-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, KGL0WqLBm5oylfSmk8XYNDyxsbyDdVIjCjIYmN7FT+0aePpq12+PuLGvautB9rPc VVa42VmFdNVzyUjDL2A0dA== 0000950129-03-002034.txt : 20030415 0000950129-03-002034.hdr.sgml : 20030415 20030415163721 ACCESSION NUMBER: 0000950129-03-002034 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030415 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ILLINOIS POWER CO CENTRAL INDEX KEY: 0000049816 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 370344645 STATE OF INCORPORATION: IL FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03004 FILM NUMBER: 03650866 BUSINESS ADDRESS: STREET 1: 500 S 27TH ST STREET 2: C/O HARRIS TRUST & SAVINGS BANK CITY: DECATUR STATE: IL ZIP: 62525-1805 BUSINESS PHONE: 2174246600 FORMER COMPANY: FORMER CONFORMED NAME: ILLINOIS IOWA POWER CO DATE OF NAME CHANGE: 19660822 10-K 1 h04359e10vk.txt ILLINOIS POWER COMPANY - 12/31/2002 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. 3 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. 4 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):
2003 MATURITIES -------------------------------------------------------------- 1ST 2ND 3RD 4TH QUARTER QUARTER QUARTER QUARTER TOTAL -------------------------------------------------------------- Transitional Funding Trust Notes $ 21.6 $ 21.6 $ 21.6 $ 21.6 $ 86.4 One-Year Term Loan -- 100.0 -- -- 100.0 6.0% Mortgage Bonds -- -- 90.0 -- 90.0 6 1/2% Mortgage Bonds -- -- 100.0 -- 100.0 -------------------------------------------------------------- Total $ 21.6 $ 121.6 $ 211.6 $ 21.6 $ 376.4 ==============================================================
2004 MATURITIES -------------------------------------------------------------- 1ST 2ND 3RD 4TH QUARTER QUARTER QUARTER QUARTER TOTAL -------------------------------------------------------------- Transitional Funding Trust Notes $ 21.6 $ 21.6 $ 21.6 $ 21.6 $ 86.4 ==============================================================
2005 MATURITIES -------------------------------------------------------------- 1ST 2ND 3RD 4TH QUARTER QUARTER QUARTER QUARTER TOTAL -------------------------------------------------------------- Transitional Funding Trust Notes $ 21.6 $ 21.6 $ 21.6 $ 21.6 $ 86.4 6 3/4% Mortgage Bonds 70.0 -- -- -- 70.0 -------------------------------------------------------------- Total $ 91.6 $ 21.6 $ 21.6 $ 21.6 $ 156.4 ==============================================================
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.
2002 2001 ---- ---- Lease expense $2.7 $4.3 Lease payments (cash flows) $2.7 $4.3
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
PAYMENTS DUE BY PERIOD - ----------------------------------------------------------------------------------------------------------------------- CASH OBLIGATIONS* TOTAL 2003 2004 2005 2006 2007 THEREAFTER - ----------------------------------------------------------------------------------------------------------------------- Long-Term Debt (1) $ 1,484.6 $ 190.0 $ -- $ 70.0 $ -- $ -- $ 1,224.6 Transitional Funding Trust Notes (2) 518.4 86.4 86.4 86.4 86.4 86.4 86.4 Term Loan (3) 100.0 100.0 -- -- -- -- -- Decommissioning Charges-Clinton (4) 9.9 5.0 4.9 -- -- -- -- Decommissioning Charges-DOE (5) 2.9 0.7 0.7 0.7 0.8 -- -- Unconditional Purchase Obligations (6) 740.9 380.3 324.4 6.1 6.1 6.1 17.9 Operating Leases (7)(8) 14.9 4.4 3.8 1.1 1.0 0.9 3.7 ---------------------------------------------------------------------------------------- Total Contractual Cash Obligations $ 2,871.6 $ 766.8 $ 420.2 $ 164.3 $ 94.3 $ 93.4 $ 1,332.6 ----------------------------------------------------------------------------------------
*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
PAYMENTS DUE BY PERIOD - ----------------------------------------------------------------------------------------------------------------------- CASH OBLIGATIONS* TOTAL 2003 2004 2005 2006 2007 THEREAFTER - ----------------------------------------------------------------------------------------------------------------------- Surety Bonds (1) $ .1 $ -- $ .1 $ -- $ -- $ -- $ -- Guarantees (2)(3) 69.6 -- 69.6 -- -- -- -- ---------------------------------------------------------------------------------------- Total Contingent Financial Commitments $ 69.7 $ -- $ 69.7 $ -- $ -- $ -- $ -- -----------------------------------------------------------------------------------------
*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:
- ------------------------------------------------------------------------------------------- STANDARD & POOR'S MOODY'S FITCH - ------------------------------------------------------------------------------------------- Senior secured debt B B3 B Senior unsecured debt * Caa1 CCC+ Preferred stock CCC Ca CC Transitional funding trust notes AAA Aaa AAA
* 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. EX-12 3 h04359exv12.txt STATEMENT OF COMPUTATION OF RATIO OF EARNINGS EXHIBIT 12 ILLINOIS POWER COMPANY STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (THOUSANDS OF DOLLARS)
Year Ended December 31, ----------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- Earnings Available for Fixed Charges: Net Income (Loss) $160,695 $166,179 $134,935 $113,089 ($1,552,435) Add: Income Taxes: Current 15,486 15,859 (102,704) 47,639 7,556 Deferred - Net 25,212 25,619 111,935 8,083 (30,203) Allocated income taxes 64,933 76,693 75,047 16,992 (3,506) Investment tax credit - deferred (1,422) (950) (982) (1,339) (8,256) Income tax effect of CPS impairment -- -- -- -- (1,143,252) Interest on long-term debt 94,738 104,861 115,329 124,261 106,879 Amortization of debt expense and premium-net, and other interest charges 18,135 18,638 23,795 24,190 28,107 One-third of all rentals (Estimated to be representative of the interest component) 2,442 2,250 3,285 3,836 4,054 Interest on in-core fuel -- -- -- 4,424 3,716 -------- -------- -------- -------- ----------- Earnings (loss) available for fixed charges $380,219 $409,149 $360,640 $341,175 ($2,587,340) ======== ======== ======== ======== =========== Fixed charges: Interest on long-term debt $94,738 $104,861 $115,329 $124,261 $ 106,879 Amortization of debt expense and premium-net, and other interest charges 18,135 18,638 23,795 29,830 35,829 One-third of all rentals (Estimated to be representative of the interest component) 2,442 2,250 3,285 3,836 4,054 -------- -------- -------- -------- ----------- Total Fixed Charges $115,315 $125,749 $142,409 $157,927 $ 146,762 ======== ======== ======== ======== =========== Ratio of earnings to fixed charges 3.30 3.25 2.53 2.16 N/A* ======== ======== ======== ======== =========== (1)
* Earnings were inadequate to cover fixed charges. Additional earnings (thousands) of $2,734,102 for 1998 were required to attain a one-to-one ratio of earnings to fixed charges. (1) The ratio of earnings to fixed charges would still be N/A if the write-off related to Clinton Impairment was excluded from the above calculation. EX-21 4 h04359exv21.txt SUBSIDIARIES OF REGISTRANT . . . EXHIBIT 21 SUBSIDIARIES OF ILLINOIS POWER COMPANY
State or Jurisdiction Name of Incorporation --------- --------------------- IP Gas Supply Company Illinois Illinois Power Capital, L.P. (1) Delaware Illinois Power Financing I (2) Delaware Illinois Power Financing II (3) Delaware Illinois Power Securitization Limited Liability Company (4) Delaware Illinois Power Special Purpose Trust (5) Delaware Illinois Power Transmission Company, LLC (6) Delaware
(1) Illinois Power Company is the general partner in Illinois Power Capital, L.P., with a 3% equity ownership share. Illinois Power Capital is consolidated in the accounts of Illinois Power Company. This subsidiary is inactive as of May 30, 2000. (2) Illinois Power Financing I is inactive as of September 30, 2001. (3) Illinois Power Financing II is not currently active. (4) Illinois Power Company is the sole member of Illinois Power Securitization Limited Liability Company. (5) Illinois Power Securitization Limited Liability Company is the sole owner of the Illinois Power Special Purpose Trust. (6) Illinois Power Transmission Company is not currently active. EX-23 5 h04359exv23.txt OPINION OF PRICEWATERHOUSECOOPERS LLP EXHIBIT 23 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-84808) of Illinois Power Company of our report dated April 4, 2003 relating to the financial statements and financial statement schedule, which appears in this Form 10-K. /s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP Houston, Texas April 15, 2003 EX-99.1 6 h04359exv99w1.txt CERTIFICATION OF CHIEF EXECUTIVE OFFICER EXHIBIT 99.1 CERTIFICATION PURSUANT TO 18 U.S.C. (S)1350 (ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002) In connection with the periodic report of Illinois Power Company (the "Company") on Form 10-K for the period ended December 31, 2002 dated April 15, 2003, filed with the Securities and Exchange Commission (the "Report"), I, Larry F. Altenbaumer, President and Chief Executive Officer of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge: (1) the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated. Date: April 15, 2003 /s/ Larry F. Altenbaumer ------------------------ Larry F. Altenbaumer President and Chief Executive Officer EX-99.2 7 h04359exv99w2.txt CERTIFICATION OF CHIEF FINANCIAL OFFICER EXHIBIT 99.2 CERTIFICATION PURSUANT TO 18 U.S.C. (S)1350 (ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002) In connection with the periodic report of Illinois Power Company (the "Company") on Form 10-K for the period ended December 31, 2002 dated April 15, 2003, filed with the Securities and Exchange Commission (the "Report"), I, Nick J. Caruso, Executive Vice President and Chief Financial Officer of the Company, hereby certify as of the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge: (1) the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated. Date: April 15, 2003 /s/ Nick J. Caruso ------------------- Nick J. Caruso Executive Vice President and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----