ILLINOIS POWER CO - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

----------------------------------
FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

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

For the transition period from __________ to _____________

COMMISSION FILE NUMBER: 1-3004
ILLINOIS POWER COMPANY
(Exact name of registrant as specified in its charter)

ILLINOIS 37-0344645
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)

500 S. 27TH STREET
DECATUR, ILLINOIS 62521-2200
(Address of principal executive offices) (Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:
Title of each class: Name of each exchange on which registered:
Each of the following securities are listed on the New York Stock Exchange.
MORTGAGE BONDS
6.0% Series due 2003 6 3/4% Series due 2005
6 1/2% Series due 2003 7 1/2% Series due 2025

Securities registered pursuant to Section 12(g) of the Act: None

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 the filing
requirements for the past 90 days.
Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ ] No [X]

Illinova Corporation is the sole holder 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.

DOCUMENTS INCORPORATED BY REFERENCE: None.

1

ILLINOIS POWER COMPANY
FORM 10-K

TABLE OF CONTENTS

PAGE

PART I

Definitions..................................................................................... 3
Item 1. Business.............................................................................. 4
Item 2. Properties............................................................................ 12
Item 3. Legal Proceedings..................................................................... 12
Item 4. Submission of Matters to a Vote of Security Holders................................... 12

PART II

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................. 12
Item 6. Selected Financial Data............................................................... 13
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations............................................................................ 14
Item 7A. Quantitative and Qualitative Disclosures About Market Risk............................ 30
Item 8. Financial Statements and Supplementary Data........................................... 31
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure............................................................................ 31

PART III

Item 10. Directors and Executive Officers of the Registrant.................................... 32
Item 11. Executive Compensation................................................................ 34
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholders Matters.................................................................. 37
Item 13. Certain Relationships and Related Transactions........................................ 38

PART IV

Item 14. Controls and Procedures............................................................... 38
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K...................... 39

Signatures...................................................................................... 40

2

PART I
------

DEFINITIONS
- -----------

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

AFUDC Allowance for Funds Used During Construction
Alliance RTO Alliance Regional Transmission Organization
AmerenCILCO Ameren - Central Illinois Light Company
AmerenCIPS Ameren - Central Illinois Public Service Company
AmerenUE Ameren - Union Electric Company
AmerGen AmerGen Energy Company
APB Accounting Principles Board
Clinton Clinton Power Station
DMG Dynegy Midwest Generation, Inc.
DOE United States Department of Energy
Dynegy Dynegy Inc.
EITF Emerging Issues Task Force of the Financial Accounting
Standards Board
EMF Electric and Magnetic Fields
EPA Environmental Protection Agency
FAS Statement of Financial Accounting Standards
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GAAP Generally Accepted Accounting Principles
ICC Illinois Commerce Commission
Illinova Illinova Corporation
IPFI Illinois Power Financing I
IPMI Illinova Power Marketing Inc.
IPSPT Illinois Power Special Purpose Trust
ISO Independent System Operator
ITC Investment Tax Credit
kW Kilowatts
kWh Kilowatt-Hour
LLC Illinois Power Securitization Limited Liability Company
MGP Manufactured-Gas Plant
MISO Midwest Independent Transmission System Operator, Inc.
MW Megawatts
National Grid National Grid, USA
P.A. 90-561 Electric Service Customer Choice and Rate Relief Law of 1997
P.A. 92-0537 Extension of Retail Electric Rate Freeze
PJM PJM Interconnection LLC
PPA Power Purchase Agreement
PUHCA Public Utility Holding Company Act of 1935
RCRA Resource Conservation and Recovery Act
ROE Return on Equity
RTO Regional Transmission Organization
SEC United States Securities and Exchange Commission
TOPrS Trust Originated Preferred Securities
TSCA Toxic Substances Control Act
TVA Tennessee Valley Authority
UGAC Uniform Gas Adjustment Clause

Additionally, the terms "IP," "we," "us" and "our" refer to Illinois Power
Company and its subsidiaries, unless the context clearly indicates otherwise.

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ITEM 1. BUSINESS
- -----------------

GENERAL
-------

We are engaged in the transmission, distribution and sale of electric energy and
the distribution, transportation and sale of natural gas in the State of
Illinois. We provide electric and natural gas service to residential, commercial
and industrial customers in substantial portions of northern, central and
southern Illinois. Our service territory includes 11 cities with populations
greater than 30,000 and 37 cities with populations greater than 10,000 (2000
U.S. Census Bureau's Redistricting Data). We also currently supply electric
transmission service to numerous utilities, electric cooperatives,
municipalities and power marketing entities in the State of Illinois. As
described below, we have previously announced an agreement to sell our electric
transmission system.

We are an indirect, wholly owned subsidiary of Dynegy Inc. Dynegy acquired
our direct parent company, Illinova, and its subsidiaries, including us, in
February 2000. Dynegy is currently restructuring itself in response to various
events that have negatively impacted it, and the energy industry, over the past
year. In the restructured Dynegy, our operations comprise one of three operating
divisions. 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 a $2.3 billion intercompany note receivable from
Illinova for a significant portion of our net cash provided by operating
activities. Please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Liquidity and Capital Resources--Our
Relationship with Dynegy" beginning on page 15 for further discussion.

We were incorporated under the laws of the State of Illinois on May 25, 1923.
Our principal executive office is located at 500 S. 27th Street, Decatur,
Illinois 62521-2200, and our telephone number at that office is (217) 424-6600.

ELECTRIC BUSINESS
-----------------

OVERVIEW
- --------

We supply electric service at retail to an estimated aggregate population of
1,372,000 in 313 incorporated municipalities, adjacent suburban and rural areas
and numerous unincorporated communities. We hold franchises in all of the 313
incorporated municipalities in which we provide retail electric service. As of
January 3, 2003, based on billable meters, we served 592,692 active electric
customers. We own an electric distribution system of 37,907 circuit miles of
overhead and underground lines. For the year ended December 31, 2002, we
delivered a total of 19,144 million kWh of electricity.

Our highest system peak hourly demand (native retail load) in 2002 was
3,472,000 kW on August 1, 2002. This compares with our record high system peak
hourly demand (native retail load) of 3,888,000 kW on July 29, 1999.

TRANSMISSION AND DISTRIBUTION
- -----------------------------

We own, but have previously announced an agreement to sell, a 1,672 circuit mile
electric transmission system. The closing of the proposed sale to Trans-Elect
Inc., an independent transmission company, is conditioned on several matters,
including the receipt of required approvals from the SEC under the PUHCA, the
Federal Trade Commission, the ICC and the FERC. With respect to the FERC, the
sale was conditioned on its approving the levelized rates application filed by
Trans-Elect seeking a 13% return on equity (based on a capital structure of
equal portions of debt and equity), which would result in a significant increase
in transmission rates over the rates we currently charge. On February 20, 2003,
the FERC voted to defer approval of the transaction and ordered a hearing to
establish the allowable transmission rates for Trans-Elect. Specifically, the
FERC stated that the benefits of the transaction, including independent
transmission ownership, may not justify the significant increase in rates
sought. The FERC also limited the period for which we could provide operational
services to Trans-Elect to one year.

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Trans-Elect and IP have since withdrawn the rate filing at the FERC and
requested a continuance of the hearing pending an order on a rehearing and a
ruling by the FERC on a new rate application. Pending resolution of the FERC
issues, the ICC proceedings have also been withdrawn and continued. We are
currently in discussions with Trans-Elect to determine the impact of the FERC
order on the transaction and to determine the course of action the parties will
take. However, under the sale agreement, if the transaction does not close on or
before July 7, 2003, either party can terminate the agreement. Because of the
lead time required for regulatory approvals, it is unlikely that the transaction
could be closed by July 7th.

ELECTRIC RATES
- --------------

Regulators historically have determined our rates for electric service-the ICC
at the retail level and the FERC at the wholesale level. These rates are
designed to recover the cost of service and to allow our shareholders the
opportunity to earn a reasonable rate of return. Please read "Competition" and
"Regulation" beginning on page 8 for further discussion of the regulatory
environment in which we operate, including the retail electric rate freeze that
will remain in effect through 2006.

POWER SUPPLY
- ------------

We own no significant generation assets and obtain the majority of the
electricity that we supply to our retail customers pursuant to long-term power
purchase agreements with AmerGen and DMG. The AmerGen agreement was entered into
in connection with the sale of our former Clinton nuclear generation facility to
AmerGen in December 1999. We are obligated to purchase a predetermined
percentage of Clinton's electricity output through 2004 at fixed prices that
exceed current and projected wholesale prices. We recorded a liability related
to the above-market portion of this purchase agreement, which is being amortized
through 2004, based on the expected energy to be purchased from AmerGen. The
AmerGen agreement does not obligate AmerGen to acquire replacement power for us
in the event of a curtailment or shutdown at Clinton.

We obtain approximately 70% of our electricity pursuant to our power purchase
agreement with DMG. This agreement has a primary term that runs through 2004,
with provisions to extend the agreement annually thereafter as the parties shall
agree. The DMG agreement requires that we compensate DMG for reserved capacity
regardless of the amount of electricity purchased and that we pay for any
electricity actually purchased based on a formula that includes various cost
factors, primarily related to the cost of fuel, plus a market price for amounts
in excess of our reserved capacity. This agreement obligates DMG to provide
power up to the amount we reserve even if DMG has individual units unavailable.
At our option, DMG is required to provide power in excess of our reserved
capacity, but we must pay market prices for any power that DMG purchases in
order to satisfy this requirement.

We believe that we have access to an adequate power supply for our expected
load plus a reserve supply above that expected level. Should we be unable to
obtain sufficient power to meet our load requirements from DMG and AmerGen, we
will have to buy power on the open market at current market prices. Volatility
in market prices for power could affect us to the extent that we would be
required to purchase power in the open market.

INTERCONNECTIONS
- ----------------

We are a participant, together with AmerenUE and AmerenCIPS, in the
Illinois-Missouri Power Pool ("Pool"), which was formed in 1952. The Pool
operates under an interconnection agreement that provides for the
interconnection of transmission lines. This agreement has no expiration date,
but any party may withdraw from the agreement on 36 months written notice.

We, AmerenCIPS and AmerenUE have contracted with the TVA for the
interconnection of the TVA system with those of the three companies. The
contract addresses power purchase provisions among the parties and other working
arrangements. This contract has no expiration date, but any party may withdraw
from the agreement on five years written notice.

5

We also have interconnections with Indiana-Michigan Power Company,
Commonwealth Edison Company, AmerenCILCO, MidAmerican Energy Corporation,
Louisville Gas & Electric, Southern Illinois Power Cooperative, Electric Energy
Inc. and the City of Springfield, Illinois.

We are a member of the Mid-America Interconnected Network ("MAIN"), one of
ten regional reliability councils established to coordinate plans and operations
of member companies regionally and nationally. However, we have given notice to
MAIN of our intent to withdraw. Such withdrawal would be effective on December
31, 2003, unless changed by subsequent events. Prior to December 31, 2003, we
expect to extend our membership in MAIN or join one of the other adjacent
regional reliability councils.

ILLINOIS ELECTRIC DEREGULATION
- ------------------------------

Our electric operations are regulated by the State of Illinois through the
Illinois Public Utilities Act and the ICC. The ICC regulates the rates at which
we can sell and distribute electricity to retail customers. On June 6, 2002, a
bill was enacted that extends Illinois' current retail electric rate freeze
through 2006. Beginning in 2007, absent further extension of the retail electric
rate freeze or other action, we expect that the distribution and transmission
component of retail electric rates will continue to be required to be based on
costs while the power and energy component may be required to be based on costs
or prices in the wholesale market. We cannot predict the structure under which
retail rates will be set after 2006 or the impact of any such rate structure on
our business.

The Illinois state legislature deregulated the Illinois retail power market
through the Electric Utility Customer Choice and Rate Relief Law of 1997,
commonly referred to as the Customer Choice Law, enacted in December 1997 and
amended in June 2002. The Customer Choice Law gave our residential electric
customers a 15% decrease in base electric rates beginning August 1, 1998 and an
additional five percent decrease in base electric rates beginning May 1, 2002.
The rate reduction savings realized by our customers during 2002 was $101.6
million. The combined impact of these rate decreases is expected to result in a
total annual revenue reduction of $101 million in 2003, $103 million in 2004,
$105 million in 2005 and $107 million in 2006, relative to rate levels in effect
prior to August 1, 1998.

The Customer Choice Law contains floor and ceiling provisions applicable to a
utility's ROE during the mandatory transition period ending in 2006. Pursuant to
the provisions in the legislation, we can request an increase in our base rates
if the two-year average of our earned ROE is below the two-year average of the
"Treasury Yield", defined as the monthly average yields of the 30-year U.S.
Treasury Bonds through January 2002, an average of the 30-year U.S. Treasury
Bonds and the monthly Treasury Long-Term Average Rates in February 2002, and the
monthly Treasury Long-Term Average Rates (25 years and above) after February
2002, for the concurrent period. The ICC would rule on such a request for a rate
increase. Conversely, through 2006, we are required to refund to our customers
50% of the amount earned above a defined ceiling limit. This ceiling limit is
exceeded if the two-year average of our ROE exceeds the two-year average of the
Treasury Yield for the concurrent period plus 8.5%. In December 2002, we filed
to increase the add-on to the Treasury Yield from 6.5% to 8.5% waiving our right
to collect transition charges in 2007 and 2008 from customers choosing direct
access. Regulatory asset amortization is included in the calculation of the ROE
for the ceiling test but is not included in the calculation of the ROE for the
floor test. During 2002 and 2001, our two-year average ROE was within the
allowable ROE collar, resulting in no rate increase requests or customer
refunds.

As of May 1, 2002, the Customer Choice Law transitioned customers to choice,
thereby permitting all Illinois electric consumers to choose their own electric
providers. The rate freeze described above does not apply to rates for electric
distribution service to customers who choose direct access. These rates are
currently required to be based on costs and can be raised or lowered subject to
approval of the ICC as the result of a rate proceeding. However, customers
choosing direct access will be required to pay applicable transition charges
based on the utility's lost revenues from such customers. Under the Customer
Choice Law, we are obligated to provide electric supply service to all of our
customers who request it, unless such service is deemed competitive by the ICC.

Although no parties have requested certification from the ICC to provide
residential electric power service pursuant to the Customer Choice Law, this
could change. There are eight registered energy

6

providers for non-residential service. Customer choice has resulted in lower
electric service revenues from our commercial and industrial customers. These
factors and others will influence the extent to which customer choice affects
our operating results. We currently estimate that by the end of 2003 commercial
and industrial customers representing approximately 16% of our eligible retail
load will have switched to other electric service providers. In addition, we
have also lost revenues as a result of some commercial and industrial customers
electing to pay for power supplied by us at market-based prices, rather than
under bundled tariffs. This power purchase option is only available to
commercial and industrial customers that would be required to pay transition
charges and is generally not available to customers with non-standard tariff
agreements until such agreements expire. We have a significant number of such
agreements that expire in the third and fourth quarters of 2003. A significant
number of customers under these agreements could elect the power purchase option
in connection with any such renewals or choose a third party provider.

GAS BUSINESS
------------

OVERVIEW
- --------

We supply retail natural gas service to residential, commercial and industrial
consumers in substantial portions of northern, central and southern Illinois. We
do not sell gas for resale.

We supply retail natural gas service to an estimated population of 1,019,000
in 258 incorporated municipalities and adjacent areas. We hold franchises in all
of the incorporated municipalities in which we provide retail gas service. As of
January 3, 2003, based on billable meters, we served 414,333 active gas
customers.

We own 774 miles of natural gas transportation pipeline and 7,598 miles of
natural gas distribution pipeline. We have contracts on six interstate pipelines
for firm transportation and storage services. These contracts have varying
expiration dates ranging from 2003 to 2012. We also have contracts for the
acquisition of natural gas ranging in duration from one to twelve months. We
attempt to manage our customers' gas price risk by buying gas forward and
injecting gas into storage at times when it is economic to do so, subject to ICC
regulations and review.

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, the rates
that we are allowed to charge for retail gas service are designed to recover the
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. For the year ended December 31,
2002, we delivered a total of 773 million therms of natural gas.

We own seven underground natural gas storage fields with a total capacity of
approximately 11.6 billion cubic feet and a total deliverability on a peak day
of approximately 327 million cubic feet. To supplement the capacity of our seven
underground storage fields, we have contracted with natural gas pipelines for an
additional 5.37 billion cubic feet of underground storage capacity, representing
additional total deliverability on a peak day of about 96 million cubic feet.
The operation of these underground storage facilities permits us to increase
deliverability to our retail gas customers during peak load periods by
withdrawal of natural gas that was previously placed in storage during off-peak
months.

We experienced our 2002 peak-day send out of 571,528 MMBtu of natural gas on
March 3, 2002. This compares with our record peak-day send out of 857,324 MMBtu
of natural gas on January 10, 1982.

RELATIONSHIP WITH DYNEGY
------------------------

As described above, we are an indirect, wholly owned subsidiary of Dynegy Inc.
We rely on Dynegy and other of its affiliates for, among other things, providing
funds to Illinova for interest payments under our

7

$2.3 billion intercompany note receivable from Illinova, a significant portion
of our purchased power and certain administrative and general services related
to our operations. Dynegy's operating results were negatively impacted by a
number of events occurring in 2002. These events affected public confidence in
Dynegy's ability to satisfy its debt and other obligations and its long-term
business strategy and resulted in continued declines in the market price for its
debt and equity securities. To learn more about Dynegy and its current financial
condition, we encourage you to read Dynegy's annual report on Form 10-K for the
fiscal year ended December 31, 2002, which is available free of charge through
the SEC's website at www.sec.gov. The SEC also has a toll free number that you
may call for information, which is 800-732-0330. Please read "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources--Our Relationship with Dynegy"
beginning on page 15 for further discussion of the effects that events affecting
Dynegy can have and have had on us.

ENVIRONMENTAL MATTERS
---------------------

We are subject to regulation by various federal and Illinois authorities with
respect to environmental matters and may in the future become subject to
additional regulation by such authorities or by other federal, state and local
governmental bodies. We do not expect that our compliance with any such
environmental regulations will have a material adverse effect upon our capital
expenditures, earnings or competitive position. For more information, please see
"Note 6 - Commitments and Contingencies" in the accompanying audited financial
statements beginning on page F-17.

MANUFACTURED-GAS PLANT SITES
- ----------------------------

For more information on our manufactured-gas plant sites, please see "Note 6 -
Commitments and Contingencies" in the accompanying audited financial statements
beginning on page F-17.

OTHER ISSUES
- ------------

Hazardous and non-hazardous wastes that we generate must be managed in
accordance with federal regulations under the TSCA, the Comprehensive
Environmental Response, Compensation and Liability Act and the RCRA and
additional state regulations promulgated under both the RCRA and state law.
Regulations promulgated in 1988 under the RCRA govern our use of underground
storage tanks. The use, storage and disposal of certain toxic substances, such
as polychlorinated biphenyls in electrical equipment, are regulated under the
TSCA. Hazardous substances used by us are subject to reporting requirements
under the Emergency Planning and Community-Right-To-Know Act. The State of
Illinois has been delegated authority for enforcement of these regulations under
the Illinois Environmental Protection Act and state statutes. These requirements
impose certain monitoring, record keeping, reporting and operational
requirements that we have implemented or are implementing to assure compliance.
We do not anticipate that compliance will have a material adverse impact on our
financial position or results of operations.

COMPETITION
-----------

We are authorized, by statute and/or certificates of public convenience and
necessity, to conduct operations in the territories we serve. In addition, we
operate under franchises and license agreements granted by the communities we
serve.

Our electric utility business faces significant competition brought about by
the implementation of a customer choice structure in the State of Illinois.
Under the Customer Choice Law, residential electric customers were given a 15%
decrease in their base electric rates beginning August 1, 1998 and an additional
5% decrease in base electric rates beginning May 1, 2002. The Customer Choice
Law also implemented a return on equity collar that is further described above
under "Illinois Electric Deregulation." Additionally, beginning in 1998 and
ending May 1, 2002, the Customer Choice Law transitioned customers to choice,
thereby permitting all Illinois electric customers to choose their own
electricity providers. Customers who buy their electricity from a supplier other
than the local electric utility are required to pay applicable transition
charges to the utility through the year 2006. These charges are not intended to

8

compensate the electric utilities for all revenues lost because of customers
buying electricity from other suppliers.

With respect to our gas distribution business, absent extraordinary
circumstances, potential competitors are barred from constructing competing
systems in our service territories by a judicial doctrine known as the "first in
the field" doctrine. In addition, the high cost of installing duplicate
distribution facilities would render the construction of a competing system
impractical. Additionally, competition in varying degrees exists between natural
gas and other fuels or forms of energy available to consumers in our service
territories.

Although no parties have requested certification from the ICC to provide
residential electric service pursuant to the Customer Choice Law, this could
change. Currently, there are eight energy providers for non-residential service.
We face competition from these and other energy providers and estimate that, by
the end of 2003, commercial and industrial customers representing approximately
16% of our eligible retail load will have switched to another such provider.
Competition typically is based on price and service reliability.

REGULATION
----------

We are subject to regulation under the Federal Power Act by the FERC as to rates
and charges in connection with the transmission of electric energy in interstate
commerce, the issuance of debt securities maturing in not more than 12 months,
accounting and depreciation policies, interaction with affiliates and certain
other matters. The FERC has declared us exempt from the Natural Gas Act and
related FERC orders, rules and regulations.

In 2003, the FERC is expected to issue a rule that would require all RTOs to
implement a Standard Market Design. The ultimate impact of this rulemaking on us
is not known at this time.

Our retail natural gas sales also are regulated by the ICC. Such sales are
currently priced under a purchased gas adjustment mechanism under which our gas
purchase costs are passed through to our customers if such costs are determined
prudent.

We are an electric utility as defined in the PUHCA. Our direct parent
company, Illinova, and Dynegy are holding companies as defined in the PUHCA.
However, both Illinova and Dynegy generally are exempt from regulation under
section 3(a)(1) of the PUHCA. They remain subject to regulation under the PUHCA
with respect to the acquisition of certain voting securities of other domestic
public utility companies and utility holding companies.

The Illinois Public Utilities Act was significantly modified in 1997 by the
Customer Choice Law, but the ICC continues to have broad powers of supervision
and regulation with respect to our rates and charges, our services and
facilities, extensions or abandonment of service, classification of accounts,
valuation and depreciation of property, issuance of securities and various other
matters. We must continue to provide bundled retail electric service to all who
choose to continue to take service at tariff rates, and we must provide
unbundled electric distribution services to all eligible customers as defined by
the Customer Choice Law at rates that must be approved by the ICC. During 2002,
the ICC ruled on (i) guidelines regarding standards of conduct and functional
separation for electric utilities; (ii) our residential electric delivery
service tariffs; and (iii) uniformity of the terms associated with residential
electric delivery service tariffs. During 2003, we expect the ICC will rule on
(i) proposed revisions to the current Market Value Index; (ii) determination
whether to continue to suspend the "neutral fact-finder" procedure; and (iii)
the proposed sale of our transmission assets. The impact of these regulations on
our financial condition and results of operations cannot be predicted with
certainty. Please see "Transmission and Distribution" above for more information
on item (iii) for 2003.

Following is a discussion of the actions taken by the Illinois State
legislature with respect to the deregulation of the State of Illinois electric
system.

9

P.A. 92-0537 - EXTENSION OF RETAIL ELECTRIC RATE FREEZE On June 6, 2002, the
Governor of Illinois signed a bill that adds two years to the current retail
electric rate freeze in Illinois. The bill extends through 2006 the mandatory
retail electric rate freeze, which was originally required by P.A. 90-561. P.A.
92-0537 freezes our rates for full service, or "bundled," electric service at
current levels unless the two-year average of our earned ROE is below the
two-year average of the Treasury Yield for the concurrent period, in which event
we may request a rate increase from the ICC. The ICC would rule on this request
for a rate increase using traditional ratemaking standards. As a result of the
retail rate freeze, our bundled service retail electric consumers are expected
to continue to pay their current electric rates for the next several years. The
rate freeze does not apply to our rates for distribution service to customers
choosing direct access. These rates are currently required to be based on cost
of service and can be raised or lowered subject to approval by the ICC.
Beginning in 2007, absent further extension of the retail electric rate freeze
or other action, we expect that the distribution and transmission component of
retail electric rates will continue to be required to be based on costs while
the energy component may be required to be based on costs or prices in the
wholesale market.

P.A. 90-561 - RATE ADJUSTMENT PROVISIONS P.A. 90-561 gave our residential
customers a 15% decrease in base electric rates beginning August 1, 1998. An
additional 5% decrease went into effect on May 1, 2002.

P.A. 90-561/92-0537 - UTILITY EARNINGS CAP The regulatory reform legislation
contains floor and ceiling provisions applicable to our ROE during the mandatory
transition period ending in 2006. Pursuant to the provisions in the legislation,
we may request an increase in our base rates if the two-year average of our
earned ROE is below the Treasury Yield. Conversely, we are required to refund
amounts to our customers equal to 50% of the value earned above a defined
"ceiling limit." The ceiling limit is exceeded if our two-year average ROE
exceeds the Treasury Yield, plus 8.5% in 2002 through 2006. In 2002, we filed to
increase the add-on to the Treasury Yield from 6.5% to 8.5%; as a result, we
waived our right to collect transition charges in 2007 and 2008. Regulatory
asset amortization is included in the calculation of the ROE for the ceiling
test but is not included in the calculation of the ROE for the floor test.
During 2002, our two-year average ROE was within the allowable ROE collar.

P.A. 90-561 - DIRECT ACCESS PROVISIONS Since October 1999, non-residential
customers with demand greater than 4 MW at a single site, customers with at
least 10 sites having aggregate total demand of at least 9.5 MW and customers
representing one-third of the remaining load in the non-residential class have
been given the right to choose their electric generation suppliers. This right,
which we refer to as direct access, was made available for remaining
non-residential customers beginning on December 31, 2000. Direct access became
available to all residential customers effective May 1, 2002. However, at the
present time, there are no Alternative Residential Electric Suppliers registered
to provide service to our residential customers. We remain obligated to provide
electric service to our customers at tariff rates and to provide delivery
service to our customers at regulated rates. Departing customers must pay
applicable transition charges to us, but those charges are not designed to
compensate us for all of our lost revenues.

Although residential rate reductions and the introduction of direct access
have led to lower electric service revenues, P.A. 90-561 is designed to protect
the financial integrity of electric utilities in three principal ways:

o Departing customers are obligated to pay applicable transition charges
based on the utility's lost revenue from that customer. The transition
charges are applicable through 2006.

o Utilities are provided the opportunity to lower their financing and
capital costs through the issuance of "securitized" bonds, also called
transitional funding trust notes.

o The ROE of utilities is managed through application of floor and
ceiling test rules contained in P.A. 90-561/92-0537 as described in the
"Utility Earnings Cap" section above.

The extent to which revenues are affected by P.A. 90-561 will depend on a
number of factors, including future market prices for wholesale and retail
energy and load growth and demand levels in the current IP service territory.
See "Illinois Electric Deregulation" above for more information.

10

P.A. 90-561 - ISO PARTICIPATION Participation in an ISO or RTO by utilities
serving retail customers in Illinois was one of the requirements included in
P.A. 90-561 and P.A. 92-12.

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

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

On May 28, 2002, we submitted a letter to the FERC indicating that we would
join PJM either as an individual transmission owner or as part of an independent
transmission company. On July 31, 2002, the FERC issued an order approving our
proposal to join PJM, subject to certain conditions. These conditions include a
requirement that (i) the parties negotiate and implement a rate design that will
eliminate rate pancaking between PJM and the MISO, and (ii) the North American
Electric Reliability Council oversee the reliability plans for the MISO and PJM.
In addition, the FERC has initiated an investigation under Federal Power Act
section 206 of the MISO, PJM West and PJM's transmission rates for through and
out service and revenue distribution. Subsequent to the July 31 order, the
parties were unable to negotiate a rate design that would eliminate rate
pancaking between PJM and the MISO and the FERC ordered a hearing on this
matter. The hearing has concluded, and an order from the Administrative Law
Judge and the FERC is expected by mid-year 2003. Although we are not currently
charging rates or collecting revenues through these entities, once we begin
operating under PJM, our transmission rates and revenues could be impacted by
the outcome of this proceeding.

While we have elected to join PJM, Trans-Elect, the party that has previously
agreed to purchase our transmission facilities, has elected to join the MISO
upon the closing of the proposed transmission sale. We expect to join the MISO
prior to or concurrent with the closing of the transmission sale, subject to
FERC approval.

SEASONALITY
-----------

Our electric and natural gas sales are affected by seasonal weather patterns.
Electricity sales are generally higher during the summer months when warm
weather typically requires air conditioner usage. Alternatively, gas sales are
generally higher in the winter months when cold weather typically requires
gas-fired heater usage. Consequently, our operating revenues and associated
operating expenses are not distributed evenly throughout the year.

SIGNIFICANT CUSTOMER
--------------------

No single customer accounted for greater than 10% of our consolidated revenues
during 2002, 2001 or 2000.

EMPLOYEES
---------

At December 31, 2002, we had 606 salaried employees and 1,275 bargaining unit
employees. We are subject to collective bargaining agreements with various
unions. We consider relations with both bargaining unit and salaried employees
to be satisfactory. Our collective bargaining agreements with 89% of our union
workforce expire on June 30, 2003. We are currently in negotiations to renew
these contracts. While we do not anticipate a work stoppage to result from these
negotiations, we are developing

11

contingency plans in the event that we are unsuccessful in the negotiations and
a work stoppage was to occur.

ITEM 2. PROPERTIES
- -------------------

We have included descriptions of the location and general character of our
principal physical operating properties above in "Item 1, Business." Those
descriptions are incorporated herein by this reference.

ITEM 3. LEGAL PROCEEDINGS
- --------------------------

For a description of our material legal proceedings, please read "Environmental
Matters" and "Other - Legal Proceedings" in "Note 6 - Commitments and
Contingencies" in the audited financial statements beginning on page F-17.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- ------------------------------------------------------------

No matter was submitted to a vote of security holders during the fourth quarter
of 2002.

PART II
-------

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- ------------------------------------------------------------------------------

All of our common stock is owned by our parent corporation, Illinova. With
respect to dividends on our common stock, payments to Illinova of $100 million
and $0.5 million were made in March of 2001 and 2002, respectively, as
authorized by the Board of Directors.

On March 28, 2002, we completed a solicitation of consents from our preferred
stockholders to amend our Restated Articles of Incorporation to eliminate a
provision that limited the amount of unsecured indebtedness that we could issue
or assume. Concurrently, Illinova completed a tender offer pursuant to which it
acquired 662,924 shares, or approximately 73%, of our preferred stock. The New
York Stock Exchange has delisted each of the series of preferred stock that were
subject to the tender offer and previously listed thereon. On March 29, 2002, we
amended our Restated Articles of Incorporation to eliminate the restriction on
incurring unsecured indebtedness. We paid approximately $1.3 million for charges
incurred in connection with the consent solicitation. These charges are
reflected as an adjustment to retained earnings in the accompanying Consolidated
Balance Sheets.

During 2001 and 2002, we have paid the required quarterly dividends on our
preferred stock as follows:

Cumulative Preferred Shares Quarterly Dividend Quarterly Dividend
Stock Series Outstanding Per Share Paid
------------ ----------- --------- ----

4.08% 225,510 $ 0.5100 $115,010
4.20% 143,760 $ 0.5250 75,474
4.26% 104,280 $ 0.5325 55,529
4.42% 102,190 $ 0.5525 56,460
4.70% 145,170 $ 0.5875 85,287
7.75% 191,765 $0.96875 185,772
--------
$573,532
========

12

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY PLANS
-----------------------------------------------------

We are an indirect, wholly owned subsidiary of Dynegy. None of our employees
receive compensation in the form of IP equity. However, there are compensation
plans with our employees, including stock option plans, pursuant to which our
employees can and do receive compensation in the form of options to purchase
Dynegy common stock. Please read Dynegy's Annual Report on Form 10-K for the
fiscal year ended December 31, 2002 for a discussion of the shares of Dynegy
common stock that are reserved for issuance pursuant to these plans. Please read
"Note 11 - Common Stock and Retained Earnings" in the accompanying audited
financial statements beginning on page F-27 for more information on these stock
option plans.

ITEM 6. SELECTED FINANCIAL DATA
- --------------------------------

The selected financial information presented below was derived from, and is
qualified by reference to, our Consolidated Financial Statements, including the
Notes thereto, contained elsewhere herein. The selected financial information
should be read in conjunction with the Consolidated Financial Statements and
related Notes and "Management's Discussion and Analysis of Financial Condition
and Results of Operations."

- ----------------------------------------------------------------------------------------------------------------------
S E L E C T E D F I N A N C I A L D A T A
(Millions of dollars)
2002 2001(4) 2000(4) 1999 1998
- ----------------------------------------------------------------------------------------------------------------------

Operating revenues
Electric $1,138.8 $1,137.1 $1,189.4 $1,178.6 $ 1,224.2
Electric interchange(1) 7.1 0.7 2.7 420.2 557.2
Gas 372.4 476.6 393.5 304.4 287.8
- ---------------------------------------------------------------------------------------------------------------------
Total operating revenues $1,518.3 $1,614.4 $1,585.6 $1,903.2 $ 2,069.2
- ---------------------------------------------------------------------------------------------------------------------
Net income (loss)(2) $ 160.7 $ 166.2 $ 134.9 $ 113.1 $(1,552.4)
Effective income tax rate 39.3% 41.4% 38.2% 38.7% 43.1%
- ---------------------------------------------------------------------------------------------------------------------
Net income (loss) applicable
to common stock(2) $ 158.4 $ 157.9 $ 121.0 $ 95.6 $(1,572.2)
Cash dividends declared on common stock 0.5 100.0 - 40.9 83.2
- ---------------------------------------------------------------------------------------------------------------------
Total assets $4,941.1 $4,861.1 $4,971.7 $5,297.8 $ 6,104.1
- ---------------------------------------------------------------------------------------------------------------------
Capitalization
Common stock equity $1,366.2 $1,221.9 $1,156.3 $1,035.2 $ 892.2
Preferred stock 45.8 45.8 45.8 45.8 57.1
Mandatorily redeemable preferred stock - - 100.0 193.4 199.0
Long-term debt 1,718.8 1,605.6 1,787.6 1,906.4 2,158.5
- ---------------------------------------------------------------------------------------------------------------------
Total capitalization $3,130.8 $2,873.3 $3,089.7 $3,180.8 $ 3,306.8
- ---------------------------------------------------------------------------------------------------------------------
Retained earnings $ 390.2 $ 233.6 $ 175.7 $ 54.7 $ -
- ---------------------------------------------------------------------------------------------------------------------
Capital expenditures $ 144.5 $ 148.8 $ 157.8 $ 197.2 $ 311.5
Cash flows from operations $ 209.4 $ 345.0 $ 381.3 $ 85.8 $ 313.3
Ratio of earnings to fixed charges(3) 3.30 3.25 2.53 2.16 N/A
=====================================================================================================================

(1) Interchange sales volumes are not comparable year to year due to the
October 1999 transfer of our generation assets. Please read "Note
5 - Related Parties" beginning on page F-16 in the accompanying audited
financial statements for more information.

(2) Please read "Note 1 - Summary of Significant Accounting Policies"
beginning on page F-8 in the accompanying audited financial statements
for a discussion of our quasi-reorganization effective December
31, 1998.

(3) For 1998, the earnings are inadequate to cover fixed charges.
Additional earnings of $2,734,102 are required to attain a one-to-one
ratio of earnings to fixed charges.

(4) The consolidated financial statements for the years ended December 31,
2001 and 2000 were

13

audited by other independent accountants who have ceased operations.
Please read "Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure" beginning on page 31 and "Report
of Independent Public Accountants" on page F-3 in the accompanying
audited financial statements.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- --------------------------------------------------------------------------------
OF OPERATIONS
- -------------

GENERAL - COMPANY PROFILE
-------------------------

We are engaged in the transmission, distribution and sale of electric energy and
the distribution, transportation and sale of natural gas in the State of
Illinois. We provide electric and natural gas service to residential, commercial
and industrial customers in substantial portions of northern, central and
southern Illinois. Our service territory includes 11 cities with populations
greater than 30,000 and 37 cities with populations greater than 10,000 (2000
U.S. Census Bureau's Redistricting Data). We also currently supply electric
transmission service to numerous utilities, electric cooperatives,
municipalities and power marketing entities in the State of Illinois. As
described above, we have previously announced an agreement to sell our electric
transmission system. Please read Item 1, Business, "Transmission and
Distribution" beginning on page 4 for further discussion.

We are an indirect, wholly owned subsidiary of Dynegy Inc. Dynegy acquired
our direct parent company, Illinova, and its subsidiaries, including us, in
February 2000. Dynegy is currently restructuring itself in response to various
events that have negatively impacted it, and the energy industry, over the past
year. In the restructured Dynegy, our operations comprise one of three operating
divisions. 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 a $2.3 billion intercompany note receivable from
Illinova, our direct parent company and a wholly owned Dynegy subsidiary ("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" beginning on page 15 for further discussion.

We were a leader in the development of the comprehensive electric utility
regulatory reform legislation for the State of Illinois, which provided the
foundation for our subsequent strategic actions and transformation. Following
the successful execution of our strategy to transfer our wholly owned generating
assets to an unregulated affiliate and to exit our nuclear operations, we are
now focused on delivering reliable transmission and distribution service in a
cost-effective manner.

LIQUIDITY AND CAPITAL RESOURCES
-------------------------------

OVERVIEW
- ---------

We have a significant amount of leverage, with near-term maturities including a
$100 million payment on our one-year term loan due in May 2003, $190 million in
aggregate mortgage bond maturities due in August and September 2003 and
quarterly payments of approximately $21.6 million due on our transitional
funding trust notes. We are required to make these same quarterly payments of
approximately $21.6 million on our transitional funding trust notes through
2008, and we have a payment of up to $81 million due on our Tilton off-balance
sheet lease financing in the third quarter 2004. Because we have no revolving
credit facility and no access to the commercial paper markets, we rely on cash
on hand, cash from liquidity initiatives and cash flows from operations,
including interest payments under our Note Receivable from Affiliate to satisfy
our debt obligations and to otherwise operate our business. We will use the
remaining cash proceeds from our December 2002 $550 million Mortgage bond
offering to pay off our term loan and to pay a substantial portion of our
August and September 2003 mortgage bond maturities. In addition to this source
of liquidity, we believe that we have sufficient capital resources through cash
flow from operations, proceeds from one or more additional liquidity
initiatives, including new bank borrowings or mortgage bond

14

issuances and, if necessary, additional liquidity support which has been
committed by Dynegy to pay the remainder of these maturities and to otherwise
satisfy our obligations over the next twelve months. Please read "--Credit
Capacity, Liquidity and Debt Maturities---Debt Maturities and Liquidity Plan--"
beginning on page 15 for further discussion.

OUR RELATIONSHIP WITH DYNEGY
- ----------------------------

We are an indirect, wholly owned subsidiary of Dynegy Inc. Due to our
relationship with Dynegy, adverse developments or announcements concerning
Dynegy have affected and could continue to affect our ability to access the
capital markets and to otherwise conduct our business. Effects in 2002 included
a significant reduction in our credit ratings, resulting in the termination of a
July 2002 mortgage bond offering and increased collateralization requirements.
We are particularly susceptible to developments at Dynegy because we rely on an
unsecured Note Receivable from Affiliate for a substantial portion of our net
cash provided by operating activities. This Note Receivable from Affiliate
relates to the transfer of our former fossil-fueled generating assets. The note
matures on September 30, 2009 and bears interest at an annual rate of 7.5%, due
semiannually in April and October. At December 31, 2002 and 2001, principal
outstanding under the note approximated $2.3 billion. At December 31, 2002,
accrued interest approximated $14.2 million, while December 31, 2001 reflected
no accrued interest.

We have reviewed the collectibility of this note to assess whether it has
become impaired under the criteria of FAS 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 read "--Critical Accounting Policies" below for further
discussion as to applicable GAAP regarding impairment of the loan. While we
believe that the note is not impaired and is fully collectible in accordance
with its contractual terms based upon, among other things, our review of
Dynegy's restructuring plan and the results of various analyses that we have
performed as to the value of Dynegy's assets relative to its outstanding debt,
we expect to continue to review the collectibility of the note on a quarterly
basis. Principal payments on the note are not required until 2009 when it is due
in full; as a result, future events may affect our view as to the collectibility
of the remaining principal owed us under the note. As further discussed in "Note
1 - Summary of Significant Accounting Policies" to the consolidated financial
statements, while the fair value of the Note Receivable from Affiliate, based on
quoted market prices for Dynegy's publicly traded unsecured debt securities at
December 31, 2002 was significantly less than $2.3 billion, our collectibility
analysis under FAS 114 indicates that the note was not impaired. Accordingly, we
have reflected the note on our December 31, 2002 Consolidated Balance Sheet at
$2.3 billion. It is possible that if negative events affect Dynegy or if we do
not receive timely interest payments on the Note Receivable from Affiliate, such
matters could cause us to believe it necessary to impair the Note Receivable
from Affiliate on our Consolidated Balance Sheet and such action could have a
material adverse affect on our liquidity, financial condition and results of
operations.

CREDIT CAPACITY, LIQUIDITY AND DEBT MATURITIES
- ----------------------------------------------

SOURCES OF LIQUIDITY We are currently satisfying our capital requirements
primarily with cash from operations, cash from financing activities, cash on
hand and interest payments under our $2.3 billion Note Receivable from
Affiliate.

On December 20, 2002, we sold $550 million of 11 1/2% Mortgage bonds due 2010
in a private offering. Of the $550 million, we issued $400 million in December
2002, with $150 million issued on a delayed delivery basis subject to ICC
approval, which we received in January 2003. The mortgage bonds were sold at a
discounted price of $97.48 to yield an effective rate of 12%. We received net
cash proceeds of approximately $380 million in December 2002 and approximately
$142.5 million in January 2003 from this offering.

One of our liquidity initiatives could include an issuance of mortgage bonds.
Under our 1992 Mortgage, we generally are able to issue debt secured by the
mortgage provided that (a) our "adjusted net earnings"

15

are at least two times our "annual interest requirements," and (b) the aggregate
amount of indebtedness secured by the mortgage does not exceed three-quarters of
the original cost of the property secured by the lien of the mortgage, reduced
to reflect property that has been retired or sold. We also generally can issue
mortgage bonds under our 1992 Mortgage in exchange for repurchased and retired
indebtedness. An additional test was added with the issuance of the December
2002 mortgage bonds. The test states that in order to issue additional mortgage
bonds, the Fixed Charge Coverage Ratio for our most recently ended four full
fiscal quarters for which internal financial statements are available must be
greater than 2.0 to 1, determined on a pro forma basis (including a pro forma
application of the net proceeds), as if the additional indebtedness had been
incurred at the beginning of such four-quarter period. Based on our December 31,
2002 financial statements, we could issue $82 million in mortgage bonds under
our 1992 Mortgage. The calculation for 2002 reflects the entire $550 million
debt issuance effective December 2002.

We also have the ability to cause the issuance by a related special purpose
trust, subject to ICC approval, of up to $864 million in additional transitional
funding trust notes pursuant to the Illinois Electric Utility Transitional
Funding Law. However, under the supplemental indenture we executed in connection
with the issuance of our 11 1/2% Mortgage bonds due 2010, we could be required
to redeem these bonds if we were to issue more than $300 million of transitional
funding trust notes. There were approximately $518.4 million in transitional
funding trust notes outstanding at December 31, 2002, the principal and interest
of which is to be repaid quarterly with cash set aside from customer billings.
As a result of our consolidation of the related special purpose trust, the cash
set aside from these customer billings is included in revenues on our
Consolidated Statement of Income and Comprehensive Income and the transitional
funding trust notes are accounted for as long-term debt on our Consolidated
Balance Sheet. However, the cash set aside from these customer billings is owned
by the special purpose trust that issued the transitional funding trust notes,
is dedicated solely to the debt service obligations on the transitional funding
trust notes and is not otherwise available to service our other debt
obligations.

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 operating cash flows will be dedicated to the payment of principal and
interest on our outstanding indebtedness, including the transitional funding
trust notes, and will not be available for other purposes. Second, our ability
to obtain additional financing for working capital, capital expenditures,
general corporate and other purposes is limited. Given these facts, we expect to
rely primarily upon cash from operations, cash on hand, cash from liquidity
initiatives, interest payments under our $2.3 billion Note Receivable from
Affiliate or, as necessary, additional liquidity support which has been
committed by Dynegy to meet our near-term obligations.

CREDIT CAPACITY On May 17, 2002, we exercised the "term-out" provision
contained in our $300 million 364-day revolving credit facility, which was
scheduled to mature on May 20, 2002. In connection with this conversion, we
borrowed the remaining $60 million available under this facility. The exercise
of the "term-out" provision converted the facility to a one-year term loan that
matures in May 2003. In December 2002, we used a portion of the proceeds from
our $550 million Mortgage bond offering to repay $200 million on this loan.
Borrowings of $100 million were outstanding at December 31, 2002.

As described above, our lack of a revolving credit facility could affect our
future operations. Our ability to meet debt service obligations and reduce total
indebtedness will be dependent upon our future operating performance and the
other factors described herein.

USES OF LIQUIDITY On July 15, 2002 we repaid $95.7 million of mortgage bonds
at maturity. We made this repayment with $85.2 million of prepaid interest on
the Note Receivable from Affiliate and $10.5 million of working capital.

We used a portion of the net proceeds from our December 2002 $550 million
Mortgage bond offering to replenish liquidity used to repay our $95.7 million
Mortgage bonds at maturity. We also repaid $200 million of the $300 million term
loan due in May 2003.

16

DEBT MATURITIES AND LIQUIDITY PLAN As of December 31, 2002, our debt
maturities through December 31, 2005 were as follows (millions of dollars):

We will use the remaining cash proceeds from our December 2002 $550 million
mortgage bond offering to pay off the remaining $100 million owed under our
one-year term loan and to pay a substantial portion of our $190 million in
aggregate mortgage bond maturities due in August and September 2003. In addition
to this source of liquidity, we believe that we have sufficient capital
resources through cash flow from operations, proceeds from one or more
additional liquidity initiatives, including new bank borrowings or mortgage bond
issuances and, if necessary, additional liquidity support which has been
committed by Dynegy to pay the remainder of these maturities and to otherwise
satisfy our obligations over the next twelve months, including the additional
interest expense that we expect as a result of our recent issuance of $550
million of Mortgage bonds at an effective 12% interest rate. Although Dynegy's
recently restructured credit facility, which expires in February 2005, prohibits
it from prepaying more than $200 million in principal under our Note Receivable
from Affiliate during the term of the credit agreement, it does not limit
Dynegy's ability to prepay interest under the Note Receivable from Affiliate.

Our execution of one or more of these initiatives is subject to a number of
risks. The risks include, among others, the ability to successfully negotiate a
new revolving credit facility and the effects of our relationship with Dynegy.
You are encouraged to read Dynegy's Annual Report on Form 10-K for the year
ended December 31, 2002 for additional information regarding Dynegy and its
current liquidity position. Please see "Our Relationship with Dynegy" above for
further discussion.

AFFILIATE TRANSACTIONS On October 23, 2002, the ICC issued an order approving
a netting agreement among us, Dynegy, Illinova and several other Dynegy
subsidiaries. Under the netting agreement, we can discharge and satisfy payments
due to the other parties to the netting agreement under a Services and
Facilities Agreement, or for natural gas and transportation services, by
offsetting and netting such payments due against interest due us, but unpaid,
under our intercompany note with Illinova, or amounts billed by us to, or owed
to us by, the other parties under certain other agreements. Similarly, Illinova
would be entitled to discharge and satisfy semiannual interest payments due to
us under the intercompany note, and for other services, by

17

offsetting and netting such payments due us against amounts billed to us but
unpaid under the Services and Facilities Agreement, which includes tax sharing
provisions between us and Dynegy, or for natural gas and transportation
services.

The netting agreement does not, however, give us a right to offset our
payments owed under the power purchase agreement with DMG against the payments
due us from Dynegy or its affiliates. Additionally, we may not pay any common
dividend to Dynegy or its affiliates until our mortgage bonds are rated
investment grade by Moody's and Standard & Poor's and specific approval for such
payment is obtained from the ICC. The ICC also approved our request, subject to
certain conditions, to advance funds to service interest on Illinova's senior
notes in February 2003 if Dynegy would have not been able to make such interest
payments and to repurchase our preferred stock held by Illinova in order to
provide funds to pay interest on Illinova's senior notes due in August 2003 and
February 2004 if Dynegy is unable to make such interest payments. The amount of
each of these three scheduled interest payments is approximately $3.6 million.

Please read "--Our Relationship with Dynegy" for discussion of our Note
Receivable from Affiliate.

OFF-BALANCE SHEET FINANCING In September 1999, we entered into an $81 million
operating lease on four gas turbines located in Tilton, Illinois. These
facilities consist of peaking units with capacity of 176 MW. The lease runs
until September 2004, with an option to renew for two additional years. In
October 1999, we subleased the turbines to DMG. We are providing a minimum
residual value guarantee on the lease of approximately $69.6 million. At the
expiration of the lease agreement we have the option to purchase or sell the
turbines to terminate the lease, with any shortfall between the purchase or sale
price and the minimum residual value to be paid by us. We may also be liable for
retiring the assets in place or dismantling them for sale and delivery to a
third party if we do not exercise our option to purchase the assets or
renegotiate the lease. At the expiration of the land lease, we may have the
obligation to restore the property to its original condition.

The following table sets forth our lease expenses and lease payments
(millions of dollars) relating to the Tilton facility for the periods presented.

Pursuant to the sublease of these facilities, DMG is reimbursing us for the
lease payments and expense.

We have determined that we have Asset Retirement Obligations ("ARO") related
to the operating lease and the related land lease for the Tilton facilities upon
adoption of FAS 143 "Accounting for Asset Retirement Obligations." For further
information regarding FAS 143, please read "Note 1 - Summary of Significant
Accounting Policies" in the accompanying audited financial statements beginning
on page F-8.

We are currently evaluating the impact, if any, FIN 46 "Consolidation of
Variable Interest Entities - an Interpretation of ARB No. 51", may have on this
obligation. For further information on FIN 46, please refer to "Note 1 -
Summary of Significant Accounting Policies" in the accompanying audited
financial statements beginning on page F-8.

FINANCIAL OBLIGATIONS AND COMMERCIAL COMMITMENTS We have entered into various
financial obligations and commitments in the course of our ongoing operations
and financing strategies. Financial obligations are considered to represent
known future cash payments that we are required to make under existing
contractual arrangements, such as debt and lease agreements. These obligations
may result from general financing activities, as well as from commercial
arrangements that are directly supported by related revenue-producing
activities. Financial commitments represent contingent obligations that become
payable only if certain pre-defined events were to occur, such as funding
financial guarantees.

18

The following table provides a summary of our financial obligations and
commercial commitments as of December 31, 2002 (millions of dollars). This table
includes cash obligations related to principal outstanding under existing debt
arrangements, decommissioning charges, operating leases and unconditional
purchase obligations.

FINANCIAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

*Cash obligations herein are not discounted and do not include related interest
or accretion.

(1) Aggregate principal outstanding under our mortgage bonds approximated $1.5
billion at December 31, 2002, bearing interest ranging from 3.35% to 11 1/2% per
annum. We have mortgage bond issues of $100 million maturing in August 2003, $90
million maturing in September 2003 and $70 million maturing in March 2005.

(2) Reflects the balance of $864 million of Transitional Funding Trust Notes
issued by IPSPT in December 1998 as allowed under the Illinois Electric Utility
Transition Funding Law in P.A. 90-561. Per annum interest on these notes
averages approximately 5.50%. We are retiring the principal outstanding under
these notes through quarterly payments of $21.6 million through 2008.

(3) On May 17, 2002, we exercised the "term-out" provision contained in our $300
million 364-day revolving credit facility, which was scheduled to mature on May
20, 2002. In connection with this conversion, we borrowed the remaining $60
million available under this facility. The exercise of the "term-out" provision
converted the facility to a one-year term loan that matures in May 2003. In
December we repaid $200 million on this loan. Borrowings of $100 million were
outstanding at December 31, 2002.

(4) Reflects decommissioning charges associated with our former Clinton
facility. See "Note 1 - Summary of Significant Accounting Policies" on page F-10
in the audited financial statements included herein for additional information.

(5) Reflects decontamination and decommissioning charges associated with our use
of a DOE facility that enriched uranium for the Clinton Power Station. We were
assessed an amount to be paid over fifteen years that would be used to pay for
DOE's decontamination and decommissioning of its facility. Our final payment is
due in 2006.

(6) Reflects an unconditional power purchase obligation between us and DMG,
another Dynegy affiliate. The agreement requires us to compensate the affiliate
for capacity charges over the next two years at a total contract cost of $639.6
million. We also have contracts on six interstate pipeline companies for firm
transportation and storage services for natural gas. These contracts have
varying expiration dates ranging from 2003 to 2012, for a total cost of $80.6
million. We also enter into obligations for the reservation of natural gas
supply. These obligations generally range in duration from one to twelve months
and require us to compensate the provider for capacity charges. The cost of the
agreements is $20.7 million. The costs associated with these contracts are a
component of our revenue requirements under our ratemaking process.

(7) Our primary operating leases reflected above relate to our material
distribution facility, Tilton facility and a lease on 15 line trucks. The
material distribution facility is a commercial property lease for our storage
warehouse that expires in 2009 and has a remaining lease cost of $3.9 million.
The lease on 15 line trucks expires in 2009 and has a remaining lease cost of
$1.5 million. The remaining leases included in this line relate to copiers, fax
machines, small equipment and a building lease.

(8) The Tilton off-balance sheet lease financing is subleased to DMG, and we
satisfy our contractual obligations under this arrangement with payments we get
from DMG. Lease payments total $8.2 million for the facility lease ending
September 2004 and a land lease ending October 2028.

19

CONTINGENT FINANCIAL OBLIGATIONS The following table provides a summary of our
contingent financial commitments as of December 31, 2002 (millions of dollars).
These commitments represent contingent obligations that may require a payment of
cash upon certain pre-defined events.

CONTINGENT FINANCIAL COMMITMENTS AS OF DECEMBER 31, 2002

*Cash obligations herein are not discounted and do not include related interest
or accretion.

(1) Surety bonds are on a rolling twelve-month basis.

(2) According to the PPA agreement 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 and is not
reflected in the above table.

(3) Amounts include the $69.6 million residual value guarantee related to the
Tilton off-balance sheet lease arrangement. Based on the estimated fair value of
the underlying assets, we do not anticipate funding such amounts.

FIN 45 "Grantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others" requires that upon
issuance of a guarantee, the guarantor must recognize a liability for the fair
value of the obligation it assumes under that guarantee, and is effective for
guarantees issued or modified after December 31, 2002. We have provided the
required disclosure with respect to our guarantees where appropriate in the
Notes to Consolidated Financial Statements. We do not expect the adoption of FIN
45 to have a material effect on our financial position or results of operations.

CREDIT RATINGS DISCUSSION Credit ratings impact our ability to obtain
short-term and long-term financing, the cost of such financing and the execution
of our commercial strategies in a cost-effective manner. In determining credit
ratings, the rating agencies consider a number of factors. Quantitative factors
that management believes are given significant weight include, among other
things, earnings before interest, taxes, and depreciation and amortization
("EBITDA"); operating cash flow; total debt outstanding; off-balance sheet
obligations and other commitments; fixed charges such as interest expense, rent
or lease payments; payments to preferred stockholders; liquidity needs and
availability; and various ratios calculated from these factors. Qualitative
factors appear to include, among other things, predictability of cash flows,
business strategy, industry position, quality of management, equity value,
litigation, regulatory investigations and other contingencies. In determining
our credit ratings, the rating agencies also consider the liquidity position and
credit ratings of Dynegy, our indirect parent company. Although these factors
are among those considered by the rating agencies, each rating agency may
calculate each factor differently.

Our credit ratings were lowered several times during 2002 by each of the
major credit rating agencies. In taking these actions, the rating agencies
generally cited concerns over, among other things, the large intercompany loan
and the structural and functional ties between affiliated companies including
Dynegy, our ability to address near-term debt maturities and the likelihood that
we will be able to renew our credit facility maturing in May 2003. We rely on
payments under a $2.3 billion Note Receivable from Affiliate for a large portion
of our operating cash flows. Most recently, on March 10, 2003, Fitch lowered its
ratings on Dynegy and us, indicating that the downgrades anticipated the
successful renewal and restructuring on a secured basis of Dynegy's maturing
credit facilities. Currently, our credit ratings are at least six notches below
investment grade at Standard & Poor's, Moody's and Fitch. Additionally, our
ratings remain on negative watch for further downgrade by both Standard & Poor's
and Fitch; Moody's currently rates us with a negative outlook.

20

As of March 31, 2003, our credit ratings, as assessed by the three major
credit rating agencies, were as follows:

* Not rated

Our non-investment grade status has limited our ability to refinance our debt
obligations as they mature and limits our access to the capital markets. Our
non-investment grade status also will likely increase the borrowing costs
incurred in connection with any such actions. Our financial flexibility has
likewise been reduced as a result of, among other things, restrictive covenants
and other terms typically imposed on non-investment grade borrowers. For a
description of the restrictions included in our recently issued 11 1/2% Mortgage
bonds, please read "Note 9 - Long-Term Debt", beginning on page F-24 in the
accompanying audited financial statements. We have been requested to provide
letters of credit or other credit security to support certain business
transactions, including our purchase of natural gas and natural gas
transportation. As of December 31, 2002, Dynegy posted $29 million in letters of
credit in support of these transactions. Additionally, in July 2002, some of our
suppliers began to require us to accelerate payment for some of our natural gas
purchases. Further downgrades would be expected to result in increased
requirements for collateral or accelerated payments.

DIVIDENDS There are restrictions on our ability to pay cash dividends,
including any dividends that we might pay indirectly to Dynegy. Under our
Restated Articles of Incorporation, we may pay dividends on our common stock,
all of which is owned by Illinova, subject to the preferential rights of the
holders of our preferred stock, of which Illinova owns approximately 73%. We
also are limited in our ability to pay dividends by the Illinois Public
Utilities Act and the Federal Power Act, which require retained earnings equal
to or greater than the amount of any proposed dividend. We paid common stock
dividends of $0.5 million and $100.0 million to Illinova in March of 2002 and
2001, respectively. Additionally, the ICC's October 23, 2002 order relating to a
netting agreement between us and Dynegy prohibits us from declaring and paying
any dividends on our common stock until such time as our mortgage bonds are
rated investment grade by both Moody's and Standard & Poor's and further
requires that we first obtain approval for any such payment from the ICC.

The ICC's October 2002 order authorized us to provide funds to Illinova to
enable it to make interest payments due in February and August 2003 and February
2004 on its senior notes, but only if and only to the extent that Illinova is
unable to obtain the necessary funds from Dynegy or another source. The amount
of each of these three scheduled interest payments is approximately $3.6
million. The February 2003 interest payment on Illinova's senior notes was made
by Illinova as scheduled. With respect to the August 2003 and February 2004
interest payments, the ICC order authorizes us to provide funds to Illinova by
repurchasing shares of our 7.75% series $50 par value preferred stock, which is
callable in whole or in part at any time after July 1, 2002. Illinova holds
approximately 95% of the shares of our 7.75% series preferred stock. The payment
of any such amounts would reduce the amounts available to us for general
corporate purposes or to satisfy our debt service or other obligations as they
become due.

CAPITAL EXPENDITURES Construction expenditures for 2002 were approximately
$144.5 million. Construction 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. Our construction expenditures for 2003 through 2007 are
expected to total approximately $140 million per year. Additional expenditures
may be required during this period to accommodate the transition to a
competitive environment, environmental compliance, system upgrades and other
costs that cannot be determined at this time. Please see "Note 4 - Transmission
Sale", beginning on page F-16 in the audited financial statements
included herein for more information on our potential sale of our high-voltage
electric transmission assets.

21

FACTORS AFFECTING FUTURE OPERATING RESULTS
------------------------------------------

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

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

o our ability to receive proceeds from one or more liquidity initiatives,
including new bank borrowings or mortgage bond issuances;

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

o our ability to receive interest payments under our Note Receivable from
Affiliate and to otherwise receive continued performance under our
arrangements with Dynegy;

o our ability to execute a sale transaction relating to our transmission
assets;

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

o our ability to maintain or improve our credit ratings;

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

o our ability to secure power and natural gas for our electric and gas
customers.

Reference is also made to the section "Uncertainty of Forward-Looking
Statements and Information" below for additional factors that could impact our
future operating results.

CRITICAL ACCOUNTING POLICIES
----------------------------

Our Accounting Department is responsible for the development and application of
accounting policy and control procedures for the organization's financial and
operational accounting functions. This department conducts its activities
independent of any active management of risk exposures confronting the
enterprise, is independent of revenue producing units and reports to the Chief
Executive Officer.

We have identified the following critical accounting policies, which require
a significant amount of judgment and are considered to be the most important to
the portrayal of our financial position and results of operations:

o revenue recognition, including developing estimates of unbilled
revenue,

o the accounting for long-lived assets, including analyzing assets for
impairment,

o note receivable from affiliate,

o regulatory asset amortization,

o valuation of pension assets and liabilities, and

o accounting for income taxes.

REVENUE RECOGNITION Revenues for utility services are recognized when services
are provided to customers. As such, we record revenues for services provided but
not yet billed. Unbilled revenues represent the estimated amount customers will
be billed for service delivered from the time meters were last read to the end
of the accounting period.

LONG-LIVED ASSETS The cost of additions to plant and replacements for retired
property units is capitalized. Cost includes labor, materials, and an allocation
of general and administrative costs, plus AFUDC or capitalized interest as
described below. Maintenance and repairs, including replacement of minor items
of property, are charged to maintenance expense as incurred. When depreciable
property units are retired, the original cost and dismantling charges, less
salvage value, are charged to accumulated depreciation.

The FERC Uniform System of Accounts defines AFUDC as the net costs for the
period of construction of borrowed funds used for construction purposes and a
reasonable rate on other funds when so used. AFUDC is capitalized as a component
of construction work in progress in applying the provisions of FAS 71,
"Accounting for the Effects of Certain Types of Regulation." In 2002, 2001 and
2000, the pre-tax rate used for

22

all construction projects was 2.9%, 4.8% and 6.8%, respectively. Although cash
is not currently realized from AFUDC, it is realized through the ratemaking
process over the service life of the related property through increased revenues
resulting from a higher rate base and higher depreciation expense.

In connection with our adoption of FAS 143 on January 1, 2003, in order to
ascertain whether a legal obligation exists associated with the retirement of
our long-lived assets, we identified all facilities and their assets by
functional classification. We reviewed those assets for obligations that may
have resulted from enacted laws, state and federal regulation, ordinances,
written and oral contracts and other applications of law. Two AROs have been
identified in connection with our off-balance sheet operating lease agreement
for four gas turbines and a separate land lease at the Tilton site. The turbine
assets are subleased to DMG; however we remain the primary obligor. We may be
liable for retiring the assets in place or dismantling them for sale and
delivery to a third party if we do not exercise our option to purchase the
assets or renegotiate the lease. At the expiration of the land lease, we may
have the obligation to restore the property to its original condition. The AROs
were calculated based on cash flows through a process that included assessment
of the timing of future retirements, the retirement method and estimated cost,
the credit-adjusted risk-free rate and development of other significant
assumptions. The credit-adjusted risk-free rate utilized was 12%, which
represents the effective interest rate on our mortgage bonds that were issued
December 2002. Upon adoption, the cumulative effect net of the associated income
taxes was approximately $2.4 million. The ARO liability for the asset operating
lease and the land lease, to be recorded during the first quarter 2003, is $5.8
million. Amortization and accretion expense for 2003 is expected to be
approximately $1.2 million.

Rate regulated companies subject to FAS 71 are allowed to record the
estimated cost of removal and salvage associated with utility plant in the
reserve for depreciation. These amounts are recorded through a composite
depreciation rate. The amounts accrued in the reserve for depreciation are not
associated with Asset Retirement Obligations in accordance with FAS 143, which
we adopted January 1, 2003. We estimate that as of the date of adoption,
approximately $68.7 million of cost of removal, net of salvage, allowed under
rate regulation is included in the depreciation reserve for utility plant.

NOTE RECEIVABLE FROM AFFILIATE As described above, we hold a $2.3 billion Note
Receivable from Affiliate. We review the collectibility of this note on a
quarterly basis to assess whether it has become impaired under the criteria of
FAS 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. However, if the
possibility that we would not be able to collect all amounts due under the
contractual terms were only "more likely than not" or "reasonably possible" but
not probable, then the Note Receivable from Affiliate would not be considered
impaired under FAS 114. The use of the terms "probable," "reasonably
possible" and "more likely than not" are used in FAS No. 5, "Accounting for
Contingencies," as follows:

o Reasonably possible - The chance of the future event or events
occurring is more than remote but less than likely.

o More likely than not - A level of likelihood that is more than 50%.

o Probable - Future events are likely to occur.

As further discussed in "Note 1 - Summary of Significant Accounting Policies"
in the consolidated financial statements, while the fair value of the Note
Receivable from Affiliate, based on quoted market prices for Dynegy's publicly
traded unsecured debt securities at December 31, 2002 was significantly less
than $2.3 billion, our collectibility analysis under FAS 114 indicates that the
note was not impaired. Accordingly, we have reflected the note on our December
31, 2002 Consolidated Balance Sheet at $2.3 billion.

A collectibility assessment in accordance with FAS 114 is highly subjective
given the inherent uncertainty of predicting future events, and principal
payments on the Note Receivable from Affiliate are not required until 2009 when
it is due in full. We will evaluate that range of likelihood of collectibility
of the Note Receivable from Affiliate on a quarterly basis. In the future,
should we conclude an impairment has occurred, we would measure the note's
realizable value based on a probability weighted analysis of multiple expected
future cash flows discounted at the note's effective interest rate of 7.5%, as
opposed to a market rate of interest, in accordance with FAS 114.

23

REGULATORY ASSET AMORTIZATION P.A. 90-561 allows utilities to recover
potentially non-competitive investment costs ("stranded costs") from retail
customers during the transition period, which extends until December 31, 2006.
During this period, we are allowed to recover stranded costs through frozen
bundled rates and transition charges from customers who select other electric
suppliers. In May 1998, the SEC Staff issued interpretive guidance on the
appropriate accounting treatment during regulatory transition periods for asset
impairments and the related regulated cash flows designed to recover such
impairments. The Staff's guidance established that an impaired portion of plant
assets identified in a state's legislation or rate order for recovery through
regulated cash flows should be treated as a regulatory asset in the portion of
the enterprise from which the regulated cash flows are derived. Based on this
guidance and on provisions of P.A. 90-561, we recorded a regulatory asset of
$457.3 million in December 1998 for the portion of our stranded costs deemed
probable of recovery during the transition period. Subsequent adjustments
related to the sale of the Clinton Power Station reduced the regulatory asset by
$115.9 million to $341.4 million. The amount of amortization recorded in each
period is based on the recovery of such costs from rate payers as measured by
our ROE, based on actual and projected recovery of such costs. The transition
period cost recovery asset amortization was $70.5 million in 2002, $47.4 million
in 2001, and $47.5 million in 2000. The increase in amortization of the
transition period cost recovery regulatory asset for 2002 is due to increased
financial performance, which allowed us to recognize additional regulatory
asset amortization and stay within the allowable ROE collar.

VALUATION OF PENSION ASSETS AND LIABILITIES Our employees participate in
defined benefit pension plans sponsored by Dynegy Inc. The values and discussion
below represent the components of the Dynegy benefit plans that were sponsored
by us prior to the merger. Plan participants include Illinova employees as of
February 1, 2000 as well as our employees and employees of DMG hired subsequent
to the merger. We are reimbursed by the other Illinova subsidiaries (prior to
the merger) and by other Dynegy subsidiaries (subsequent to the merger) for
their share of the expenses of the benefit plans. Please see "Note 12 - Employee
Compensation, Savings and Pension Plans" in the audited financial statements on
page F-29 included herein for more information.

Our pension and postretirement benefit costs are developed from actuarial
valuations. Inherent in these valuations are key assumptions provided by us to
our actuaries, including the discount rate and expected long-term rate of return
on plan assets. Material changes in our pension and postretirement benefit costs
may occur in the future due to changes in these assumptions, changes in the
number of plan participants, and changes in the level of benefits provided.

The discount rate is subject to change each year, consistent with changes in
applicable high-quality, long-term corporate bond indices. Long-term interest
rates declined during 2002, and as such, at December 31, 2002, we used a
discount rate of 6.5%, a decline of 100 basis points from the 7.5% rate used as
of December 31, 2001. This decline in the discount rate had the impact of
decreasing the funded status of our pension plans by approximately $67 million.

The expected long-term rate of return on pension plan assets is selected by
taking into account the expected duration of the projected benefit obligation
for the plans, the asset mix of the plans, and the fact that the plan assets are
actively managed to mitigate downside risk. Based on these factors, our expected
long-term rate of return as of December 31, 2002 is 9%, compared with the actual
return on assets of 9.47% for the year ended December 31, 2001. The reduction is
primarily due to the decline in the rate of return on pension assets through
2002. This change did not impact 2002 pension expense, but it will adversely
impact pension expense beginning in 2003. We expect the decrease in this
assumption, coupled with the decreased discount rate discussed above, will
decrease our pension gain by approximately $13.6 million over the 2002 gain.

On December 31, 2002, our annual measurement date, the accumulated benefit
obligation related to our pension plans exceeded the fair value of the pension
plan assets (such excess is referred to as an unfunded accumulated benefit
obligation). This difference is attributed to (1) an increase in the accumulated
benefit obligation that resulted from the decrease in the discount rate and the
expected long-term rate of return and (2) a decline in the fair value of the
plan assets due to a sharp decrease in the equity markets through

24

December 31, 2002. As a result, in accordance with FAS No. 87, "Employers'
Accounting for Pensions", we recognized a charge to other comprehensive income
of $22.2 million ($13.4 million after-tax), which decreased common stock equity.
The charge to common stock equity for the excess of additional pension liability
over the unrecognized prior service cost represents a net loss not yet
recognized as pension expense.

We expect to have minimal, if any, cash requirements related to our pension
plans during 2003. However during 2004, it is likely that contributions will be
required for the Dynegy-sponsored plans covering our employees. Although it is
difficult to estimate these potential cash requirements due to uncertain market
conditions, we currently expect that cash requirements for these plans could be
up to $42 million of which a portion is expected to be allocated to us by
Dynegy.

The following table illustrates the effect that changes in the assumptions
made for discount rate and rate of return would have had on our pension plan
assets and liabilities (millions of dollars):

PBO** 2003
12/31/2003 EXPENSE
------------- ----------

2003 estimate* $ 760.0 $ 13.6

Impact of changes in rate assumptions:
Increase Discount Rate 50 basis points $ (43.2) $ (1.1)
Decrease Discount Rate 50 basis points $ 45.7 $ 1.3
Increase Expected Rate of Return 50 basis points $ - $ (3.1)
Decrease Expected Rate of Return 50 basis points $ - $ 3.1

* Liabilities projected from December 31, 2002 to December 31, 2003 assuming no
gains or losses. Assets projected from December 31, 2002 to December 31, 2003
assuming a 9.00% return and a funding policy of the minimum required
contribution ($0 for all plans).

** Pension Benefit Obligation

INCOME TAXES We follow the guidelines in FAS No. 109, "Accounting for Income
Taxes," which requires that we use the asset and liability method of accounting
for deferred income taxes and provide deferred income taxes for all significant
income tax temporary differences. (See "Note 8 - Income Taxes" on page F-21 in
the accompanying audited financial statements for additional details).

As part of the process of preparing our financial statements, we are required
to estimate our income taxes. This process involves estimating our actual
current tax exposure together with assessing temporary differences resulting
from differing treatment of items, such as depreciation, for tax and accounting
purposes. These differences result in deferred tax assets and liabilities, which
are included within our Consolidated Balance Sheets.

DISCUSSION ON ESTIMATES The preparation of the consolidated financial
statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities, the disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. On an ongoing basis, management reviews
its estimates, and any changes in facts and circumstances may result in revised
estimates. Actual results could differ materially from those estimates. Certain
prior year amounts have been reclassified to conform to the current year
presentation.

See "Note 1 - Summary of Significant Accounting Policies" on page F-8 in the
audited financial statements included herein for a discussion of new accounting
standards. For additional disclosure on our accounting for long-lived assets,
revenue recognition and regulatory asset amortization, refer to "Note 1 -
Summary of Significant Accounting Policies" in the audited financial statements
on page F-8 included herein. For additional disclosure on our pension plan
accounting please see "Note 12 - Employee Compensation, Savings and Pension
Plans" in the audited financial statements on page F-29 included herein for more
information.

25

RESULTS OF OPERATIONS
---------------------

Our operations consist of a single reportable segment. This segment includes the
transmission, distribution and sale of electric energy; and the transportation,
distribution and sale of natural gas in Illinois. Also included in this segment
are specialized support functions, including accounting, legal, regulatory,
performance management, information technology, human resources, environmental
resources, purchasing and materials management and public affairs.

NET INCOME We had net income of $160.7 million in 2002. This compares with net
income of $166.2 million and $134.9 million in 2001 and 2000, respectively. The
decrease in 2002 earnings compared to 2001 was due to lower industrial sales and
a 5% residential rate reduction effective May 1, 2002, offset by favorable
weather-driven margin from residential and commercial customers. In addition,
results were favorably impacted by increased operating efficiencies and
litigation and billing settlements, offset by increased regulatory asset
amortization. The increase in 2001 earnings compared to 2000 was primarily due
to incremental operating efficiencies, differences in two separate early
retirement/severance programs, final distribution of an insurance investment and
lower interest expense.

The following table provides summary financial data and operating statistics
regarding our results of operations for 2002, 2001 and 2000, respectively.

YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001 2000
---------- ---------- ----------
($ in millions)

Electric Operations:
Revenues $ 1,145.9 $ 1,137.8 $ 1,192.1
Power Purchased (677.5) (661.8) (729.3)
Gas Operations:
Revenues 372.4 476.6 393.5
Gas Purchased (231.7) (332.8) (252.7)
Other Expenses (348.2) (344.3) (360.4)
General Taxes (57.6) (68.4) (74.0)
Income Taxes (39.3) (40.6) (13.2)
Other Income and Deductions - Net 109.1 121.5 116.7
Interest Charges (112.4) (121.8) (137.8)
---------- --------- ---------
Net Income $ 160.7 $ 166.2 $ 134.9
---------- --------- ---------

Net Non-Cash Items Included in Net Income $ 117.5 $ 112.4 $ 190.2
---------- --------- ---------
Operating Cash Flows Before Changes in Working Capital 278.2 278.6 325.1
Increase (Decrease) in Working Capital (68.8) 66.4 56.2
---------- --------- ---------
Net Cash Provided by Operating Activities $ 209.4 $ 345.0 $ 381.3
========== ========= =========

26

YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001 2000
---------- ---------- ----------

OPERATING STATISTICS:
Electric Sales in kWh (Millions):
Residential 5,548 5,202 5,046
Commercial 4,415 4,337 4,256
Industrial 6,306 6,353 8,324
Transportation of Customer-Owned Electricity 2,505 2,645 963
Other 370 373 412
---------- --------- ---------
Total Electricity Delivered 19,144 18,910 19,001
========== ========= =========
Gas Sales in Therms (Millions):
Residential 323 315 337
Commercial 137 136 141
Industrial 80 88 96
Transportation of Customer-Owned Gas 233 246 259
---------- --------- ---------
Total Gas Delivered 773 785 833
========== ========= ==========
Cooling Degree Days 1,467 1,302 1,173
Heating Degree Days 5,118 4,749 5,233

ELECTRIC OPERATIONS
- -------------------

ELECTRIC REVENUES For the years 2000 through 2002, electric revenues,
including interchange, decreased 4%. The increase in electric revenues in 2002
compared to 2001 reflected an increase in sales volume due to favorable weather
partially offset by a 5% residential rate reduction effective May 1, 2002.
Interchange revenues in 2002 reflect a resolution of a contingent liability for
a bulk power billing dispute. Electric revenues including interchange sales were
lower in 2001 compared to 2000 due to industrial customers purchasing energy
from alternative retail electric suppliers and a downturn in economic
conditions.

The components of annual changes in electric revenues excluding interchange
were:

- ------------------------------------------------------------------------------------------------
(Millions of dollars) 2002 2001
- ------------------------------------------------------------------------------------------------

Price $ (22.2) $ (65.4)
Volume and other 23.9 13.1
---------------------
Revenue increase (decrease) $ 1.7 $ (52.3)
=====================

POWER PURCHASED Power purchased increased $15.7 million in 2002 due to higher
sales associated with more favorable weather, partially offset by a lower
average per unit cost. The decrease in power purchased cost in 2001 of $67.5
million was primarily due to lower customer demand related to the industrial
downturn and fewer units purchased due to industrial customers choosing
alternative energy suppliers, partially offset by increased per unit costs.

Changes in the cost of electricity purchased to serve our native load were:

- ------------------------------------------------------------------------------------------------
(Millions of dollars) 2002 2001
- ------------------------------------------------------------------------------------------------

Electricity purchased:
Cost $ (6.2) $ 8.7
Volume 21.9 (76.2)
---------------------
Total increase (decrease) $ 15.7 $ (67.5)
=====================

27

GAS OPERATIONS
- --------------

GAS REVENUES For the years 2000 through 2002, gas revenues, including
transportation, decreased 5%. Gas revenues excluding transportation revenues
were $372.1 million in 2002 compared to $469.8 million and $388.0 million in
2001 and 2000, respectively. The 2002 decrease in gas revenues was a direct
result of lower natural gas prices which are passed through to our end use
customers and a continued decline in industrial sales. The 2001 gas revenues
reflect the high gas prices.

The components of annual changes in gas revenues excluding transportation
revenues were:

- ------------------------------------------------------------------------------------------------
(Millions of dollars) 2002 2001
- ------------------------------------------------------------------------------------------------

Price $ (97.0) $ 104.2
Volume and other (0.7) (22.4)
---------------------
Revenue increase (decrease) $ (97.7) $ 81.8
=====================

GAS PURCHASED The 2002 decrease in gas revenues and purchases related to
weather-driven residential and commercial sales offset by a decrease in the cost
of gas and lower industrial sales. The 2001 increase in gas costs was
attributable to market conditions that caused natural gas prices to reach
unprecedented highs partially offset by the effects of UGAC.

Changes in the cost of gas purchased to serve our native load were:

- ------------------------------------------------------------------------------------------------
(Millions of dollars) 2002 2001
- ------------------------------------------------------------------------------------------------

Gas purchased:
Cost $ (68.1) $ 29.6
Volume 7.6 (30.0)
Gas cost recoveries (40.6) 80.5
---------------------
Total increase (decrease) $ (101.1) $ 80.1
=====================

OTHER EXPENSES Other expenses were $348.2 million in 2002 compared to $344.3
million and $360.4 million in 2001 and 2000, respectively. A comparison of
significant increases (decreases) in other operating expenses, maintenance, and
depreciation and amortization for the last two years is presented in the
following table:

- -------------------------------------------------------------------------------------------------
(Millions of dollars) 2002 2001
- -------------------------------------------------------------------------------------------------

Other operating expenses $ (2.1) $ (1.2)
Maintenance (0.7) (3.1)
Retirement and severance expense (16.0) (15.7)
Depreciation and amortization (0.2) 3.3
Amortization of regulatory assets 22.9 0.6
---------------------
Total increase (decrease) $ 3.9 $ (16.1)
=====================

The decrease in other operating and maintenance expense for 2002 and 2001 is
primarily due to incremental operating efficiencies.

The decrease in retirement and severance expense in 2002 was due to an early
retirement/severance program we offered in 2001 related to a corporate
reorganization compared to 2002 which did not have a severance program. The
decrease in 2001 for retirement and severance expense primarily reflects the
lower number of people included in the 2001 program compared to the early
retirement/severance program we offered in 2000 related to the Dynegy-Illinova
merger.

The increase in depreciation expense in 2001 reflected normal additions of
utility plant. The net decrease in depreciation expense in 2002 reflected normal
utility plant additions offset by retirements of utility plant and information
technology assets.

28

The increase in amortization of regulatory assets for 2002 is due to
increased financial performance, which allowed us to recognize additional
regulatory asset amortization and stay within the allowable ROE collar.

GENERAL TAXES The decrease in general taxes of $10.8 million in 2002 is
attributable to a favorable result from a State of Illinois sales tax audit, a
municipal utility tax adjustment ("MUT") and lower gas revenue taxes resulting
from lower gas prices in 2002, partially offset by a favorable 2001 Invested
Capital Tax dispute settlement with the Illinois Department of Revenue. The
decrease in general taxes of $5.6 million in 2001 is attributable to a change in
methodology in the calculation of the electric MUT partially offset by higher
gas revenue taxes early in 2001. As required by the Electric Service Customer
Choice and Rate Relief Law of 1997, effective December 31, 2000 the electric MUT
calculation is now calculated on consumption instead of gross revenue.

INCOME TAXES See "Note 8 - Income Taxes" in the audited financial statements
beginning on page F-21 for additional information on current and deferred income
taxes and analysis of federal and state income tax.

OTHER INCOME AND DEDUCTIONS - NET The decrease of $12.4 million in 2002 of
other income and deductions - net was attributable to favorable insurance and
litigation settlements in 2001 partially offset by a favorable litigation
settlement in 2002. For 2001, total other income and deductions - net increased
by $4.8 million primarily due to favorable insurance and litigation settlements,
partially offset by a decrease in interest income from affiliates and reduced
revenues from non-utility support services.

INTEREST CHARGES Total interest charges, including AFUDC, decreased $9.4
million and $16.0 million in 2002 and 2001, respectively, primarily due to the
ongoing redemption of Transitional Funding Trust Notes, and lower average
long-term debt balances coupled with lower interest charges on short-term debt.
See "Note 7 - Revolving Credit Facilities and Short-Term Loans" and "Note 9 -
Long-Term Debt" in the audited financial statements beginning on page F-20 and
F-24, respectively, for additional information.

NET CASH PROVIDED BY OPERATING ACTIVITIES Operating cash flows were $209.4
million for the year ended December 31, 2002 compared to $345.0 million and
$381.3 million for the year ended December 31, 2001 and 2000, respectively. The
changes in net income period to period, including the components related to
depreciation and amortization, have been previously discussed. The changes in
working capital relate primarily to timing differences in cash flows. We paid
more in tax payments to Dynegy under the Services and Facilities Agreement in
2002 compared to 2001. We received prepayment of interest on the note receivable
from Illinova in 2001 which related to payments that would have been received in
2002. Higher underrecoveries at the end of 2000 related to UGAC caused higher
recoveries from customers during 2001. Finally, the requirements in 2002 from
some of our gas suppliers to accelerate payment for natural gas purchases
resulted in an extra month's worth of payments in 2002 compared to 2001.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION This Annual 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. 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:

- - projected operating or financial results;

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

- - beliefs about the financial impact of deregulation;

- - assumptions regarding the outcomes of legal and administrative
proceedings;

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

- - beliefs regarding the consummation of asset sales;

- - intentions with respect to future energy supplies; and

- - anticipated costs associated with legal and regulatory compliance.

29

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:

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

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

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

- - competition from alternate retail electric providers;

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

- - the risk that the previously announced sale of our electric transmission
system to Trans-Elect, Inc. may not close as a result of the regulatory,
financing and other contingencies related to that transaction;

- - our ability to negotiate a new bank credit facility on terms acceptable to
us and our lenders;

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

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

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

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

- - 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

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

Many of these factors will be important in determining our actual future
results. However, 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 our forward-looking statements, whether written or oral, are expressly
qualified by these cautionary statements and any other cautionary statements
that may accompany such forward-looking statements. In addition, we disclaim any
obligation to update any forward-looking statements to reflect events or
circumstances after the date of this report.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- --------------------------------------------------------------------

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

The ICC determines our delivery rates for gas service. These rates have been
designed to recover the cost of service and allow shareholders the opportunity
to earn a reasonable rate of return. The gas commodity is a pass through cost to
the end-use customer and is subject to an annual ICC prudence review. Future
natural gas sales will continue to be affected by an increasingly competitive
marketplace, changes in the

30

regulatory environment, transmission access, weather conditions, gas cost
recoveries, customer conservation efforts and the overall economy. Price risk
associated with our gas operations is mitigated through contractual terms
applicable to the business, as allowed by the ICC. We apply prudent
risk-management practices in order to minimize these market risks. Such risk
management practices may not fully mitigate these exposures.

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- ----------------------------------------------------

Our 2000-2002 audited financial statements are set forth, beginning on page F-1,
found at the end of this report, and are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
- ------------------------------------------------------------------------
FINANCIAL DISCLOSURE
- --------------------

Dynegy's Board of Directors on March 15, 2002, dismissed Arthur Andersen LLP
("Andersen") as independent public accountants of Dynegy and its subsidiaries
and engaged PricewaterhouseCoopers LLP to serve as independent public
accountants of Dynegy and its subsidiaries for 2002. The appointment of
PricewaterhouseCoopers LLP was ratified by Dynegy's shareholders at the 2002
annual meeting held on May 17, 2002.

Andersen's reports on our consolidated financial statements for the past two
years did not contain an adverse opinion or disclaimer of opinion, nor were they
qualified or modified as to uncertainty, audit scope or accounting principles.

During 2001 and 2000, there were no disagreements with Andersen on any matter
of accounting principles or practices, financial statement disclosure, or
auditing scope or procedure which, if not resolved to Andersen's satisfaction,
would have caused them to make reference to the subject matter in connection
with their report on IP's consolidated financial statements for such years; and
there were no reportable events, as listed in Item 304(a)(1)(v) of Regulation
S-K.

We provided Andersen with a copy of the foregoing disclosures. Andersen's
letter, dated March 20, 2002, attached as Exhibit 16 to our 2001 Annual Report
on Form 10-K filed on March 22, 2002, concurred with such disclosures.

During 2001 and 2000, we did not consult PricewaterhouseCoopers LLP with
respect to the application of accounting principles to a specified transaction,
either completed or proposed, or the type of audit opinion that might be
rendered on our consolidated financial statements, or any other matters or
reportable events listed in Items 304(a)(2)(i) and (ii) of Regulation S-K.

31

PART III
--------

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- ------------------------------------------------------------

The following table sets forth certain information with respect to our directors
and executive officers as of March 31, 2003:

SERVED WITH THE
NAME AGE POSITION(S) COMPANY SINCE
- ---- --- ----------- ---------------

Daniel L. Dienstbier 62 Chairman of the Board 2002

Larry F. Altenbaumer 55 President, Chief Executive Officer and Director 1970

Nick J. Caruso 57 Executive Vice President and Chief Financial Officer 2003

Kathryn L. Patton 38 Senior Vice President, General Counsel and 2000
Secretary

Peggy E. Carter 40 Vice President and Controller 1985

Kenneth E. Randolph 46 Director 2000

Bruce A. Williamson 43 Director 2002

The directors named above will serve in such capacity until our next annual
shareholder meeting or until their respective successors have been duly elected
and qualified, or until their earlier death, resignation or removal. The
executive officers named above will serve in such capacities until our next
annual Board of Directors meeting or until their respective successors have been
duly elected and qualified or until their earlier death, resignation or removal.

DANIEL L. DIENSTBIER has served as Chairman of our Board of Directors since June
2002. Mr. Dienstbier has also served as Chairman of the Board of Dynegy since
September 2002 and as a director of Dynegy since 1995. He served as interim
Chief Executive Officer of Dynegy from May 2002 until October 2002 and as
President of Northern Natural Gas Company, which was a subsidiary of Dynegy,
from February 2002 until July 2002. Mr. Dienstbier has over thirty years of
experience in the oil and gas industry. He served as President and Chief
Operating Officer of American Oil & Gas Corp. from October 1993 through July
1994, President and Chief Operating Officer of Arkla, Inc. from July 1992
through October 1993, and President of Jule, Inc., a private company involved in
energy consulting and joint venture investments in the pipeline, gathering and
exploration and production industries, from February 1991 through June 1992.
Previously, Mr. Dienstbier served as President and Chief Executive Officer of
Dyco Petroleum Corp. and Executive Vice President of Diversified Energy from
February 1989 through February 1991. In addition, he served as President of the
Gas Pipeline Group of Enron Corp. from July 1985 through July 1988. Mr.
Dienstbier is a former director of American Oil & Gas Corp., Arkla, Inc., Enron
Corp. and Midwest Resources. He is also a former member of the Audit and
Compliance Committee of Northern Border Partners, L.P.

LARRY F. ALTENBAUMER has served as our President since September 1999 and as our
Chief Executive Officer since November 2002. Mr. Altenbaumer has also served as
one of our Directors and as a Senior Vice President of Dynegy since February
2000, following the consummation of the Dynegy-Illinova merger. Mr. Altenbaumer
previously served us and Illinova in various capacities since 1970, including as
our Senior Vice President and Chief Financial Officer from 1992 until September
1999 and as Senior Vice President, Chief Financial Officer, Treasurer and
Controller of Illinova from June 1994 until September 1999.

32

NICK J. CARUSO is our Executive Vice President and Chief Financial Officer. He
has served in this position since March 3, 2003. Mr. Caruso has also served as
the Executive Vice President and Chief Financial Officer of Dynegy, since
December 2002, and is responsible for internal audit, risk management, tax,
treasury, accounting, investor relations and finance functions. He was
previously employed by Shell Oil Company from 1969 to 2001. He most recently
served as that company's Vice President of Finance and Chief Financial Officer
before retiring in December 2001. He was responsible for the controller's
organization, treasury, insurance, auditing and retirement funds, interfacing
with the board of directors on internal controls and preparation of financial
statements.

KATHRYN L. PATTON has served as our General Counsel and Secretary since February
2000, following the consummation of the Dynegy-Illinova merger. Ms. Patton also
has served us as a Senior Vice President and as Vice President and Assistant
General Counsel of Dynegy since July 2001, prior to which she served us as a
Vice President from February 2000 to July 2001. Ms. Patton previously served
Dynegy as Director and Regulatory Counsel from May 1995 to March 1999 and Senior
Director and Regulatory Counsel from March 1999 until February 2000. Ms. Patton
also served as Senior Vice President, General Counsel and Secretary of Northern
Natural Gas Company, then another Dynegy subsidiary, from February 2002 to
August 2002.

PEGGY E. CARTER has served us as a Vice President since February 2000 and as
Controller since November 1999. Ms. Carter was elected to serve as Vice
President following the consummation of the Dynegy-Illinova merger. Ms. Carter
previously served in various capacities with us from 1985, including Business
Leader in our accounting department from August 1994 until November 1999.

KENNETH E. RANDOLPH has served as one of our Directors since February 2000,
following the consummation of the Dynegy-Illinova merger. Mr. Randolph
previously served as Executive Vice President and General Counsel of Dynegy. He
served as Executive Vice President of Dynegy from July 2001 until March 2003 and
as General Counsel of Dynegy and its predecessor, Clearinghouse, from July 1987
until March 2003. In addition, he served as a member of Dynegy's Management
Committee from May 1989 through February 1994 and managed its marketing
operations in the Western and Northwestern United States from July 1984 through
July 1987. Prior to his employment with Dynegy, Mr. Randolph was associated with
the Washington, D.C. office of Akin, Gump, Strauss, Hauer & Feld, LLP.

BRUCE A. WILLIAMSON has served as one of our Directors since November 2002. Mr.
Williamson also serves as Dynegy's President and Chief Executive Officer and as
a Director. He has served in these positions with Dynegy since joining that
company in October 2002. Prior to joining Dynegy, Mr. Williamson served in
various capacities for Duke Energy and its affiliates, most recently serving as
President and Chief Executive Officer of Duke Energy Global Markets. In this
capacity, he was responsible for all Duke Energy business units with global
communications and international business positions. Mr. Williamson joined the
Duke family of companies in 1997 following the Duke Power and PanEnergy
Corporation merger. Prior to the Duke-PanEnergy merger, he served as PanEnergy's
Vice President of Finance. Before joining PanEnergy, he held positions of
increasing responsibility at Royal Dutch/Shell Group, advancing over a 14-year
period to Assistant Treasurer of Shell Oil Company.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
- -------------------------------------------------------

Section 16(a) of the Securities Exchange Act of 1934 requires that reports of
ownership and changes in ownership be filed with respect to directors, executive
officers and persons who beneficially own more than 10% of a class of equity
securities registered under Section 12 thereof. IP believes that all such
requirements were satisfied with respect to its cumulative preferred stock
during the fiscal year ended December 31, 2002.

33

ITEM 11. EXECUTIVE COMPENSATION
- --------------------------------

The following table sets forth certain information regarding the compensation
earned by each individual who served as our Chief Executive Officer during 2002
and our two other executive officers at the end of 2002 (the "Named Executive
Officers"), as well as amounts earned by or awarded to certain of such
individuals for services rendered in all capacities to us for the fiscal years
of 2001 and 2000. We did not have another executive officer who earned more than
$100,000 in 2002.

SUMMARY COMPENSATION TABLE
- --------------------------

LONG TERM
COMPENSATION AWARDS
ANNUAL COMPENSATION -----------------------------------------
------------------------------------------------------ RESTRICTED SECURITIES
OTHER ANNUAL STOCK UNDERLYING ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY(1) BONUS (2) COMPENSATION(3) AWARDS(4) OPTIONS (5) COMPENSATION(6)
- --------------------------- ------------------------------------------------------ -----------------------------------------

Larry F. Altenbaumer 2002 $ 288,770 $ --- $ --- $ --- 90,000 $ 5,500
President and 2001 $ 299,500 $ 350,000 $ --- $ --- 79,050 $ 5,250
Chief Executive Officer 2000 $ 303,208 $ 485,000 $ --- $250,000 84,553 $ 5,250

Stephen W. Bergstrom 2002(8) (8) (8) (8) (8) (8) (8)
Former Chief Executive 2001(8) (8) (8) (8) (8) (8) (8)
Officer 2000(7) (8) (8) (8) (8) (8) (8)

Kathryn L. Patton 2002 $ 212,420 $ --- $ 27,924(10) $ --- 24,000 $ 7,870
Senior Vice President, 2001 $ 188,317 $ 125,000 $ 27,924(10) $ --- 42,439 $ 27,200
General Counsel 2000(9) $ 176,750 $ 130,000 $ 45,943 $ --- 16,548 $ 25,500
and Secretary

Peggy E. Carter 2002 $ 123,780 $ --- $ --- $ --- 12,000 $ 3,310
Vice President and 2001 $ 117,706 $ 47,500 $ --- $ --- 7,918 $ 5,250
Controller 2000(11) $ 112,371 $ 75,850 $ --- $ --- 3,129 $ 2,329

(1) Salary amounts for Mr. Altenbaumer for 2000 includes additional base
salary payments of $12,083 representing payment for the period from
September 1999, when he became an executive officer of IP, to February 1,
2000, the closing date of the Dynegy-Illinova merger, covering the
pro-rata difference between his new base salary and his final base salary
at Illinova. Salary amount for Ms. Carter for 2000 includes a similar
payment of $7,560 relative to her promotion to Controller in November
1999.

(2) As applicable, bonus amounts include bonuses earned in 2000 and 2001,
which were paid in 2001 and 2002, respectively. No bonuses were paid for
2002.

(3) Includes "Perquisites and Other Personal Benefits" if value is greater
than the lesser of $50,000 or 10% of the reported salary and bonus.

(4) For 2000, Mr. Altenbaumer received 10,696 shares of restricted Dynegy
Class A common stock valued at $23.38 per share. Such shares vest five
years from the date of grant. During such period, dividend equivalents
will be credited to Mr. Altenbaumer's account.

(5) Number of shares underlying options reflects the two-for-one stock split
affected by Dynegy Inc. in August 2000 and the .69 merger conversion ratio
used in the Dynegy-Illinova merger. Securities underlying options for 2000
and 2002 includes options granted in 2001 and 2003, respectively, for work
done in the preceding year.

(6) The amounts included as "All Other Compensation" represent contributions
to the Named Executive Officers' respective savings plan accounts.

(7) Mr. Bergstrom became an executive officer of ours in February 2000.

(8) Mr. Bergstrom was not compensated by us for services rendered in periods
indicated above for serving as our Chief Executive Officer. Mr. Bergstrom
was compensated by Dynegy for services rendered in all capacities to
Dynegy and its affiliates, including us. Information with respect to Mr.
Bergstrom's compensation for 2002, 2001 and 2000 will be contained in
Dynegy's Proxy Statement for its 2003 Annual Meeting of Shareholders (the
"Proxy Statement"). Mr. Bergstrom resigned from his position with Dynegy
and IP in October 2002.

(9) Ms. Patton became an executive officer of ours in February 2000.

(10) Amount reflects an aggregate annual allowance for living and car expenses
related to expenses incurred by Ms. Patton in connection with her
relocation to Illinois following the Dynegy-Illinova merger. See
"Employment Contracts and Change-in-Control Arrangements."

(11) Ms. Carter became an executive officer of ours in February 2000.

34

OPTION GRANTS IN 2002
- ---------------------

The following table sets forth certain information with respect to Dynegy stock
option grants made to the Named Executive Officers for 2002 under the Dynegy
Inc. 2000 Long Term Incentive Plan and the Dynegy Inc. 2001 Non-Executive Stock
Incentive Plan. Dynegy indirectly owns all of our common stock. No stock options
were granted during 2002.

INDIVIDUAL GRANTS
- -----------------

NUMBER OF % OF TOTAL
SECURITIES OPTIONS POTENTIAL REALIZABLE VALUE AT
UNDERLYING GRANTED TO ASSUMED ANNUAL RATES OF
OPTIONS EMPLOYEES EXERCISE EXPIRATION STOCK PRICE APPRECIATION FOR
GRANTED(1) FOR 2002(1) PRICE $/SHARE(1) DATE OPTION TERM(2)
---------- ----------- ---------------- ---- --------------
NAME 5% 10%
- ---- ---------- --------

Larry F. Altenbaumer 90,000 2.2 $1.77 2/4/2013 $ 100,183 $253,883
Stephen W. Bergstrom (3) (3) (3) (3) (3) (3)
Kathryn L. Patton 24,000 * $1.77 2/4/2013 $ 26,715 $ 67,702
Peggy E. Carter 12,000 * $1.77 2/4/2013 $ 13,357 $ 33,851

* Less than 1%.

(1) Number of securities underlying options/exercise price reflects the
two-for-one stock split effected by Dynegy Inc. in August 2000 and the .69
merger conversion ratio used in the Dynegy-Illinova merger. Securities
underlying options granted and percent of total options granted to
employees in 2002 reflects Dynegy stock options granted to employees of
Dynegy and its affiliates, including IP, for 2002 performance in 2003.

(2) The dollar amounts under these columns represent the potential realizable
value of each grant of options assuming that the market price of Dynegy
common stock appreciates in value from the date of grant at the 5% and 10%
annual rates prescribed by the SEC and are not intended to forecast
possible future appreciation, if any, of the price of Dynegy common stock.

(3) Information with respect to Mr. Bergstrom's Dynegy stock option grants
will be contained in Dynegy's Proxy Statement under the heading "Executive
Compensation."

AGGREGATED OPTION EXERCISES AND FISCAL YEAR-END OPTION VALUES
- -------------------------------------------------------------

The following table sets forth certain information regarding Dynegy stock
options held by the Named Executive Officers at December 31, 2002. No Dynegy
stock options were exercised by any of the Named Executive Officers in 2002.

NUMBER OF SECURITIES VALUE OF UNEXERCISED IN-THE-
UNDERLYING UNEXERCISED MONEY OPTIONS AT FISCAL
OPTIONS AT FISCAL YEAR-END (1) YEAR-END (2)
NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- ------------- ----------- -------------

Larry F. Altenbaumer 182,700 183,368 $ --- $ ---
Stephen W. Bergstrom (3) (3) (3) (3)
Kathryn L. Patton 55,908 63,324 $ --- $ ---
Peggy E. Carter 9,683 19,364 $ --- $ ---

(1) Number of shares underlying options reflects the two-for-one stock split
effected by Dynegy Inc. in August 2000 and the .69 merger conversion ratio
used in the Dynegy-Illinova merger. Certain unexercisable options held by
Mr. Altenbaumer and Ms. Patton became fully vested and exercisable
effective upon the closing of the merger on February 1, 2000. See
"Employment Contracts and Change-in-Control Arrangements."

(2) Value based on the closing price of $1.18 on the New York Stock
Exchange - Composite Tape for Dynegy common stock on December 31, 2002.

(3) Information with respect to Mr. Bergstrom's Dynegy stock option
exercises and year-end values will be contained in Dynegy's Proxy
Statement under the heading "Executive Compensation."

35

PENSION BENEFITS
- ----------------

The following table shows the estimated annual pension benefits on a
straight-life annuity basis payable on retirement to Mr. Altenbaumer and Ms.
Carter based on specified annual average earnings and years of credited service
classifications, assuming continuation of the Dynegy Inc. Retirement Plan,
formerly the IP Retirement Income Plan for Salaried Employees (the "IP
Retirement Plan"), and employment until age 65. Estimated annual benefits under
the IP Retirement Plan are payable only with respect to annual earnings up to
$200,000. This table does not reflect the Social Security offset, but any actual
pension benefit payments would be subject to this offset.

ESTIMATED ANNUAL BENEFITS (ROUNDED)
-----------------------------------

- -------------------------------------------------------------
Annual 15 Yrs. 20 Yrs. 25 Yrs. 30 Yrs.
Average Credited Credited Credited Credited
Earnings Service Service Service Service
- -------------------------------------------------------------

$125,000 $ 37,500 $ 50,000 $ 62,500 $ 75,000
- -------------------------------------------------------------
150,000 45,000 60,000 75,000 90,000
- -------------------------------------------------------------
170,000 51,000 68,000 85,000 102,000
- -------------------------------------------------------------
200,000 60,000 80,000 100,000 120,000
- -------------------------------------------------------------

The earnings used in determining pension benefits under the IP Retirement
Plan are the participants' regular base compensation, as set forth under the
"Salary" column in the Summary Compensation Table above.

At December 31, 2002, for purposes of the IP Retirement Plan, Mr. Altenbaumer
and Ms. Carter had completed 29 and 16 years of credited service, respectively.
None of the other current Named Executive Officers participate in the IP
Retirement Plan.

COMPENSATION OF DIRECTORS
- -------------------------

None of our Directors receive special or additional compensation as a result of
their service on the Board of Directors or any committee of the Board of
Directors.

EMPLOYMENT CONTRACTS AND CHANGE-IN-CONTROL ARRANGEMENTS
- -------------------------------------------------------

Dynegy has employment agreements with Mr. Altenbaumer and Ms. Patton, which are
described below. Dynegy also has an employment agreement with Nick J. Caruso,
which will be described in Dynegy's Proxy Statement.

LARRY F. ALTENBAUMER EMPLOYMENT AGREEMENT Effective upon the closing of the
Dynegy-Illinova merger on February 1, 2000, Dynegy Inc. entered into a
three-year employment agreement with Mr. Altenbaumer, pursuant to which Mr.
Altenbaumer serves as President of IP and Senior Vice President of Dynegy. The
agreement provided that the term of the agreement will automatically be extended
for additional one-year periods unless either party elects otherwise. In May
2002, the parties executed an addendum to the agreement that extended the
original term for an additional year. Mr. Altenbaumer's employment agreement
entitles him to a base salary of $290,000, subject to increase at the discretion
of the Board of Directors, and the annual opportunity to earn additional bonus
amounts. Upon the closing of the merger, Mr. Altenbaumer also was awarded grants
of Dynegy stock options under the Dynegy Inc. 2000 Long Term Incentive Plan with
a value equal to 150% of his base salary and restricted stock with an
in-the-money value equal to approximately $250,000. Under the terms of the
employment agreement, all options granted to Mr. Altenbaumer prior to November
1, 1999 became fully vested as of February 1, 2000. The employment agreement
also contains non-compete provisions in the event of Mr. Altenbaumer's
termination of employment.

Mr. Altenbaumer's employment agreement also includes provisions governing the
payment of severance benefits if his employment is terminated due to resignation
following a "constructive termination," as

36

defined in the agreement, or for any other reason other than his voluntary
resignation, death, disability or discharge for cause. Any such severance
benefits shall be made as follows: (i) a lump sum amount equal to the product of
(a) 2.99 and (b) the greater of (1) the average annual base salary and incentive
compensation paid to Mr. Altenbaumer for the highest three calendar years
preceding the year of termination, and (2) Mr. Altenbaumer's base salary and
target bonus amount for the year of termination; (ii) a lump sum amount equal to
the present value, as defined by Dynegy's Board of Directors, of the senior
management benefits and other perquisites otherwise owed to Mr. Altenbaumer
through the remaining term of his employment; (iii) vesting of any previously
granted unvested Dynegy stock options to be exercised until the later of the
term of his agreement and the one-year anniversary of the termination date; and
(iv) continued health and welfare benefits for 36 months from the termination
date.

KATHRYN L. PATTON EMPLOYMENT AGREEMENT Effective upon the closing of the
Dynegy-Illinova merger on February 1, 2000, Dynegy Inc. entered into a two-year
employment agreement with Ms. Patton, pursuant to which Ms. Patton agreed to
serve as Vice President and General Counsel of IP. Effective February 2, 2002,
Ms. Patton entered into a new contract under which she will serve as Senior Vice
President and General Counsel of IP and Vice President and Assistant General
Counsel of Dynegy. The initial term of the contract ended September 1, 2002 and
was automatically extended for an additional one-year period. Ms. Patton's
employment agreement entitles her to a base salary of $210,000, subject to
increase at the discretion of the Board of Directors, and the annual opportunity
to earn additional bonus amounts, dependent upon certain financial objectives,
as a participant in Dynegy's Incentive Compensation Plan. Ms. Patton is also
entitled to a housing and automobile allowance of $2,327 per month. After
September 1, 2002, Ms. Patton may request to be returned to the Dynegy
organization in Houston, Texas as a Vice President at the same base salary and
target bonus. If such request is not granted within 90 days, Ms. Patton may
terminate her employment and would be entitled to 18 months of base salary and
target bonus and vesting of any unvested options granted before December 31,
1999. Under the terms of the original employment agreement, all options granted
to Ms. Patton prior to November 1, 1999 became fully vested as of February 1,
2000. The employment agreement also contains non-compete provisions in the event
of Ms. Patton's termination of employment.

Ms. Patton's employment agreement also includes provisions governing the
payment of severance benefits if her employment is terminated due to resignation
following a "constructive termination," as defined in the agreement, or for any
other reason other than her voluntary resignation, death, disability or
discharge for cause. Any such severance benefits shall be made as follows: (i) a
lump sum amount equal to 150% of Ms. Patton's base salary and target bonus
amount for the year of termination; (ii) vesting of any previously granted
unvested Dynegy stock options to be exercised until the later of the term of her
agreement and the one-year anniversary of the termination date; (iii)
reimbursement of all reasonable out-of-pocket moving expenses from Decatur,
Illinois to Houston, Texas and assumption of liability through the end of the
contract term for Ms. Patton's housing and automobile leases in Decatur,
Illinois up to $2,327 per month; and (iv) continued health and welfare benefits
for 24 months from the termination date.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
- -----------------------------------------------------------

Dynegy and IP have a joint Compensation Committee that, as of December 31, 2002,
was comprised of the following Dynegy directors: Barry J. Galt (Chairperson),
Linda Bynoe, Joe Stewart, John Watson and Otis Winters. There are no matters
relating to interlocks or insider participation that we are required to report.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
- ---------------------------------------------------------------------------
RELATED STOCKHOLDERS MATTERS
- ----------------------------

All of our common stock is owned by Illinova, which is a wholly owned subsidiary
of Dynegy. A subsidiary of ChevronTexaco now holds approximately 26.5% of
Dynegy's outstanding common stock and $1.5 billion of its Series B Mandatorily
Convertible Redeemable Preferred Stock. We also have six series of preferred
stock outstanding, none of which is owned by any director or executive officer.
Illinova owns approximately 73% of our outstanding preferred stock.

37

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- ---------------------------------------------------------

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. We derived
approximately $33.0 million in operating revenue from these transactions during
2002. Aggregate operating expenses charged by affiliates in 2002 approximated
$530.5 million, including $486.4 million for power purchased. See "Note 5 -
Related Parties" in the audited financial statements beginning on page F-16 for
more information pertaining to related party transactions.

With respect to electricity purchases, 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. The primary term may be extended annually, subject to
concurrence by both parties and regulatory approval. The PPA defines the terms
and conditions under which DMG provides capacity and energy to us pursuant to a
tiered pricing structure. For more information regarding the PPA, see Item 1,
"Business," beginning on page 4.

Effective January 1, 2000, the Dynegy consolidated group, which includes us,
began operating under a Services and Facilities Agreement, whereby other Dynegy
affiliates exchange services with us such as financial, legal, information
technology and human resources as well as shared facility space. Our services
are exchanged at fully distributed costs and revenue is not recorded under this
agreement.

Effective October 1, 1999, we transferred our wholly owned fossil generating
assets and other generation-related assets and liabilities at net book value to
Illinova in exchange for an unsecured note receivable of approximately $2.8
billion. Such assets subsequently were contributed by Illinova to an affiliate
that later became DMG. Effective August 31, 2001, approximately $9.3 million of
additional fossil generation-related assets were transferred to Illinova and the
unsecured note receivable was adjusted accordingly. The note matures on
September 30, 2009 and bears interest at a rate of 7.5%, due semiannually in
April and October. At December 31, 2002, principal outstanding under the note
approximated $2.3 billion with $14.2 million accrued interest. We recognized
$170.4 million in interest income on the note from Illinova in 2002.

The ICC recently approved a netting agreement among us, Dynegy and other of
its affiliates. Please read "Affiliate Transactions" beginning on page 17 for
further discussion.

PART IV
-------

ITEM 14. CONTROLS AND PROCEDURES
- ---------------------------------

Within the 90-day period immediately preceding the filing of this report, an
evaluation was carried out under the supervision and with the participation of
our management, including our chief executive officer and our chief financial
officer, of the effectiveness of the design and operation of our disclosure
controls and procedures (as defined in Rule 13a-14(c) and 15d-14 under the
Exchange Act). Based upon that evaluation, the chief executive officer and chief
financial officer concluded that the design and operation of these disclosure
controls and procedures were effective. No significant changes were made to our
internal controls or in other factors that could significantly affect these
controls subsequent to the date of this evaluation.

38

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
- --------------------------------------------------------------------------

The following documents, which we have filed with the SEC pursuant to the
Securities Exchange Act of 1934, as amended, are by this reference incorporated
in and made a part of this report:

(1) Financial Statements - Our consolidated financial statements are
incorporated under Item 8 of this Form 10-K.

(2) Financial Statement Schedules

All Financial Statement Schedules are omitted because they are not applicable
or the required information is shown in the financial statements or notes
thereto.

(3) Exhibits

The exhibits filed with this Form 10-K are listed in the Exhibit Index
located elsewhere herein. All management contracts and compensatory plans or
arrangements set forth in such list are marked with a~.

(a) Reports on Form 8-K during the quarter ended December 31, 2002:

Current Report on Form 8-K dated October 23, 2002. Items 5 and
7 were reported and no financial statements were filed.

Current Report on Form 8-K dated December 12, 2002. Items 5
and 7 were reported and no financial statements were filed.

Current Report on Form 8-K dated December 23, 2002. Items 5
and 7 were reported and no financial statements were filed.

39

SIGNATURES
----------

Pursuant to the requirements of Section 13 or 15(d) 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: April 15, 2003 By: /s/ Larry F. Altenbaumer
-----------------------------
Larry F. Altenbaumer
President and Chief Executive Officer

Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant in the capacities and on the dates indicated.

/s/ Larry F. Altenbaumer President, Chief Executive Officer April 15, 2003
- ------------------------------ and Director
Larry F. Altenbaumer
(Principal Executive Officer)

/s/ Nick J. Caruso Executive Vice President and April 15, 2003
- ------------------------------ Chief Financial Officer
Nick J. Caruso
(Principal Financial Officer)

/s/ Peggy E. Carter Vice President and Controller April 15, 2003
- ------------------------------
Peggy E. Carter
(Principal Accounting Officer)

/s/ Daniel L. Dienstbier Director April 15, 2003
- ------------------------------
Daniel L. Dienstbier

/s/ Kenneth E. Randolph Director April 15, 2003
- ------------------------------
Kenneth E. Randolph

/s/ Bruce A. Williamson Director April 15, 2003
- ------------------------------
Bruce A. Williamson

40

SECTION 302 CERTIFICATION

I, Larry F. Altenbaumer, certify that:

1. I have reviewed this 2002 Annual Report on Form 10-K ("10-K") of
Illinois Power Company ("IP");

2. Based on my knowledge, this 10-K does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this 10-K;

3. Based on my knowledge, the financial statements, and other financial
information included in this 10-K, fairly present in all material
respects the financial condition, results of operations and cash flows
of IP as of, and for, the periods presented in this 10-K;

4. IP's other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for IP and we have:

(a) designed such disclosure controls and procedures to
ensure that material information relating to IP,
including its consolidated subsidiaries, is made
known to us by others within those entities,
particularly during the period in which this annual
report is being prepared;

(b) evaluated the effectiveness of IP's disclosure
controls and procedures as of a date within 90 days
prior to the filing date of this annual report (the
"Evaluation Date"); and

(c) presented in this annual report our conclusions about
the effectiveness of the disclosure controls and
procedures based on our evaluation as of the
Evaluation Date;

5. IP's other certifying officer and I have disclosed, based on our most
recent evaluation, to IP's auditors and the audit committee of the
registrant's board of directors (or persons performing the equivalent
functions):

(a) all significant deficiencies in the design or
operation of internal controls which could adversely
affect IP's ability to record, process, summarize and
report financial data and have identified for IP's
auditors any material weaknesses in internal
controls; and

(b) any fraud, whether or not material, that involves
management or other employees who have a significant
role in IP's internal controls; and

6. IP's other certifying officer and I have indicated in this annual
report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.

Date: April 15, 2003

/s/ Larry F. Altenbaumer
------------------------
Larry F. Altenbaumer
President and Chief Executive Officer

41

SECTION 302 CERTIFICATION

I, Nick J. Caruso, certify that:

1. I have reviewed this 2002 Annual Report on Form 10-K ("10-K") of
Illinois Power Company ("IP");

2. Based on my knowledge, this 10-K does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered
by this 10-K;

3. Based on my knowledge, the financial statements, and other financial
information included in this 10-K, fairly present in all material
respects the financial condition, results of operations and cash flows
of IP as of, and for, the periods presented in this 10-K;

4. IP's other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to
ensure that material information relating to IP,
including its consolidated subsidiaries, is made
known to us by others within those entities,
particularly during the period in which this annual
report is being prepared;

(b) evaluated the effectiveness of IP's disclosure
controls and procedures as of a date within 90 days
prior to the filing date of this annual report (the
"Evaluation Date"); and

(c) presented in this annual report our conclusions about
the effectiveness of the disclosure controls and
procedures based on our evaluation as of the
Evaluation Date;

5. IP's other certifying officer and I have disclosed, based on our most
recent evaluation, to IP's auditors and the audit committee of the
registrant's board of directors (or persons performing the equivalent
functions):

(a) all significant deficiencies in the design or
operation of internal controls which could adversely
affect IP's ability to record, process, summarize and
report financial data and have identified for IP's
auditors any material weaknesses in internal
controls; and

(b) any fraud, whether or not material, that involves
management or other employees who have a significant
role in IP's internal controls; and

6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.

Date: April 15, 2003

/s/ Nick J. Caruso
------------------
Nick J. Caruso
Executive Vice President and Chief Financial Officer

42

ILLINOIS POWER COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED FINANCIAL STATEMENTS PAGE
----

Report of Independent Accountants............................................. F-2

Report of Independent Public Accountants...................................... F-3

Consolidated Balance Sheets as of December 31, 2002 and 2001.................. F-4

Consolidated Statements of Income and Comprehensive Income for
the years ended December 31, 2002, 2001 and 2000........................... F-5

Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000........................................... F-6

Consolidated Statements of Retained Earnings for the years ended
December 31, 2002, 2001 and 2000........................................... F-7

Notes to Consolidated Financial Statements.................................... F-8

F-1

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and
Shareholders of Illinois Power Company:

In our opinion, the accompanying consolidated balance sheet as of December 31,
2002 and the related consolidated statements of income and comprehensive income,
of cash flows and of retained earnings for the year then ended present fairly,
in all material respects, the financial position of Illinois Power Company at
December 31, 2002, and the results of its operations and its cash flows for the
year then ended in conformity with accounting principles generally accepted in
the United States of America. These financial statements are the responsibility
of the Company's management; our responsibility is to express an opinion on
these financial statements based on our audit. We conducted our audit of these
statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion. The consolidated financial
statements of the Company as of December 31, 2001 and for each of the two years
in the period ended December 31, 2001, were audited by other independent
accountants who have ceased operations. Those independent accountants expressed
an unqualified opinion on those financial statements in their report dated
February 25, 2002.

The Company has a $2.3 billion unsecured Note Receivable from Affiliate at
December 31, 2002 and, as discussed in Note 3, the interest income from this
Note Receivable provides the Company with substantial income and cash flows.
Company management evaluated the Note Receivable from Affiliate for possible
impairment under the requirements of Statement of Financial Accounting Standards
No. 114 (SFAS 114), Accounting by Creditors for Impairment of a Loan. As
discussed in Note 1, SFAS 114 does not require the Note Receivable from
Affiliate to be carried at fair value and considers a loan as impaired only when
it is probable that the Company will be unable to collect all amounts due
according to the contractual terms of the loan agreement. Therefore, under this
standard, it could be reasonably possible, or even more likely than not, that
all such payments would not be collected and a loan not be considered impaired.
Company management believes the Note Receivable from Affiliate is fully
collectible and no impairment is required by SFAS 114. As further discussed in
Notes 5 and 14, the Note Receivable from Affiliate is carried in the
accompanying consolidated financial statements at cost which is significantly
greater than its fair value, as estimated by Company management based on quoted
market prices for the Affiliate's publicly traded unsecured debt securities.

PricewaterhouseCoopers LLP
Houston, Texas
April 4, 2003

F-2

THE FOLLOWING REPORT IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN
LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Shareholder of Illinois Power Company:

We have audited the accompanying consolidated balance sheets of Illinois Power
Company (an indirect, wholly owned subsidiary of Dynegy, Inc.) and subsidiaries
as of December 31, 2001 and 2000, and the related statements of income, retained
earnings and cash flows for the years then ended. These financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Illinois Power Company and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for the years then ended in conformity with
accounting principles generally accepted in the United States.

ARTHUR ANDERSEN LLP

Houston, Texas
February 25, 2002

F-3

ILLINOIS POWER COMPANY
- ----------------------

C O N S O L I D A T E D B A L A N C E S H E E T S
- -----------------------------------------------------

- --------------------------------------------------------------------------------------------------------------------
(Millions of dollars)
- --------------------------------------------------------------------------------------------------------------------
December 31, 2002 2001

ASSETS
UTILITY PLANT
Electric (includes construction work in progress of $91.0 million and $113.8
million, respectively) $ 2,409.6 $ 2,368.7
Gas (includes construction work in progress of $18.4 million and $18.6 million,
respectively) 770.6 756.7
- --------------------------------------------------------------------------------------------------------------------
3,180.2 3,125.4

Less -- accumulated depreciation 1,218.9 1,220.0
- --------------------------------------------------------------------------------------------------------------------
1,961.3 1,905.4
- --------------------------------------------------------------------------------------------------------------------
INVESTMENTS AND OTHER ASSETS 8.9 10.9
- --------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents 117.4 41.3
Restricted cash 16.6 11.3
Accounts receivable (less allowance of $5.5 million and $5.5 million,
respectively)
Service 80.4 80.2
Other 23.4 16.9
Accounts receivable, affiliates 22.1 6.8
Accrued unbilled revenue 77.8 78.3
Materials and supplies, at average cost
Gas in underground storage 33.1 32.1
Operating materials 10.6 13.1
Prepayments and other 19.7 24.1
- --------------------------------------------------------------------------------------------------------------------
401.1 304.1
- --------------------------------------------------------------------------------------------------------------------
NOTE RECEIVABLE FROM AFFILIATE 2,271.4 2,271.4
- --------------------------------------------------------------------------------------------------------------------
DEFERRED DEBITS
Transition period cost recovery 154.9 225.4
Other 143.5 143.9
- --------------------------------------------------------------------------------------------------------------------
298.4 369.3
- --------------------------------------------------------------------------------------------------------------------
$ 4,941.1 $ 4,861.1
- --------------------------------------------------------------------------------------------------------------------
CAPITAL AND LIABILITIES
CAPITALIZATION
Common stock -- No par value, 100,000,000 shares authorized; 75,643,937 shares
issued, stated at $ 1,274.1 $ 1,274.1
Additional paid-in capital 8.9 7.8
Retained earnings - accumulated since 1/1/99 390.2 233.6
Accumulated other comprehensive income (loss), net of tax (13.4) -
Less -- Capital stock expense 7.2 7.2
Less -- 12,751,724 shares of common stock in treasury, at cost 286.4 286.4
- --------------------------------------------------------------------------------------------------------------------
Total common stock equity 1,366.2 1,221.9
Preferred stock 45.8 45.8
Long-term debt 1,718.8 1,605.6
- --------------------------------------------------------------------------------------------------------------------
Total capitalization 3,130.8 2,873.3
- --------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Accounts payable 66.1 70.9
Accounts payable, affiliates 18.3 14.7
Notes payable 100.0 278.2
Long-term debt maturing within one year 276.4 182.1
Taxes accrued 48.5 64.3
Interest accrued 15.4 16.5
Other 80.1 78.9
- --------------------------------------------------------------------------------------------------------------------
604.8 705.6
- --------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS
Accumulated deferred income taxes 1,038.2 1,086.6
Accumulated deferred investment tax credits 21.2 22.6
Other 146.1 173.0
- --------------------------------------------------------------------------------------------------------------------
1,205.5 1,282.2
- --------------------------------------------------------------------------------------------------------------------
$ 4,941.1 $ 4,861.1
====================================================================================================================

(Commitments and Contingencies Note 6)
See notes to consolidated financial statements, which are an integral part of
these statements.

F-4

ILLINOIS POWER COMPANY
- ----------------------

C O N S O L I D A T E D S T A T E M E N T S O F I N C O M E
- -----------------------------------------------------------------
A N D C O M P R E H E N S I V E I N C O M E
- -----------------------------------------------

- ---------------------------------------------------------------------------------------------------
(Millions of dollars)
- ---------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2002 2001 2000

OPERATING REVENUES
Electric $ 1,138.8 $ 1,137.1 $ 1,189.4
Electric interchange 7.1 0 .7 2.7
Gas 372.4 476.6 393.5
- ---------------------------------------------------------------------------------------------------
Total 1,518.3 1,614.4 1,585.6
- ---------------------------------------------------------------------------------------------------

OPERATING EXPENSES AND TAXES
Power purchased 677.5 661.8 729.3
Gas purchased 231.7 332.8 252.7
Other operating expenses 140.2 142.3 143.5
Retirement and severance expense (0.7) 15.3 31.0
Maintenance 53.9 54.6 57.7
Depreciation and amortization 80.7 80.9 77.6
Amortization of regulatory assets 74.1 51.2 50.6
General taxes 57.6 68.4 74.0
Income taxes 39.3 40.6 13.2
- ---------------------------------------------------------------------------------------------------
Total 1,354.3 1,447.9 1,429.6
- ---------------------------------------------------------------------------------------------------
Operating income 164.0 166.5 156.0
- ---------------------------------------------------------------------------------------------------

OTHER INCOME AND DEDUCTIONS - NET
Interest income from affiliates 170.4 171.0 175.3
Miscellaneous - net (61.3) (49.5) (58.6)
- ---------------------------------------------------------------------------------------------------
Total 109.1 121.5 116.7
- ---------------------------------------------------------------------------------------------------
Income before interest charges 273.1 288.0 272.7
- ---------------------------------------------------------------------------------------------------

INTEREST CHARGES
Interest expense 112.9 123.5 139.1
Allowance for borrowed funds used during construction (0.5) (1.7) (1.3)
- ---------------------------------------------------------------------------------------------------
Total 112.4 121.8 137.8
- ---------------------------------------------------------------------------------------------------

Net income 160.7 166.2 134.9
Less -- Preferred dividend requirements 2.3 8.3 13.9
- ---------------------------------------------------------------------------------------------------
Net income applicable to common shareholder $ 158.4 $ 157.9 $ 121.0
===================================================================================================

Net income $ 160.7 $ 166.2 $ 134.9
Other comprehensive income (loss), net of tax (13.4) - -
- ---------------------------------------------------------------------------------------------------
Comprehensive income $ 147.3 $ 166.2 $ 134.9
===================================================================================================

See notes to consolidated financial statements, which are an integral part of
these statements.

F-5

ILLINOIS POWER COMPANY
- ----------------------

C O N S O L I D A T E D S T A T E M E N T S O F C A S H F L O W S
- -------------------------------------------------------------------------

- ---------------------------------------------------------------------------------------------------
(Millions of dollars)
- ---------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2002 2001 2000

CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 160.7 $ 166.2 $ 134.9
Items not affecting cash flows from operating
activities --
Depreciation and amortization 161.8 138.0 134.9
Deferred income taxes (44.3) (25.6) 55.3
Changes in assets and liabilities resulting from
operating activities --
Accounts receivable (22.0) 116.8 (29.0)
Accrued unbilled revenue 0.5 38.4 (33.3)
Materials and supplies 1.5 5.2 (9.4)
Prepayments 0.1 4.1 68.8
Accounts payable (1.2) (65.5) 58.8
Other deferred credits (38.7) (42.3) (43.3)
Interest accrued and other, net (9.0) 9.7 43.6
- ---------------------------------------------------------------------------------------------------
Net cash provided by operating activities 209.4 345.0 381.3
- ---------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (144.5) (148.8) (157.8)
Proceeds from note receivable, affiliate - - 335.5
Other investing activities 3.4 2.1 (4.8)
- ---------------------------------------------------------------------------------------------------
Net cash provided by (used in) investing activities (141.1) (146.7) 172.9
- ---------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on common stock and preferred stock (2.8) (108.3) (13.4)
Redemptions --
Short-term debt (238.2) (346.8) (429.1)
Long-term debt (182.1) (273.2) (268.4)
Preferred stock - (100.0) (93.1)
Issuances --
Short-term debt 60.0 477.2 249.6
Long-term debt 400.0 186.8 -
Decrease (increase) in restricted cash (5.3) 1.2 -
Other financing activities (23.8) (5.5) 0.8
- ---------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 7.8 (168.6) (553.6)
- ---------------------------------------------------------------------------------------------------
Net change in cash and cash equivalents 76.1 29.7 0.6
Cash and cash equivalents at beginning of year 41.3 11.6 11.0
- ---------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 117.4 $ 41.3 $ 11.6
===================================================================================================

See notes to consolidated financial statements, which are an integral part of
these statements.

F-6

ILLINOIS POWER COMPANY
- ----------------------

C O N S O L I D A T E D S T A T E M E N T S O F R E T A I N E D
- ------------------------------------------------------------------
E A R N I N G S
- ---------------

- ---------------------------------------------------------------------------------------------------
(Millions of dollars)
- ---------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2002 2001 2000

Balance at beginning of year $ 233.6 $ 175.7 $ 54.7
Net income 160.7 166.2 134.9
- ---------------------------------------------------------------------------------------------------
394.3 341.9 189.6
- ---------------------------------------------------------------------------------------------------
Less--
Dividends-
Preferred stock 2.3 8.3 13.9
Common stock 0.5 100.0 -
Preferred stock tender charges 1.3 - -
- ---------------------------------------------------------------------------------------------------
4.1 108.3 13.9
- ---------------------------------------------------------------------------------------------------
Balance at end of year $ 390.2 $ 233.6 $ 175.7
===================================================================================================

See notes to consolidated financial statements, which are an integral part of
these statements.

F-7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- ------------------------------------------

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
- ---------------------------------------------------

PRINCIPLES OF CONSOLIDATION We are an indirect, wholly owned subsidiary of
Dynegy Inc. All of our outstanding common equity and 73% of our outstanding
preferred stock is held by our parent company, Illinova, which is a wholly owned
subsidiary of Dynegy. We are engaged in the transmission, distribution and sale
of electric energy and distribution, transportation and sale of natural gas in
the State of Illinois. Our consolidated financial statements include the
accounts of IP; Illinois Power Financing I, a statutory business trust in which
we serve as sponsor (inactive as of September 30, 2001); Illinois Power
Financing II, a statutory business trust in which we serve as sponsor that is
currently inactive; Illinois Power Securitization Limited Liability Company
("LLC"), a Delaware special purpose limited liability company in which we are
the sole member; Illinois Power Special Purpose Trust, a Delaware special
purpose business trust whose sole owner is LLC; and Illinois Power Transmission
Company LLC, a limited liability Delaware company that is currently inactive.
See "Note 9 - Long-Term Debt" on page F-24 and "Note 10 - Preferred Stock" on
page F-26 for additional information.

All significant intercompany balances and transactions have been eliminated
from the consolidated financial statements. The preparation of the consolidated
financial statements in conformity with generally accepted accounting principles
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, the disclosure of contingent assets and
liabilities and the reported amounts of revenues and expenses during the
reporting period. On an ongoing basis, management reviews its estimates, and any
changes in facts and circumstances may result in revised estimates. Actual
results could differ materially from those estimates. Certain prior year amounts
have been reclassified to conform to the current year presentation.

CLINTON IMPAIRMENT, QUASI-REORGANIZATION AND SALE OF CLINTON In December 1998,
IP's Board of Directors decided to exit Clinton operations, resulting in an
impairment of Clinton-related assets and the accrual of exit-related costs.
Concurrent with the decision to exit Clinton, IP's Board of Directors also
decided to effect a quasi-reorganization, whereby IP's consolidated accumulated
deficit in retained earnings at December 31, 1998 was eliminated. On December
15, 1999, IP sold Clinton to AmerGen. The sale resulted in revisions to the
impairment of Clinton-related assets and the previously accrued exit-related
costs. All such revisions were made directly to common stock equity on the
balance sheet.

UTILITY PLANT The cost of additions to plant and replacements for retired
property units is capitalized. Cost includes labor, materials, and an allocation
of general and administrative costs, plus AFUDC or capitalized interest as
described below. Maintenance and repairs, including replacement of minor items
of property, are charged to maintenance expense as incurred. When depreciable
property units are retired, the original cost and dismantling charges, less
salvage value, are charged to accumulated depreciation.

Rate regulated companies subject to FAS 71, "Accounting for the Effects of
Certain Types of Regulation," are allowed to record the estimated or actual cost
of removal and salvage associated with utility plant in the reserve for
depreciation. These amounts are recorded through a composite depreciation rate.
The amounts accrued in the reserve for depreciation are not associated with
Asset Retirement Obligations in accordance with FAS 143, "Accounting for Asset
Retirement Obligations", which we adopted January 1, 2003. We estimate that as
of the date of adoption, approximately $68.7 million of cost of removal, net of
salvage, allowed under rate regulation is included in the depreciation reserve
for utility plant.

ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION The FERC Uniform System of
Accounts defines AFUDC as the net costs for the period of construction of
borrowed funds used for construction purposes and a reasonable rate on other
funds when so used. AFUDC is capitalized as a component of construction work in
progress in applying the provisions of FAS 71. In 2002, 2001 and 2000, the
pre-tax rate used for all construction projects was 2.9%, 4.8% and 6.8%,
respectively. Although cash is not currently realized from AFUDC, it is realized
through the ratemaking process over the service life of the related property
through increased revenues resulting from a higher rate base and higher
depreciation expense.

F-8

DEPRECIATION For financial statement purposes, various classes of depreciable
property are depreciated over their estimated useful lives by applying composite
rates on a straight-line basis. Provisions for depreciation for electric plant
facilities, as a percentage of the average depreciable cost, were 2.2%, 2.3% and
2.3% in 2002, 2001 and 2000, respectively. Provisions for depreciation of gas
utility plant, as a percentage of the average depreciable cost, were 3.5% in
2002, 3.5% in 2001 and 3.6% in 2000.

NOTE RECEIVABLE FROM AFFILIATE We hold an unsecured note receivable due from
our parent, Illinova, a wholly owned subsidiary of Dynegy, relating to the
transfer of our former fossil-fueled generating assets. The note matures on
September 30, 2009 and bears interest at an annual rate of 7.5%, due
semi-annually in April and October. At December 31, 2002 and 2001, principal
outstanding under the note receivable approximated $2.3 billion. At December 31,
2002, accrued interest approximated $14.2 million, while at December 31, 2001
there was no accrued interest.

We review the collectibility of this note on a quarterly basis to assess
whether it has become impaired under the criteria of FAS 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. However, if the possibility that we would not be able to
collect all amounts due under the contractual terms were only "more likely than
not" or "reasonably possible," but not "probable," then the Note Receivable from
Affiliate would not be considered impaired under FAS 114. The use of the
terms "probable," "reasonably possible" and "more likely than not" are used in
FAS No. 5, "Accounting for Contingencies," as follows:

o Reasonably possible - The chance of the future event or events
occurring is more than remote but less than likely.

o More likely than not - A level of likelihood that is more than 50%.

o Probable - Future events are likely to occur.

While we believe that the note is not impaired and is fully collectible in
accordance with its contractual terms based upon, among other things, our review
of Dynegy's restructuring plan and the results of various analyses that we have
performed as to the value of Dynegy's assets related to its outstanding debt, we
expect to continue to review the collectibility of the note on a quarterly
basis. Principal payments of the note 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. While the fair
value of the Note Receivable from Affiliate, based on quoted market prices for
Dynegy's publicly traded unsecured debt securities at December 31, 2002, was
significantly less than $2.3 billion, our collectibility analysis under FAS 114
indicates that the note was not impaired. Accordingly, we have reflected the
note on our December 31, 2002 Consolidated Balance Sheet at $2.3 billion. It is
possible that if negative events affect Dynegy or if we do not receive timely
interest payments on the Note Receivable from Affiliate, such matters could
cause us to believe it necessary to impair the Note Receivable from Affiliate on
our Consolidated Balance Sheet and such action could have a material adverse
affect on our liquidity, financial condition and results of operations. See
further discussion in "Note 5 - Related Parties" and "Note 14 - Fair Value of
Financial Instruments."

This assessment is highly subjective given the inherent uncertainty of
predicting future events. We will evaluate that range of likelihood of
collectibility of the Note Receivable from Affiliate on a quarterly basis. In
the future, should we conclude an impairment has occurred, we would measure the
note's realizable value based on a probability weighted analysis of multiple
expected future cash flows discounted at the note's effective interest rate of
7.5%, as opposed to a market rate of interest, in accordance with FAS 114.

REGULATION AND REGULATORY ASSETS We are regulated primarily by the ICC and the
FERC. We prepare our consolidated financial statements in accordance with FAS
71. Reporting under FAS 71 requires companies like ours, whose service
obligations and prices are regulated, to maintain balance sheet assets
representing costs probable of recovery through inclusion in future rates.
Regulatory assets represent probable future revenues associated with costs that
are expected to be recovered from customers through the ratemaking process.
Significant regulatory assets, which are included in Deferred Debits on our
Consolidated Balance Sheets are:

F-9

- -------------------------------------------------------------------
(Millions of dollars) 2002 2001
- -------------------------------------------------------------------

Transition period cost recovery $154.9 $225.4
Unamortized losses on reacquired debt 53.6 60.1
Manufactured-gas plant site cleanup costs 39.7 39.1
Clinton decommissioning cost recovery 8.0 11.7
------ ------
Totals $256.2 $336.3
------ ------

TRANSITION PERIOD COST RECOVERY P.A. 90-561 allows utilities to recover
potentially non-competitive investment costs ("stranded costs") from retail
customers during the transition period, which extends until December 31, 2006.
During this period, we are allowed to recover stranded costs through frozen
bundled rates and transition charges from customers who select other electric
suppliers. In May 1998, the SEC Staff issued interpretive guidance on the
appropriate accounting treatment during regulatory transition periods for asset
impairments and the related regulated cash flows designed to recover such
impairments. The Staff's guidance established that an impaired portion of plant
assets identified in a state's legislation or rate order for recovery through
regulated cash flows should be treated as a regulatory asset in the portion of
the enterprise from which the regulated cash flows are derived. Based on this
guidance and on provisions of P.A. 90-561, we recorded a regulatory asset of
$457.3 million in December 1998 for the portion of our stranded costs deemed
probable of recovery during the transition period. Subsequent adjustments
related to the sale of the Clinton Power Station reduced the regulatory asset by
$115.9 million to $341.4 million. The amount of amortization recorded in each
period is based on the recovery of such costs from rate payers as measured by
our ROE. The transition period cost recovery asset amortization was $70.5
million in 2002, $47.4 million in 2001, and $47.5 million in 2000. The increase
in amortization of the transition period cost recovery regulatory asset for 2002
is due to increased financial performance, which allowed us to recognize
additional regulatory asset amortization and stay within the allowable ROE
collar. See "Note 6 - Commitments and Contingencies" on page F-17 for additional
information on the transition period cost recovery regulatory asset.

UNAMORTIZED LOSSES ON REACQUIRED DEBT In accordance with FAS 71, costs related
to refunded debt are amortized over the lives of the related new debt issues or
the remaining life of the old debt if no new debt is issued.

MANUFACTURED-GAS PLANT SITE CLEANUP COSTS The regulatory asset for the
probable future collections from rate payers of allowable MGP site cleanup costs
is amortized as the allowable costs are collected from rate payers. See "Note 6
- - Commitments and Contingencies" on page F-18 for additional information.

CLINTON DECOMMISSIONING COST RECOVERY As a result of the sale of Clinton to
AmerGen, AmerGen has assumed responsibility for operating and ultimately
decommissioning the power plant. When the sale closed in December 1999, we were
required to transfer decommissioning trust funds in the amount of $98.5 million
to AmerGen and to make an additional payment of $113.4 million to the
decommissioning trust funds. In addition, we agreed to make five annual payments
of approximately $5.0 million through 2004, of which three payments have been
made through December 2002. The accrual balances for decommissioning costs at
December 31, 2002 and 2001 were $9.9 million and $14.9 million, respectively.

- -------------------------------------------------------------------
Decommissioning costs (Millions of dollars) 2002 2001
- -------------------------------------------------------------------

Accrual balance, beginning of period $14.9 $19.9
Cash payments (5.0) (5.0)
----- -----
Accrual balance, end of period $ 9.9 $14.9
----- -----

The ICC has allowed for continued recovery of decommissioning costs
associated with Clinton after the sale to AmerGen. We adjusted the regulatory
asset for probable future collections from our customers of decommissioning
costs to reflect the ICC's limitation on recovery of such costs to approximately
$3.7 million annually through 2004. At December 31, 2002 and 2001, the
regulatory asset balances were $8.0 million and $11.7 million, respectively. The

F-10

regulatory asset for the probable future collections from rate payers of
decommissioning costs is amortized as the decommissioning costs are collected
from rate payers.

UNAMORTIZED DEBT DISCOUNT AND EXPENSE Discount and expense associated with
long-term debt are amortized over the lives of the related issues.

POWER PURCHASE AGREEMENT COSTS The Clinton sale was contingent on our signing
a PPA with AmerGen. The PPA requires that we purchase a predetermined percentage
of Clinton's output over the 5-year life of the agreement at fixed prices that
exceed current and projected wholesale prices. Therefore, we accrued $145.0
million for the premium that we estimate would be paid over the life of the
agreement, which is being amortized based on the energy purchased from AmerGen.
At December 31, 2002 and 2001, $30.4 million and $27.4 million, respectively,
are included in other current liabilities and $29.5 million and $60.1 million,
respectively, are included in Other Deferred Credits in the accompanying
Consolidated Balance Sheets.

- --------------------------------------------------------------------------------
Power purchase agreement costs (Millions of dollars) 2002 2001
- --------------------------------------------------------------------------------

Accrual balance, beginning of period $ 87.5 $118.0
Amortization (27.6) (30.5)
------ ------
Accrual balance, end of period $ 59.9 $ 87.5
------ ------

REVENUE RECOGNITION AND ENERGY COST Revenues for utility services are
recognized when services are provided to customers. As such, we record revenues
for services provided but not yet billed. Unbilled revenues represent the
estimated amount customers will be billed for service delivered from the time
meters were last read to the end of the accounting period.

In 2002, 2001 and 2000, public utility and municipal utility taxes included
in operating revenues were $17.3 million, $19.4 million and $23.1 million,
respectively.

The cost of gas purchased to serve our native load is recovered from
customers pursuant to the UGAC. Accordingly, allowable gas costs that are to be
passed on to customers in a subsequent accounting period are deferred. The
recovery of costs deferred under this clause is subject to review and approval
by the ICC.

INCOME TAXES We provide deferred income taxes for the temporary differences in
the tax and financial reporting bases of our assets and liabilities in
accordance with FAS 109, "Accounting for Income Taxes." The temporary
differences relate principally to net utility plant in service and depreciation.

ITCs used to reduce federal income taxes have been deferred and are being
amortized to income over the service life of the property that gave rise to the
credits.

We are included in the consolidated federal income tax and combined state tax
returns of Dynegy in 2002, 2001 and 2000. Under our Services and Facilities
income tax allocation agreement with Dynegy, we calculate our own tax liability
under the separate return approach and reimburse Dynegy for such amount. See
"Note 8 - Income Taxes" on page F-21 for additional information about our income
taxes.

PREFERRED DIVIDEND REQUIREMENTS Our preferred dividend requirements are
recorded on the accrual basis and reflected in the Consolidated Statements of
Income and Comprehensive Income.

OTHER COMPREHENSIVE INCOME On December 31, 2002, our annual measurement date,
the accumulated benefit obligation related to our pension plans exceeded the
fair value of the pension plan assets. This difference is attributed to (1) an
increase in the accumulated benefit obligation that resulted from the decrease
in the discount rate and the expected long-term rate of return and (2) a decline
in the fair value of the plan assets due to a sharp decrease in the equity
markets through December 31, 2002. As a result, in accordance with FAS 87,
"Employers' Accounting for Pensions", we

F-11

recognized a charge to other comprehensive income in 2002 of $22.2 million
($13.4 million after-tax), which decreased common stock equity.

DERIVATIVE INSTRUMENTS During 2002, 2001 and 2000, all of our purchase
contracts qualified for the normal purchase and sale exemption within FAS 133,
"Accounting for Derivative Instruments and Hedging Activities" and, therefore,
we accounted for such contracts under the accrual method. We had no other
derivative instruments qualifying under FAS 133 during these years.

CONSOLIDATED STATEMENTS OF CASH FLOWS Cash and cash equivalents include cash
on hand and temporary investments purchased with an initial maturity of three
months or less. We had cash and cash equivalents of $117.4 million, $41.3
million and $11.6 million at December 31, 2002, 2001 and 2000, respectively.

Income taxes and interest paid are as follows:

(Millions of dollars)
- -----------------------------------------------------------------
Years Ended December 31, 2002 2001 2000
- -----------------------------------------------------------------

Income taxes $151.1 $116.4 $ -
Interest $106.3 $121.1 $139.7

There were no material non-cash investing or financing activities in 2002,
2001 or 2000.

RESTRICTED CASH This cash is reserved for use in paying off the Transitional
Funding Trust Notes issued under the provisions of P.A. 90-561. See "Note 9 -
Long-Term Debt" on page F-24, for additional discussion of the Transitional
Funding Trust Notes. The amount of restricted cash was $16.6 million at December
31, 2002 and $11.3 million at December 31, 2001.

EMPLOYEE STOCK OPTIONS As permitted by FAS 123, "Accounting for Stock-Based
Compensation," we apply the provisions of APB Opinion No. 25, "Accounting for
Stock Issued to Employees" ("APB No. 25") and related interpretations in
accounting for our stock compensation plans. Accordingly, compensation expense
is not recognized for stock options unless the options were granted at an
exercise price lower than the market value on the grant date. If the options
were granted at an exercise price lower than the market value on the grant date,
the compensation expense is recognized over the vesting period. Additionally, in
2001, a charge of $0.6 million was incurred and recorded as compensation expense
due to the extension of the exercise period and the acceleration of vesting for
certain stock options due to the early retirement and severance components of
our corporate reorganization as more fully discussed in "Note 2 - Business
Combination and Reorganization" on page F-14. Pursuant to the Dynegy-Illinova
merger, all stock options granted to our employees prior to the merger were
converted to options to purchase Dynegy Class A common stock on a one-for-one
basis. The December 2002 issuance of FAS 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure" as discussed below, amends the
disclosure requirements of FAS 123. As described above, we account for our stock
option plan in accordance with APB No. 25 and plan to transition to a fair
value-based method of accounting. We will use the prospective method of
transition as described in FAS 148.

Had compensation expense for stock options held by our employees been
recognized based on the fair value on the grant date under the methodology
prescribed by FAS 123, our net income applicable to common stock for the three
years ended December 31, would have been impacted as shown in the following
table (millions of dollars).

2002 2001 2000
---- ---- ----

Reported net income $160.7 $166.2 $134.9
Less: pro forma expense, net-of-tax 4.6 3.9 1.8
------ ------ ------
Pro forma net income $156.1 $162.3 $133.1
------ ------ ------

See "Note 11 - Common Stock and Retained Earnings" on page F-27 for
additional information.

F-12

ACCOUNTING PRONOUNCEMENTS In June 2001, the FASB issued FAS No. 143,
"Accounting for Asset Retirement Obligations." FAS 143, which was adopted
January 1, 2003, requires that the fair value of a liability for an asset
retirement obligation be recognized in the period in which it is incurred with
the associated asset retirement costs being capitalized as a part of the
carrying amount of the long-lived asset. FAS 143 also includes disclosure
requirements that provide a description of asset retirement obligations and
reconciliation of changes in the components of those obligations.

In order to ascertain whether a legal obligation exists associated with the
retirement of our long-lived assets, we identified all facilities and their
assets by functional classification. We reviewed those assets for obligations
that may have resulted from enacted laws, state and federal regulation,
ordinances, written and oral contracts and other applications of law. Two AROs
were identified in connection with our operating lease agreement for four gas
turbines and a separate land lease at the Tilton site. The turbine assets are
sublet to DMG; however we remain the primary obligor. In that capacity we are
liable for retiring the assets in place or dismantling them for sale and
delivery to a third party if we do not exercise our option to purchase the
assets or renegotiate the lease. At the expiration of the land lease, we may
have the obligation to restore the property to its original condition. The AROs
were calculated based on cash flows, through a process that included assessment
of the timing of future retirements, the retirement method and estimated cost,
the credit-adjusted risk-free rate and development of other significant
assumptions. The credit-adjusted risk-free rate utilized was 12%, which
represents the effective interest rate on our Mortgage bonds that were issued
December 2002. Upon adoption, the cumulative effect, net of the associated
income taxes, was approximately $2.4 million. The ARO liability for the asset
operating lease and the land lease, to be recorded during the first quarter
2003, was $5.8 million. Amortization and accretion expense for 2003 is expected
to be approximately $1.2 million.

In August 2001, the FASB issued FAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." FAS 144 addresses the accounting and
reporting for the impairment or disposal of long-lived assets and supersedes FAS
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of
Operations - Reporting the Effects of Disposal of a Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions." The
objective of FAS 144 is to establish one accounting model for long-lived assets
to be disposed of by sale as well as resolve implementation issues related to
FAS 121. We adopted FAS 144 on January 1, 2002 with no impact on our financial
position or results of operations.

In April 2002, the FASB issued FAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." This Statement rescinds FASB Statement No. 4, "Reporting Gains and
Losses from Extinguishment of Debt", and an amendment of that Statement, FASB
Statement No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund
Requirements." This Statement also rescinds FASB Statement No. 44, "Accounting
for Intangible Assets of Motor Carriers." The Statement amends FASB Statement
No. 13, "Accounting for Leases", to eliminate inconsistency between the required
accounting for sale-leaseback transactions and the required accounting for
certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. This Statement also amends other existing
authoritative pronouncements to make various technical corrections, clarify
meanings, or describe their applicability under changed conditions. We adopted
FAS 145 on January 1, 2003 with no impact on our financial statements or results
of operations.

In June 2002, the FASB issued FAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities." FAS 146 addresses significant issues
regarding the recognition, measurement and reporting of costs that are
associated with exit and disposal activities, including restructuring activities
that are currently accounted for pursuant to the guidance that the Emerging
Issues Task Force ("EITF" or the "Task Force") has set forth in EITF Issue No.
94-3, "Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." The scope of FAS 146 also includes (1) costs related to
terminating a contract that is not a capital lease and (2) termination benefits
that employees who are involuntarily terminated receive under the terms of a
one-time benefit arrangement that is not an ongoing benefit arrangement or an
individual deferred compensation contract. FAS 146 will be effective for exit or
disposal activities that are initiated after December 31, 2002.

F-13

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others", an interpretation of FASB statements No.
5, 57, and 107 and rescission of FASB Interpretation No. 34. FIN 45 clarifies
the requirements of FASB Statement No. 5, "Accounting for Contingencies",
relating to a guarantor's accounting for, and disclosure of, the issuance of
certain types of guarantees. FIN 45 requires that upon issuance of a guarantee,
the guarantor must recognize a liability for the fair value of the obligation it
assumes under that guarantee, and is effective for guarantees issued or modified
after December 31, 2002, with certain disclosures required immediately. As
required by FIN 45, we adopted the disclosure requirements on December 31, 2002
(See Note 6 - Commitments and Contingencies), and we will adopt the initial
recognition and measurement provisions on a prospective basis for guarantees
issued or modified after December 31, 2002. We do not expect the adoption of FIN
45 to have a material effect on our financial position or results of operations.

In December 2002, the FASB issued FAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure." FAS 148 amends the disclosure
requirements of Statement No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used on reporting
results. This statement provides alternative methods of transition (prospective,
modified prospective, or retroactive) for a voluntary change to the fair
value-based method of accounting for stock-based employee compensation and
specifies the form, content and location of the required disclosures. FAS 148
does not permit the use of the original Statement 123 prospective method of
transition for changes to the fair value based method made in fiscal years
beginning after December 15, 2003. We account for our stock option plan in
accordance with APB No. 25 and plan to transition to a fair value-based method
of accounting. We will use the prospective method of transition as described in
FAS 148.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities - an interpretation of ARB No. 51" ("FIN 46"). FIN 46
addresses the consolidation of "variable interest entities" having certain
characteristics. In summary, this interpretation increases the level of risk
that must be assumed by equity investors in special purpose entities. FIN 46
requires that the equity investor have significant equity at risk (minimum of
10% with few exceptions, increased from 3% under previous guidance) and hold a
controlling interest, evidenced by voting rights, risk of loss and the benefit
of residual returns. If the equity investor is unable to evidence these
characteristics, the entity that does retain these ownership characteristics
will consolidate the variable interest entity. We are in the process of
evaluating the impact of FIN 46. While we have not entered into any arrangement
in 2003 that would be subject to FIN 46, we may have existing arrangements that
are impacted. FIN 46 is applicable immediately to variable interest entities
created or obtained after January 31, 2003. For variable interest entities
acquired before February 1, 2003, FIN 46 is applicable as of July 1, 2003.

NOTE 2 - BUSINESS COMBINATION AND REORGANIZATION
- ------------------------------------------------

Dynegy completed its acquisition of Illinova on February 1, 2000. The merger of
Dynegy and Illinova involved the creation of a new holding company, now known as
Dynegy Inc., and two separate but concurrent mergers. In one merger, a wholly
owned subsidiary of Dynegy Inc. merged with and into Illinova. In the other
merger, a second wholly owned subsidiary of Dynegy Inc. merged with and into
former Dynegy. As a result of these two concurrent mergers, Illinova and former
Dynegy continue to exist as wholly owned subsidiaries of Dynegy Inc. and are
referred to as Illinova Corporation and Dynegy Holdings Inc., respectively.
Dynegy accounted for the acquisition as a purchase of Illinova. As a result, the
consolidated financial statements of Dynegy after the merger reflect the assets
and liabilities of Illinova at allocated fair values. We continue to be a wholly
owned subsidiary of Illinova. For accounting purposes, the effective date of the
merger was January 1, 2000.

Our consolidated financial statements were prepared on the historical cost
basis and do not reflect an allocation of the purchase price to us that was
recorded by Dynegy as a result of the merger. Push down accounting was not
required because we had publicly held debt and preferred stock outstanding.

As part of the merger, severance and early retirement costs of $31.0 million
($18.6 million after-tax) were recorded in 2000. Severance charges represented
approximately $19.8 million ($11.9 million after-tax) of the total costs

F-14

incurred. As a result of the merger, 284 employees were either severed or have
retired. This severance/retirement plan and related actions were substantially
completed by December 31, 2000.

We subsequently implemented a corporate restructuring in November 2001 that
affected departments throughout the organization. As part of the restructuring,
severance and early retirement costs of $15.3 million ($9.2 million after-tax)
were recorded in 2001. Severance charges represented approximately $5.3 million
($3.2 million after-tax) of the total costs incurred, of which $4.5 million had
been paid by the end of 2002 as compared to $.2 million by the end of 2001.
Adjustments made in 2002 relate to expenses accrued for the 2001 and 2000
severance plans that will not be paid out. These expenses were accrued using the
best data available at the time, but upon review, such expenses were not
incurred. As of December 31, 2002, 98 employees were either severed or elected
early retirement as a result of the restructuring. The severance/retirement plan
and related actions were substantially completed by December 31, 2002.

The following table provides the summary of the activity for the liabilities
associated with our severance programs (millions of dollars):

2002 2001
---- ----

Balance, beginning of period $ 5.4 $ .8
Severance:
2001 provision - 5.3
Adjustments (1.2) .2
Cash payments (3.6) (.9)
------ -----
Balance, end of period $ .6 $ 5.4
------ -----

NOTE 3 - LIQUIDITY
- ------------------

We have a significant amount of leverage, with near-term maturities including
the following:

o $100 million due on our one- year term loan in May 2003;

o $100 million in mortgage bond maturities in August 2003;

o $90 million in mortgage bond maturities in September 2003; and

o $21.6 million due quarterly in 2003 for repayment of our transitional
funding trust notes.

Because we have no revolving credit facility and no access to the commercial
paper markets, we rely on cash on hand, cash from liquidity initiatives and cash
flows from operations, including interest payments under our $2.3 billion
intercompany note receivable from Illinova, our direct parent company and a
wholly owned Dynegy subsidiary ("Note Receivable from Affiliate"), to satisfy
our debt obligations and to otherwise operate our business. We will use the
remaining cash proceeds from a December 2002 mortgage bond offering to pay off
our term loan and to pay a substantial portion of our August and September 2003
mortgage bond maturities. In addition to this source of liquidity, we believe
that we have sufficient capital resources through cash flow from operations,
proceeds from one or more additional liquidity initiatives, including new bank
borrowings or mortgage bond issuances and, if necessary, additional liquidity
support which has been committed by Dynegy to pay the remainder of these
maturities and to otherwise satisfy our obligations over the next twelve months.
Although Dynegy's recently restructured credit facility, which expires in
February 2005, prohibits it from prepaying more than $200 million in principal
under our Note Receivable from Affiliate during the term of the credit
agreement, it does not limit Dynegy's ability to prepay interest under the Note
Receivable from Affiliate.

Our ability to successfully execute one or more of these initiatives is
subject to a number of risks. These risks include, among others, the ability to
successfully negotiate a new revolving credit facility and the financial effects
of our relationship with Dynegy. You are encouraged to read Dynegy's Annual
Report on Form 10-K for the year ended December 31, 2002 for additional
information regarding Dynegy and its current liquidity position.

F-15

NOTE 4 - TRANSMISSION SALE
- --------------------------

We own, but have previously announced an agreement to sell, a 1,672 circuit mile
electric transmission system. The closing of the proposed sale to Trans-Elect
Inc., an independent transmission company, is conditioned on several matters,
including the receipt of required approvals from the SEC under the PUHCA, the
Federal Trade Commission, the ICC and the FERC. With respect to the FERC, the
sale was conditioned on its approving the levelized rates application filed by
Trans-Elect seeking a 13% return on equity (based on a capital structure of
equal portions of debt and equity), which would result in a significant increase
in transmission rates over the rates we currently charge. On February 20, 2003,
the FERC voted to defer approval of the transaction and ordered a hearing to
establish the allowable transmission rates for Trans-Elect. Specifically, the
FERC stated that the benefits of the transaction, including independent
transmission ownership, may not justify the significant increase in rates
sought. The FERC also limited the period for which we could provide operational
services to Trans-Elect to one year.

Trans-Elect and IP have since withdrawn the rate filing at the FERC and
requested a continuance of the hearing pending an order on a rehearing and a
ruling by the FERC on a new rate application. Pending resolution of the FERC
issues, the ICC proceedings have also been withdrawn and continued. We are
currently in discussions with Trans-Elect to determine the impact of the FERC
order on the transaction and to determine the course of action the parties will
take. Under the sale agreement, if the transaction does not close on or before
July 7, 2003, either party can terminate the agreement. Because of the lead time
required for regulatory approvals, it is unlikely that the transaction could be
closed by July 7th.

NOTE 5 - RELATED PARTIES
- ------------------------

Effective October 1, 1999, we transferred our wholly owned fossil generating
assets and other generation-related assets and liabilities at net book value to
Illinova in exchange for an unsecured note receivable of approximately $2.8
billion. Such assets were subsequently contributed by Illinova to IPMI, which
was later renamed DMG. Effective August 31, 2001, approximately $9.3 million of
additional fossil generation-related assets were transferred to Illinova and the
unsecured note receivable was adjusted accordingly. The note matures on
September 30, 2009 and bears interest at an annual rate of 7.5%, due
semiannually in April and October. At December 31, 2002, principal outstanding
under the note receivable approximated $2.3 billion with $14.2 million of
accrued interest. At December 31, 2001, principal outstanding under the note
receivable approximated $2.3 billion with no accrued interest due to a
prepayment in the fourth quarter. We have recognized $170.4 million interest
income from Illinova on the note in 2002, $169.9 million in 2001 and $174.9
million in 2000. Under the terms of Dynegy's restructured credit agreement,
which expires in February 2005, principal prepayments on the note cannot exceed
$200 million during the term of the agreement; however, the agreement does not
limit Dynegy's ability to prepay interest on the Note Receivable from Affiliate.
We reviewed this Note Receivable from Affiliate for impairment at December 31,
2002. For a full discussion of the requirements and results of such impairment
analysis, please read "Note 1 - Summary of Significant Accounting Policies."
Please also read "Note 14 - Fair Value of Financial Instruments" for a
discussion of the Note Receivable's fair value.

We routinely conduct business with other subsidiaries of Dynegy. These
transactions include the purchase or sale of electricity, natural gas and
transmission services as well as certain other services. Operating revenue
derived from transactions with affiliates approximated $33.0 million for 2002,
$34.8 million for 2001 and $39.6 million for 2000. Aggregate operating expenses
charged by affiliates in 2002 approximated $530.5 million, including $486.4
million for power purchased. Aggregate operating expenses charged by affiliates
in 2001 approximated $526.6 million, including $459.7 million for power
purchased. Aggregate operating expenses charged by affiliates in 2000
approximated $628.0 million, including $557.9 million for power purchased.
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 FAS 133 and,
therefore, we have accounted for the PPA under the accrual method. The primary
term may be

F-16

extended on an annual basis, subject to concurrence by both parties. 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 compensate the
affiliate for capacity charges through 2004 at a total contract cost of $639.6
million. According to the PPA agreement 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.

Effective January 1, 2000, the Dynegy consolidated group, including us, began
operating under a Services and Facilities Agreement which was approved by the
ICC, whereby other Dynegy affiliates exchange services with us such as
financial, legal, information technology and human resources as well as shared
facility space. 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. 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 Rating Service and specific approval is
obtained from the ICC. The ICC also granted our request, subject to certain
conditions, to advance funds to service interest on Illinova Senior Notes
through February 2004, if Dynegy is not able to make such payments.

NOTE 6 - COMMITMENTS AND CONTINGENCIES
- --------------------------------------

COMMITMENTS We have contracts on six interstate pipelines for firm
transportation and storage services for natural gas. These contracts have
varying expiration dates ranging from 2003 to 2012, for a total cost of $80.6
million. We also enter into obligations for the reservation of natural gas
supply. These obligations generally range in duration from one to twelve months
and require us to reimburse capacity charges. The cost of the agreements is
$20.7 million. Total natural gas purchased was approximately $236 million in
2002 and $296 million in each of 2001 and 2000. We anticipate that all
gas-related costs will be recoverable under our UGAC.

UTILITY EARNINGS CAP P.A. 90-561 contains floor and ceiling provisions
applicable to our ROE during the mandatory transition period ending in 2006.
Pursuant to the provisions in the legislation, we may request an increase in our
base rates if the two-year average of our earned ROE is below the two-year
average of the Treasury Yield for the concurrent period. Conversely, we are
required to refund amounts to our customers equal to 50% of the value earned
above a defined "ceiling limit." The ceiling limit is exceeded if our two-year
average ROE exceeds the Treasury Yield, plus 8.5% in 2002 through 2006. In
December 2002, we filed to increase the add-on to the Treasury Yield from 6.5%
to 8.5%. Consequently, we may not request the collection of transition charges
in 2007 and 2008. Regulatory asset amortization is included in the calculation
of the ROE for the ceiling test but is not included in the calculation of the
ROE for the floor test. Prior to February 2002, the ROE test was based on the
two-year average of the monthly average yields of 30-year U.S. Treasury Bonds.
During 2002 and 2001, our two-year average ROE was within the allowable ROE
collar.

ENVIRONMENTAL MATTERS
- ---------------------

U.S. ENVIRONMENTAL PROTECTION AGENCY COMPLAINT IP and DMG (collectively, the
"Defendants") are currently the subject of a Notice of Violation ("NOV") from
the EPA and a complaint filed by the EPA and the Department of Justice alleging
violations of the Clean Air Act (the "Act") and the regulations promulgated
under the Act. Similar

F-17

notices and complaints have been filed against a number of other utilities. Both
the NOV and the complaint allege that certain equipment repairs, replacements
and maintenance activities at the Defendants' three Baldwin Station generating
units constituted "major modifications" under the Prevention of Significant
Deterioration ("PSD") and/or the New Source Performance Standards ("NSPS")
regulations. When activities that meet the definition of "major modifications"
occur and they are not otherwise exempt, the Act and related regulations
generally require that generating facilities meet more stringent emissions
standards, which may entail the installation of potentially costly pollution
control equipment. The Defendants filed an answer denying all claims and
asserting various specific defenses and a trial date of June 3, 2003 has been
set.

We believe that we have meritorious defenses to the EPA allegations and will
vigorously defend against these claims. DMG has undertaken activities to
significantly reduce emissions at the Baldwin Station since the complaint was
filed in 1999. In 2000, the Baldwin Station was converted from high to low
sulfur coal. This conversion resulted in sulfur dioxide emission reductions of
over 90% from 1999 levels. Furthermore, selective catalytic reduction equipment
has been installed at two of the three units at Baldwin Station resulting in
significant emission reductions of nitrogen oxides. However, the EPA may seek to
require the installation of the "best available control technology" (or the
equivalent) at the Baldwin Station. Independent experts hired by Dynegy estimate
capital expenditures of up to $410 million could be incurred if the installation
of best available control technology is required. The EPA also has the authority
to seek penalties for the alleged violations in question at the rate of up to
$27,500 per day for each violation. On February 18, 2003, the Court granted
Dynegy's motion for partial summary judgment based on the five-year statute of
limitations. As a result of the Court's ruling, the EPA will not be able to seek
any monetary civil penalties for claims related to construction without a permit
under the PSD regulations. The Order also precludes monetary civil penalties for
a portion of the claims under the NSPS regulations. Dynegy has recorded a
reserve for potential penalties that could be imposed if the EPA were to
successfully prosecute its claims.

MANUFACTURED-GAS PLANTS We previously operated two dozen sites at which
natural gas was manufactured from coal. Operation of these MGP sites was
generally discontinued in the 1950s when natural gas became available from
interstate gas transmission pipelines. Many of these MGP sites were contaminated
with residues from the gas manufacturing process. The Illinois EPA has issued No
Further Remediation Letters for two of our MGP sites. Although we estimate our
liability for MGP site remediation to be approximately $50 million for our
remaining 22 MGP sites, because of the unknown 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.

P.A. 90-561 - ISO PARTICIPATION Participation in an ISO or RTO by utilities
serving retail customers in Illinois was one of the requirements included in
P.A. 90-561 and P.A. 92-12.

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

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

On May 28, 2002, we submitted a letter to the FERC indicating that we would
join PJM either as an individual transmission owner or as part of an independent
transmission company. On July 31, 2002, the FERC issued an order approving our
proposal to join PJM, subject to certain conditions. These conditions include a
requirement that (i) the parties negotiate and implement a rate design that will
eliminate rate pancaking between PJM and the MISO, and (ii) the North American
Electric Reliability Council oversee the reliability plans for the MISO and PJM.
In addition, the FERC has initiated an investigation under Federal Power Act
section 206 of the MISO, PJM West and PJM's

F-18

transmission rates for through and out service and revenue distribution.
Subsequent to the July 31 order, the parties were unable to negotiate a rate
design that would eliminate rate pancaking between PJM and the MISO and the FERC
ordered a hearing on this matter. The hearing has concluded, and an order from
the Administrative Law Judge and the FERC is expected by mid-year 2003. Although
we are not currently charging rates or collecting revenues through these
entities, once we begin operating under PJM, our transmission rates and revenues
could be impacted by the outcome of this proceeding.

While we have elected to join PJM, Trans-Elect, the purchaser of our
transmission facilities, has elected to join the MISO upon the closing of the
proposed transmission sale. For this reason, we now expect to join the MISO
prior to or concurrent with the closing of the transmission sale, subject to
FERC approval.

OTHER
- -----

LEGAL PROCEEDINGS 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 believes that the final disposition of
these proceedings will not have a material adverse effect on our consolidated
financial position or results of operations.

In addition, as of December 31, 2002, fourteen lawsuits were pending against
us for illnesses based on alleged exposure to asbestos at generation facilities
previously owned by us. Forty-five asbestos lawsuits were served on us during
2002, with fourteen of these served subsequent to September 30, 2002. We were
dismissed, without prejudice, from thirty-three lawsuits during 2002. We intend
to vigorously defend against the remaining pending lawsuits. It is not possible
to predict with certainty the extent to which we will incur any liability or to
estimate the damages, if any, that might be incurred in connection with these or
subsequent similar lawsuits; however, we do not expect to incur any material
liability with respect to the pending lawsuits.

ELECTRIC AND MAGNETIC FIELDS The possibility that exposure to EMF emanating
from power lines, household appliances and other electric sources may result in
adverse health effects continues to be the subject of governmental, medical and
media attention. Two major scientific studies concluded in 1999 failed to
demonstrate significant EMF health risk; however, a definitive conclusion may
never be reached on this topic, and future impacts are unpredictable. Therefore,
we continue to compile the latest research information on this topic. At the
same time, we conduct EMF monitoring in the field when customers express a
concern. To date, we have not been named in any lawsuits relating to this issue.

ACCOUNTS RECEIVABLE We sell electric energy and natural gas to residential,
commercial, and industrial customers throughout Illinois. At December 31, 2002,
56%, 31% and 13% of "Accounts Receivable - Service" were from residential,
commercial and industrial customers, respectively. At December 31, 2001, 55%,
28% and 17% of "Accounts Receivable - Service" were from residential, commercial
and industrial customers, respectively. We maintain reserves for potential
credit losses and such losses have been within management's expectations. The
allowance for doubtful accounts remained at $5.5 million in 2002 and 2001.

OPERATING LEASES Minimum commitments in connection with operating leases at
December 31, 2002 were as follows: 2003 - $4.4 million; 2004 - $3.8 million,
2005 - $1.1 million, 2006 - $1.0 million, 2007 - $0.9 million; and thereafter
$3.7 million. These operating lease payments primarily relate to our material
distribution facility, which is a commercial property lease for our storage
warehouse, the lease on 15 line trucks and the off-balance sheet lease related
to Tilton.

We have a lease/sublease agreement on four gas turbines located at the Tilton
site which is reflected in the above lease commitments. We treat the lease as an
operating lease for accounting purposes. A payment of up to $81 million on the
lease financing may be due in the third quarter of 2004, if we elect to purchase
the turbines. We entered into the five-year operating lease beginning in
September 1999, with the option for renewal for two additional years. Beginning
in October 1999, we subsequently sublet the turbines to DMG. We are providing a
minimum residual value guarantee on the lease of approximately $69.6 million. At
the expiration of the lease, we have the option to purchase the gas turbines. If
we do not purchase the turbines, the turbines will be sold. We will be
responsible for any shortfall if the sale proceeds are less than $81 million up
to our minimum residual value guarantee on the lease of 86% of the $81 million
payment due, or $69.6 million.

F-19

NOTE 7 - REVOLVING CREDIT FACILITIES AND SHORT-TERM LOANS
- ---------------------------------------------------------

On May 17, 2002, we exercised the "term-out" provision contained in our $300
million 364-day revolving credit facility, which was scheduled to mature on May
20, 2002. In connection with this conversion, we borrowed the remaining $60
million available under this facility. The exercise of the "term-out" provision
converted the facility to a one-year term loan that matures in May 2003. In
December 2002, we paid $200 million to reduce this term loan to $100 million.
The interest rate on borrowings under the short term loan agreement is generally
at a Eurodollar rate plus a margin that is determined based on our senior
unsecured long-term debt rating. If greater than 25% of the aggregate commitment
is utilized, this margin will be increased by .125%. We pay facility fees of
..25% on the outstanding balance of our short term loan agreement.

At December 31, 2002, we had no commercial paper outstanding, while at
December 31, 2001, we had $38.2 million of commercial paper outstanding.

We have been requested to provide letters of credit or other credit security
to support certain business transactions, including our purchase of natural gas
and natural gas transportation. As of December 31, 2002, Dynegy posted $29
million in letters of credit in support of these transactions.

The following table summarizes our short-term borrowing activity and relevant
interest rates for the years ended December 31:

- ------------------------------------------------------------------------------------
(Millions of dollars, except rates) 2002 2001
- ------------------------------------------------------------------------------------

Short-term borrowings at December 31, $ 100.0 $ 278.2
Weighted average interest rate at December 31, 2.7% 2.8%
Maximum amount outstanding at any month end $ 300.0 $ 278.2
Average daily borrowings outstanding during the year $ 276.8 $ 216.0
Weighted average interest rate during the year 2.8% 4.4%

F-20

NOTE 8 - INCOME TAXES
- ---------------------

Deferred tax assets and liabilities were comprised of the following:

(Millions of dollars)
- ------------------------------------------------------------------------------------------
Balances as of December 31, 2002 2001
- ------------------------------------------------------------------------------------------

Deferred tax assets
- ------------------------------------------------------------------------------------------
Current -
Miscellaneous book/tax recognition differences $ 20.4 $ 23.9
- ------------------------------------------------------------------------------------------

Noncurrent -
Depreciation and other property related 45.7 44.8
Alternative minimum tax - 15.8
Unamortized investment tax credit 11.8 12.6
Miscellaneous book/tax recognition differences 45.6 59.5
Minimum pension funding liability 8.8 -
- ------------------------------------------------------------------------------------------
111.9 132.7
- ------------------------------------------------------------------------------------------
Total deferred tax assets $ 132.3 $ 156.6
==========================================================================================

Deferred tax liabilities
- ------------------------------------------------------------------------------------------

Current -
Miscellaneous book/tax recognition differences $ 3.2 $ 6.8
- ------------------------------------------------------------------------------------------

Noncurrent -
Depreciation and other property related 1,059.2 1,099.0
Miscellaneous book/tax recognition differences 90.9 120.3
- ------------------------------------------------------------------------------------------
1,150.1 1,219.3
- ------------------------------------------------------------------------------------------

Total deferred tax liabilities $ 1,153.3 $ 1,226.1
==========================================================================================

F-21

Income taxes included in the Consolidated Statements of Income and Comprehensive
Income consist of the following components:

(Millions of dollars)
- ------------------------------------------------------------------------------------------------------------
Years Ended December 31, 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------

Current taxes -

Included in operating
expenses and taxes $ 15.5 $ 15.9 $ (102.7)
Included in other income
and deductions 124.0 129.8 131.7

- ------------------------------------------------------------------------------------------------------------
Total current taxes 139.5 145.7 29.0
- ------------------------------------------------------------------------------------------------------------

Deferred taxes -

Included in operating
expenses and taxes
Property related differences 20.3 7.8 9.9
Alternative minimum tax 15.8 35.1 104.0
Gain/loss on reacquired debt (0.7) 3.5 (1.6)
Clinton power purchase agreement costs 11.0 12.1 10.7
Transition period cost recovery (28.0) (18.8) (18.8)
Uniform gas adjustment clause 1.5 (14.6) 17.4
Miscellaneous book/tax recognition differences (1.1) 0.5 (4.7)
Pension expense/funding 6.4 - -

Included in other income
and deductions - net
Property related differences (58.2) (57.3) (64.7)
Miscellaneous book/tax recognition differences (0.9) 4.1 3.1

- ------------------------------------------------------------------------------------------------------------
Total deferred taxes (33.9) (27.6) 55.3
- ------------------------------------------------------------------------------------------------------------

- ------------------------------------------------------------------------------------------------------------
Deferred investment tax credit - net
Included in operating expenses and taxes (1.4) (0.9) (1.0)
- ------------------------------------------------------------------------------------------------------------

Total income taxes $ 104.2 $ 117.2 $ 83.3
============================================================================================================

Note: For the years ended December 31, 2002, 2001 and 2000, income tax
expenses in the amount of $64.9 million, $76.6 million and $70.1 million,
respectively, are reported in Miscellaneous-Net in the accompanying Consolidated
Statements of Income and Comprehensive Income. Other tax expenses for the years
ended December 31, 2002, 2001 and 2000 are reported as separate components on
the accompanying Consolidated Statements of Income and Comprehensive Income.

F-22

The reconciliations of income tax expense to amounts computed by applying the
statutory tax rate to reported pretax income from continuing operations for the
period are set-out below:

(Millions of dollars)
- ------------------------------------------------------------------------------------------------------------
Years Ended December 31, 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------

Income tax expense at the
federal statutory tax rate $ 92.7 $ 99.2 $ 76.4
Increases / (decreases) in taxes
resulting from -
State taxes, net of federal effect 12.3 13.2 10.2
Investment tax credit amortization (1.4) (0.9) (1.0)
Depreciation not normalized 3.4 4.4 3.5
Interest expense on preferred securities - (2.4) (4.6)
Other - net (2.8) 3.7 (1.2)

- ------------------------------------------------------------------------------------------------------------
Total income taxes from continuing operations $ 104.2 $ 117.2 $ 83.3
============================================================================================================

Combined federal and state effective income tax rates were 39.3%, 41.4% and
38.2% for the years 2002, 2001 and 2000, respectively.

We are included in the consolidated federal income tax and unitary state tax
returns of Dynegy. Under our Services and Facilities income tax allocation
agreement with Dynegy, we calculate our own tax liability under the separate
return approach and reimburse Dynegy for such amount.

We are subject to the Alternative Minimum Tax and have utilized the remaining
Alternative Minimum Tax credit carryforward at December 31, 2002.

F-23

NOTE 9 - LONG-TERM DEBT
- -----------------------

(Millions of dollars)
- -------------------------------------------------------------------------------------------------------------------
December 31, 2002 2001
- -------------------------------------------------------------------------------------------------------------------
CARRYING FAIR Carrying Fair
VALUE VALUE Value Value
------------------------- ----------------------

Mortgage bonds--
6.25% series due 2002 $ - $ - $ 95.7 $ 96.0
6.0% series due 2003 90.0 86.7 90.0 89.7
6 1/2% series due 2003 100.0 96.7 100.0 100.4
6 3/4% series due 2005 70.0 66.4 70.0 70.2
7.5% series due 2009 250.0 215.0 250.0 237.5
5.70% series due 2024 (Pollution Control Series U) 35.6 36.2 35.6 37.5
7.40% series due 2024 (Pollution Control Series V) 84.1 88.4 84.1 92.0
7 1/2% series due 2025 65.6 51.7 65.6 55.7
5.40% series due 2028 (Pollution Control Series S) 18.7 18.7 18.7 19.1
5.40% series due 2028 (Pollution Control Series T) 33.8 33.8 33.8 34.5
11 1/2% series due 2010 400.0 388.0 - -
Adjustable rate series due 2032
(Pollution Control Series P, Q, and R) 150.0 150.0 150.0 150.0
Adjustable rate series due 2028 (Series W) 111.8 111.8 111.8 111.8
Adjustable rate series due 2017 (Series X) 75.0 75.0 75.0 75.0
----------------------- ----------------------
Total mortgage bonds 1,484.6 1,418.4 1,180.3 1,169.4
Transitional Funding Trust Notes--
5.31% due 2002 - - 30.8 31.1
5.34% due 2003 29.4 29.6 85.0 86.3
5.38% due 2005 175.0 178.4 175.0 177.5
5.54% due 2007 175.0 181.6 175.0 173.9
5.65% due 2008 139.0 152.8 139.0 138.2
----------------------- ----------------------
Total transitional funding trust notes 518.4 542.4 604.8 607.0
----------------------- ----------------------
2,003.0 $ 1,960.8 1,785.1 $ 1,776.4
========== =========
Adjustment to fair value 8.7 9.6
Unamortized discount on debt (16.5) (7.0)
-------- --------
1,995.2 1,787.7
Long-term debt maturing within one year (276.4) (182.1)
-------- --------
Total long-term debt $1,718.8 $1,605.6
======== ========

In the above table, the "adjustment to fair value" is the total adjustment of
debt to fair value as a result of our 1998 quasi-reorganization. The
quasi-reorganization was a process whereby our consolidated accumulated deficit
in retained earnings at December 31, 1998 was eliminated by the adjustment to
fair market value of certain assets and liabilities and a transfer from common
stock equity. The adjustment to the fair value of each debt series is being
amortized over its respective remaining life to interest expense.

In the above table, the fair value of our long-term debt is estimated based
on the quoted market prices for similar issues or by discounting expected cash
flows at the rates currently offered to us for debt of the same remaining
maturities, as advised by our bankers.

We had one standby bond purchase facility in the aggregate amount of $151.7
million that provided credit enhancement for $150.0 million of Illinois
Development Finance Authority ("IDFA") 1997 Series A, B and C bonds (the
"Pollution Control Bonds"), along with one month's interest of approximately
$1.7 million, for which our Pollution Control Series P, Q and R mortgage bonds
were issued without coupon and pledged to secure payment on the Pollution
Control Bonds. On April 9, 2002, the related indenture was amended to
incorporate an additional interest rate setting mechanism, the auction rate
mode. After the indenture was amended, the Pollution Control Bonds were reissued

F-24

without further change. The auction rate mode did not require the use of a
standby purchase facility, allowing the standby bond purchase facility to expire
without consequence.

Our $95.7 million Mortgage bonds, which matured on July 15, 2002, were
redeemed using $85.2 million of prepaid interest on the Illinova note and
approximately $10.5 million of working capital.

On December 20, 2002, we sold $550 million of 11 1/2% Mortgage bonds due 2010
in a private offering. Of the $550 million, we issued $400 million in December
2002, with $150 million issued on a delayed delivery basis subject to ICC
approval, which we received in January 2003. The mortgage bonds were sold at a
discounted price of $97.48 to yield an effective rate of 12%. We realized net
cash proceeds of approximately $380 million in December 2002 and approximately
$142.5 million in January 2003 from this offering. We used a portion of the
proceeds from the issuance to replenish the liquidity used to repay the $95.7
million 6.25% Mortgage bonds on July 15, 2002. Also, we used a portion of the
proceeds to reduce our $300 million short term loan due May 2003 by $200
million.

The 11 1/2% Mortgage bonds due 2010 contain triggering events that could
require us to redeem the bonds if we take certain actions, including the payment
of certain dividends and investments in areas outside of our normal utility
operations, the redemption of equity or subordinated debt, the incurrence of
further debt beyond that needed for refunding purposes, the issuance of
preferred stock, and the incurrence of certain liens. We also agreed, pursuant
to a registration rights agreement, to effect an exchange offer or to otherwise
provide the purchasers of these mortgage bonds with an equivalent amount of
registered mortgage bonds.

In addition to the quarterly payments on our Transitional Funding Trust Notes
(the "Notes"), we have long-term debt maturities, for the years 2003 through
2007, of $190 million in 2003 and $70 million in 2005.

In December 1998, the IPSPT issued $864 million of the Notes as allowed under
the Illinois Electric Utility Transition Funding Law in P.A. 90-561. As of
December 31, 2002, we have used $790.3 million of the funds to repurchase
outstanding debt obligations, $13.6 million to repurchase preferred stock, $49.3
million to repurchase 2.3 million shares of our common stock owned by Illinova
and $10.8 million for issuance expenses. In accordance with the Transitional
Funding Securitization Financing Agreement, we must designate a percentage of
the cash received from customer billings to fund payment of the Notes. The
amounts received are remitted to the IPSPT and are restricted for the sole
purpose of paying down such Notes. During 2002, we paid down the Notes by $86.4
million with cash from the IPSPT. We estimate that the IPSPT will continue to
pay down such Notes ratably, $86.4 million annually, through 2008. At December
31, 2002, $86.4 million of these $518.4 million Notes outstanding are classified
as long-term debt maturing within one year.

At December 31, 2002 and 2001, the aggregate total of unamortized debt
expense and unamortized loss on reacquired debt was approximately $84.6 million
and $80.4 million, respectively. This amount is included in the Consolidated
Balance Sheets under Other Deferred Charges.

The remaining balance of net bondable additions at December 31, 2002 and
2001, was approximately $82 million and $502 million, respectively. The
calculation for 2002 reflects the entire $550 million debt issuance effective
December 2002. See also "Note 7 - Revolving Credit Facilities and Short Term
Loans" above for additional information.

F-25

NOTE 10 - PREFERRED STOCK
- -------------------------

(Millions of dollars)
- ------------------------------------------------------------------------------------------------------
December 31, 2002 2001
- ------------------------------------------------------------------------------------------------------

SERIAL PREFERRED STOCK, cumulative, $50 par value --
Authorized 5,000,000 shares; 912,675 shares outstanding at
December 31, 2002 and 2001, respectively.

2002 2001 REDEMPTION
SERIES SHARES SHARES PRICES
4.08% 225,510 225,510 $ 51.50 $ 11.3 $ 11.3
4.26% 104,280 104,280 51.50 5.2 5.2
4.70% 145,170 145,170 51.50 7.2 7.2
4.42% 102,190 102,190 51.50 5.1 5.1
4.20% 143,760 143,760 52.00 7.2 7.2
7.75% 191,765 191,765 50.00 after July 1, 2003 9.6 9.6
Net premium on preferred stock 0.2 0.2
- ------------------------------------------------------------------------------------------------------
Total Preferred Stock, $50 par value 45.8 45.8
- ------------------------------------------------------------------------------------------------------
SERIAL PREFERRED STOCK, cumulative, without par value--
Authorized 5,000,000 shares; none outstanding - -
- ------------------------------------------------------------------------------------------------------
PREFERENCE STOCK, cumulative, without par value --
Authorized 5,000,000 shares; none outstanding - -
- ------------------------------------------------------------------------------------------------------
Total Serial Preferred Stock and Preference Stock $ 45.8 $ 45.8
======================================================================================================
COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF:
ILLINOIS POWER FINANCING I
Trust Originated Preferred Securities, cumulative, $25 liquidation
preference--4,000,000 shares authorized, none outstanding $ - $ -
======================================================================================================

All but one of the above series of Serial Preferred Stock ($50 par value) is
currently redeemable at our option, in whole or in part, at any time with not
less than 30 days and not more than 60 days notice by publication.

REDEMPTION OF PREFERRED SECURITIES OF SUBSIDIARY TRUST IPFI is a statutory
business trust in which we serve as sponsor. In 1996, IPFI issued $100 million
aggregate liquidation amount of 8% (4.8% after tax rate) TOPrS in a private
transaction. The TOPrS were to mature on January 31, 2045 and could be redeemed
at our option, in whole or in part, from time to time on or after January 31,
2001. On September 30, 2001, we redeemed all $100 million of the TOPrS. The
redemption was financed with $85 million cash and $15 million in commercial
paper.

REDEMPTION OF PREFERRED STOCK AND CONSENT SOLICITATION At December 31, 2001, a
provision of our Restated Articles of Incorporation prohibited us from incurring
additional unsecured debt of more than approximately $210 million. On March 28,
2002, we completed a solicitation of consents from our preferred stockholders to
amend our Restated Articles of Incorporation to eliminate this provision.
Concurrently, Illinova completed a tender offer pursuant to which it acquired
662,924 shares, or approximately 73%, of our preferred stock. The New York Stock
Exchange subsequently delisted each of the series of preferred stock that were
subject to the tender offer. On March 29, 2002, we amended our Restated Articles
of Incorporation to eliminate this provision. We incurred approximately $1.3
million in charges in connection with the consent solicitation. These charges
are reflected as an adjustment to Retained Earnings in the accompanying
Consolidated Balance Sheets.

F-26

NOTE 11 - COMMON STOCK AND RETAINED EARNINGS
- --------------------------------------------

Illinova is the sole holder of all of our common stock. At December 31, 2002,
there were 100,000,000 shares authorized with 75,643,937 shares issued. There is
no voting or non-voting common equity held by non-affiliates of IP. We are an
indirect wholly owned subsidiary of Dynegy.

As of December 31, 2002, we had repurchased 12,751,724 shares of our common
stock from Illinova. Under Illinois law, such shares may be held as treasury
stock and treated as authorized but unissued, or may be canceled by resolution
of the Board of Directors. We hold the common stock as treasury stock and deduct
it from common equity at the cost of the repurchased shares.

Under our Restated Articles of Incorporation, common stock dividends are
subject to the preferential rights of the holders of preferred and preference
stock. We are also limited in our payment of dividends by the Illinois Public
Utilities Act, which requires retained earnings equal to or greater than the
amount of any proposed dividend declaration or payment and by the netting
agreement, effective October 2002. Please read "Note 5 - Related Parties" for
more information on our netting agreement. The Federal Power Act precludes
declaration or payment of dividends by electric utilities "out of money properly
stated in a capital account." During March 2002, we declared and paid common
stock dividends of $0.5 million to Illinova. In 2001, we paid common stock
dividends of $100.0 million to Illinova.

EMPLOYEE STOCK OWNERSHIP PLAN Our employees historically participated in an
Employees' Stock Ownership Plan ("ESOP") that included a stock matching and an
incentive compensation feature tied to employee achievement of specified
corporate performance goals. This arrangement began in 1991 when we loaned $35
million to the Trustee of the Plan, which used the loan proceeds to purchase
2,031,445 shares of our common stock on the open market. We financed the loan
with funds borrowed under our bank credit agreements. The loan and common shares
became Illinova instruments on formation of Illinova in May 1994. These shares
were held in a Loan Suspense Account under the ESOP and were released and
allocated to the accounts of participating employees as the loan was repaid by
the Trustee with cash contributed by us for company stock matching and incentive
compensation awards. Common dividends received on allocated and unallocated
shares held by the Plan were used to repay the loan, which then released
additional shares to cover dividends on shares held in participating employees'
accounts. The number of shares released when funds were received by the Trustee
was based on the closing price of the common stock on the last day of the award
period or the common stock dividend date. Effective with the merger of Dynegy
and Illinova, the shares of Illinova stock in the ESOP were converted to the
same number of shares of Dynegy Class A common stock. The ESOP plan ended in
April 2001 upon distribution of the remaining shares held by the Plan.

During 2001, final distribution was made when 11,540 common shares were
allocated to salaried employees and 12,948 shares to employees covered under the
Collective Bargaining Agreement through the stock matching contribution feature
of the ESOP arrangement. No expense was recognized in 2002 due to the
termination of the ESOP plan in April 2001. Using the shares allocated method,
we recognized $0.2 million of expense in 2001. During 2001 and 2000, we
contributed $0.9 million and $3.5 million, respectively, to the ESOP. Interest
paid on the ESOP debt was negligible in 2001 and $0.1 million in 2000. Dividends
used for debt service were approximately $0.2 million in 2001 and $0.9 million
in 2000.

STOCK OPTIONS In 1992, the Board of Directors adopted and the shareholders
approved a Long-Term Incentive Compensation Plan ("LTIP") for officers or
employee members of the Board, but excluding directors who were not officers or
employees. Restricted stock, incentive stock options, non-qualified stock
options, stock appreciation rights, dividend equivalents, and other stock-based
awards could be granted under LTIP for up to 1,500,000 shares of Illinova's
common stock. These stock-based awards generally vest over three years, have a
maximum term of 10 years and have exercise prices equal to the market price on
the date the awards were granted. Pursuant to terms of the merger, certain
vesting requirements on outstanding options granted prior to the merger were
accelerated.

Each option granted is valued at an option price. Options granted at market
value vest and become exercisable ratably over a three-year period. The
difference between the option price and the stock price, if any, of each option
on the date of grant is recorded as compensation expense over a vesting period.
No compensation expense was recorded related to options granted during 2002,
2001 and 2000. However, compensation expense of $0.6 million

F-27

was recorded in 2001 related to revisions to vesting and exercise provisions
extended to employees participating in the severance and retirement components
of our 2001 reorganization plan. Refer to "Note 2 - Business Combination and
Reorganization" above for additional information. Pursuant to the merger, all
stock options granted to our employees prior to the merger were converted to
options to purchase Dynegy Class A common stock on a one-for-one basis.

We recognized tax benefits associated with the exercise of Dynegy stock
options by our employees in 2002 and 2001 in accordance with our tax sharing
agreement. In 2002 and 2001, $0.8 million and $7.8 million, respectively was
reflected as a reduction in current taxes payable and an increase to additional
paid-in capital.

The following summary of options granted and option transactions for 2002,
2001 and 2000 reflect the effect of the two-for-one stock split during 2000.

Year Ended December 31,
--------------------------------------------------------------------------------------------
2002 2002 2001 2001 2000 2000
SHARES OPTION PRICE Shares Option Price Shares Option Price
---------------------------- ---------------------------- ----------------------------

Outstanding at beginning of period 1,710,841 $12.14 - $56.98 1,408,977 $12.14 - $47.75 1,902,800 $10.44 - $15.56

Granted - N/A 559,421 $23.85 - $56.98 314,109 $23.38 - $47.75

Exercised (16,497) $23.38 (195,733) $12.14 - $23.38 (788,700) $10.44 - $14.88

Canceled, forfeited or expired (50,413) $23.38 - $47.75 (61,824) $15.56 - $47.19 (19,232) $15.56 - $23.38

--------- --------- ---------
Outstanding at end of period 1,643,931 $12.14 - $56.98 1,710,841 $12.14 - $56.98 1,408,977 $12.14 - $47.75
========= ========= =========

Exercisable at end of period 1,224,425 $12.14 - $56.98 834,334 $12.14 - $47.75 876,433 $12.14 - $15.56

Weighted average fair value of each
option granted during the period
at market $ N/A $ 19.10 $ 14.17
=============== =============== ===============

Weighted average fair value of each
option granted during the period
at below market N/A N/A N/A
=============== =============== ===============

F-28

Options outstanding as of December 31, 2002 are summarized below:

OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------ ----------------------------------
NUMBER OF SHARES
OUTSTANDING AT WEIGHTED AVERAGE WEIGHTED NUMBER OF SHARES WEIGHTED
RANGE OF DECEMBER 31, REMAINING CONTRACTUAL AVERAGE EXERCISABLE AT AVERAGE
EXERCISE PRICES 2002 LIFE (YEARS) EXERCISE PRICE DECEMBER 31, 2002 EXERCISE PRICE
- --------------------- ------------------------------------------------------ ----------------------------------

$12.14 - $14.88 256,200 5.1 $13.56 256,200 $13.56

$14.89 - $23.38 863,970 6.9 $17.43 788,820 $16.87

$23.39 - $56.98 523,761 8.4 $33.45 179,405 $33.75

--------- ---------
1,643,931 1,224,425
========= =========

The fair value of options granted, which is amortized to expense over the
option vesting period in determining the pro forma impact, is estimated on the
date of grant issuance using the Black-Scholes option-pricing model with the
following weighted average assumptions:

2002 2001 2000
-------- -------- --------

Expected life of options N/A 10 years 10 years
Risk-free interest rates N/A 3.97% 6.65%
Expected volatility of stock N/A 48% 44%
Expected dividend yield N/A 1.0% 1.3%

See Note 1 for a tabular presentation of the pro forma report.

NOTE 12 - EMPLOYEE COMPENSATION, SAVINGS AND PENSION PLANS
- ----------------------------------------------------------

CORPORATE INCENTIVE PLAN Dynegy maintains a discretionary incentive plan to
provide employees, including ours, competitive and meaningful rewards for
reaching corporate and individual objectives. Specific rewards are at the
discretion of Dynegy's Compensation Committee of the Board of Directors.

401(k) SAVINGS PLAN Our employees are eligible to participate in one of two
incentive savings plans, which meet the requirements of Section 401(k) of the
Internal Revenue Code and are defined contribution plans subject to the
provisions of ERISA. We match 50% of employee contributions to the incentive
savings plans, subject to a maximum of six percent of compensation. Employees
are immediately 100% vested in Company contributions. Matching contributions are
made in Dynegy common stock.

PENSION AND OTHER BENEFITS COSTS Our employees are participants in defined
benefit plans sponsored by Dynegy Inc., which prior to the February 1, 2000
Dynegy-Illinova merger, were sponsored and administered by us. See "Note 1 -
Summary of Significant Accounting Policies" above for more information.

The values and discussion below represent the components of the Dynegy
benefit plans that were sponsored and administered by us prior to the merger.
Plan participants include Illinova employees as of February 1, 2000 as well as
our employees and employees DMG hired subsequent to the merger. We are
reimbursed by the other Illinova subsidiaries (prior to the merger) and by other
Dynegy subsidiaries (subsequent to the merger) for their share of the expenses
of these benefit plans.

F-29

(Millions of dollars)
- ----------------------------------------------------------------------------------------------------------------------
PENSION BENEFITS OTHER BENEFITS
2002 2001 2002 2001
- ----------------------------------------------------------------------------------------------------------------------

CHANGE IN BENEFIT OBLIGATION

Projected benefit obligation at beginning of year $ 489.6 $ 439.4 $ 133.7 $ 99.1
Service cost 10.6 9.8 3.0 2.4
Interest cost 35.6 33.7 9.6 8.4
Participant contributions - - 1.1 -
Plan amendments - - - -
Actuarial (gain)/loss 69.5 26.4 11.3 29.9
Special termination benefits - 8.7 - -
Benefits paid (31.8) (28.4) (8.1) (6.1)
- ----------------------------------------------------------------------------------------------------------------------
Projected benefit obligation at end of year $ 573.5 $ 489.6 $ 150.6 $ 133.7
- ----------------------------------------------------------------------------------------------------------------------

CHANGE IN PLAN ASSETS

Fair value of plan assets, beginning of year $ 557.4 $ 615.8 $ 79.4 $ 82.5
Actual return/(loss) on plan assets (48.9) (30.0) (11.0) (7.4)
Employer contributions - - 5.6 9.4
Participant contributions - - 1.1 1.0
Benefits paid (31.8) (28.4) (8.1) (6.1)
- ----------------------------------------------------------------------------------------------------------------------
Fair value of plan assets, end of year $ 476.7 $ 557.4 $ 67.0 $ 79.4
- ----------------------------------------------------------------------------------------------------------------------
RECONCILIATION OF FUNDED STATUS

Funded status $ (96.8) $ 67.8 $ (83.6) $ (54.3)
Unrecognized actuarial (gain)/loss 114.3 (64.8) 72.0 44.7
Unrecognized prior service cost 6.6 7.8 - -
Unrecognized transition obligation/(asset) (5.9) (9.3) 19.3 21.4
- ----------------------------------------------------------------------------------------------------------------------
Net amount recognized $ 18.2 $ 1.5 $ 7.7 $ 11.8
======================================================================================================================

AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEETS CONSIST OF:
Prepaid benefit cost $ 37.6 $ 26.8 $ 7.7 $ 11.8
Accrued benefit liability (44.5) (25.3) - -
Intangible asset 3.0 - - -
Accumulated other comprehensive income (pretax) 22.1 - - -
- ----------------------------------------------------------------------------------------------------------------------
Net amount recognized $ 18.2 $ 1.5 $ 7.7 $ 11.8
======================================================================================================================

F-30

- ----------------------------------------------------------------------------------------------------------------------
PENSION BENEFITS OTHER BENEFITS
2002 2001 2002 2001
- ----------------------------------------------------------------------------------------------------------------------

ASSUMPTIONS AS OF DECEMBER 31

Discount rate 6.5% 7.5% 6.5% 7.5%
Expected return on plan assets 9.0% 9.5% 9.0% 9.5%
Rate of compensation increase 4.5% 4.5% 4.5% 4.5%
Medical trend - initial trend 9.3% 10.0%
Medical trend - ultimate trend 5.5% 5.5%
Medical trend - year of ultimate trend 2009 2009

(Millions of dollars)
- ------------------------------------------------------------------------------------------------------------------
PENSION BENEFITS OTHER BENEFITS
2002 2001 2000 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------

COMPONENTS OF NET PERIODIC BENEFIT COST

Service cost $ 10.6 $ 9.8 $ 10.0 $ 3.0 $ 2.4 $ 2.3
Interest cost 35.6 33.7 32.8 9.6 8.4 7.4
Expected return on plan assets (56.6) (53.8) (47.8) (7.1) (7.8) (7.8)
Amortization of prior service cost 1.4 1.4 1.4 - - -
Amortization of transition liability/(asset) (3.4) (4.2) (4.2) 2.1 2.1 2.1
Recognized net actuarial (gain)/loss (4.4) (6.7) (4.0) 2.0 - -
----------------------------------------------------------------
Net periodic benefit cost/(income) $ (16.8) $ (19.8) $ (11.8) $ 9.6 $ 5.1 $ 4.0
Additional cost/(income) due to FAS 88 - 8.7 10.9 - - 1.0
----------------------------------------------------------------
Total net periodic benefit cost/(income) $ (16.8) $ (11.1) $ (.9) $ 9.6 $ 5.1 $ 5.0
==================================================================================================================

For measurement purposes, a 9.3% health care trend rate was used for 2003.
Trend rates were assumed to decrease gradually to 5.5% in 2009 and remain at
this level going forward. Assumed health care cost trend rates have a
significant effect on the amounts reported for the health care plan.

A one percentage point change in assumed health care cost trend rates would
have the following effects for 2002:

(Millions of dollars)
--------------------------------------
1 Percentage 1 Percentage
Point Increase Point Decrease
--------------------------------------

Aggregate effect on service cost and interest cost $ 1.7 $ (1.5)
Effect on accumulated postretirement benefit obligation $ 15.7 $ (14.2)

As permitted under Paragraph 26 of FAS 87,"Employers' Accounting for
Pensions", the amortization of any prior service cost is determined using a
straight-line amortization of the cost over the average remaining service period
of employees expected to receive benefits under the Plan.

During 2000, we recognized special termination benefit pension expense of
$10.9 million and postretirement medical plan expense of $1 million due to our
staffing reduction plan resulting from the merger with Dynegy. See "Note 2 -
Business Combination and Reorganization" above for additional information.

During 2001, we recognized special termination benefit pension expense of
$8.7 million due to our staffing reduction due to reorganization. See "Note 2 -
Business Combination and Reorganization" above for additional information.

F-31

On December 31, 2002, our annual measurement date, the accumulated benefit
obligation related to our pension plans exceeded the fair value of the pension
plan assets. This difference is attributed to (1) an increase in the accumulated
benefit obligation that resulted from the decrease in the discount rate and the
expected long-term rate of return and (2) a decline in the fair value of the
plan assets due to a sharp decrease in the equity markets through December 31,
2002. As a result, in accordance with FAS 87, "Employers' Accounting for
Pensions", we recognized a charge to other comprehensive income of $22.2 million
($13.4 million after-tax), which decreased common stock equity.

NOTE 13 - SEGMENTS OF BUSINESS
- ------------------------------

Our operations consist of a single reportable segment. This segment includes the
transmission, distribution and sale of electric energy in Illinois; and the
transportation, distribution and sale of natural gas in Illinois. Also included
in this segment are specialized support functions, including accounting, legal,
regulatory, performance management, information technology, human resources,
environmental resources, purchasing and materials management and public affairs.

NOTE 14 - FAIR VALUE OF FINANCIAL INSTRUMENTS
- ---------------------------------------------

The following disclosure of the estimated fair value of financial instruments is
made in accordance with the requirements of FAS 107, "Disclosures About Fair
Value of Financial Instruments." Using available market information and selected
valuation methodologies, we have determined the estimated fair value amounts.
Considerable judgment is required in interpreting market data to develop the
estimates of fair value. The use of different market assumptions or valuation
methodologies could have a material effect on the estimated fair value amounts.

- ---------------------------------------------------------------------------------------------------------------
2002 2001
-------------------------------------------------------
CARRYING FAIR Carrying Fair
(Millions of dollars) VALUE VALUE Value Value
- ---------------------------------------------------------------------------------------------------------------

Cash and cash equivalents $ 117.4 $ 117.4 $ 41.3 $ 41.3

Note receivable from affiliate 2,271.4 989.1 2,271.4 2,094.1

Preferred stock 45.8 17.6 45.8 39.0

Long-term debt (including current maturities) 1,995.2 1,960.8 1,787.7 1,776.4

Notes payable 100.0 100.0 278.2 278.2

Our operations are subject to regulation; therefore, gains or losses on the
redemption of long-term debt may be included in rates over a prescribed
amortization period, if they are in fact, settled at amounts approximating those
in the above table.

The following methods and assumptions were used to estimate the fair value of
each class of financial instruments listed in the table above:

CASH AND CASH EQUIVALENTS The carrying amount of cash and cash equivalents
approximates fair value due to the short maturity of these instruments.

F-32

NOTE RECEIVABLE FROM AFFILIATE The fair value of our Note Receivable from
Affiliate is estimated based on the quoted market prices for Dynegy's publicly
traded senior unsecured debt securities having similar terms. As of March 25,
2003, the fair value of our Note Receivable from Affiliate was estimated at
$1,713.7 million. This calculation was prepared using the same methodology to
determine the fair value of our Note Receivable from Affiliate at December 31,
2002 and 2001.

PREFERRED STOCK Our preferred stock is no longer listed on the New York Stock
Exchange as a result of the March 2002 tender offer pursuant to which Illinova
acquired 73% of our outstanding shares. As a result, reliable "market prices" of
the various preferred series could not be obtained. For each series, the annual
dividend was divided by the risk-adjusted return of 13% to derive a market
price.

LONG-TERM DEBT The fair value of our long-term debt is estimated based on the
quoted market prices for similar issues or by discounting expected cash flows at
the rates currently offered to us for debt of the same remaining maturities, as
advised by our bankers. The detail related to the carrying amounts and fair
values of each debt instrument are included in "Note 9 - Long-Term Debt"
beginning on page F-24.

NOTES PAYABLE The carrying amount of notes payable approximates fair value due
to the short maturity of these instruments.

OTHER The carrying values of all other current financial assets and
liabilities approximate fair value due to the short-term maturities of these
instruments.

NOTE 15 - FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS
- ----------------------------------------------------

TRADING ACTIVITIES During 2002, 2001 and 2000, we did not participate in
trading activities.

NON-TRADING ACTIVITIES During 2002, 2001 and 2000, all of our purchase
contracts qualified for the normal purchase and sale exemption within FAS 133
and, therefore, we accounted for such contracts under the accrual method. We had
no other derivative instruments qualifying under FAS 133.

NOTE 16 - QUARTERLY CONSOLIDATED FINANCIAL INFORMATION AND COMMON STOCK DATA
- ----------------------------------------------------------------------------
(UNAUDITED)
- -----------

(Millions of dollars)
----------------------------------------------------------------
FIRST QUARTER SECOND QUARTER THIRD QUARTER FOURTH QUARTER
2002 2002 2002 2002
----------------------------------------------------------------

Operating revenues $ 393.2 $ 343.9 $ 406.0 $ 375.2
Operating income 35.5 45.1 57.7 25.7
Net income 34.5 46.2 56.9 23.1
Net income applicable to common shareholder 33.9 45.6 56.3 22.6

----------------------------------------------------------------
First Quarter Second Quarter Third Quarter Fourth Quarter
2001 2001 2001 2001
----------------------------------------------------------------

Operating revenues $ 529.5 $ 341.1 $ 400.6 $ 343.2
Operating income 40.3 50.2 56.2 19.8
Net income 59.7 34.8 54.0 17.7
Net income applicable to common shareholder 57.2 32.3 51.4 17.0

F-33

EXHIBIT INDEX

EXHIBIT DESCRIPTION

(3)(i) ARTICLES OF INCORPORATION

Amended and Restated Articles of Incorporation of Illinois Power Company, dated
September 7, 1994. Filed as Exhibit 3(a) to the Current Report on Form 8-K dated
September 7, 1994 (File No. 1-3004).*

(3)(ii) BY-LAWS

By-laws of Illinois Power Company, as amended December 14, 1994. Filed as
Exhibit 3(b)(1) to the Annual Report on Form 10-K for the year ended December
31, 1994 (File No. 1-3004).*

(4) INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING INDENTURES

4.1 - General Mortgage Indenture and Deed of Trust dated as of November 1, 1992.
Filed as Exhibit 4(cc) to the Annual Report on Form 10-K for the year ended
December 31, 1992 (File No. 1-3004).*

4.2 - Supplemental Indenture No. 2 dated March 15, 1993, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the 6 3/4% bonds
due 2005. Filed as Exhibit 4(ii) to the Annual Report on Form 10-K for the year
ended December 31, 1992 (File No. 1-3004).*

4.3 - Supplemental Indenture dated July 15, 1993, to General Mortgage Indenture
and Deed of Trust dated as of November 1, 1992 for the 7 1/2% bonds due 2025.
Filed as Exhibit 4(kk) to the Quarterly Report on Form 10-Q for the quarter
ended June 30, 1993 (File No. 1-3004).*

4.4 - Supplemental Indenture dated August 1, 1993, to General Mortgage Indenture
and Deed of Trust dated as of November 1, 1992 for the 6 1/2% bonds due 2003.
Filed as Exhibit 4(mm) to the Quarterly Report on Form 10-Q for the quarter
ended June 30, 1993 (File No. 1-3004).*

4.5 - Supplemental Indenture dated April 1, 1997, to General Mortgage Indenture
and Deed of Trust dated as of November 1, 1992 for the series P, Q, and R bonds.
Filed as Exhibit 4(b) to the Quarterly Report on Form 10-Q for the quarter ended
March 31, 1997 (File No. 1-3004).*

4.6 - Supplemental Indenture dated as of March 1, 1998, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the series S bonds.
Filed as Exhibit 4.41 to the Registration Statement on Form S-3, filed January
22, 1999 (Registration No. 333-71061).*

4.7 - Supplemental Indenture dated as of March 1, 1998, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the series T bonds.
Filed as Exhibit 4.42 to the Registration Statement on Form S-3, filed January
22, 1999 (Registration No. 333-71061).*

4.8 - Supplemental Indenture dated as of July 15, 1998, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the 6 1/4% bonds
due 2002. Filed as Exhibit 4.44 to the Registration Statement on Form S-3, filed
January 22, 1999 (Registration No. 333-71061).*

4.9 - Supplemental Indenture dated as of September 15, 1998, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the 6% bonds due
2003. Filed as Exhibit 4.46 to the Registration Statement on Form S-3, filed
January 22, 1999 (Registration No. 333-71061).*

4.10 - Supplemental Indenture dated as of June 15, 1999, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the 7.5% bonds due
2009. Filed as Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter
ended June 30, 1999 (File No. 1-3004).*

EXHIBIT INDEX(CONTINUED)

EXHIBIT DESCRIPTION

4.11 - Supplemental Indenture dated as of July 15, 1999, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the series U bonds.
Filed as Exhibit 4.4 to the Quarterly Report on Form 10-Q for the quarter ended
June 30, 1999 (File No. 1-3004).*

4.12 - Supplemental Indenture dated as of July 15, 1999, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the series V bonds.
Filed as Exhibit 4.6 to the Quarterly Report on Form 10-Q for the quarter ended
June 30, 1999 (File No. 1-3004).*

4.13 - Supplemental Indenture No. 1 dated as of May 1, 2001, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the series W
bonds.*

4.14 - Supplemental Indenture No. 2 dated as of May 1, 2001, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the series X
bonds.*

4.15 - Supplemental Indenture dated as of December 20, 2002, to General Mortgage
Indenture and Deed of Trust dated as of November 1, 1992 for the 11 1/2% bonds
due 2010. Filed as Exhibit 4.1 to the Current Report on Form 8-K dated
December 23, 2002.*

(10) MATERIAL CONTRACTS

10.1 - Group Insurance Benefits for Managerial Employees of Illinois Power
Company as amended January 1, 1983. Filed as Exhibit 10(a) to the Annual Report
on Form 10-K for the year ended December 31, 1983 (File No. 1-3004).~*

10.2 - Illinois Power Company Retirement Income Plan for Salaried Employees, as
amended and restated effective January 1, 1989, as further amended through
January 1, 1994. Filed as Exhibit 10(m) to the Annual Report on Form 10-K for
the year ended December 31, 1994. (File No. 1-3004).~*

10.3 - Illinois Power Company Retirement Income Plan for Employees Covered Under
a Collective Bargaining Agreement, as amended and restated effective as of
January 1, 1994. Filed as Exhibit 10(n) to the Annual Report on Form 10-K for
the year ended December 31, 1994. (File No. 1-3004).~*

10.4 - Illinois Power Company Incentive Savings Plan, as amended and restated
effective January 1, 2002. Filed as Exhibit 10.3 to the Registration Statement
on Form S-8 of Dynegy Inc., Registration No. 333-76570.~*

10.5 - Illinois Power Company Incentive Savings Plan Trust Agreement. Filed as
Exhibit 10.4 to the Registration Statement on Form S-8 of Dynegy Inc.,
Registration No. 333-76570.~*

10.6 - Illinois Power Company Incentive Savings Plan for Employees Covered Under
a Collective Bargaining Agreement, as amended and restated effective January 1,
2002. Filed as Exhibit 10.5 to the Registration Statement on Form S-8 of Dynegy
Inc., Registration No. 333-76570.~*

10.7 - Illinois Power Company Incentive Savings Plan for Employees Covered Under
a Collective Bargaining Agreement Trust Agreement. Filed as Exhibit 10.6 to the
Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76570.~*

10.8 - Illinois Power Company Supplemental Retirement Income Plan for Salaried
Employees, as amended by resolutions adopted by the Board of Directors on June
10-11, 1997. Filed as Exhibit 10(b)(13) to the Annual Report on Form 10-K for
the year ended December 31, 1997. (File No. 1-3004).~*

10.9 - Registration Rights Agreement dated as of December 20, 2002 among
Illinois Power Company and the initial purchasers of the 11 1/2% Mortgage bonds
due 2010. Filed as Exhibit 4.2 to the Current Report on Form 8-K dated December
23, 2002.*

EXHIBIT INDEX(CONTINUED)

EXHIBIT DESCRIPTION

+(12) STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

+(21) SUBSIDIARIES OF ILLINOIS POWER COMPANY

+(23) CONSENT OF INDEPENDENT ACCOUNTANTS

+(99) ADDITIONAL EXHIBITS

+99.1 - Certification of Chief Executive Officer pursuant to Section 906
of the Sarbannes-Oxley Act of 2002

+99.2 - Certification of Chief Financial Officer pursuant to Section 906
of the Sarbannes-Oxley Act of 2002

- --------------------------------------
* Incorporated herein by reference.

~ Management contract and compensatory plans or arrangements.

+ Filed herewith.