could cause our actual results to be materially different from the results referenced in the forward-looking statements. Many of these factors will be important in determining our actual future results. Consequently, no forward-looking statement can be guaranteed. Our actual future results may vary materially from those expressed or implied in any forward-looking statements. 

All of the forward-looking statements contained in this quarterly report are qualified in their entirety by this cautionary statement. Forward-looking statements speak only as of the date they are made, and we disclaim any obligation to update any forward-looking statement to reflect events or circumstances after the date of this quarterly report except as otherwise required by applicable law. 


	29

ILLINOIS POWER COMPANY

Item 3. Quantitative and Qualitative Disclosures About Market Risk 

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 the Clinton Power Station. 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 purchase s would expose us to commodity price risk. As discussed in “Regulation” included in the Form 10-K, P.A. 90-561 was amended to extend the retail electric rate freeze for two additional years, through 2006. We are attempting to establish PPAs to cover this period, including discussions to modify or extend our existing PPAs, which modifications or extensions would likely require regulatory approval. Under an agreement conditioned upon the closing of the proposed transaction with Exelon, DMG has contracted to sell 3,100 MW of generating capacity and 2,900 MW of generating capacity and energy to an Exelon subsidiary, which in turn would contract to sell power to New IP Company, for six years beginning in January 2005. It is anticipated that this agreement will be in place concurrently with the termination of our power purchase agreement with DMG, which expires in December 2004, and the closing of the sale to Exelon. Our failure to consummate the sale to Exelon and satisfy t he condition to the effectiveness of this agreement or to otherwise extend or renegotiate our current PPAs with DMG and AmerGen could negatively impact our results of operations. We cannot make any assurances that we will be able to successfully consummate our proposed sale to Exelon or to extend or renegotiate our PPAs with DMG and AmerGen on substantially similar terms or at all.

Please read Note 2, “Agreed Sale to Exelon” for a discussion of our recent agreement to sell substantially all of our assets and liabilities, excluding, among other things, the Note Receivable from Affiliate and deferred taxes from the previous transfer of our fossil generating assets to DMG, to Exelon for $2.225 billion and DMG’s agreement to sell 3,100 MW of generating capacity and 2,900 MW of generating capacity and energy to an Exelon subsidiary.

The ICC determines our delivery rates for gas service. These rates have been designed to recover the cost of service and allow shareholders the opportunity to earn a reasonable rate of return. The gas commodity is a pass through cost to the end-use customer and is subject to an annual ICC prudence review. Future natural gas sales will continue to be affected by an increasingly competitive marketplace, changes in the 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. Such risk-man
agement practices may not fully mitigate these exposures. 

Our market risk is considered as a component of the entity-wide risk-management policies of our parent company, Dynegy. Dynegy measures entity-wide market risk in its risk-management portfolios using Value at Risk. Additional measures are used to determine the treatment of risks outside the Value at Risk methodologies, such as market volatility, liquidity, event and correlation risk. 

Item 4. Controls and Procedures 

Effective as of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective. No significant changes were made to our internal controls or in other factors that could significantly affect these controls subsequent to the date of this evaluation. 


	30

ILLINOIS POWER COMPANY PART II. OTHER INFORMATION

Item 1 - Legal Proceedings 

Please read Note 4, "Commitments and Contingencies – Legal and Environmental Matters," for a description of our material legal proceedings. 

Item 6 - Exhibits and Reports on Form 8-K 

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

10.1        Purchase Agreement dated October 31, 2003 among Exelon Energy Delivery Company, LLC, New IP Company, Illinois Power Company, IP Gas Supply Company and Dynegy Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2003, File No. 1-15659). 

31.1        Certification Pursuant to 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 

31.2        Certification Pursuant to 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 

*32.1      Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 

*32.2      Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 

*Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as "accompanying" this report and not "filed" as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act. 

(b)     Reports on Form 8-K filed during the third quarter of 2003:

Current report on Form 8-K dated July 9, 2003. Item 5 was reported and no financial statements were filed.

Current report on Form 8-K dated August 12, 2003. Items 5 and 7 were reported and no financial statements were filed.

Current report on Form 8-K dated August 29, 2003. Item 5 was reported and no financial statements were filed. 


	31

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 14, 2003
By:  
/s/ Peggy E. Carter

Peggy E. Carter, Managing Director, Controller

(Duly Authorized Officer and Principal Accounting Officer)


	32

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the quarterly period ended September 30, 2003

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from __________ to __________

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


	Illinois Power Company

Date: November 14, 2003	By:	/s/ Peggy E. Carter

		Peggy E. Carter, Managing Director, Controller
		(Duly Authorized Officer and Principal Accounting Officer)