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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 June 30, 2004
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

Commission file number: 1-3004

Illinois Power Company
(Exact name of registrant as specified in its charter)

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

500 S. 27th Street
Decatur, Illinois 62521-2200
(Address of principal executive offices)
(Zip Code)

(217) 424-6600
(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
YES ___  NO ü 

Illinova Corporation is the sole holder of all 62,892,213 outstanding shares of the common stock of Illinois Power Company. There is no voting or non-voting common equity held by non-affiliates of Illinois Power Company. Illinova also owns 662,924 shares, or approximately 73%, of IP’s preferred stock. Illinois Power Company is an indirect wholly-owned subsidiary of Dynegy Inc.

 
1
 

ILLINOIS POWER COMPANY
TABLE OF CONTENTS


 
 
Page
   
PART I. FINANCIAL INFORMATION
  
   
3
   
Item 1.   CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED):
  
   
June 30, 2004 and December 31, 2003
4
For the three and six months ended June 30, 2004 and 2003
5
For the six months ended June 30, 2004 and 2003
6
7
   
Item 2.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
19
 
  
Item 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
29
   
Item 4.       CONTROLS AND PROCEDURES
29
   
PART II.   OTHER INFORMATION
  
   
Item 1.   LEGAL PROCEEDINGS
31
   
Item 6.   EXHIBITS AND REPORTS ON FORM 8-K
31

 
2
Table of Contents

PART I

Definitions

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

AmerGen
AmerGen Energy Company
Ameren
Ameren Corporation
ARB
Accounting Research Board
ARO
Asset Retirement Obligation
Bcf
Billion cubic feet
Clinton
Clinton Power Station
CWIP
Construction work in progress
DHI
Dynegy Holdings Inc.
DMG
Dynegy Midwest Generation, Inc.
DPM
Dynegy Power Marketing Inc.
Dynegy
Dynegy Inc.
EPA
Environmental Protection Agency
Exchange Act
Securities Exchange Act of 1934, as amended
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Form 10-K
Our Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 12, 2004
FIN
FASB Interpretation
GAAP
Accounting principles generally accepted in the United States of America
ICC
Illinois Commerce Commission
Illinova
Illinova Corporation, our direct parent company and a wholly-owned subsidiary of Dynegy
IP
Illinois Power Company
IPSPT
Illinois Power Special Purpose Trust
ISO
Independent System Operator
kWh
Kilowatt-hour
LLC
Illinois Power Securitization Limited Liability Company
MGP
Manufactured-Gas Plant
MISO
Midwest Independent Transmission System Operator, Inc.
MW
Megawatts
MWh
Megawatt-hour
NOV
Notice of Violation
NSPS
New Source Performance Standard
P.A. 90-561
Electric Service Customer Choice and Rate Relief Law of 1997
PGA
Purchase Gas Adjustment
PPA
Power Purchase Agreement
PSD
Prevention of Significant Deterioration
RTO
Regional Transmission Organization
SEC
U.S. Securities and Exchange Commission
SFAS
Statement of Financial Accounting Standards
SPE
Special Purpose Entity
Trans-Elect
Trans-Elect, Inc.
VIE
Variable Interest Entity

 
3
Table of Contents

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

   
June 30,
2004
  
December 31,
2003
  
ASSETS
Utility Plant:
              
Electric (includes CWIP of $70 million and $86 million, respectively)
  
$
    2,515
  
$
    2,499
  
Gas (includes CWIP of $6 million and $14 million, respectively)
    
    795
    
783
  
     
3,310
    
3,282
  
Less -- accumulated depreciation
    
1,203
    
1,199
  
     
2,107
    
2,083
  
               
Investments and Other Assets
    
5
    
7
  
               
Current Assets:
              
Cash and cash equivalents
    
42
    
17
  
Accounts receivable, net
    
114
    
116
  
Accounts receivable, affiliates
    
84
    
75
  
Accrued unbilled revenue
    
59
    
82
  
Inventories, at average cost
    
37
    
66
  
Prepayments and other
    
38
    
50
  
     
374
    
406
  
               
Note Receivable from Affiliate
    
2,271
    
2,271
  
               
Deferred Debits:
              
Transition period cost recovery
   
97
    
116
  
Investment in IPSPT
    
4
    
4
  
Receivable from IPSPT
    
2
    
2
  
Other
    
160
    
170
  
 
    
263
    
292
  
   
$
    5,020
  
$
    5,059
  
               
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
    
565
    
505
  
Accumulated other comprehensive income (loss), net of tax
    
(9
)
  
(10
)
Less -- Capital stock expense
   
7
    
7
  
Less -- 12,751,724 shares of common stock in treasury, at cost
   
287
    
287
  
     
1,545
    
1,484
  
Preferred stock
    
46
    
46
  
Long-term debt
    
1,366
    
1,435
  
Long-term debt, IPSPT
    
302
    
345
  
     
3,259
    
3,310
  
               
Current Liabilities:
              
Accounts payable
    
47
    
38
  
Accounts payable, affiliates
    
6
    
14
  
Notes payable and long-term debt maturing within one year
    
148
    
71
  
Long-term debt maturing within one year to IPSPT
    
72
    
74
  
Accrued liabilities
   
126
    
155
  
     
399
    
352
  
               
Deferred Credits:
              
Accumulated deferred income taxes
    
1,003
    
1,011
  
Accumulated deferred investment tax credits
    
19
    
20
  
Other
    
340
    
366
  
     
1,362
    
1,397
  
   
$
    5,020
  
$
    5,059
  

See notes to condensed consolidated financial statements.

 
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Table of Contents
 
ILLINOIS POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (in millions) (unaudited)
 
   
Three Months Ended
June 30,
  
Six Months Ended
June 30,
  
   
2004
  
2003
  
2004
  
2003
  
                           
Operating Revenues:
                          
Electric
  
$
258
  
$
257
  
$
505
  
$
508
  
Gas
    
66
    
71
    
276
    
281
  
Total
    
324
    
328
    
781
    
789
  
                           
Operating Expenses and Taxes:
                          
Power purchased
    
154
    
160
    
305
    
318
  
Gas purchased for resale
    
39
    
41
    
193
    
193
  
Other operating expenses
    
36
    
33
    
72
    
63
  
Maintenance
    
16
    
16
    
27
    
28
  
Depreciation and amortization
    
20
    
20
    
40
    
40
  
Amortization of regulatory assets
    
10
    
10
    
21
    
21
  
General taxes
    
16
    
17
    
37
    
38
  
Income taxes
    
---
   
(2
)
  
8
    
5
  
Total
    
291
    
295
    
703
    
706
  
Operating income
   
33
    
33
    
78
    
83
  
                           
Other Income and Deductions:
                          
Interest income from affiliates
   
42
    
42
    
85
    
85
  
Other income taxes
    
(17
)
  
(16
)
  
(34
)
  
(33
)
Other income
    
7
    
2
    
12
    
3
  
Other expense
    
(1
)
  
(2
)
  
(1
)
  
(2
)
Total
    
31
    
26
    
62
    
53
  
                           
Interest Charges:
                          
Interest expense
    
35
    
41
    
68
    
84
  
Interest expense - IPSPT
    
6
    
---
    
12
    
---
  
Allowance for borrowed funds used during construction
    
(1
)
  
---
    
(1
)
  
---
  
Total
    
40
    
41
    
79
    
84
  
                           
Earnings before cumulative effect of change in accounting principle
    
24
    
18
    
61
    
52
  
Cumulative effect of change in accounting principle, net of tax
   
---
    
---
    
---
    
(2
)
                           
Net income
   
24
    
18
    
61
    
50
  
Less - Preferred dividend requirements
   
---
    
---
    
1
    
1
  
Net income applicable to common shareholder
  
$
24
  
$
18
  
$
60
  
$
49
  
                           
                           
Net income
  
$
24
  
$
18
  
$
61
  
$
50
  
Other comprehensive income, net of tax
    
---
   
---
    
1
   
---
  
Comprehensive income
  
$
24
  
$
18
  
$
62
  
$
50
  


See notes to condensed consolidated financial statements.

 
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Table of Contents

ILLINOIS POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) (unaudited)

   

Six Months Ended

 

 

 

June 30,

 

June 30,

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

2004

 

2003

  
               
Net income
  
$
61
  
$
50
  
Items not affecting cash flows from operating activities:
              
Depreciation and amortization
    
65
    
65
  
Deferred income taxes
    
(10
)
  
(9
)
Cumulative effect of change in accounting principle (Note 1)
    
---
    
2
  
Changes in assets and liabilities resulting from operating activities:
              
Accounts receivable
    
11
    
(33
)
Unbilled revenue
    
23
    
19
  
Inventories
    
19
    
7
  
Other assets
    
7
    
8
  
Prepayments
    
17
    
(4
)
Accounts payable
    
1
    
(20
)
Other deferred credits
    
1
    
(17
)
Other liabilities
    
(18
)
  
6
  
               
Net cash provided by operating activities
    
177
    
74
  
               
CASH FLOWS FROM INVESTING ACTIVITIES:
              
               
Capital expenditures
    
(63
)
  
(67
)
Other investing activities
    
1
    
(1
)
               
Net cash used in investing activities
    
(62
)
  
(68
)
               
CASH FLOWS FROM FINANCING ACTIVITIES:
              
               
Dividends on common and preferred stock
    
(1
)
  
(1
)
Prepaid interest on affiliate note receivable
    
(43
)
  
---
  
Redemptions:
              
Short-term debt
    
---
    
(100
)
Long-term debt
    
(43
)
  
(43
)
Issuances:
             
Long-term debt
    
---
    
150
  
Increase in restricted cash
    
---
    
(1
)
Transitional funding trust notes overfunding
    
(3
)
  
---
  
Other financing activities
    
---
    
(8
)
               
Net cash used in financing activities
    
(90
)
  
(3
)
               
Net change in cash and cash equivalents
    
25
    
3
  
Cash and cash equivalents at beginning of period
    
17
    
117
  
               
Cash and cash equivalents at end of period
  
$
42
  
$
120
  

See notes to condensed consolidated financial statements.

 
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Table of Contents
ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003
 
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. The year end condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our Form 10-K.

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

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

All significant intercompany balances and transactions have been eliminated from the unaudited condensed consolidated financial statements included in this report. All nonutility operating transactions are included in the section titled "Other Income and Deductions" in our condensed consolidated statements of income and comprehensive income.

Utility Plant   The following tables present the details, by functional classification, of the items that comprise the balances related to Utility Plant on our condensed consolidated balance sheets:

Electric Utility Plant
  

June 30, 2004

 

December 31, 2003
Avg. Useful Life
  
   

(in millions)

  
(in years)
  
Transmission
  
$
282
  
$
279
    
49.0
  
Distribution
    
1,656
    
1,625
    
36.0
  
General (1)
    
254
    
249
    
31.3
  
Other (1)
    
253
    
260
    
5.0 - 50.0
  
Construction Work-In-Progress
    
70
    
86
        
Total Electric Utility Plant
    
2,515
    
2,499
        
Less: Accumulated Depreciation-Electric
    
865
    
870
        
   
$
1,650
  
$
1,629
        
 
(1)   Joint function assets used in both electric and gas operations are included in the captions General and Other Electric Utility Plant.

 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003
 
Gas Utility Plant
  
June 30, 2004
  
December 31, 2003
  
Avg. Useful Life
  
   
(in millions)
  
(in years)
  
Transmission
  
$
123
  
$
121
    
48.2
  
Distribution
    
538
    
530
    
36.3
  
General
    
23
    
21
    
20.7
  
Other
   
105
    
97
    
5.0 - 42.0
  
Construction Work-In-Progress
    
6
    
14
        
Total Gas Utility Plant
    
795
    
783
        
Less: Accumulated Depreciation-Gas
    
338
    
329
        
   
$
457
  
$
454
        

Other Income and Other Expense   The following table presents the details of the items that comprise the balances related to Other income and Other expense on our condensed consolidated statements of income and comprehensive income:
 

   
Three Months Ended
Six Months Ended
   
June 30,
June 30,
   
2004
2003
2004
2003
   
(in millions)
Other income:
                          
Other interest income
  
$
5
  
$
1
  
$
9
  
$
2
  
Gain on disposition of property
    
1
    
---
    
1
    
---
  
Other non-operating income
    
1
    
1
    
2
    
1
  
Total other income
  
$
7
  
$
2
  
$
12
  
$
3
  
                           
Other expense:
                          
Other non-operating expense
 
$
(1
)
$
(2
)
$
(1
)
$
(2
)
Total other expense
  
$
(1
)
$
(2
)
$
(1
)
$
(2
)
 
Accounting Principles Adopted

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

At January 1, 2004, our ARO liability related to the Tilton site was approximately $1 million. This ARO related to the dismantling of the generation plant and remediation of the site. For the three- and six-month periods ended June 30, 2004, accretion expense was negligible as compared to accretion expense of approximately $0.2 million and $0.4 million, respectively, for the three- and six-month periods ended June 30, 2003. For additional information related to our Tilton ARO liability and remeasurement, please read Note 1 - Summary of Significant Accounting Policies - SFAS No. 143 beginning on page F-14 of our Form 10-K. There were no additional AROs recorded or settled, nor were there any revisions to estimated cash flows associated with this ARO during the three- and six - -month periods ended June 30, 2004. Please read Note 9 - Subsequent Event for additional information regarding the Tilton facility.

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

 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003

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

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

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

     
Three Months Ended
June 30, 
    
Six Months Ended
June 30, 
  
     
2004 
    
2003 
    
2004 
    
2003 
  
   

 (in millions) 

  
Net income as reported
  
$
24
  
$
18
  
$
61
  
$
50
  
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects (1)
    
---
    
---
    
---
    
---
  
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects
    
1
    
1
    
2
    
2
  
Pro forma net income
  
$
23
  
$
17
  
$
59
  
$
48
  
 
(1)   Compensation expense recorded for stock options granted after January 1, 2003 was negligible for the three- and six-month periods ended June 30, 2004 and 2003.

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

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

 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003
 
FSP No. 106-2   FSP No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, supersedes FSP 106-1 and became effective for interim periods beginning after June 15, 2004. FSP No. 106-2 requires additional disclosures relating to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which was signed into law on December 8, 2003 and which we refer to as the Act. We have elected to defer accounting for the Act and the amounts included within the accumulated postretirement benefit obligation and net periodic postretirement benefit cost in the financial statements and accompanying notes do not reflect the effects of the Act on our plan. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require us to change previously reported information.
 

Note 2 - Agreed Sale to Ameren

In February 2004, Dynegy entered into a $2.3 billion sale agreement with Ameren pursuant to which Ameren will acquire all of our outstanding common and preferred stock owned by Illinova and Dynegy’s 20% ownership in the Joppa power generation facility in Joppa, IL. Upon acquiring our company, Ameren will effectively assume our debt, expected to approximate $1.8 billion at closing, and Dynegy will receive approximately $400 million in cash, subject to working capital adjustments, with another $100 million being placed in escrow.

In a related agreement that is conditioned upon the closing of the transaction, DPM has contracted to sell up to 2,800 MWs of capacity and up to 11.5 million MWh of energy to us at fixed prices for two years beginning in January 2005. DPM has also agreed to sell 300 MWs of capacity in 2005 and 150 MWs of capacity in 2006 to us at a fixed price with an option to purchase energy at market-based prices. Please read Note 3 - Related Parties for further discussion of our power purchase agreements with other Dynegy affiliates.

In connection with Dynegy’s agreement to sell our common and preferred stock to Ameren, the Note Receivable from Affiliate is required to be addressed. Please read Note 3 - Related Parties for additional information concerning our Note Receivable from Affiliate. Additionally, the sale is conditioned upon, among other things, the receipt of approvals from the ICC, the SEC and other governmental and regulatory agencies. In July 2004, the FERC approved the sale and two-year power purchase agreement described above. Pending receipt of the remaining approvals, the transaction is expected to close before the end of 2004.
 

Note 3 - Related Parties

At June 30, 2004, principal outstanding under the Note Receivable from Affiliate approximated $2.3 billion with no accrued interest. We recognized approximately $85 million in interest income from Illinova on the note for each of the six-month periods ended June 30, 2004 and 2003 and approximately $42 million for each of the three-month periods ended June 30, 2004 and 2003. In January 2004, Dynegy made an accelerated interest payment of approximately $43 million on its $2.3 billion intercompany note payable to Illinova, which in turn made an interest payment of approximately $43 million to us under our Note Receivable from Affiliate.  At June 30, 2004, we carried approximately $85 million in prepaid interest on our Note Receivable from Affiliate, which represents six months of interest paid before it has been earned. In the same period of 2003, we had no prepaid interest and carried approximately $43 million in interest receivable.  In July 2004, we received an additional payment of interest under our Note Receivable from Affiliate of approximately $14 million.

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 - Note Receivable from Affiliate beginning on page F-9 of our 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 collecti bility of the note on a quarterly basis. Principal payments on our Note Receivable from Affiliate 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. 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 consolidated balance sheet and such action could have a material adverse effect on our financial condition and results of operations.

 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003

In connection with Dynegy’s agreement to sell our common and preferred stock to Ameren, the Note Receivable from Affiliate is required to be addressed. Pursuant to this requirement, we anticipate that the Note Receivable from Affiliate will be significantly reduced or eliminated from our consolidated balance sheet in exchange for value, in the form of cash and/or other consideration, to be received by us.

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. The following table presents aggregate amounts derived from transactions with affiliates:

 
   
Three Months Ended
 
Six Months Ended
   

 June 30,

  

 June 30,

  
2004
  
2003
  
2004
  
2003
  
   
(in millions)
  
Operating revenues
 
$
6
  
$
7
  
$
12
  
$
15
  
                           
Power purchased
 
$
108
  
$
114
  
$
232
  
$
232
  
Other operating expenses
    
5
    
17
    
14
    
41
  
Operating expenses
  
$
113
  
$
131
  
$
246
  
$
273
  
                           
 
The reduction in operating expenses, excluding power purchased, resulted from making fewer gas purchases from our affiliates during 2004. Management believes that the methods of allocating costs, where used, are reasonable and related party transactions have been conducted at prices and terms similar to those available to and transacted with unrelated parties.

We have a PPA with DMG that provides us the right to purchase power from DMG for a primary term extending through December 31, 2004. This right to purchase power qualifies under the normal purchase and sale exemption of SFAS No. 133 and, therefore, we have accounted for the PPA under the accrual method. The PPA defines the terms and conditions under which DMG provides power and energy to us using a tiered pricing structure. The agreement requires us to pay DMG approximately $311 million for capacity charges in 2004.  According to the PPA with DMG, we are to provide a security guarantee of $50 million upon a credit downgrade event. This guarantee is being fulfilled by a $50 million guarantee from Dynegy on our behalf. With this arrangement, we believe we have provided adequate power supply for our expected load plus a reserve supply above that expected level. Should power acquired under this agreement, when combined with our other power purchase agreements, be insufficient to meet our load requirements, we will have to buy power at current market prices. The PPA obligates DMG to provide power up to the reservation amount even if DMG has individual units unavailable at various times.

Please read Note 2 - Agreed Sale to Ameren for a discussion of a contingent power purchase agreement with DPM to provide us power following the closing of the sale to Ameren. In the event that the pending sale transaction does not close before the end of 2004, we will enter into an interim power purchase agreement with DPM. The interim PPA was approved by the FERC in July 2004 and will take effect only if the pending sale does not close before year end. It will remain in effect only until the earlier of the closing of the pending sale or December 31, 2006, which latter date coincides with the expiration of the retail electric rate freeze in the State of Illinois. The interim PPA will provide for capacity and energy to serve our customers through 2006 if the sale is not completed and contains terms and conditions, including pricing terms, substantially similar to those contained in the PPA to be entered into upon our sale to Ameren. If we are unable to sufficiently contract for all of our future power and energy needs, we would be required to satisfy our needs through existing agreements, through a competitive purchasing process or, in limited circumstances, through open market purchases; however, we are currently in the process of acquiring additional contracted capacity and energy for 2005 and 2006.

 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003

At June 30, 2004, the outstanding balance on our receivable from DMG related to the Tilton lease was approximately $78 million. We recognized approximately $4 million and $8 million, respectively, of interest income from accretion of the receivable for the three- and six-month periods ended June 30, 2004. The interest income from DMG was offset by the corresponding interest we paid to the original lessor. In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, we terminated our lease with the original lessor and the related turbines were purchased from the original lessor by DMG. Please see Note 4 - Commitments and Contingencies - Capital Leases for further discussion of the Tilton lease and Note 9 - Subsequent Event for further discussion of the July transactions related to Tilton.

Effective January 1, 2000, the Dynegy consolidated group, including us, began operating under a Services and Facilities Agreement which was approved by the ICC. Under this agreement, we share facility space and exchange services (such as financial, legal, information technology and human resources) with other Dynegy affiliates. Our services are exchanged at fully distributed costs and revenue is not recorded under this agreement. Management believes that the allocation method utilized under this agreement is reasonable and amounts charged under this agreement would result in costs to us similar to costs we would have incurred for these services on a stand-alone basis.
 
On October 23, 2002, the ICC issued an order approving a petition submitted by us to enter into an agreement with Dynegy and its affiliates that would allow for certain payments due to Dynegy under the Services and Facilities Agreement to be netted against certain payments due to us from Dynegy, should Dynegy or its affiliates fail to make payments due to us on or before their due dates. However, the PPA with DMG is specifically exempted from this agreement. The agreement also allows Dynegy to net payments in the event we fail to make our required payments to Dynegy. To date, there have been no triggering events to necessitate such netting of transactions. Additionally, under the terms of this petition and the ICC’s approval, we will not pay any common dividend to Dynegy or its affiliates until our first mortgage bonds are rated investment grade by Moody’s Investors Service and Standard & Poor’s Ratings Group and specific approval is obtained from the ICC.

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

     
   
6/30/04
12/31/03
               
Investment in IPSPT
  
$
4
  
$
4
  
Receivable from IPSPT (noncurrent)
  
$
2
  
$
2
  
Long-term debt to IPSPT (including maturing within one year)
  
$
374
  
$
420
  

In addition to the transactions above, we recorded $6 million and $12 million, respectively, in interest expense related to IPSPT for the three- and six-month periods ended June 30, 2004.


Note 4 - Commitments and Contingencies

Commitments

Please read Note 5 - Commitments and Contingencies beginning on page F-20 of our Form 10-K for a discussion of the material commitments and contingencies affecting us. No material developments affecting us have occurred with respect to such matters since the filing of our 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 set forth below, we are involved in legal or administrative proceedings before various courts and agencies with respect to matters occurring in the ordinary course of business. Management has recorded reserves against some of these matters in amounts believed to be appropriate and expects that the final disposition of all such ordinary course proceedings will not have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003

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

With respect to some of the items listed below, management has determined that a loss is not probable or that any such loss, to the extent probable, is not reasonably estimable. In some cases, management is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, management has assessed these matters based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. 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.

Asbestos Litigation   As of June 30, 2004, forty-one lawsuits were pending against us for illnesses based on alleged exposure to asbestos at generation facilities previously owned by us. Eight of these pending asbestos lawsuits were served on us during the second quarter of 2004. We intend to defend vigorously against the remaining pending lawsuits. Reserves have been established with respect to the pending lawsuits; however, we do not expect the outcome of any such pending lawsuits to have a material adverse effect upon our financial condition or results of operations.

Trans-Elect Litigation   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 an asset purchase and sale agreement entered into by the parties in October 2002. Under the terms of the agreement, we agreed to sell our transmission assets to Trans-Elect if, on or before July 7, 2003, the agreement received the required FERC, ICC, SEC and Hart-Scott Rodino approvals . 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. Trans-Elect claims that we breached the agreement by failing to use our "best efforts" to obtain the required approvals and/or to negotiate an alternate agreement that could be approved. In April 2004, the plaintiffs amended their complaint to add Dynegy Inc. as a defendant, claiming that Dynegy tortiously interfered with the asset purchase and sale agreement. In May 2004, the parties entered into a settlement agreement and these lawsuits were settled for less than $ 3 million, which was paid by Dynegy. The lawsuits have been dismissed.

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

Sarah Lucash and Kyle Johnson v. Illinois Power Company   Plaintiffs Lucash and Johnson were killed in an automobile accident in February 2001 when their car struck an Illinois Power guy wire and utility pole and caught fire. Plaintiffs’ families assert wrongful death and survivorship causes of action alleging that we failed to properly maintain our electrical equipment and did not have authority for the location of the pole. The parties are currently engaged in discovery. Although a date has not been set, we expect the trial to occur in the first quarter 2005. We cannot predict with any certainty the extent to which we will incur any liability or to estimate the damages, if any, that might be i ncurred
 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003
 
in connection with this lawsuit; however, we do not expect the outcome of this litigation to have a material adverse effect upon our financial condition or results of operations. We have established a reserve in connection with this litigation.
 
U.S. Environmental Protection Agency Complaint   IP and DMG are the subject of an NOV from the EPA and a complaint filed by the EPA and the Department of Justice in federal district court alleging violations of the Clean Air Act and certain related federal and Illinois regulations. Similar notices and complaints were filed against other owners of coal-fired power plants in what we refer to as the Utility Enforcement Initiative. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at the three Baldwin Station generating units constituted "major modifications" under the PSD, the NSPS regulations and the applicable Illinois regulations, and that the Defenda nts failed to obtain required operating permits under the applicable Illinois regulations. When activities which are not otherwise exempt result in an increase in annual emissions that exceeds the amount deemed significant under the PSD regulations, those activities are considered "major modifications". When activities meeting this definition occur, the Clean Air Act and related regulations generally subject those activities to PSD review and permit requirements and require that the generating facilities where the activities occur meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment.

DMG has significantly reduced emissions of sulphur dioxide and nitrogen oxides at the Baldwin Station since the 1999 complaint by converting from high to low sulfur coal, and installing selective catalytic reduction equipment. However, the EPA may seek to require the installation of the "best available control technology," or the equivalent, at the Baldwin Station, which we estimate could require capital expenditures of up to $410 million. The EPA also has the authority 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 resolve claims of liability began in June 2003 and closing arguments occurred in September 2003. Shortly after closing arguments, several interveners were granted the right to file briefs in support of arguments they believe the United States ceased to pursue . These interventions and delays in post-trial briefing have postponed the issuance of the liability order, and we cannot predict with any certainty when a decision will be rendered. Dynegy has recorded reserves in an aggregate amount considered reasonable for potential penalties that could be imposed if the Court finds us and/or DMG liable and the EPA prosecutes successfully the remaining claims for penalties.

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

None of our or DMG’s other facilities are covered in the complaint and NOV, but the EPA previously requested information, which has been provided, concerning activities at DMG’s Vermilion, Wood River and Hennepin plants. Although the EPA could eventually commence enforcement actions based on activities at these plants, we are unable to assess the likelihood of any such additional EPA enforcement actions.

Manufactured-Gas Plants   In the early 1900s, we operated two dozen sites at which synthetic natural gas was manufactured from coal. Operation of these MGP sites was generally discontinued in the 1950s when natural gas became available from interstate gas transmission pipelines. Many of these MGP sites were contaminated with residues from the gas manufacturing process. The Illinois EPA has issued No Further Remediation Letters for three of our MGP sites. Although we estimate our liability for MGP site remediation to be approximately $47 million for our remaining 21 MGP sites, because of the unknown

 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003
 
and unique characteristics at each site, we cannot be 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, based upon ICC Docket 91-0085.
 
Other

Operating Leases   There were no material changes in minimum commitments in connection with operating leases from those reported in our form 10-K.  These operating lease payments primarily relate to our material distribution facility, which is a commercial property lease for our storage warehouse, the Tilton land lease and the lease on 15 line trucks. Please read Note 9 - Subsequent Event for additional information related to the Tilton lease.

Capital Leases   An off-balance sheet operating lease for four gas turbines located in Tilton, Illinois was reclassified as a capital lease in September 2003, pursuant to the delivery of notice of an intent to exercise an option to purchase the assets when the lease expired in September 2004. The turbine assets were sublet to DMG and we became the capital sublessor. In July 2004, subsequent to the expiration of a statutory notice period after a fi ling at the ICC, we terminated our lease with the original lessor and the related turbines were purchased from the original lessor by DMG. As a result, we no longer have any off-balance sheet financing arrangements or capital lease agreements. Please read Note 9 - Subsequent Event for additional information related to Tilton.

Please read Note 5 - Commitments and Contingencies beginning on page F-20 of our Form 10-K and Note 7 - Regulatory Issues for a discussion of the other material regulatory matters affecting us. No additional material developments affecting us have occurred with respect to such matters since the filing of our Form 10-K.


Note 5 - Debt

During each of the three- and six-month periods ended June 30, 2004 and 2003, we paid IPSPT approximately $22 million and $43 million, respectively, which IPSPT used to pay down the transitional funding trust notes. We estimate that IPSPT will continue to pay down such notes, approximately $22 million per quarter, through 2008. LLC and IPSPT, which are VIEs under FIN No. 46R, are separate legal entities from IP. The assets of the VIEs are not available to our creditors and the transitional properties held by the VIEs are not assets of IP.

We make periodic interest payments related to our fixed-rate and variable rate debt obligations. Interest rates on these obligations ranged from 1.25% to 11.5% per annum during the six months ended June 30, 2004. Interest expense for the three- and six-month periods ended June 30, 2004 was approximately $40 million and $79 million, respectively. During the three- and six-month periods ended June 30, 2003 interest expense was approximately $41 million and $84 million, respectively. The reduction in expense is due to the repayments to IPSPT discussed above.

Tilton Capital Lease   In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, we terminated our lease with the original lessor and the related turbines were purchased from the original lessor by DMG for $81 million. This resulted in a reduction of debt of $78 million. Please read Note 4 - Commitments and Contingencies - Capital Leases and Note 9 - Subsequent Event for additional information con cerning our Tilton capital lease.
 
Note 6 - Liquidity

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 increased interest expense associated with our December 2002 $550 million Mortgage bond financing, and will not be
 
 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003
 
 available for other purposes. Second, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes is limited.

For the near term, our debt maturities primarily consist of (i) quarterly payments of approximately $22 million on the IPSPT transitional funding trust notes, for which we receive a separate revenue stream from our customers, and (ii) redemption of $70 million in mortgage bonds due March 2005. We believe that we have sufficient internal liquidity sources, including Dynegy’s commitment of support, to satisfy these near term debt maturities and our commercial obligations. The ability of Dynegy and it's other subsidiaries to support our liquidity needs is restricted, however, by their financing agreements. DHI’s May 2004 credit facility permits DHI to fund prepayments of up to $450 million in principal under our Note Receivable from Affiliate, but only to the extent that such prepayment does not c ause Dynegy’s liquidity to fall below $200 million for any ten business day period. DHI’s credit facility also prohibits prepayment by DHI of more than 12 months of interest under our Note Receivable from Affiliate. In addition, the indenture governing DHI’s 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.

Over the longer term, our liquidity and capital resources will be materially affected by the outcome of the pending sale of our company to Ameren. If the sale is consummated, Ameren has committed to contribute cash to us in order to support our ongoing operating commitments and to reduce our leverage. If the sale is not consummated, we would explore other liquidity initiatives. These initiatives would include an integration of many processes into those of Dynegy’s, which we expect would yield significant cost savings. Another liquidity initiative could include an issuance of mortgage bonds.

Our ability to consummate other liquidity initiatives, as described above, is subject to a number of risks, some of which are beyond our control. The outcome of the agreed sale to Ameren is also subject to a number of risks, some of which are beyond our control. These risks include, among others, the receipt of required regulatory approvals, particularly from the ICC, and satisfaction of other closing conditions. We encourage you to read Dynegy’s Quarterly Report on Form 10-Q for the period ended June 30, 2004 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.

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

 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003

In May 2004, we submitted a conditional application to the MISO. The application was conditioned in part on FERC approval of the sale of IP to Ameren, which FERC approval was received in July 2004. The FERC approval of the Ameren transaction included an approval for us to join the MISO. We are proceeding quickly to integrate into the MISO and are in the process of making preparations necessary for that integration, including submission of a filing with the FERC to gain approval for our recovery of (i) the exit fee we paid to the MISO in May 2001 to exit the MISO and to join the Alliance RTO and (ii) the Alliance RTO development costs.
 
Underground Storage   We continuously monitor the operating efficiencies of our underground gas storage fields. In 1999, we reduced the capacity of our working gas in the Hillsboro gas storage field from 7.6 Bcf to 4.0 Bcf, based on results from an engineering study and the annual operating results of the field, thereby increasing the base gas inventory. During 2003, we initiated further engineering studies to analyze the base/working gas ratio and confirm the gas in inventory. In March 2004, as a result of the studies, we decreased both the base gas and working gas inventories, returning the base gas volume to its pre-1999 level. Because of the increase in gas prices over time, the average price per Bcf of base gas increased as a result of this adjustment. We expect the approximately $10 million in working gas adjustment to be recovered from our customers through the purchase gas adjustment clause, subject to ICC prudency review.
 
Gas Rate Case   In June 2004, we filed with the ICC seeking authority to raise our natural gas delivery rates by approximately $40 million annually, or about $5.85 per month for the average residential gas customer. We have operated under the same rate structure for 10 years. The requested increase will allow us to recover investments in our natural gas delivery system. In addition, the increase reflects the increase in our operating costs, including materials and labor, since 1994. The requested increase applies only to base rates and does not affect the cost of gas itself, which typically accounts for approximately two-thirds of customers’ total gas bills and is recovered via the PGA process. As part of the regulatory process, which can be expected to take up to eleven months, the ICC will decide the amount of increase, if any, to provide recovery of costs from our customers. Upon approval, the new rates will go into effect in spring 2005, after the expected close of the sale of IP to Ameren.


Note 8 - Pension Plan Assets

Our employees are participants in defined benefit plans sponsored by Dynegy, which prior to the Dynegy-Illinova merger in February 2000, were sponsored and administered by us. Please read Note 12 - Employee Compensation, Savings and Pension Plans beginning on page F-35 of our Form 10-K for more information on our pension plans.

Components of Net Periodic Benefit Cost  The components of net periodic benefit cost were:
   
Pension Benefits
  
Other Benefits
  
   
Three Months Ended June 30,
  
   
2004
  
2003
  
2004
  
2003
  
   
(in millions)
  
Service cost benefits earned during period
  
$
3.9
  
$
3.4
  
$
1.2
  
$
1.0
  
Interest cost on projected benefit obligation
    
9.3
    
9.0
    
2.8
    
2.6
  
Expected return on plan assets
    
(11.6
)
  
(12.6
)
  
(1.6
)
  
(1.5
)
Amortization of net transition
    
(0.4
)
  
(0.4
)
  
0.5
    
0.5
  
Amortization of prior service cost
    
0.4
    
0.4
    
0.0
    
0.0
  
Amortization of net loss
    
0.8
    
0.0
    
1.2
    
1.2
  
Net periodic benefit cost (income)
  
$
2.4
  
$
(0.2
)
$
4.1
  
$
3.8
  

   
Pension Benefits
  
Other Benefits
  
   
Six Months Ended June 30,
  
   
2004
  
2003
  
2004
  
2003
  
   
(in millions)
Service cost benefits earned during period
  
$
7.8
  
$
6.8
  
$
2.4
  
$
2.0
  
Interest cost on projected benefit obligation
    
18.6
    
18.0
    
5.6
    
5.2
  
Expected return on plan assets
    
(23.2
)
  
(25.2
)
  
(3.2
)
  
(3.0
)
Amortization of net transition
    
(0.8
)
  
(0.8
)
  
1.0
    
1.0
  
Amortization of prior service cost
    
0.8
    
0.8
    
0.0
    
0.0
  
Amortization of net loss
    
1.6
    
0.0
    
2.4
    
2.4
  
Net periodic benefit cost (income)
  
$
4.8
  
$
(0.4
)
$
8.2
  
$
7.6
  


 
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ILLINOIS POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

For the Interim Periods Ended June 30, 2004 and 2003

Contributions   In Note 12 - Employee Compensation, Savings and Pension Plans beginning on page F-35 of our Form 10-K, we reported that we expected to contribute approximately $2 million related to our pension plan liability in 2004. Pursuant to the Pension Funding Equity Act of 2004, we are no longer required to make estimated quarterly contributions in 2004.


Note 9 - Subsequent Event

In September 1999, we entered into an operating lease on four gas turbines located in Tilton, IL and a separate land lease at the Tilton site. We sublet the turbines to DMG in October 1999. For additional information relating to the Tilton capital lease and related ARO liability and remeasurement, please read Note 1 - Summary of Significant Accounting Policies - SFAS No. 143, beginning on page F-14 and Note 7 - Commitments and Contingencies - Other - Capital Leases, beginning on page F-24 of our Form 10-K.

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

 
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ILLINOIS POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003

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 the audited consolidated financial statements and the notes thereto included in our Form 10-K.


General - Company Profile

We are a regulated utility that serves more than 590,000 electricity customers and nearly 415,000 natural gas customers in northern, central and southern Illinois. We also currently supply electric transmission service to numerous utilities, electric cooperatives, municipalities and power marketing entities in the State of Illinois.

We are an indirect, wholly-owned subsidiary of Dynegy Inc. Dynegy and Illinova recently entered into an agreement with Ameren to sell the shares of our common and preferred stock owned by Illinova, together with Dynegy’s 20% interest in a Joppa, IL power generating facility, for $2.3 billion. The transaction is expected to close before the end of 2004, subject to the receipt of required regulatory approvals and other closing conditions. Please read Note 2 - Agreed Sale to Ameren for further discussion.

Our results of operations and financial condition are affected by the consolidated financial and liquidity position of Dynegy, particularly because we rely on interest payments under an unsecured $2.3 billion intercompany note receivable from Illinova, our direct parent company and a wholly-owned Dynegy subsidiary, which we refer to as our Note Receivable from Affiliate, for a significant portion of our net cash provided by operating activities. Please read "- Liquidity and Capital Resources - Our Relationship with Dynegy" for further discussion.

Operationally, our performance for the first six months of 2004 was substantially in line with our performance during the same period in 2003. Electric and gas revenues were slightly down in 2004 as compared to 2003, primarily as a result of industrial customers choosing alternative suppliers.


Liquidity and Capital Resources

Overview

In this section, we provide updates related to our liquidity, capital requirements and capital resources. Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, contractual obligations, capital expenditures and working capital needs. Examples of working capital needs include purchases of electricity and natural gas, facility maintenance costs (including required environmental expenditures) and other costs such as payroll. Our liquidity and capital resources are primarily derived from cash flows from operations, cash on hand and interest payments under our Note Receivable from Affiliate.

Our Relationship with Dynegy

As stated above, we are an indirect, wholly owned subsidiary of Dynegy Inc. We are susceptible to developments at Dynegy because we rely on our Note Receivable from Affiliate for a substantial portion of our net cash provided by operating activities. The note, which had $2.3 billion in principal outstanding at June 30, 2004 and December 31, 2003, matures on September 30, 2009 and bears interest at an annual rate of 7.5%, due semiannually in April and October. Because our operating cash flows, cash on hand and other capital resources were insufficient to satisfy our 2003 debt maturities and other capital resource requirements, Dynegy prepaid approximately $128 million of interest on our Note Receivable from Affiliate in 2003. In January and July 2004, we received an additional $43 million and $14 million, respectively, of prepaid interest under our Note Receivable from Affiliate. At June 30, 2004, we carried approximately $85 million in prepaid interest on our Note Receivable from Affiliate, which

 
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ILLINOIS POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003
 
 represents six months of interest paid before it has been earned. At June 30, 2003, we had no prepaid interest and carried approximately $43 million in interest receivable.
 
We have reviewed the collectibility of this note to assess whether it has become impaired, as required by GAAP. Based upon our assessment, we do not believe that our Note Receivable from Affiliate is impaired. Please read "Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies - Note Receivable from Affiliate" beginning on page 23 of our Form 10-K for further discussion as to applicable GAAP requirements regarding impairment of our Note Receivable from Affiliate. Principal payments on our Note Receivable from Affiliate are not required until 2009 when it is due in full; as a result, future events may affect our view as to the collectiblity of the remaining principal owed to us thereunder. 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 consolidated balance sheet and such action could have a material adverse effect on our financial condition and results of operations.

Liquidity

Sources of Liquidity   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. 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 committed by Dynegy. We believe that we have sufficient internal liquidity sources, including Dynegy’s commitment of support, to satisfy our debt maturities and other capital resource requirements for the near term.

In connection with Dynegy’s agreement to sell our common and preferred stock to Ameren, the Note Receivable from Affiliate is required to be addressed. Pursuant to this requirement, we anticipate that the Note Receivable from Affiliate will be significantly reduced or eliminated from our consolidated balance sheet in exchange for value, in the form of cash and/or other consideration, to be received by us. While Ameren representatives have publicly submitted testimony to applicable regulatory authorities that Ameren plans to infuse substantial equity into IP in connection with the pending sale, the exact amount or structure of this infusion will not be known until the required regulatory approvals are obtained. In any case, we believe that Ameren will provide us with sufficient capital resources in connection with the reduction or elimination of our Note Receivable from Affiliate and thereafter such that the loss of interest income from our Note Receivable from Affiliate will not materially adversely affect our financial condition or results of operations.

Debt Maturities   In each of the three- and six-month periods ended June 30, 2004 and 2003, we paid approximately $22 million and $43 million, respectively, on the IPSPT transitional funding trust notes. For the near term, our debt maturities primarily comprise (i) similar quarterly payments on the IPSPT transitional funding trust notes, for which we receive a separate revenue stream from our customers; and (ii) redemption of $70 million in mortgage bonds due March 2005.

In September 1999, we entered into an operating lease on four gas turbines located in Tilton, IL and a separate land lease at the Tilton site. We sublet the turbines to DMG in October 1999. In September 2003, we delivered notice of our intent to exercise our option to purchase the turbines upon expiration of the lease in September 2004. Upon delivery of this notice of intent, our operating lease converted to a capital lease. Pursuant to these events, we recorded a receivable from DMG in accordance with our sublease agreement and a corresponding payable to the original lessor of approximately $66 million. We were ratably recording the interest income related to the receivable and the accretion expense related to the payable to the full c ontractual purchase obligation of approximately $81 million which was due at the expiration of the lease in September 2004. The effect on net income of the interest on the receivable was offset by the accretion of the payable. For additional information relating to the Tilton capital lease, please read Note 7 - Commitments and Contingencies - Other - Capital Leases beginning on page F-24 of our Form 10-K. In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, we terminated our lease with the original lessor and the related turbines were purchased from the original lessor by DMG for the full contract price of approximately $81 million. This resulted in a reduction of debt of $78 million. Additionally, we assigned our associated land lease on the Tilton site to DMG

Contractual Obligations and Contingent Financial Commitments   We have entered into various financial obligations and commitments in the course of our ongoing operations and financing strategies. Please read "Management’s Discussion and

 
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ILLINOIS POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003
 
Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Financial Obligations and Commercial Commitments" beginning on page 20 of our Form 10-K for a complete listing of our obligations and commitments.
 
Subsequent to year-end, obligations associated with contracts for firm transportation and storage services for natural gas that have varying expiration dates ranging from 2004 to 2012, increased from $66 million, as reported in our Form 10-K, to approximately $78 million. The increase is the result of the renewal of three contracts under different terms and the signing of an additional contract. Gas purchase commitments have increased from approximately $38.7 million, as reported in our Form 10-K, to approximately $49 million at June 30, 2004. We began entering into fixed-price forward contracts during April 2004 and will continue through October 2004. Typically these obligations range in duration from one to twelve months and require us to compensate the provider for capacity charges. In addition, we are in the process of acquiring additional capacity and associated energy to replace that which is supplied under the AmerGen PPA, which will expire at year end, for 2005 and 2006. The specific terms and conditions under which these resources will be acquired are not currently known.

We make periodic interest payments related to our fixed-rate and variable rate debt obligations. Interest rates on these obligations ranged from 1.25% to 11.5% per annum during the six months ended June 30, 2004. Interest expense for the three- and six-month periods ended June 30, 2004 was approximately $40 million and $79 million, respectively. During the three- and six-month periods ended June 30, 2003, interest expense was approximately $41 million and $84 million, respectively.

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%. However, we are limited in our ability to pay dividends by the Illinois Public Utilities Act and the Federal Power Act, which require retained earnings equal to or greater than the amount of any proposed dividend. Additionally, the ICC’s October 23, 2002 order relating to a netting agreement between Dynegy and us prohibits us from decla ring and paying any dividends on our common stock until 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. Please read Note 3 - Related Parties for further discussion of this ICC order.

During each of the six-month periods ended June 30, 2004 and 2003, we paid preferred stock dividends of approximately $1 million. We paid no common stock dividends in the first six months of 2004 or 2003.

Capital Expenditures   Capital expenditures for the six months ended June 30, 2004 were approximately $63 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   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 increased interest expense associated with our December 2002 $550 million Mortgage bond financing, and will not be available for other purposes. Second, our ability to obtain additional financ ing for working capital, capital expenditures, general corporate and other purposes is limited.

For the near term, our debt maturities primarily comprise (i) quarterly payments of approximately $22 million on the IPSPT transitional funding trust notes, for which we receive a separate revenue stream from our customers; and (ii) redemption of $70 million in mortgage bonds due March 2005. We believe that we have sufficient internal liquidity sources, including Dynegy’s commitment of support, to satisfy these near term debt maturities and our commercial obligations. The ability of Dynegy and it's other subsidiaries to support our liquidity needs is restricted, however, by their financing agreements. DHI's May 2004 credit facility permits DHI to fund prepayments of up to $450 million in principal under our Note Receivable from Affiliate, but only to the extent that such prepayment does not cause Dynegy& #146;s liquidity to fall below $200 million for any ten business day period. Dynegy’s credit

 
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ILLINOIS POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003
 
facility also prohibits prepayment by DHI of more than 12 months of interest under our Note Receivable from Affiliate. In addition, the indenture governing DHI's 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.
 
Over the longer term, our liquidity and capital resources will be materially affected by the outcome of the pending sale of our company to Ameren. If the sale is consummated, Ameren has committed to contribute cash to us in order to support our ongoing operating commitments and to reduce our leverage. If the sale is not consummated, we would explore other liquidity initiatives. These initiatives would include an integration of many processes into those of Dynegy’s, which we expect would yield significant cost savings. Another liquidity initiative could include an issuance of mortgage bonds.

Our ability to consummate other liquidity initiatives, as described above, is subject to a number of risks, some of which are beyond our control. The outcome of the agreed sale to Ameren is also subject to a number of risks, some of which are beyond our control. These risks include, among others, the receipt of required regulatory approvals, particularly from the ICC, and satisfaction of other closing conditions. We encourage you to read Dynegy’s Quarterly Report on Form 10-Q for the period ended June 30, 2004 for additional information regarding Dynegy and its current liquidity position.

Please read "Uncertainty of Forward-Looking Statements and Information" below for additional factors that could impact our future operating results, including the pending sale of our company to Ameren.


Factors Affecting Future Operating Results

In "Management’s Discussion and Analysis of Financial Condition and Results of Operations - General - Company Profile" beginning on page 16 of our Form 10-K, we detailed the primary factors that have impacted, and are expected to continue to impact, our earnings and cash flows. Our earnings and cash flows for the remainder of 2004 and beyond may be significantly affected by any or all of these factors, including the following in particular:

  Ø weather and its effect on demand for our services, particularly with respect to residential electric customers;
  Ø the number of customers that choose another retail electric provider under the Illinois Customer Choice Law; and
  Ø general economic conditions and the resulting effect on demand for our services, particularly with respect to commercial and industrial customers.

Please read the section "Uncertainty of Forward-Looking Statements and Information" below for additional factors that could impact our future operating results, including the pending sale of our company to Ameren.

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 our Form 10-K.

 
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ILLINOIS POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003

Results of Operations

Overview

In this section, we discuss our results of operations for the three- and six-month periods ended June 30, 2004 and 2003. We have also included our business outlook.

Three-Month Periods Ended June 30, 2004 and 2003

The following table presents key operating and financial statistics for the three-month periods ended June 30, 2004 and 2003, respectively.



   
Three Months Ended June 30,
2004
  
2003
  
   
(in millions)
  
Electric Sales Revenues -
          
Residential
  
$
93
  
$
83
  
Commercial
    
85
    
82
  
Commercial-distribution(1)
    
---
    
---
  
Industrial
    
61
    
72
  
Industrial-distribution(1)
    
1
    
2
  
Other
    
9
    
8
  
Revenues from ultimate consumers
    
249
    
247
  
Interchange
    
---
    
---
  
Transmission/Wheeling
    
9
    
10
  
Total Electric Revenues
  
$
258
  
$
257
  
               
Electric Sales in kWh (Millions) -
              
Residential
    
1,135
    
998
  
Commercial
    
1,118
    
1,052
  
Commercial-distribution(1)
    
2
    
1
  
Industrial
    
1,371
    
1,648
  
Industrial-distribution(1)
    
801
    
600
  
Other
    
90
    
88
  
Sales to ultimate consumers
    
4,517
    
4,387
  
Interchange
    
---
    
---
  
Total Electric Sales
    
4,517
    
4,387
  
               
Cooling Degree Days (2) - Actual
    
373
    
198
  
Cooling Degree Days (2) - 10 year Rolling Average
    
373
    
364
  
 
(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.

 
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ILLINOIS POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003
 
   
Three Months Ended June 30,
  
   
2004
  
2003
(in millions)
  
Gas Sales Revenues -
          
Residential
  
$
41
  
$
43
  
Commercial
    
16
    
16
  
Industrial
    
8
    
11
  
Other
    
1
    
1
  
Revenues from ultimate consumers
    
66
    
71
  
Transportation of customer-owned gas
    
(1
)
  
(2
)
Sales to affiliates
    
1
    
2
  
Total Gas Revenues
  
$
66
  
$
71
  
               
Gas Sales in Therms (Millions) -
              
Residential
    
34
    
35
  
Commercial
    
16
    
16
  
Industrial
    
8
    
16
  
Sales to ultimate consumers
    
58
    
67
  
Transportation of customer-owned gas
    
56
    
57
  
Total gas sold and transported
    
114
    
124
  
Sales to affiliates
    
2
    
2
  
Total Gas Delivered
    
116
    
126
  
               
Heating Degree Days (1) - Actual
    
388
    
469
  
Heating Degree Days (1) - 10 year Rolling Average
    
453
    
431
  
 
(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.
 
For the quarter ended June 30, 2004, we reported net income of $24 million, compared with second quarter 2003 net income of $18 million.

Operating revenues in 2004 decreased $4 million period over period. Electric revenues increased slightly, primarily due to warmer summer weather as compared to 2003, offset by lower industrial usage as a result of customers switching to alternative suppliers. Gas revenues were negatively impacted by lower industrial sales.

Operating expenses, exclusive of income taxes discussed below, decreased $6 million in the second quarter 2004 compared to the same period in 2003. Electric power purchases decreased due to lower average cost of power. Gas costs decreased due to a reduction in industrial usage, partially offset by a higher average price of gas. Other operating expenses, which increased in 2004 as compared to 2003, were impacted by higher employee benefits costs.
 
Other income in the second quarter 2004 and 2003 included interest income associated with our Note Receivable from Affiliate and allocated income taxes, while 2004 also includes interest income on our Tilton capital lease of $8 million.

Interest expense decreased $1 million period over period due to lower aggregate outstanding debt balances.

We reported total income tax provisions of $17 million and $14 million for the three-month periods ended June 30, 2004 and 2003, respectively. The effective income tax rates approximated 41% and 43%, respectively, for these periods.

 
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ILLINOIS POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003

Six-Month Periods Ended June 30, 2004 and 2003

The following table presents key operating and financial statistics for the six-month periods ended June 30, 2004 and 2003, respectively.
 
   
Six Months Ended June 30,
  
   
2004
  
2003
  
   
(in millions)
  
Electric Sales Revenues -
          
Residential
  
$
190
  
$
179
  
Commercial
    
159
    
156
  
Commercial-distribution(1)
    
---
    
---
  
Industrial
    
117
    
134
  
Industrial-distribution(1)
    
2
    
3
  
Other
    
18
    
17
  
Revenues from ultimate consumers
    
486
    
489
  
Interchange
    
---
    
---
  
Transmission/Wheeling
    
19
    
19
  
Total Electric Revenues
  
$
505
  
$
508
  
               
Electric Sales in kWh (Millions) -
              
Residential
    
2,590
    
2,431
  
Commercial
    
2,172
    
2,110
  
Commercial-distribution(1)
    
3
    
2
  
Industrial
    
2,691
    
3,053
  
Industrial-distribution(1)
    
1,429
    
1,148
  
Other
    
187
    
186
  
Sales to ultimate consumers
    
9,072
    
8,930
  
Interchange
    
1
    
1
  
Total Electric Sales
    
9,073
    
8,931
  
               
Cooling Degree Days (2) - Actual
    
373
    
198
  
Cooling Degree Days (2) - 10 year Rolling Average
    
374
    
364
  
 
(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.

 
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ILLINOIS POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003
 
   
Six Months Ended June 30,
2004
2003
  
   
(in millions)
  
Gas Sales Revenues -
          
Residential
  
$
187
  
$
186
  
Commercial
    
65
    
67
  
Industrial
    
20
    
23
  
Other
    
2
    
2
  
Revenues from ultimate consumers
    
274
    
278
  
Transportation of customer-owned gas
    
(1
)
  
(2
)
Sales to affiliates
    
3
    
5
  
Total Gas Revenues
  
$
276
  
$
281
  
               
Gas Sales in Therms (Millions) -
              
Residential
    
194
    
220
  
Commercial
    
74
    
88
  
Industrial
    
23
    
35
  
Sales to ultimate consumers
    
291
    
343
  
Transportation of customer-owned gas
    
125
    
122
  
Total gas sold and transported
    
416
    
465
  
Sales to affiliates
    
6
    
6
  
Total Gas Delivered
    
422
    
471
  
               
Heating Degree Days (1) - Actual
    
3,096
    
3,404
  
Heating Degree Days (1) - 10 year Rolling Average
    
3,131
    
3,018
  
 
(1)  A Heating Degree Day ("HDD") represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit. The HDDs for a period of time are computed by adding the HDDs for each day during the period.

For the six-month period ended June 30, 2004, we reported net income of $61 million, compared with net income of $50 million for the same period in 2003.

Operating revenues in 2004 decreased $8 million period over period. Electric revenues decreased, primarily due to lower industrial usage due to customers switching to alternative suppliers, partially offset by higher residential usage due to warmer summer weather as compared to 2003. Gas revenues were negatively impacted by slightly warmer winter weather and lower industrial sales.

Operating expenses, exclusive of income taxes discussed below, decreased $6 million in 2004 compared to 2003. Electric power purchases decreased due to lower average cost of power.  Gas costs remained flat, resulting from less gas purchased in the 2004 period offset by a higher average price of gas.  Other operating expenses, which increased in 2004, were primarily impacted by higher employee benefits and costs associated with claims and litigation reserves.

Other income in 2004 and 2003 included interest income associated with our Note Receivable from Affiliate and allocated income taxes, while 2004 also includes interest income on our Tilton capital lease of $8 million.

Interest expense decreased $5 million period over period due to lower aggregate outstanding debt balances.

We reported total income tax provisions of $42 million and $38 million for the six-month periods ended June 30, 2004 and 2003, respectively. The effective income tax rates approximated 41% and 42%, respectively, for these periods.

 
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ILLINOIS POWER COMPANY

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003

Operating Cash Flow

Cash flow from operating activities totaled $177 million for the six-month period ended June 30, 2004, compared to $74 million reported in the 2003 period. Changes in operating cash flow reflect the operating results previously discussed herein and the following significant factors. For the six-month period ended June 30, 2004, we recognized $28 million more of operating cash flow from the prepaid interest on our Note Receivable from Affiliate compared to the prior year period. Cash flow from operations also benefited by the reduction in gas inventories as a result of gas withdrawals during the winter heating season and the recovery of prepayments related to our natural gas purchase contracts.

Outlook

Future results of operations for us may be affected, either positively or negatively, by regulatory actions (with respect to rates or otherwise), general economic conditions, weather and customers choosing to utilize competitive alternate electric service providers. We expect 2004 operating income to be similar to actual results for 2003. Cash flow from operations is expected to be higher in 2004 than in 2003 as a result of the delayed recovery from our customers of costs we incurred in 2003 relating to gas inventories and higher prepaid deposits associated with gas purchases. Future results of operations will be significantly impacted by the outcome of the pending sale transaction with Ameren and by the decision of the ICC regarding the gas rate case which was filed in June 2004. Please read Note 2 - Agreed Sale to Ameren for further discussion of the pending sale transaction and Note 7- Regulatory Issues for more information concerning the gas rate case. Our ability to meet our capacity and energy needs beyond 2004 is partially addressed in connection with the pending sale to Ameren. We have also commenced a bidding process to replace the capacity and energy currently supplied under the AmerGen PPA. Please read Item 1 - Business - Power Supply beginning on page 3 of our Form 10-K and Note 3 - Related Parties for further discussion.

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 o ur reasonable judgment on the 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 the consummation of the agreed sale transaction with Ameren;
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 our ability to obtain required funding from Dynegy in the short-term and to consummate one or more liquidity initiatives in the long-term;
Ø intentions with respect to future energy supplies; and
Ø anticipated costs associated with legal and regulatory compliance.

 
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003

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 outcome of the agreed sale transaction with Ameren;
Ø our substantial indebtedness and our ability to generate sufficient cash flows either from our operations or other liquidity initiatives to service principal and interest on such indebtedness;
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 the effects of our relationship with Dynegy, 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 markets 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, including ICC approval of our gas rate case filed in June 2004.

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.

 
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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Supply 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. Unde r a Clinton shutdown scenario, to the extent we exceed our capacity reservation with DMG, we will have to buy power at current market prices. Such purchases would expose us to commodity price risk. As discussed in our Form 10-K, P.A. 90-561 was amended to extend the retail electric rate freeze for two additional years, through 2006.

Our ability to meet our power and energy needs beyond 2004 is provided for in the proposed sale transaction with Ameren. In the event that the pending sale transaction does not close before the end of 2004, we will enter into an interim power purchase agreement with DPM. The interim PPA, which was approved by the FERC in July 2004, will take effect only if the pending sale does not close before year end and will remain in effect only until the earlier of the closing of the pending sale or December 31, 2006, which latter date coincides with the expiration of the retail electric freeze in the State of Illinois. The interim PPA will provide for capacity and energy to serve our customers through 2006 if the sale is not completed and contains terms and conditions, including pricing terms, substantially similar to those cont ained in the agreement with Ameren described in Note 2 - Agreed Sale to Ameren above. Additionally, we are in the process of acquiring additional contracted capacity and associated energy for 2005 and 2006. The specific terms and conditions under which these resources will be acquired are not currently known. If we are unable to sufficiently contract for all of our power and energy needs, we would be required to satisfy our needs through open market purchases.

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

In June 2004, we filed with the ICC seeking authority to raise our natural gas delivery rates by approximately $40 million annually, or about $5.85 per month for the average residential gas customer. The requested increase will allow us to recover investments in our natural gas delivery system. The requested increase applies only to base rates and does not affect the cost of gas itself, which typically accounts for approximately two-thirds of customers’ total gas bills and is recovered via the PGA process. As part of the regulatory process, which can be expected to take up to eleven months, the ICC will decide the amount of increase, if any, to provide recovery of costs from our customers. Upon approval, the new rates will go into effect in spring 2005, after the expected close of the sale of IP to Ameren.< /DIV>

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures   Effective as of the end of the second quarter 2004, 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 Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective at the reasonable assurance level and designed to ensure that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported with in the
 
 
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requisite time periods. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.
 
Changes in Internal Controls   There was no change in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of our internal controls performed during the second quarter 2004 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

 
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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:

†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.

† Filed herewith.
* 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 second quarter of 2004:
 
We filed a Current Report on Form 8-K on April 2, 2004. Items 5 and 7 were reported and no financial statements were filed.

 
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SIGNATURES


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

     
  Illinois Power Company
   
 
 		  
 		  
 
Date: August 11, 2004 By:   /s/ Peggy E. Carter
 
 
Peggy E. Carter, Managing Director, Controller
(Duly Authorized Officer and Principal Accounting Officer)

 
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