ITEM 1. BUSINESS.
GENERAL
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren's primary asset is the common stock of its subsidiaries. Ameren's subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas distribution businesses and non rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren's common stock are dependent on distributions made to it by its subsidiaries. Ameren's principal subsidiaries are listed below. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8 of this report for a more detailed description of the Ameren Companies.
o UE, also known as Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas distribution business in Missouri and Illinois.
o CIPS, also known as Central Illinois Public Service Company, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
o Genco, also known as Ameren Energy Generating Company, operates a non rate-regulated electric generation business.
o CILCO, also known as Central Illinois Light Company, is a subsidiary of CILCORP (a holding company) and operates a rate-regulated electric transmission and distribution business, a primarily non rate-regulated electric generation business and a rate-regulated natural gas distribution business in Illinois.
At December 31, 2003, Ameren employed 7,650 employees, UE employed 3,996 employees, CIPS employed 764 employees, Genco employed 701 employees and CILCORP employed 862 employees, of which 855 employees are employed by CILCO. During the second and third quarters of 2003, we entered into new four-year labor agreements with the IBEW and the IUOE representing eleven bargaining units covering approximately 70% of Ameren's, UE's, CIPS' and Genco's entire workforces. The new agreements include no wage increase for year one of the agreements, 3.5% increases for both years two and three, and an increase of 3.25% for year four. In addition, the agreements include a pension supplement, more flexible work rules and a change to employee medical benefits resulting in employees paying a greater portion of future benefit cost increases. CILCO has a labor agreement with the IBEW which will expire on July 1, 2004. Employees covered by the agreement represent approximately 4% of Ameren's and CILCO's entire workforce.
For additional information regarding our business operations, see Management's Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report and Note 1- Summary of Significant Accounting Policies to our financial statements under Part II, Item 8 of this report.
CAPITAL PROGRAM AND FINANCING
For information on our capital program and financing needs, see Liquidity and Capital Resources in Management's Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report and Note 5 - Short-term Borrowings and Liquidity, Note 6 - Long-term Debt and Equity Financings, Note 10 - Stockholder Rights Plan and Preferred Stock and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8 of this report.
RATES AND REGULATION
Rates
Rates that UE, CIPS and CILCO are allowed to charge for their services are the single most important item influencing their and Ameren's consolidated financial position, results of operations and liquidity. The rates charged to UE, CIPS and CILCO customers are determined by governmental organizations. Decisions by these organizations are influenced by many factors, including the cost of providing service, the quality of service, regulatory staff knowledge and experience, economic conditions and social and political views. Decisions made by these organizations regarding rates could have a material impact on the financial position, results of operations and liquidity of UE, CIPS, CILCO and Ameren on a consolidated basis.
UE, CIPS and CILCO are subject to regulation by the ICC, and UE is also subject to regulation by the MoPSC, as to rates, service, issuance of equity securities, issuance of debt having a maturity of more than twelve months, mergers, affiliate transactions, and various other matters. Genco is not subject to regulation by the ICC or the MoPSC. See Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8 of this report for information regarding UE's proposed discontinuance of its utility operations subject to ICC jurisdiction by transferring its Illinois-based electric and natural gas transmission and distribution business to CIPS.
UE, CIPS, CILCO and Genco are also subject to regulation by the FERC as to rates and charges in connection with the wholesale sale of energy and transmission in interstate commerce, mergers, affiliate transactions, and certain other matters. Issuance of short-term and long-term debt by Genco is subject to approval by the FERC.
The following table presents the approximate percentage of electric operating revenues subject to regulation by the MoPSC, the ICC and the FERC for each of the Ameren Companies for the year ended December 31, 2003:
The following table presents the approximate percentage of gas operating revenues subject to regulation by the MoPSC and the ICC for each of the Ameren Companies for the year ended December 31, 2003:
Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A of this report and Note 3 - Rate and Regulatory Matters and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8 of this report.
For information on rate matters in these jurisdictions, including UE's 2002 Missouri electric rate case, see Results of Operations in Management's Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report and Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8 of this report.
General Regulatory Matters
As a holding company registered with the SEC under the PUHCA, Ameren is subject to the regulatory provisions of the PUHCA, including provisions relating to the issuance of securities, sales and acquisitions of securities and utility assets, affiliate transactions, financial reporting requirements, the services performed by Ameren Services and AFS, and the activities of certain other subsidiaries. Issuance of common stock and short-term and long-term debt and other securities by Ameren and CILCORP and issuance of debt having a maturity of twelve months or less by UE, CIPS and CILCO are subject to approval by the SEC under the PUHCA.
Genco is certified by the FERC as an "exempt wholesale generator" under the Energy Policy Act of 1992 and as a result is not a "public utility company" under the PUHCA. As an exempt wholesale generator, Genco is exempt from most of the provisions of the PUHCA that otherwise would apply to it as a subsidiary of a registered holding company. Issuance of securities by Genco is not subject to approval by the SEC under the PUHCA. The SEC may impose limitations on Ameren in connection with its financing for the purpose of investing in exempt wholesale generators and foreign utility companies if Ameren's aggregate investment in those activities exceeds 50% of its consolidated retained earnings. At December 31, 2003, Ameren's aggregate investment in exempt wholesale generators was 23% of its consolidated retained earnings. Ameren has no investment in foreign utility companies.
In many states, including Illinois, companies that sell electricity directly to retail customers pursuant to state statutes and regulations must be registered or licensed. Marketing Company has obtained "alternative retail electricity supplier" status in Illinois and plans to seek comparable status in other states where retail competition is developing. In December 2003, the IBEW filed a complaint before the ICC challenging Marketing Company's certification status, based on its interpretation of the reciprocity clause requirements. Marketing Company believes the complaint should be denied, but cannot predict how or when the complaint will be resolved. CILCO is an Illinois electric utility, and as such, is permitted to provide power and energy on a competitive basis to retail customers located outside its service territory. CILCO was required to seek Integrated Distribution Company status in the first quarter of 2004 whereby, upon approval, it would cease selling power and energy on a retail basis as prescribed by the Integrated Distribution Company rules. However, as a result of the IBEW complaint, CILCO has filed a notice with the ICC to extend the deadline for CILCO becoming an Integrated Distribution Company. This extension would ensure that either Marketing Company or CILCO would be able to sell on a competitive basis to retail customers in Illinois given the uncertainty presented by the IBEW complaint. We cannot predict how or when the ICC will rule on CILCO's motion.
Operation of UE's Callaway Nuclear Plant is subject to regulation by the NRC. Its Facility Operating License expires on October 18, 2024. UE's Osage hydroelectric plant and UE's Taum Sauk pumped-storage hydro plant, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other things, the general operation and maintenance of the projects. The license for the Osage Plant expires on February 28, 2006, and the license for the Taum Sauk Plant expires on June 30, 2010. In February 2004, UE filed an application with the FERC to renew the license for its Osage hydroelectric plant for an additional 50 year term. UE's Keokuk Plant and dam located in the Mississippi River between Hamilton, Illinois and Keokuk, Iowa, are operated under authority, unlimited in time, granted by an Act of Congress in 1905.
For information on regulatory matters in these jurisdictions, including the current status of electric transmission matters pending before the FERC, see Regulatory Matters in Management's Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report and Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8 of this report.
Environmental Matters
Certain of our operations are subject to federal, state and local environmental regulations relating to the safety and health of personnel, the public and the environment, including the identification, generation, storage, handling, transportation, disposal, record-keeping, labeling, reporting of and emergency response in connection with hazardous and toxic materials, safety and health standards, and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants. Failure to comply with those statutes or regulations could have material adverse effects on us, including the imposition of criminal or civil liability by regulatory agencies or civil fines and liability to private parties, and the required expenditure of funds to bring us into compliance. We believe we are in material compliance with existing regulations.
For additional discussion of environmental matters, including NOx credit requirements, see Liquidity and Capital Resources in Management's Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8 of this report.
SUPPLY FOR ELECTRIC POWER
During 2003, the Ameren Companies peak demand from retail and wholesale customers was 12,860 megawatts and the peak capability to deliver power from owned generation and power supply agreements was 15,090 megawatts. Forecasted peak demand from retail and wholesale customers for 2004 is 13,198 megawatts with a 15% reserve margin. Ameren-owned generation and purchased power are used to meet the energy needs of our customers. Factors that could cause us to purchase power include, among other things, generating plant outages, extreme weather conditions and the availability of power for a lower cost than we could generate it.
UE, Genco and CILCO utilize coal, nuclear, natural gas, hydro and oil to produce electric power for sale. On October 3, 2003, CILCO transferred substantially all its generating property and plant to AERG. See additional information regarding this transfer in Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8 of this report. The following table presents the fuel supply for electric generation for the years ended December 31, 2003, 2002 and 2001:
Coal
UE, Genco and CILCO have long-term agreements in place for the purchase of coal to supply electric generating facilities. These agreements have terms through 2010. Coal supply agreements typically have an initial term of five years, with approximately 20% of the contracts expiring annually. As of December 31, 2003, nearly 100% of UE's, Genco's and CILCO's expected 2004 coal usage was under contract, and approximately 47% of the expected coal usage for 2005 to 2008 was under contract. Ameren burned 31 million tons of coal in 2003.
UE, Genco and CILCO have a policy of maintaining coal inventory consistent with their historical usage. Levels may be adjusted based on uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns and other factors. The following table presents the number of days supply of coal in inventory as of December 31, 2003 and 2002:
=============================================================================== 2003 2002 - ------------------------------------------------------------------------------- Ameren(a)....................................... 56 59 UE.............................................. 59 63 Genco........................................... 55 46 CILCORP(b)...................................... 38 49 CILCO........................................... 38 49 =============================================================================== (a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) 2002 amounts represent predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
Nuclear
UE has agreements and/or inventories to fulfill its Callaway Nuclear Plant needs for uranium, conversion, enrichment and fabrication services through 2006. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected remainder of the life of the plant, at prices which cannot now be accurately predicted. The Callaway Nuclear Plant normally requires refueling at 18-month intervals, and the next refueling is scheduled for the spring of 2004. The Callaway Nuclear Plant is expected to be out of service for approximately 40 to 45 days during this refueling. See Note 16 - Callaway Nuclear Plant to our financial statements under Part II, Item 8 of this report for additional information.
Natural Gas Supply for Power Generation
Ameren owns 2,509 megawatts of natural gas-fired generating capacity. The gas-fired capacity is primarily CTs, and some have the capability to use natural gas or oil. See Item 2.
ITEM 2. PROPERTIES.
For information on our principal properties, planned additions or replacements and transfers, see the generating facilities table below and Liquidity and Capital Resources and Regulatory Matters in Management's Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report and Note 3 - Rate and Regulatory Matters, Note 6 - - Long-term Debt and Equity Financings and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8 of this report.
UE, CIPS and CILCO are members of MAIN, which is one of the ten regional electric reliability councils organized for coordinating the planning and operation of the nation's bulk power supply. MAIN operates in Illinois and portions of Michigan, Wisconsin, Iowa, Minnesota and Missouri. UE, CIPS and CILCO provided formal written notice to the MAIN Board of Directors on June 23, 2003 of their intent to withdraw from MAIN effective January 1, 2005. These Ameren companies intend to join another Regional Reliability Organization prior to their withdrawal from MAIN becoming effective. Until their withdrawal is effective, they will continue to honor all of their obligations as members of MAIN. If these Ameren companies do not join another Regional Reliability Organization, they may withdraw their notice of intent to withdraw from MAIN.
The bulk power system of UE, CIPS and Genco is operated as an Ameren-wide control area and transmission system under the FERC-approved amended joint dispatch agreement. The amended joint dispatch agreement provides a basis upon which UE and Genco can participate in the coordinated operation of CIPS' and UE's transmission facilities with UE's and Genco's generating facilities in order to achieve economies consistent with the provision of reliable electric service and an equitable sharing of the benefits and costs of that coordinated operation. In 2003, we had a minimum of 24 direct connections with other control areas and the exchange of electric energy, directly and through the facilities of others. CILCO continues to operate as a separate control area. As such, its generating plants and those of its subsidiary, AERG, have not been jointly dispatched with the generating plants owned by UE and Genco. CILCO is a transmission owning member of the Midwest ISO and has transferred functional control of its system to the Midwest ISO. Transmission service on the CILCO transmission system is provided pursuant to the terms of the Midwest ISO OATT on file with the FERC. For information on CIPS' and UE's participation in the Midwest ISO, see Note 3 - Rate and Regulatory Matters to our financial statements under Part II, Item 8 of this report.
The following table presents information with respect to our electric generating facilities and capability at the time of our expected 2004 peak summer electrical demand:
As of December 31, 2003, UE owned approximately 3,200 circuit miles of electric transmission lines and operated two propane-air plants and 2,950 miles of natural gas transmission and distribution mains. As of December 31, 2003, CIPS owned approximately 1,900 circuit miles of electric transmission lines and operated one propane-air plant, three underground gas storage fields and approximately 4,975 miles of natural gas transmission and distribution mains. As of December 31, 2003, CILCO owned approximately 333 circuit miles of electric transmission lines. CILCO operates two underground gas storage fields and approximately 3,757 miles of gas transmission and distribution mains. Other properties of the companies include distribution lines, underground cables, office buildings, warehouses, garages and repair shops.
We have fee title to all principal plants and other important units of property, and to the real property on which such facilities are located (subject to mortgage liens securing our outstanding first mortgage bond indebtedness and to certain permitted liens and judgment liens), except that:
o A portion of UE's Osage Plant reservoir, certain facilities at UE's Sioux Plant, most of UE's Peno Creek CT facility, Genco's Columbia CT facility, certain of Ameren's substations and most of our transmission and distribution lines and gas mains are situated on lands occupied under leases, easements, franchises, licenses or permits; o The United States and/or the State of Missouri own, or have or may have, paramount rights to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River, on which certain of UE's generating and other properties are located; and o The United States and/or the State of Illinois and/or the State of Iowa and/or the City of Keokuk, Iowa own or have or may have, paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of UE's Keokuk Plant is located.
Substantially all of the properties and plant of UE, CIPS and CILCO are subject to the direct first liens of the indentures securing their first mortgage bonds. On May 1, 2000, CIPS transferred all of its generating facilities and related assets to Genco. As a part of this transfer, CIPS' generating property and plant were released from the lien of the indenture securing its first mortgage bonds, and such property and plant are presently unencumbered. On October 3, 2003, CILCO transferred substantially all of its generating property and plant to its non rate-regulated electric generating subsidiary, AERG. As part of the transfer, CILCO's transferred generating property and plant was released from the lien of the indenture securing its first mortgage bonds. During 2004, UE plans to transfer its Illinois electric and gas transmission and distribution properties to CIPS. As a part of the transfer, UE's Illinois electric and gas transmission and distribution properties will be released from the lien of the indenture securing its first mortgage bonds and will become encumbered by the direct first lien of the indenture securing CIPS first mortgage bonds.
In December 2002, UE conveyed most of its Peno Creek CT facility to the City of Bowling Green, Missouri, and leased back the facility from the city for a 20 year term. As a part of the transaction, most of UE's Peno Creek property and plant was released from the lien of the indenture securing UE's first mortgage bonds. Under the terms of this capital lease, UE retains all operation and maintenance responsibilities for the facility and ownership of the facility is returned to UE at the expiration of the lease. When ownership of the Peno Creek facility is returned to UE by the City, the property and plant may again become encumbered by the direct first lien of any outstanding UE first mortgage bond indenture.
Ameren indirectly owns 60% of the common stock of EEI, which operates electric generation and transmission facilities in Illinois. UE owns 40% of the common stock of EEI, and Resources Company owns 20% of such stock. On April 30, 2002, CIPS transferred its 20% common stock interest in EEI to Ameren in the form of a non-cash dividend of
common stock in EEI. The book value of CIPS investment in EEI was $1.8 million. Subsequently, Ameren contributed such stock to Resources Company. This transfer completed the process of achieving a full divestiture of all electric generating capacity that had been owned directly or indirectly by CIPS pursuant to restructuring of the Illinois power industry. On February 2, 2004, Ameren entered into a definitive agreement to purchase a 20% interest in EEI from Dynegy, which upon closing, will be registered in the name of Resources Company. See Note 2 - Acquisitions to our financial statements under Part II, Item 8 of this report for further information on the acquisition of Illinois Power and the 20% interest in EEI. The remaining 20% of the common stock of EEI is held by Kentucky Utilities Company.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business, some of which involve substantial amounts. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our financial position, results of operations or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe we have established appropriate reserves for potential losses.
For additional information on legal and administrative proceedings, see Rates and Regulation under Item 1. Business above, Liquidity and Capital Resources and Regulatory Matters in Management's Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report and Note 3 - Rate and Regulatory Matters and Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8 of this report.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the fourth quarter of 2003 with respect to any of the Ameren Companies.
EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):
Officers are generally elected or appointed annually by the respective board of directors of each company following the election of such board at the annual meetings of shareholders. There are no family relationships between the foregoing officers except that Charles W. Mueller is the father of Michael G. Mueller. Charles W. Mueller retired as an officer on December 31, 2003, but continues as a director of Ameren. Except for Martin J. Lyons, Richard J. Mark, Michael L. Moehn and Donna K. Martin, each of the above-named executive officers has been employed by an Ameren company for more than five years in executive or management positions. Mr. Lyons was previously employed as an accountant by PricewaterhouseCoopers LLP; Mr. Mark as Chief Executive Officer of St. Mary's Hospital by Ancilla Systems, Incorporated; Mr. Moehn as an accountant by PricewaterhouseCoopers LLP; and Ms. Martin in human resources by Faulding Pharmaceuticals.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Ameren's common stock is listed on the New York Stock Exchange (ticker symbol: AEE). Ameren began trading on January 2, 1998, following the merger of UE and CIPSCO on December 31, 1997.
Ameren common stockholders of record totaled 89,970 on January 31, 2004. The following table presents the price ranges and dividends paid per common share for Ameren for each quarter during 2003 and 2002.
There is no trading market for the common stock of UE, CIPS, Genco, CILCORP or CILCO. Ameren holds all outstanding common stock of UE, CIPS and CILCORP; Development Company holds all outstanding common stock of Genco; and CILCORP holds all outstanding common stock of CILCO.
For a discussion of restrictions on the Ameren Companies payment of dividends, see Liquidity and Capital Resources in Management's Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Executive Summary
As we began 2003, Ameren was faced with a weak economy and energy market, electric rate reductions in our Missouri service territory and rising employee benefit costs. To tackle these challenges, we initiated a voluntary retirement program that reduced staffing levels by over 500 people, closed inefficient generating units, took steps to reduce employee benefit costs and focused on cost containment throughout our business. While decisions to undertake these initiatives were difficult, management felt they were necessary to meet investors' expectations and better position Ameren for the future so as to benefit all of our stakeholders.
Strong operating performance at our power plants during 2003 permitted Ameren to offset reduced sales due to milder-than-normal summer weather and to take advantage of better-than-expected interchange power prices. In 2003, our plants produced more electricity in a single year than ever before, resulting in an increased contribution from interchange sales. In 2003, we also successfully completed the acquisition and integration of CILCORP, realizing anticipated synergies.
With the addition of CILCORP, Ameren now serves over 1.7 million electric and over 500,000 natural gas customers in Missouri and Illinois. We are the largest electric utility in Missouri and the second largest electric utility in Illinois. In February 2004, we signed a definitive agreement to purchase from Dynegy the stock of Illinois Power and an additional 20% interest in EEI. We believe Illinois Power is an excellent strategic fit with our core transmission and distribution business and the additional interest in EEI will bring us more value from EEI's low cost generation plant. The acquisition of Illinois Power will add approximately 590,000 electric customers and 415,000 gas customers. Subject to regulatory approval, we expect to complete the acquisition by the end of 2004.
We expect factors positively impacting 2004 earnings to include, among other things, sales growth in our service territory, almost $30 million in gas rate increases for our gas operations, incremental synergies from the CILCORP acquisition and continued cost control. Factors negatively impacting 2004 earnings are expected to be the implementation of a $30 million reduction in annual electric revenues in Missouri in April 2004, a Callaway Nuclear Plant refueling outage in the spring of 2004, and rising employee benefit costs. Our 2004 earnings will also be affected by the short-term dilutive effect of the issuance of common shares in February 2004, the proceeds of which are intended to be ultimately used for the acquisitions of Illinois Power and the 20% interest in EEI. However, once completed, we expect these acquisitions to increase our earnings per share.
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren's primary asset is the common stock of its subsidiaries. Ameren's subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas distribution businesses and non rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren's common stock are dependent on distributions made to it by its subsidiaries. Ameren's Registrants are listed below. See Note 1 - Summary of Significant Accounting Policies to our financial statements for a detailed description of our principal subsidiaries. Also see the Glossary of Terms and Abbreviations.
o UE, also known as Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas distribution business in Missouri and Illinois.
o CIPS, also known as Central Illinois Public Service Company, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
o Genco, also known as Ameren Energy Generating Company, operates a non rate-regulated electric generation business.
o CILCO, also known as Central Illinois Light Company, is a subsidiary of CILCORP (a holding company) and operates a rate-regulated electric transmission and distribution business, a primarily non rate-regulated electric generation business and a rate-regulated natural gas distribution business in Illinois.
When we refer to our, we or us, it indicates that the referenced information relates to Ameren and its subsidiaries. When we refer to financing or acquisition activities, we are defining Ameren as the parent holding company. When appropriate, each Registrant is specifically referenced in order to distinguish among our different business activities.
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. Results of CILCORP and CILCO reflected in Ameren's consolidated financial statements include the period from the acquisition date of January 31, 2003 through December 31, 2003. However, tabular presentation of CILCORP and CILCO's results and other discussions specific to CILCORP and CILCO represent the full twelve month period. See Note 2 - Acquisitions to our financial statements under Part II, Item 8 of this report for further information. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
Acquisitions
CILCORP and Medina Valley
On January 31, 2003, Ameren completed the acquisition of all of the outstanding common stock of CILCORP from AES. CILCORP is the parent company of Peoria, Illinois-based CILCO. With the acquisition, CILCO became an indirect Ameren subsidiary, but remains a separate utility company, operating as AmerenCILCO. On February 4, 2003, Ameren also completed the acquisition of Medina Valley, which indirectly owns a 40 megawatt, gas-fired electric generation plant. The results of operations for CILCORP and Medina Valley were included in Ameren's consolidated financial statements effective with the respective January and February 2003 acquisition dates.
Ameren acquired CILCORP to complement its existing Illinois gas and electric operations. The purchase included CILCO's rate-regulated electric and natural gas businesses in Illinois serving approximately 205,000 and 210,000 customers, respectively, of which approximately 150,000 are combination electric and gas customers. CILCO's service territory is contiguous to CIPS' service territory. CILCO also has a non rate-regulated electric and gas marketing business principally focused in the Chicago, Illinois region. Finally, the purchase included approximately 1,200 megawatts of largely coal-fired generating capacity, most of which became non rate-regulated on October 3, 2003, due to CILCO's transfer of approximately 1,100 megawatts of generating capacity to AERG. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8 of this report for further information on the transfer to AERG.
The total acquisition cost was approximately $1.4 billion and included the assumption by Ameren of CILCORP and Medina Valley debt and preferred stock at closing of $895 million and consideration of $479 million in cash, net of $38 million cash acquired. The cash component of the purchase price came from Ameren's issuance in September 2002 of 8.05 million common shares and its issuance in early 2003 of an additional 6.325 million common shares, which together generated aggregate net proceeds of $575 million. See Note 2 - Acquisitions to our financial statements under Part II, Item 8 of this report for further information.
Illinois Power
On February 2, 2004, we entered into an agreement with Dynegy to purchase the stock of Decatur, Illinois-based Illinois Power and Dynegy's 20% ownership interest in EEI. Illinois Power operates a rate-regulated electric and natural gas transmission and distribution business serving approximately 590,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. The total transaction value is approximately $2.3 billion, including the assumption of approximately $1.8 billion of Illinois Power debt and preferred stock, with the balance of the
purchase price to be paid in cash at closing. Ameren will place $100 million of the cash portion of the purchase price in a six-year escrow pending resolution of certain contingent environmental obligations of Illinois Power and other Dynegy affiliates for which Ameren has been provided indemnification by Dynegy.
Ameren's financing plan for this transaction includes the issuance of new Ameren common stock, which in total, is expected to equal at least 50% of the transaction value. In February 2004, Ameren issued 19.1 million common shares that generated net proceeds of $853 million. Proceeds from this sale and future offerings are expected to be used to finance the cash portion of the purchase price, to reduce Illinois Power debt assumed as part of this transaction, to pay any related premiums and possibly to reduce present or future indebtedness and/or repurchase securities of Ameren or our subsidiaries.
Upon completion of the acquisition, expected by the end of 2004, Illinois Power will become an Ameren subsidiary operating as AmerenIP. The transaction is subject to the approval of the ICC, the SEC, the FERC, the Federal Communications Commission, the expiration of the waiting period under the Hart-Scott-Rodino Act and other customary closing conditions.
In addition, this transaction includes a firm capacity power supply contract for Illinois Power's annual purchase of 2,800 megawatts of electricity from a subsidiary of Dynegy. This contract will extend through 2006 and is expected to supply about 75% of Illinois Power's customer requirements.
For the nine months ended September 30, 2003, Illinois Power had revenues of $1.2 billion, operating income of $130 million, and net income applicable to its common shareholder of $88 million, and at September 30, 2003, had total assets of $2.6 billion, excluding an intercompany note receivable from its parent company of approximately $2.3 billion. For the year ended December 31, 2002, Illinois Power had revenues of $1.5 billion, operating income of $164 million, and net income applicable to its common shareholder of $158 million, and at December 31, 2002, had total assets of $2.6 billion, excluding an intercompany note receivable from its parent company of approximately $2.3 billion. See also Liquidity and Capital Resources below for the potential impact on credit ratings that could result from the acquisition of Illinois Power. Illinois Power also files quarterly and annual reports with the SEC.
RESULTS OF OPERATIONS
Earnings Summary
Our results of operations and financial position are affected by many factors. Weather, economic conditions and the actions of key customers or competitors can significantly impact the demand for our services. Our results are also affected by seasonal fluctuations caused by winter heating and summer cooling demand. With approximately 90% of Ameren's revenues directly subject to regulation by various state and federal agencies, decisions by regulators can have a material impact on the price we charge for our services. Our non rate-regulated sales are subject to market conditions for power. We principally utilize coal, nuclear fuel, natural gas and oil in our operations. The prices for these commodities can fluctuate significantly due to the world economic and political environment, weather, supply and demand levels and many other factors. We do not have fuel or purchased power cost recovery mechanisms in Missouri or Illinois for our electric utility businesses, but we do have gas cost recovery mechanisms in each state for our gas utility businesses. The electric rates for UE, CIPS and CILCO are largely set through 2006 such that cost decreases or increases will not be immediately reflected in rates. In addition, the gas delivery rates for UE in Missouri are set through June 2006. Fluctuations in interest rates impact our cost of borrowing and pension and postretirement benefits. We employ various risk management strategies in order to try to reduce our exposure to commodity risks and other risks inherent in our business. The reliability of our power plants, and transmission and distribution systems, and the level of operating and administrative costs, and capital investment are key factors that we seek to control in order to optimize our results of operations, cash flows and financial position.
Ameren's net income for 2003, 2002 and 2001, was $524 million ($3.25 per share before dilution), $382 million ($2.61 per share before dilution), and $469 million ($3.41 per share before dilution), respectively. In 2003, Ameren's net income included an after-tax gain ($31 million or 19 cents per share) related to the settlement of a dispute over mine
reclamation issues with a coal supplier and a net cumulative effect after-tax gain ($18 million or 11 cents per share) associated with the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." The coal contract settlement gain represented a return of coal costs plus accrued interest previously paid to a coal supplier for future reclamation of a coal mine. The SFAS No. 143 net gain resulted principally from the elimination of non-legal obligation costs of removal for non rate-regulated assets from accumulated depreciation.
The following table presents the net cumulative effect after-tax gain recorded at each of the Ameren Companies upon adoption of SFAS No. 143:
============================================================================ Net Cumulative Effect After-Tax Gain ---------------------------------------------------------------------------- Ameren(a)................................................. $ 18 UE........................................................ - CIPS...................................................... - Genco..................................................... 18 CILCORP(b)................................................ 4 CILCO(c).................................................. 24 ============================================================================ (a) Excludes amounts for CILCORP and CILCO prior to t January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) Represents predecessor information recorded in January 2003 prior to the acquisition date of January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. (c) CILCO's financial statements are presented on a historical basis of accounting for all periods presented. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8 of this report for further information.
In 2002, Ameren's net income included restructuring charges of $58 million, net of taxes, or 40 cents per share, which consisted of a voluntary employee retirement program, the retirement of UE's Venice, Illinois plant, and the temporary suspension of operation of two coal-fired generating units at Genco's Meredosia, Illinois plant. See Note 7 - Restructuring Charges and Other Special Items to our financial statements under Part II, Item 8 of this report for further information. In 2001, Ameren's net income was reduced by $7 million, net of taxes, or 5 cents per share, due to the adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities."
The following table presents a reconciliation of Ameren's net income to net income excluding restructuring charges and other special items (e.g. coal contract settlement), as well as the effect of SFAS No. 143 and SFAS No. 133 adoption, all net of taxes, for the years ended December 31, 2003, 2002, and 2001. Ameren believes this reconciliation presents results from continuing operations on a more comparable basis. However, net income, or earnings per share, excluding these items is not a presentation defined under GAAP and may not be comparable to other companies or more useful than the GAAP presentation included in Ameren's financial statements.
Excluding the gains and losses discussed above, Ameren's net income increased $35 million, and earnings per share decreased six cents, in 2003 as compared to 2002. The change in net income was primarily due to the acquisition of CILCORP, as discussed below, favorable interchange margins (35 cents per share) due to improved power prices in the energy markets and greater low-cost generation available for sale, organic growth, lower labor costs due to the voluntary
employee retirement program implemented in early 2003 (11 cents per share), lower maintenance expenses in Ameren's pre-CILCORP acquisition operations (25 cents per share), and a decrease in Other Miscellaneous Expense as a result of the expensing of economic development and energy assistance programs in the second quarter of 2002 related to the UE Missouri electric rate case settlement. These benefits to Ameren's 2003 net income were partially offset by unfavorable weather conditions (estimated to be 40 to 50 cents per share) primarily due to cooler summer weather in Ameren's pre-CILCORP territory, an electric rate reduction in UE's Missouri service territory that went into effect in April 2003 (11 cents per share), lower sales of emission credits (7 cents per share), higher employee benefit costs and increased common shares outstanding.
Excluding the charges discussed above, Ameren's net income decreased $36 million (45 cents per share) in 2002 as compared to 2001, primarily due to the impact of the settlement of our Missouri electric rate case (26 cents per share), increased costs of employee benefits, higher depreciation (17 cents per share), excluding the effect of the rate case that is included in the 26 cents above, and a decline in industrial sales due to the continued soft economy. Increased average common shares outstanding (8.8 million shares) and financing costs also reduced Ameren's earnings per share in 2002 (29 cents per share). Factors decreasing net income in 2002 were partially offset by favorable weather conditions (estimated to be 20 to 30 cents per share), sales of emission credits by EEI (10 cents per share) and organic growth.
The impact from the acquisitions of CILCORP and Medina Valley and related financings was accretive to Ameren's earnings per share in 2003 by an estimated four cents per share as Ameren realized synergies associated with the acquisitions following the integration of systems and operating practices.
The amortization of non-cash purchase accounting fair value adjustments at CILCORP increased Ameren's and CILCORP's net income by $24 million for the eleven months ended December 31, 2003, as compared to the prior year period. The amortization of the fair value adjustments that increased net income were related to pension and postretirement liabilities, coal contract liabilities, severance liabilities and long-term debt. The amortization of fair value adjustments that decreased net income were related to electric plant in service, purchased power and emission credits. The following table presents the favorable (unfavorable) impact on Ameren's and CILCORP's net income related to the amortization of purchase accounting fair value adjustments during 2003:
============================================================================ For the eleven months ended December 31, 2003: ---------------------------------------------------------------------------- Statement of Income line item: Other operations and maintenance(a)........................... $ 39 Interest(b)................................................... 7 Fuel and purchased power(c)................................... 1 Depreciation and amortization(d).............................. (7) Income taxes(e)............................................... (16) ----------------------------------------------------------------------------- Impact on net income.......................................... $ 24 ============================================================================ (a) Included in other operations and maintenance are the amortization of the adjustment of the pension plan assets to fair value; the increase in the fair value of the retail customer contracts amortized over the remaining useful life of 10 years; the adjustment to fair value of the investment assets amortized over the useful lives ranging from 6 to 16 years; the adjustment of severance liabilities; and the write-off of CILCO software. (b) The impact on interest of the amortization of purchase accounting adjustments is due to CILCORP's 9.375% senior notes due 2029 and 8.70% senior notes due 2009 being written up to fair value and amortized over the average remaining life of the debt. See Note 6 - Long-term Debt and Equity Financings to our financial statements under Part II, Item 8 of this report for additional information. (c) Included in fuel and purchased power are the amortization of the adjustment of emission credits to fair value amortized over 28 years and the amortization of the adjustment of coal contracts to fair value amortized over the remaining useful life of 2 years. (d) The impact on depreciation and amortization of the amortization of purchase accounting adjustments is due to the plant assets at Duck Creek, E. D. Edwards, and Sterling Avenue being written up to fair value and amortized over the remaining useful lives of the plants (Duck Creek - 34 years; E. D. Edwards - 27 years; and Sterling Avenue - 15 years). (e) Tax effect of the above amortization adjustments. (e) Tax effect of the above amortization adjustments.
As a holding company, Ameren's net income and cash flows are primarily generated by its principal subsidiaries, UE, CIPS, Genco and CILCORP. The following table presents the contribution by Ameren's principal subsidiaries to Ameren's consolidated net income for the years ended December 31, 2003, 2002, and 2001:
Electric Operations
The following tables present the favorable (unfavorable) variations in electric margins, defined as electric revenues less fuel and purchased power, as compared to the prior periods for the years ended December 31, 2003 and 2002. Although electric margin may be considered a non-GAAP measure, we believe it is a useful measure to analyze the change in profitability of our electric operations between periods. The variation for Ameren reflects the entire contribution from CILCORP as a separate line item. The variations in CILCORP and CILCO electric margins are for 2003 as compared to 2002 when Ameren did not own these companies, and they did not contribute to Ameren's electric margins.
Ameren
2003 versus 2002
Ameren's electric margin increased $187 million in 2003 as compared to 2002. Increases in electric margin in 2003 were primarily attributable to the acquisition of CILCORP, increased interchange margins and organic sales growth, partially offset by unfavorable weather conditions relative to 2002, lower sales of emission credits and rate reductions. CILCORP's electric margin for the eleven months ended December 31, 2003, was $236 million. Interchange margins increased $92 million in 2003 due to improved power prices in the energy markets and increased low-cost generation availability. Average realized power prices on interchange sales increased to approximately $32 per megawatthour in 2003 from approximately $25 per megawatthour in 2002. Availability of coal-fired generating plants increased to 86% in 2003 from 82% in 2002 due to fewer scheduled and unscheduled outages. In addition, there was no refueling outage at the Callaway Nuclear Plant in 2003.
The unfavorable weather conditions were primarily due to cooler summer weather in the second and third quarters of 2003 versus warmer than normal conditions in the same periods in 2002. Cooling degree days were approximately 25% less in 2003 in our service territory compared to 2002 and approximately 10% less compared to normal conditions. Heating degree days in 2003 were comparable to 2002 and normal conditions. In Ameren's pre-CILCORP acquisition service territory, weather-sensitive residential and commercial electric kilowatthour sales declined 4% and 2%, respectively, in 2003 compared to 2002. Industrial electric kilowatthour sales increased 2% in 2003 in Ameren's pre-CILCORP acquisition service territory due to improving economic conditions.
Annual rate reductions of $50 million and $30 million were effective April 1, 2002 and 2003, respectively, as a result of the 2002 UE electric rate case settlement in Missouri, and negatively impacted electric revenues in 2003 and 2002. Revenues will be further reduced at UE by the 2002 UE settlement of the Missouri electric rate case, due to an additional $30 million of annual electric rate reduction effective April 1, 2004.
EEI's revenues decreased in 2003 compared to 2002 due to lower emission credit sales and decreased sales to its principal customer, which also resulted in a decrease in fuel and purchased power. EEI's sales of emission credits were $10 million in 2003 as compared to $38 million in 2002.
Ameren's fuel and purchased power increased in 2003 compared to 2002 due to increased kilowatthour sales related primarily to the addition of CILCORP. Excluding CILCORP, fuel and purchased power decreased in 2003 primarily due to the greater availability of low-cost generation.
2002 versus 2001
Ameren's electric margin increased $102 million in 2002 as compared to 2001. Increases in electric margin in 2002 were primarily attributable to more favorable weather conditions and increased sales of emission credits. In 2002, weather-sensitive residential electric kilowatthour sales increased by 7% and commercial electric kilowatthour sales
increased by 2% as cooling degree days were approximately 10% greater in 2002 compared to 2001. However, industrial sales were approximately 5% lower in 2002 as compared to 2001 due primarily to the impact of the soft economy. Revenues were also reduced by $47 million in 2002 due to the settlement of UE's Missouri electric rate case.
Contribution to electric margin from EEI increased in 2002 from 2001 principally due to EEI's sale of $38 million in emission credits, which is included in the overall $75 million increase in EEI revenues. The remaining EEI increase was due to increased sales to its principal customer, which also resulted in an increase in fuel and purchased power.
Interchange revenues decreased in 2002 from 2001 due to lower energy prices and less low-cost generation available for sale, resulting primarily from increased demand for generation from native load customers. Fuel and purchased power decreased in 2002 from 2001 due primarily to lower energy prices, partially offset by increased fuel and purchase power costs due to increased kilowatthour sales and unscheduled plant outages.
During 2002, we adopted the provisions of EITF No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," that required revenues and costs associated with certain energy contracts to be shown on a net basis in the Statement of Income. See also Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8 of this report for further information on the impact of netting these operating revenues and costs.
UE
UE's electric margin decreased $27 million in 2003 as compared to 2002. Decreases in electric margin in 2003 were primarily attributable to the unfavorable weather conditions and the rate reductions resulting from the 2002 Missouri electric rate case settlement as mentioned above. However, interchange margins increased $64 million due to improved power prices in the energy markets and increased low-cost generation availability as mentioned above. Fuel and purchased power in 2003 was comparable to 2002.
UE's electric margin increased $70 million in 2002 as compared to 2001. Increases in electric margin in 2002 were primarily attributable to more favorable weather conditions and lower fuel and purchased power costs. Revenues decreased due to the settlement of the 2002 Missouri electric rate case as mentioned above. Interchange margins decreased due to lower energy prices and less low-cost generation available for sale, resulting primarily from increased demand for generation from native load customers. Fuel and purchased power decreased due primarily to lower energy prices, partially offset by increased kilowatthour sales and unscheduled plant outages.
CIPS
CIPS' electric margin decreased $27 million in 2003, as compared to 2002, primarily due to unfavorable weather conditions as mentioned above and several customers switching from CIPS to Marketing Company. Commencing in 2002, all of CIPS', CILCO's and UE's Illinois residential, commercial and industrial customers had a choice in electric suppliers as provided by the Illinois Customer Choice Law. Several of CIPS' commercial and industrial customers switched to Marketing Company for their energy supply resulting in a decline in CIPS' revenues included in the growth and other line item in the table above of approximately $95 million and a decrease of approximately $85 million in purchased power of approximately $95 million for 2003. CIPS continues to provide electric delivery service to these customers and charges them ICC-approved delivery service tariff rates for that service. There was no significant switching of customers outside the Ameren Companies in 2002 or 2003.
CIPS' electric margin increased $6 million in 2002, as compared to 2001, primarily due to more favorable weather conditions and decreased purchased power costs attributable to lower energy prices. Partially offsetting the favorable weather were lower industrial and commercial sales related to the impact of the soft economy along with certain industrial customers electing to switch to Marketing Company as mentioned above.
Genco
Genco's electric margin increased $39 million in 2003 as compared to 2002. Increases in electric margin in 2003 were primarily attributable to increased interchange margins. Interchange margins increased $33 million in 2003 due to improved power prices in the energy markets. Fuel and purchased power increased $6 million in 2003 due to higher purchased power costs associated with higher energy prices and lower generation. These increased costs were partially offset by lower generation costs due to a 12% decline in megawatthour generation. The decline in generation during 2003 was primarily attributable to the timing of outages at Genco's power plants and unexpected downtime and unfavorable margins associated with Genco's CTs.
Genco's electric margin decreased $20 million in 2002 as compared to 2001. Decreases in electric margin in 2002 were primarily due to lower power prices and the reduction of indirect sales to UE under the 2001 and 2002 Marketing Company - UE power supply agreements, partially offset by increases in other wholesale and interchange revenues and increases in the use of lower cost generation due to better availability. See Note 14 - Related Party Transactions to our financial statements under Part II, Item 8 of this report for discussion of our power supply agreements. Genco's power plant availability increased 9 percentage points to 89% in 2002 compared to 80% in 2001. Revenues increased in 2002 due to an increase in the volume of interchange sales for the year, although these sales provided lower margins due to lower electricity prices. In addition, a net increase in new wholesale customers added by Marketing Company and an increase in sales to existing wholesale customers increased revenues. Fuel cost increased $51 million in 2002 due primarily to increased use of coal-fired generation stations due to better availability and increased wholesale demand. Purchased power costs decreased $18 million due to lower energy prices and improved plant availability.
CILCORP
CILCORP's electric margin decreased $13 million in 2003 as compared to 2002. Decreases in electric margin in 2003 were primarily attributable to lower margin per megawatthour sold on a non rate-regulated basis to electric customers outside of CILCO's service territory, the switch of two large CILCO customers to Marketing Company and unfavorable weather conditions as mentioned above. In addition, fuel and purchased power increased due to the net effect of purchase accounting fair value adjustments related to emission allowances and coal contracts.
CILCORP's electric margin decreased $19 million in 2002 as compared to 2001. Decreases in electric margin in 2002 were primarily attributable to purchase accounting adjustments of $83 million associated with coal contracts related to the purchase of CILCORP by AES, offset by favorable weather conditions and higher margin per megawatthour sold on a non rate-regulated basis to electric customers outside CILCORP's service territory.
CILCO
CILCO's electric margin decreased $14 million in 2003 as compared to 2002. Decreases in electric margin in 2003 were primarily attributable to a lower margin per megawatthour sold on a non rate-regulated basis to electric customers outside CILCO's service territory, the switch of two large CILCO customers to Marketing Company and unfavorable weather conditions as mentioned above.
CILCO's electric margin increased $64 million in 2002 as compared to 2001. Increases in electric margin in 2002 were primarily attributable to favorable weather conditions and a higher margin per megawatthour sold on a non rate-regulated basis to electric customers outside CILCO's service territory. This resulted from the termination of a higher priced supply contract that was replaced with lower-cost purchases. The termination of the supply contract was unusual due to the bankruptcy of the supplier and therefore, the higher margins were not expected to continue beyond 2002.
Gas Operations
The following table presents the favorable (unfavorable) variations in gas margins, defined as gas revenues less gas purchased for resale, as compared to the prior periods for the years ended December 31, 2003 and 2002. Although gas margin may be considered a non-GAAP measure, we believe it is a useful measure to analyze the change in profitability of gas operations between periods.
============================================================================ 2003 2002 ---------------------------------------------------------------------------- Ameren(a)............................ $ 74 $ (3) UE................................... (2) (6) CIPS................................. 1 4 Genco................................ - - CILCORP(b)........................... 3 2 CILCO(c)............................. 6 1 ============================================================================ (a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) Includes predecessor information for periods prior to January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. (c) CILCO's financial statements are presented on a historical basis of accounting for all periods presented. See Note 1 - Summary of Significant Accounting Policies to our financial statements under Part II, Item 8 of this report for further information.
Ameren's gas margin increased in 2003, as compared to 2002, primarily due to the acquisition of CILCORP (eleven months ended December 31, 2003 - $73 million). The gas margins at UE, CIPS, CILCORP and CILCO in 2003 were comparable to 2002 as heating degree days were consistent with 2002.
Ameren's and UE's gas margins decreased in 2002, as compared to 2001, primarily due to warmer winter weather in early 2002, partially offset by increased gas sales due to colder than normal temperatures in late 2002. The gas margins at CIPS, CILCORP and CILCO increased due to a decrease in gas costs attributable to lower natural gas prices, partially offset by warmer winter weather in early 2002 as compared to normal.
Operating Expenses and Other Statement of Income Items
The following tables present the favorable (unfavorable) variations in operating and other expenses as compared to the prior periods for the years ended December 31, 2003 and 2002:
Other Operations and Maintenance
Ameren
Ameren's other operations and maintenance expenses increased $64 million in 2003, as compared to 2002, primarily due to the addition of CILCORP (eleven months ended December 31, 2003 - $135 million), transition costs related to the CILCORP acquisition, higher employee benefit costs ($17 million) and a net increase in injuries and damages costs based on claims experience ($6 million). These increases in other operations and maintenance expenses were partially offset by lower labor costs resulting primarily from the voluntary employee retirement program implemented in early 2003 and lower plant maintenance costs primarily due to the number and timing of outages ($60 million). There was not a refueling outage at the Callaway Nuclear Plant in 2003. See also Equity Price Risk under Part II, Item 7A
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the risk of changes in value of a physical asset or a financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates. The following discussion of our risk management activities includes "forward-looking" statements that involve risks and uncertainties. Actual results could differ materially from those projected in the "forward-looking" statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either non-financial or non-quantifiable. Such risks principally include business, legal and operational risks and are not represented in the following discussion.
Our risk management objective is to optimize our physical generating assets within prudent risk parameters. Our risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated with:
o long-term and short-term variable-rate debt; o fixed-rate debt; o commercial paper; o auction-rate long-term debt; and o auction-rate preferred stock.
We manage our interest rate exposure by controlling the amount of these instruments we hold within our total capitalization portfolio and by monitoring the effects of market changes in interest rates.
The following table presents the estimated increase (decrease) in our annual interest expense and net income if interest rates were to change by 1% on variable rate debt outstanding at December 31, 2003:
=============================================================================== Interest Expense Net Income(a) - ------------------------------------------------------------------------------- Ameren................................. $ 9 $ (6) UE..................................... 7 (4) CIPS................................... 1 (1) Genco.................................. 1 (1) CILCORP................................ 3 (2) CILCO.................................. 3 (2) =============================================================================== (a) Calculations are based on an effective tax rate of 37%.
The model does not consider the effects of the reduced level of potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no change in our financial structure.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. On all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction.
Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables, executory contracts with market risk exposures and leverage lease investments. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups comprising our customer base. No non-affiliated customer represents greater than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. UE and Genco have credit exposure associated with accounts receivables from non-affiliated companies for interchange sales. At December 31, 2003, UE's, Genco's and Marketing Company's combined credit exposure to non-investment grade counterparties related to interchange sales was $4 million, net of collateral. We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program which involves daily exposure reporting to senior management, master trading and netting agreements, and credit support such as letters of credit and parental guarantees. We also analyze each counterparty's financial condition prior to entering into sales, forwards, swaps, futures or option contracts and monitor counterparty exposure associated with our leveraged leases.
Equity Price Risk
Our costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rate of return on plan assets, discount rate, the rate of increase in healthcare costs and contributions made to the plans. The market value of our plan assets was affected by declines in the equity market for 2000 through 2002 for the pension and postretirement plans. As a result, at December 31, 2002, we recognized an
additional minimum pension liability as prescribed by SFAS No. 87, "Employers' Accounting for Pensions," which resulted in an after-tax charge to OCI and a reduction in stockholders' equity of $102 million. At December 31, 2003, the minimum pension liability was reduced, resulting in OCI of $46 million and an increase in stockholders' equity. The following table presents the minimum pension liability amounts, after taxes, for the Ameren Companies as of December 31, 2003 and 2002:
=============================================================================== 2003 2002 - ------------------------------------------------------------------------------- Ameren(a)................................... $ 56 $ 102 UE.......................................... 34 62 CIPS........................................ 7 13 Genco....................................... 4 6 CILCORP(b).................................. - 60 CILCO....................................... 13 30 =============================================================================== (a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries. (b) 2002 amounts represent predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
The amount of the pension liability as of December 31, 2003, was the result of asset returns, interest rates and our contributions to the plans during 2003. In future years, the liability recorded, the costs reflected in net income, or OCI, or cash contributions to the plans could increase materially without a recovery in equity markets in excess of our assumed return on plan assets of 8.5%. If the fair value of the plan assets were to grow and exceed the accumulated benefit obligations in the future, then the recorded liability would be reduced and a corresponding amount of equity would be restored, net of taxes.
UE also maintains trust funds, as required by the NRC and Missouri and Illinois state laws, to fund certain costs of nuclear plant decommissioning. As of December 31, 2003, these funds were invested primarily in domestic equity securities (68%), debt securities (30%), and cash and cash equivalents (2%) and totaled $212 million at fair value. By maintaining a portfolio that includes long-term equity investments, UE seeks to maximize the returns to be utilized to fund nuclear decommissioning costs. However, the equity securities included in the portfolio are exposed to price fluctuations in equity markets and the fixed-rate, fixed-income securities are exposed to changes in interest rates. UE actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, established target allocation percentages of the assets of the trusts to various investment options. UE's exposure to equity price market risk is, in large part, mitigated, due to the fact that UE is currently allowed to recover decommissioning costs in its rates.
Commodity Price Risk
We are exposed to changes in market prices for natural gas, fuel and electricity to the extent they cannot be recovered through rates. UE has electric rate freezes in place in Missouri through June 30, 2006, and UE, CIPS and CILCO have electric rate freezes in place in Illinois through January 1, 2007. We utilize several techniques to mitigate risk, including utilizing derivative financial instruments. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset. The derivative financial instruments that we use (primarily forward contracts, futures contracts, option contracts and financial swap contracts) are dictated by risk management policies.
With regard to UE, CIPS and CILCO's natural gas utility business, exposure to changing market prices is in large part mitigated by the fact there are gas cost recovery mechanisms (PGA clauses) in place in both Missouri and Illinois. These gas cost recovery mechanisms allow UE, CIPS and CILCO to pass on to retail customers prudently incurred costs of natural gas.
We use fixed-price forward contracts, as well as futures, options and financial swaps to manage risks associated with fuel and natural gas prices. The majority of our fuel supply contracts are physical forward contracts. Since we do not have a provision similar to the PGA clause for our electric operations, we have entered into long-term contracts with various suppliers to purchase coal and nuclear fuel in order to manage our exposure to fuel prices. See Note 15 - Commitments and Contingencies to our financial statements under Part II, Item 8
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholders of Ameren Corporation:
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, common stockholders' equity and cash flows present fairly, in all material respects, the financial position of Ameren Corporation and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, 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 audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003. As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for derivative instruments and hedging activities effective January 1, 2001.
/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
St. Louis, Missouri February 12, 2004
REPORT OF INDEPENDENT AUDITORS ON FINANCIAL STATEMENT SCHEDULE
To the Board of Directors and Shareholders of Ameren Corporation:
Our audits of the consolidated financial statements referred to in our report dated February 12, 2004, appearing in this Annual Report on Form 10-K, also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
St. Louis, Missouri February 12, 2004
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholder of Union Electric Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Union Electric Company at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003. As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for derivative instruments and hedging activities effective January 1, 2001.
/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
St. Louis, Missouri February 12, 2004
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholder of Central Illinois Public Service Company:
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Public Service Company at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for derivative instruments and hedging activities effective January 1, 2001.
/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
St. Louis, Missouri February 12, 2004
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholder of Ameren Energy Generating Company:
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Ameren Energy Generating Company at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003. As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for derivative instruments and hedging activities effective January 1, 2001.
/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
St. Louis, Missouri February 12, 2004
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholder of CILCORP Inc.:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of CILCORP Inc. and its subsidiaries at December 31, 2003 (successor), and the results of their operations and their cash flows for the periods February 1, 2003 to December 31, 2003 (successor) and January 1, 2003 to January 31, 2003 (predecessor), in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the year ended December 31, 2003, listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule 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 predecessor financial statements of the Company as of December 31, 2002, and for each of the two years in the period then ended and the financial statement schedule for the two years in the period ended December 31, 2002, were audited by other auditors whose report dated April 11, 2003, expressed an unqualified opinion on those statements.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003.
/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
St. Louis, Missouri February 12, 2004
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholder of Central Illinois Light Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Light Company at December 31, 2003, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the year ended December 31, 2003, listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule 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 predecessor financial statements of the Company as of December 31, 2002, and for each of the two years in the period then ended and the financial statement schedule for the two years in the period ended December 31, 2002, were audited by other auditors whose report dated April 11, 2003, expressed an unqualified opinion on those statements.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003.
/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
St. Louis, Missouri February 12, 2004
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Stockholder of CILCORP Inc. Peoria, Illinois
We have audited the accompanying consolidated balance sheet of CILCORP Inc. and subsidiaries as of December 31, 2002, and the related consolidated statements of income and comprehensive income, stockholder's equity, and cash flows for the years ended December 31, 2002 and 2001. Our audits also included the 2002 and 2001 financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, such 2002 and 2001 consolidated financial statements present fairly, in all material respects, the financial position of CILCORP Inc. and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2002 and 2001 financial statement schedules, when considered in relation to the basic 2002 and 2001 consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 1, effective January 1, 2001, CILCORP Inc. and subsidiaries changed its method of accounting for derivative instruments to conform to Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." As discussed in Note 1, effective January 1, 2002, CILCORP Inc. and subsidiaries changed its method of accounting for goodwill and intangible assets to conform to Statement of Financial Accounting Standards No. 142, "Goodwill and Intangible Assets."
/s/ DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Indianapolis, IN April 11, 2003
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Stockholder of Central Illinois Light Company Peoria, Illinois
We have audited the accompanying consolidated balance sheet of Central Illinois Light Company and subsidiaries as of December 31, 2002, and the related consolidated statements of income and comprehensive income, stockholder's equity, and cash flows for the years ended December 31, 2002 and 2001. Our audits also included the 2002 and 2001 financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, such 2002 and 2001 consolidated financial statements present fairly, in all material respects, the financial position of Central Illinois Light Company and subsidiaries as of December 31, 2002, and the results of their operations and their cash flows for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such 2002 and 2001 financial statement schedules, when considered in relation to the basic 2002 and 2001 consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 1, effective January 1, 2001, Central Illinois Light Company and subsidiaries changed its method of accounting for derivative instruments to conform to Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."
/s/ DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Indianapolis, IN April 11, 2003
AMEREN CORPORATION (CONSOLIDATED) UNION ELECTRIC COMPANY (CONSOLIDATED) CENTRAL ILLINOIS PUBLIC SERVICE COMPANY AMEREN ENERGY GENERATING COMPANY CILCORP INC. (CONSOLIDATED) CENTRAL ILLINOIS LIGHT COMPANY (CONSOLIDATED)
COMBINED NOTES TO FINANCIAL STATEMENTS December 31, 2003
NOTE 1 - Summary of Significant Accounting Policies
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with the SEC under the PUHCA. Ameren's primary asset is the common stock of its subsidiaries. Ameren's subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas distribution businesses and non rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren's common stock are dependent on distributions made to it by its subsidiaries. Ameren's principal subsidiaries are listed below. Also see Glossary of Terms and Abbreviations.
o UE, also known as Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas distribution business in Missouri and Illinois. UE was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the State of Missouri and supplies electric and gas service to a 24,500 square mile area located in central and eastern Missouri and west central Illinois. This area has an estimated population of 3 million and includes the greater St. Louis area. UE supplies electric service to approximately 1.2 million customers and natural gas service to approximately 130,000 customers. See Note 3 - Rate and Regulatory Matters for information regarding the proposed transfer in 2004 of UE's Illinois electric and natural gas transmission and distribution businesses to CIPS.
o CIPS, also known as Central Illinois Public Service Company, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. CIPS was incorporated in Illinois in 1902. It supplies electric and gas utility service to portions of central and southern Illinois having an estimated population of 1 million in an area of approximately 20,000 square miles. CIPS supplies electric service to approximately 325,000 customers and natural gas service to approximately 170,000 customers.
o Genco, also known as Ameren Energy Generating Company, operates a non rate-regulated electric generation business. Genco was incorporated in Illinois in March 2000, in conjunction with the Illinois Customer Choice Law. Genco commenced operations on May 1, 2000, when CIPS transferred its five coal-fired power plants representing in the aggregate approximately 2,860 megawatts of capacity and related liabilities to Genco at historical net book value. The transfer was made in exchange for a subordinated promissory note from Genco in the amount of $552 million and shares of Genco's common stock. Since Genco commenced operations, it has acquired 25 CTs providing it a total installed generating capacity of approximately 4,749 megawatts as of December 31, 2003. Genco currently has no plans to develop additional capacity. Genco is a subsidiary of Development Company, a subsidiary of Ameren Energy Resources, which is a subsidiary of Ameren. See Note 3 - Rate and Regulatory Matters for information regarding the proposed transfer in 2004 of Genco's CTs located in Pinckneyville and Kinmundy, Illinois to UE.
o CILCO, also known as Central Illinois Light Company, is a subsidiary of CILCORP (a holding company) and operates a rate-regulated electric transmission and distribution business, a primarily non rate-regulated electric generation business and a rate-regulated natural gas distribution business in Illinois. CILCO was incorporated in Illinois in 1913. It supplies electric and gas utility service to portions of central and east central Illinois in areas of approximately 3,700 and 4,500 square miles, respectively, with an estimated population of 1 million. CILCO supplies electric service to approximately 205,000 customers and natural gas service to approximately 210,000 customers. In October 2003, CILCO transferred its coal-fired plants and a CT facility, representing in the aggregate
approximately 1,100 megawatts of electric generating capacity, to a wholly owned subsidiary, known as AERG, as a contribution in respect of all the outstanding stock of AERG and AERG's assumption of certain liabilities. The net book value of the transferred assets was approximately $378 million and no gain or loss was recognized as the transaction was accounted for as a transfer between entities under common control. The transfer was made in conjunction with the Illinois Customer Choice Law. CILCORP was incorporated in Illinois in 1985.
Ameren has various other subsidiaries responsible for the short and long-term marketing of power, procurement of fuel, management of commodity risks and providing other shared services. Ameren also has a 60% ownership interest in EEI through UE, which owns 40%, and Resources Company, which owns 20%. Ameren consolidates EEI for financial reporting purposes, while UE and Resources Company report EEI under the equity method.
When we refer to our, we or us, it indicates that the referenced information relates to Ameren and its subsidiaries. When we refer to financing or acquisition activities, we are defining Ameren as the parent holding company. When appropriate, the Ameren Companies are specifically referenced in order to distinguish among their different business activities.
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. Results of CILCORP and CILCO reflected in Ameren's consolidated financial statements include the period from the acquisition date of January 31, 2003 through December 31, 2003. January 2003 and prior year data for CILCORP and CILCO are not included in Ameren's consolidated totals. See Note 2 - Acquisitions for further information. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
In order to be more consistent with industry reporting trends, our Statements of Income have been reclassified to present all income taxes as one line item. Previously, we reported a portion of our income taxes in Operating Expenses and a portion in Other Income and Deductions. This change results in our calculation of Operating Income now being on a pre-tax basis with no effect on net income. Additionally, our Balance Sheet presentations have been reformatted to change the order in which current and non-current items appear, with no effect on total assets, total liabilities or any sub-categories included on our Balance Sheets.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. Certain reclassifications have been made to prior years' financial statements to conform to 2003 reporting. See Accounting Changes and Other Matters relating to SFAS No. 143, "Accounting for Asset Retirement Obligations," below and Note 4 - Property and Plant, Net for further information.
Regulation
Ameren is subject to regulation by the SEC. Certain of Ameren's subsidiaries are also regulated by the MoPSC, ICC, NRC and the FERC. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," UE, CIPS and CILCO defer certain costs pursuant to actions of our rate regulators and are currently recovering such costs in rates charged to customers. See Note 3 - Rate and Regulatory Matters for further information.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
The following table presents the restricted cash amounts as of December 31, 2003 and 2002:
================================================================================ 2003 2002 - -------------------------------------------------------------------------------- Ameren(a)............................... $ 5 $ 5 UE...................................... 3 3 CIPS.................................... 1 2 Genco................................... - - CILCORP(b).............................. 1 - CILCO................................... 1 - ================================================================================ (a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) 2002 amounts represent predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
Property and Plant
We capitalize the cost of additions to, and betterments of, units of property and plant. The cost includes labor, material, applicable taxes and overhead. An allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders' equity) applicable to rate-regulated construction expenditures, is also added for our rate-regulated assets, and interest during construction is added for non rate-regulated assets. Maintenance expenditures and the renewal of items not considered units of property are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage value, are charged to accumulated depreciation. Asset removal costs incurred by our non rate-regulated operations, which do not constitute legal obligations, were expensed as incurred beginning in 2003. Asset removal costs accrued by our rate-regulated operations, which do not constitute legal obligations, are classified as a regulatory liability. See Accounting Changes and Other Matters relating to SFAS No. 143 below and Note 4 - Property and Plant, Net for further information.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis. The provision for depreciation for the Ameren Companies in 2003, 2002 and 2001 ranged from 3% to 4% of the average depreciable cost. Beginning in January 2003, with the adoption of SFAS No. 143, depreciation rates for our non rate-regulated assets were reduced to reflect the discontinuation of the accrual of dismantling and removal costs. See Accounting Changes and Other Matters relating to SFAS No. 143 below for further information.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the allowance for funds used during construction, which is a utility industry accounting practice. Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of allowance for funds used during construction, as well as other construction costs, occurs when completed projects are placed in service and reflected in customer rates. The following table presents the allowance for funds used during construction ranges of rates that were used during 2003, 2002 and 2001:
================================================================================ 2003 2002 2001 - -------------------------------------------------------------------------------- Ameren.................. 3% - 4% 5% - 9% 4% - 10% UE...................... 4 5 10 CIPS.................... 3 9 4 Genco................... - - - CILCORP................. 3 6 5 CILCO................... 3 6 5 ================================================================================
Goodwill
Goodwill is the excess of the purchase price of an acquisition over the fair value of the net assets acquired. Under the provisions of SFAS No. 142, "Goodwill and Other Intangible Assets," goodwill and other intangibles with indefinite lives are no longer subject to amortization. As required by SFAS No. 142, we evaluate goodwill for impairment in the fourth quarter annually or more frequently if events and circumstances indicate that the asset might be impaired. Ameren and CILCORP's goodwill relates to the acquisitions of CILCORP and Medina Valley in 2003. See Note 2 - Acquisitions for additional information regarding the acquisitions.
Leveraged Leases
Certain Ameren subsidiaries own interests in assets which have been financed as a leveraged lease. Ameren's investment in these leveraged leases represents the equity portion, generally 20% of the total investment, either as an undivided interest in the equipment or as a part owner through a partnership. In accordance with SFAS No. 13, "Accounting for Leases," at the time of lease inception a debit for rents receivable and estimated residual value is recorded with a credit to unearned income. These amounts are then adjusted over time as rents are received, income is realized and the asset is eventually sold. Ameren and CILCORP account for these investments as a net investment in these assets and do not include the amount of outstanding debt since the third party debt is non-recourse to the Ameren subsidiaries.
Impairment of Long-Lived Assets
We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared with the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value.
Unamortized Debt Discount, Premium and Expense
Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues.
Revenue
We accrue an estimate of electric and gas revenues for service rendered, but unbilled, at the end of each accounting period.
Interchange Revenues
The following table presents the interchange revenues included in Operating Revenues - Electric for the years ended December 31, 2003, 2002, and 2001:
================================================================================ 2003 2002 2001 - -------------------------------------------------------------------------------- Ameren(a)............ $ 351 $ 259 $ 364 UE................... 320 257 375 CIPS................. 37 35 35 Genco................ 140 99 91 CILCORP(b)........... 19 10 16 CILCO(c)............. 19 10 16 ================================================================================ (a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. Includes interchange revenues at EEI of $56 million for the year ended December 31, 2003 (2002 - $59 million; 2001 - $55 million). (b) 2002 and 2001 amounts represent predecessor information. 2003 amounts include January 2003 predecessor information, which was $3 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. (c) CILCO's financial statements are presented on a historical basis of accounting for all periods presented. See further information within this Note.
See EITF No. 02-3 discussion under Accounting Changes and Other Matters below for further information.
Purchased Power
The following table presents the purchased power expenses included in Operating Expenses - Fuel and Purchased Power for the years ended December 31, 2003, 2002, and 2001. See Note 14 - Related Party Transactions for further information on affiliate purchased power transactions.
================================================================================ 2003 2002 2001 - -------------------------------------------------------------------------------- Ameren(a)............... $ 256 $ 167 $ 298 UE...................... 161 206 384 CIPS.................... 341 418 433 Genco................... 144 107 125 CILCORP(b).............. 157 143 123 CILCO................... 157 143 123 ================================================================================ (a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) 2002 and 2001 amounts represent predecessor information. 2003 amounts include January 2003 predecessor information, which was $12 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
See EITF No. 02-3 discussion under Accounting Changes and Other Matters below for further information.
Fuel and Gas Costs
In UE's, CIPS' and CILCO's retail electric utility jurisdictions, there are no provisions for adjusting rates for changes in the cost of fuel for electric generation. In UE's, CIPS' and CILCO's retail gas utility jurisdictions, changes in gas costs are generally reflected in billings to gas customers through PGA clauses.
UE's cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is charged to expense, based on net kilowatthours generated and sold.
Excise Taxes
Excise taxes reflected on Missouri electric and gas, and Illinois gas, customer bills are imposed on us and are recorded gross in Operating Revenues and Other Taxes. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are recorded as tax collections payable and included in Taxes Accrued. The following table presents excise taxes recorded in Operating Revenues and Taxes Other than Income Taxes for the years ended 2003, 2002 and 2001:
================================================================================ 2003 2002 2001 - -------------------------------------------------------------------------------- Ameren(a)......................... $ 137 $ 116 $ 113 UE................................ 101 103 101 CIPS.............................. 14 13 12 Genco............................. - - - CILCORP(b)........................ 24 16 16 CILCO(c).......................... 24 16 16 ================================================================================ (a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) 2002 and 2001 amounts represent predecessor information. 2003 amounts include January 2003 predecessor information which was $2 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. (c) With the exception of taxes reflected on CILCO customer bills issued prior to October 27, 2003, excise taxes at CILCO are recorded as tax collections payable and are included on the Balance Sheet as Taxes Accrued.
Income Taxes
We file a consolidated federal tax return. Deferred tax assets and liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes, measured using statutory tax rates.
Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the related properties.
Earnings Per Share
There were no differences between the basic and diluted earnings per share amounts for Ameren in 2003. The inclusion of assumed stock option conversions in the calculation of earnings per share resulted in dilution of $0.01 for 2002 and 2001. The assumed stock option conversions increased the number of shares outstanding in the diluted earnings per share calculation by 289,244 in 2003, 332,909 shares in 2002 and 331,813 shares in 2001. Ameren's equity security units have no dilutive effect on earnings per share, except during periods when the average market price of Ameren's common stock is above $46.61. As only the Ameren parent company has publicly held common stock, earnings per share calculations are not relevant and are not presented for any of the subsidiary companies.
Accounting Changes and Other Matters
SFAS No. 133 - "Accounting for Derivative Instruments and Hedging Activities"
In January 2001, we adopted SFAS No. 133. The following table presents the impact of that adoption, which resulted in cumulative effect charges, net of taxes:
================================================================================ Ameren(a).................................................... $ 7 UE........................................................... 5 CIPS......................................................... - Genco........................................................ 2 CILCORP...................................................... - CILCO........................................................ - ================================================================================ (a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations.
In addition, the following table presents the impact of the 2001 adoption's cumulative effect adjustment, net of taxes, to OCI, which increased (reduced) common stockholders' equity:
================================================================================ Ameren(a).................................................... $ (11) UE........................................................... (8) CIPS......................................................... - Genco........................................................ (3) CILCORP(b)................................................... 2 CILCO........................................................ 2 ================================================================================ (a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) Represents predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
See Note 9 - Derivative Financial Instruments for further information.
SFAS No.143 - "Accounting for Asset Retirement Obligations"
We adopted the provisions of SFAS No. 143, effective January 1, 2003. SFAS No. 143 provides the accounting requirements for asset retirement obligations associated with tangible, long-lived assets. SFAS No. 143 requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to adjust asset retirement obligations based on changes in estimated fair value. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing or amount of cash flows associated with an asset retirement obligation affect our estimates of fair value.
Upon adoption of this standard, Ameren and UE recognized additional asset retirement obligations of approximately $213 million and a net increase in net property and plant of approximately $77 million related primarily to UE's Callaway Nuclear Plant decommissioning costs and retirement costs for a UE river structure. The difference between the net asset and the liability recorded upon adoption of SFAS No. 143 related to rate-regulated assets was recorded as an additional regulatory asset of approximately $136 million as Ameren and UE expect to continue to recover in electric rates the cost of Callaway Nuclear Plant decommissioning and other costs of removal. These asset retirement obligations and associated assets are in addition to assets and liabilities of $174 million that UE had recorded prior to the adoption of SFAS No. 143, related to the future obligations and funds accumulated to decommission the Callaway Nuclear Plant.
Also upon adoption of this standard, Ameren and Genco recognized an asset retirement obligation of approximately $4 million and a net increase in net property and plant of approximately $34 million. The asset retirement obligation relates to retirement costs for a Genco power plant ash pond. The net increase in property and plant, as well as the majority of the net after-tax gain of $18 million recognized upon adoption, resulted from the elimination of costs of removal for non rate-regulated assets previously accrued as a component of accumulated depreciation that were not legal obligations ($20 million). Ameren and Genco also recognized a loss for the difference between the net asset and liability for the retirement obligation recorded upon adoption related to Genco's assets ($2 million).
As a result of the acquisition of CILCORP on January 31, 2003, Ameren's asset retirement obligations increased due to the assumption of asset retirement obligations of approximately $6 million related to CILCO's power plant ash ponds (now owned by AERG). Prior to the acquisition, predecessor CILCORP and CILCO recognized a net after-tax gain upon adoption of SFAS No. 143 of $4 million and $24 million, respectively, due to the elimination of costs of removal for non rate-regulated assets previously accrued as a component of accumulated depreciation that were not a legal obligation. Similar to the treatment applied by Ameren in the acquisition of CILCORP, AES recorded purchase accounting at the CILCORP parent level following its 1999 acquisition of CILCORP, but did not "push down" the purchase accounting to any of CILCORP's subsidiaries, including CILCO. Accordingly, accumulated depreciation, including the embedded cost of removal liabilities, was reset to zero in purchase accounting for the CILCORP parent while CILCO continued to carry property and plant and the related accumulated depreciation on a historical basis. As a result, the gain upon adoption of SFAS No. 143 recognized by CILCO exceeded the gain recognized by CILCORP because the cost of removal liabilities reversed by CILCORP upon adoption of SFAS No. 143 included only those liabilities recorded since the 1999 AES acquisition.
Asset retirement obligations at Ameren and UE increased by $22 million during the year ended December 31, 2003, to reflect the accretion of obligations to their present value. Increases to Genco's, CILCORP's and CILCO's asset retirement obligations were immaterial during these periods. Substantially all of this accretion was recorded as an increase to regulatory assets.
In addition to those obligations that were identified and valued, we determined that certain other asset retirement obligations exist. However, we were unable to estimate the fair value of those obligations because the probability, timing or cash flows associated with the obligations were indeterminable. We do not believe that these obligations, when incurred, will have a material adverse impact on our financial position, results of operations or liquidity.
The fair value of the nuclear decommissioning trust fund for UE's Callaway Nuclear Plant is reported in Nuclear Decommissioning Trust Fund in Ameren's and UE's Consolidated Balance Sheet. This amount is legally restricted to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the regulatory asset recorded in connection with the adoption of SFAS No. 143.
SFAS No. 143 required a change in the depreciation methodology we historically utilized for our non rate-regulated operations. Historically, we included an estimated cost of dismantling and removing plant from service upon retirement in the basis upon which our depreciation rates were determined. SFAS No. 143 required us to exclude costs of dismantling and removal upon retirement from the depreciation rates applied to non rate-regulated plant balances. Further, we were required to remove accumulated provisions for dismantling and removal costs from accumulated depreciation, where they were embedded, and to reflect such adjustment as a gain upon adoption of this standard, to the extent such dismantling and removal activities were not considered legal asset retirement obligations as defined by SFAS No. 143. The elimination of costs of removal from accumulated depreciation resulted in a gain for a change in accounting principle at Ameren and Genco, as noted above, of $20 million, net of taxes. At CILCO, the elimination of costs of removal from accumulated depreciation resulted in a gain of $24 million, net of taxes, due to a change in
accounting principle. As noted above, the gain for predecessor CILCORP on a consolidated basis was only $4 million, net of taxes, due to the reset of accumulated depreciation at the time of AES' acquisition of CILCORP in 1999. Beginning in January 2003, depreciation rates for non rate-regulated assets were reduced to reflect the discontinuation of the accrual of dismantling and removal costs. In addition, non rate-regulated asset removal costs will prospectively be expensed as incurred. The impact of this change in accounting results in a decrease in depreciation expense and an increase in operations and maintenance expense, the net impact of which is indeterminable, but not expected to be material.
Like the methodology employed by our non rate-regulated operations, the depreciation methodology historically utilized by our rate-regulated operations has included an estimated cost of dismantling and removing plant from service upon retirement. Because these estimated costs of removal have been included in the cost of service upon which our present utility rates are based, and with the expectation that this practice will continue in the jurisdictions in which we operate, adoption of SFAS No. 143 did not result in any change in the depreciation accounting practices of our rate-regulated operations and, therefore, had no impact on net income from rate-regulated operations. However, in accordance with SFAS No. 143, estimated future removal costs previously embedded in accumulated depreciation were classified as a regulatory liability at December 31, 2003. A corresponding reclassification was made to conform the December 31, 2002, balance sheets to the current year presentation. These reclassifications had no impact on our results of operations or cash flows. The following table presents the estimated future removal costs recognized as a regulatory liability at December 31, 2003 and 2002:
================================================================================ 2003 2002 - -------------------------------------------------------------------------------- Ameren........................... $ 694(a) $ 652(b) UE............................... 556 528 CIPS............................. 131 124 Genco............................ - - CILCORP.......................... 7 27 CILCO............................ 150 141 ================================================================================ (a) Excludes amount for CILCO, as the elimination of accumulated depreciation in purchase accounting was recorded at the CILCORP parent level. (b) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003.
The following table presents the asset retirement obligation as though SFAS No. 143 had been in effect for 2001 and 2002:
(a) Excludes amounts for CILCORP and CILCO. (b) Represents predecessor information.
Pro forma net income, as well as pro forma earnings per share for Ameren, has not been presented for the years ended December 31, 2002 and 2001 because the pro forma application of SFAS No. 143 to prior periods would result in pro forma net income not materially different from the actual amounts reported for these periods.
EITF Issue No. 02-3, EITF Issue No. 98-10 and EITF Issue No. 03-11
During 2002, we adopted the provisions of EITF No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," that required revenues and costs associated with certain energy contracts to be shown on a net basis in the Statement of Income. Prior to adopting EITF No. 02-3 and the rescission of EITF No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," our accounting practice was to present all settled energy purchase or sale contracts within our power risk management program on a gross basis in Operating Revenues - Electric and Other and in Operating Expenses - Fuel and Purchased Power and Other Operations and Maintenance. This meant that revenues were
recorded for the sum of the notional amounts of the power sales contracts with a corresponding charge to income for the costs of the energy that was generated, or for the sum of the notional amounts of a purchased power contract.
In October 2002, the EITF reached a consensus to rescind EITF No. 98-10. The effective date for the full rescission of EITF No. 98-10 was for fiscal periods beginning after December 15, 2002, with early adoption permitted. In addition, the EITF reached a consensus in October 2002, that all SFAS No. 133 trading derivatives (subsequent to the rescission of EITF No. 98-10) should be shown net in the income statement, whether or not physically settled. This consensus applies to all energy and non-energy related trading derivatives that meet the definition of a derivative pursuant to SFAS No. 133. The following table presents the operating revenues and costs that were netted for the years ended December 31, 2002 and 2001, which reduced Operating Revenues - Electric and Other, and Operating Expenses - Fuel and Purchased Power and Other Operations and Maintenance, by equal amounts:
================================================================================ 2002 2001 - -------------------------------------------------------------------------------- Ameren(a)...................... $ 738 $ 648 UE............................. 458 392 CIPS........................... - - Genco.......................... 253 256 CILCORP........................ - - CILCO.......................... - - ================================================================================ (a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations.
The adoption of EITF No. 02-3, the rescission of EITF No. 98-10 and the related transition guidance resulted in the netting of energy contracts for financial reporting purposes, which lowered our reported revenues and costs with no impact on earnings.
In July 2003, the EITF reached a consensus on EITF No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, 'Accounting for Derivative Instruments and Hedging Activities,' and Not Held for Trading Purposes as Defined in EITF No. 02-3, 'Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,' " that was ratified by the FASB in August 2003. The EITF concluded that determining whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. The adoption of EITF No. 03-11 will have no impact on our results of operations.
SFAS No. 148 - "Accounting for Stock-based Compensation - Transition and Disclosure"
In December 2002, the FASB issued SFAS No. 148. SFAS No. 148 amended SFAS No. 123, "Accounting for Stock-based Compensation," to provide alternative methods of transition for an entity that voluntarily changes to the fair value-based method of accounting for stock-based employee compensation. It also amended the disclosure provisions to require disclosure about the effects on reported net income of an entity's accounting policy decisions with respect to stock-based employee compensation.
Prior to 2003, Ameren and CILCORP accounted for stock options granted under long-term incentive plans under the recognition and measurement provisions of APB Opinion No. 25, "Accounting for Stock Issued to Employees." No stock-based employee compensation cost was recognized for options under either Ameren's plan or CILCORP's plan under the AES Stock Option Plan in 2002 and 2001, as all options granted under the plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The pre-tax cost based on the weighted-average grant-date fair value of options for Ameren would have been approximately $2 million in each of the years ended 2002 and 2001 and $4 million and $2 million, respectively, for predecessor CILCORP, had the fair value method under SFAS No. 123 been used for options granted. Effective January 1, 2003, we adopted the fair value recognition provisions of SFAS No. 123 by using the prospective method of adoption under SFAS No. 148. As stock options have not been granted since 2000 at Ameren, SFAS No. 148 did not have any effect on Ameren's financial position, results of operations or liquidity since adoption. As stock options at CILCORP were granted under the AES Stock Option Plan, prior to our acquisition of CILCORP in January 2003, and no options were granted since 2001 under the AES Stock
Option Plan, SFAS No. 148 did not have any effect on Ameren's or CILCORP's financial position, results of operations or liquidity since adoption. See also Note 12 - Stock-based Compensation for further information.
SFAS No. 149 - "Amendment of Statement 133 on Derivative Instruments and Hedging Activities"
In April 2003, the FASB issued SFAS No. 149. SFAS No. 149 further clarifies and amends accounting and reporting for derivative instruments. The statement amends SFAS No. 133 for decisions made by the Derivative Implementation Group, as well as issues raised in connection with other FASB projects and implementation issues. The statement is effective for contracts entered into or modified after June 30, 2003 except for implementation issues that have been effective for reporting periods beginning before June 15, 2003, which continue to be applied based on their original effective dates. SFAS No. 149 did not have any effect on our financial position, results of operations or liquidity upon adoption in the third quarter of 2003.
SFAS No. 150 - "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity"
In May 2003, the FASB issued SFAS No. 150 that established standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Among other things, SFAS No. 150 requires financial instruments that were issued in the form of shares, with an unconditional obligation to redeem the instrument by transferring assets on a specified date, to be classified as liabilities. Accordingly, SFAS No. 150 requires issuers to classify mandatorily redeemable financial instruments as liabilities. SFAS No. 150 also requires such financial instruments to be measured at fair value and a cumulative effect adjustment to be recognized in the Statement of Income for any difference between the carrying amount and fair value. SFAS No. 150 became effective July 1, 2003. At July 1, 2003, CILCO had $21 million of preferred stock subject to mandatory redemption, which was reclassified to the liability section of Ameren's, CILCORP's and CILCO's Consolidated Balance Sheets. In accordance with the requirements of SFAS No. 150, no reclassification was made to the presentation on the December 31, 2002 Consolidated Balance Sheets of Ameren, CILCORP and CILCO. This preferred stock is redeemable at par at any time, and therefore, it was estimated there was no difference between book value and fair value.
FIN No. 46 - "Consolidation of Variable Interest Entities"
In January 2003, the FASB issued FIN No. 46, which significantly changed the consolidation requirements for traditional special purpose entities (SPE) and certain other entities and addressed the consolidation of variable-interest entities (VIEs). The primary objective of FIN No. 46 was to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights. If an entity absorbs the majority of the VIEs' expected losses or receives a majority of the VIEs' expected residual returns, or both, it must consolidate the VIE.
Initially, FIN No. 46 was effective no later than the beginning of the first interim period after June 15, 2003, for VIEs created before February 1, 2003. For VIEs created after January 31, 2003, FIN No. 46 was effective immediately. In September 2003, the FASB deferred the effective date of FIN No. 46 until the end of the first interim or annual period ending after December 15, 2003 for VIEs created prior to January 31, 2003. In December 2003, the FASB further deferred this effective date of FIN No. 46 for non-SPEs until the end of the first interim or annual period ending after March 15, 2004. During these deferral periods, the FASB has continued to clarify and amend several provisions, much of which will assist in the application of FIN No. 46 to operating entities. Ameren does not have any interests in entities that are considered SPEs. In addition, FIN No. 46 requires the deconsolidation of certain trust-preferred arrangements; however, Ameren does not have any trust-preferred arrangements.
Ameren is continuing to evaluate the impact of FIN No. 46 for non-SPEs. Ameren has a 60% ownership interest in EEI through UE, which owns 40%, and Resources Company, which owns 20%. Ameren consolidates EEI for financial reporting purposes. Ameren has several leveraged leases and other investments that we currently do not consolidate. We are still evaluating the impact of adopting FIN No. 46 in our first quarter ended March 31, 2004.
SFAS No. 132 (revised 2003) - "Employers' Disclosures about Pensions and Other Postretirement Benefits"
In December 2003, the FASB issued SFAS No. 132 (revised) to improve financial statement disclosures for defined benefit plans. The standard requires more details about plan assets, benefit obligations, cash flows, benefit costs and
other relevant information. SFAS No. 132 (revised) became effective for fiscal years ending after December 15, 2003. See Note 11 - Retirement Benefits for further information.
FASB Staff Position SFAS No. 106-1 - "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003"
Through its postretirement benefit plans, Ameren provides retirees with prescription drug coverage. On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Prescription Drug Act) was enacted. The Prescription Drug Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree healthcare benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. In response to the enactment of the Prescription Drug Act, the FASB issued FASB Staff Position SFAS No. 106-1 in January 2004, which permits a plan sponsor of a postretirement healthcare plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Prescription Drug Act. Ameren has made this one-time election allowed by FASB Staff Position SFAS No. 106-1. Thus, any measures of the accumulated projected benefit obligation or net periodic postretirement benefit costs in Ameren's financial statements and included in Note 11 - Retirement Benefits do not reflect the effects of the Prescription Drug Act on Ameren's postretirement plans. Ameren is evaluating what impact the Prescription Drug Act will have on its postretirement benefit plans and whether it will be eligible for a federal subsidy beginning in 2006. Specific authoritative guidance on the accounting for the federal subsidy is pending.
NOTE 2 - Acquisitions
CILCORP and Medina Valley
On January 31, 2003, Ameren completed the acquisition of all of the outstanding common stock of CILCORP from AES. CILCORP is the parent company of Peoria, Illinois-based CILCO. With the acquisition, CILCO became an indirect Ameren subsidiary, but remains a separate utility company, operating as AmerenCILCO. On February 4, 2003, Ameren also completed the acquisition from AES of Medina Valley, which indirectly owns a 40 megawatt, gas-fired electric generation plant. The results of operations for CILCORP and Medina Valley were included in Ameren's consolidated financial statements effective with the respective January and February 2003 acquisition dates. See Note 1 - Summary of Significant Accounting Policies for further information on the presentation of the results of CILCORP and CILCO in Ameren's consolidated financial statements.
Ameren acquired CILCORP to complement its existing Illinois gas and electric operations. The purchase included CILCO's rate-regulated electric and natural gas businesses in Illinois serving approximately 205,000 and 210,000 customers, respectively, of which approximately 150,000 are combination electric and gas customers. CILCO's service territory is contiguous to CIPS' service territory. CILCO also has a non rate-regulated electric and gas marketing business principally focused in the Chicago, Illinois region. Finally, the purchase included approximately 1,200 megawatts of largely coal-fired generating capacity, most of which became non rate-regulated on October 3, 2003, due to CILCO's transfer of 1,100 megawatts of generating capacity to AERG. See Note 1 - Summary of Significant Accounting Policies for further information on the transfer to AERG.
The total acquisition cost was approximately $1.4 billion and included the assumption by Ameren of CILCORP and Medina Valley debt and preferred stock at closing of $895 million and consideration of $479 million in cash, net of $38 million cash acquired. The cash component of the purchase price came from Ameren's issuance in September 2002 of 8.05 million common shares and its issuance in early 2003 of an additional 6.325 million common shares, which together generated aggregate net proceeds of $575 million.
The following table presents the estimated fair values of the assets acquired and liabilities assumed at the dates of our acquisitions of CILCORP and Medina Valley. A third party valuation of acquired property and plant and intangible assets is substantially complete; however, the allocation of the purchase price is subject to refinement until the valuation is finalized.
============================================================================= Current assets.......................................... $ 315 Property and plant...................................... 1,169 Investments and other non-current assets................ 154 Specifically-identifiable intangible assets............. 6 Goodwill................................................ 568 ----------------------------------------------------------------------------- Total assets acquired................................ 2,212 ----------------------------------------------------------------------------- ----------------------------------------------------------------------------- Current liabilities..................................... 196 Long-term debt, including current maturities............ 937 Other non-current liabilities........................... 521 ----------------------------------------------------------------------------- Total liabilities assumed............................ 1,654 ----------------------------------------------------------------------------- Preferred stock assumed................................. 41 ----------------------------------------------------------------------------- Net assets acquired.................................. $ 517 =============================================================================
Specifically-identifiable intangible assets of $6 million are comprised of retail customer contracts, which are subject to amortization with an average life of 10 years.
Goodwill of $568 million (CILCORP - $561 million; Medina Valley - $7 million) was recognized in connection with the CILCORP and Medina Valley acquisitions. None of this goodwill is expected to be deductible for tax purposes.
The following unaudited pro forma financial information presents a summary of Ameren's consolidated results of operations for the years ended December 31, 2003 and 2002, assuming the acquisitions of CILCORP and Medina Valley had been completed at the beginning of fiscal year 2002, including pro forma adjustments, which are based upon preliminary estimates, to reflect the allocation of the purchase price to the acquired net assets.
This pro forma information is not necessarily indicative of the results of operations as they would have been had the transactions been effected on the assumed date, nor is it an indication of trends in future results.
The amortization of non-cash purchase accounting adjustments at CILCORP increased Ameren's and CILCORP's net income by $24 million for the eleven months ended December 31, 2003. The amortization of the fair value adjustments that increased net income were related to pension and postretirement liabilities, coal contract liabilities, severance liabilities and long-term debt. The amortization of fair value adjustments that decreased net income were related to electric plant in service, purchased power and emission credits. The following table presents the favorable (unfavorable) impact on Ameren's and CILCORP's net income related to the amortization of purchase accounting fair value adjustments during 2003:
(a) Included in other operations and maintenance are the amortization of a purchase accounting liability associated with pension and postretirement benefit plan obligation; a purchase accounting asset associated with customer retail contracts amortized over the
remaining useful life of 10 years; a purchase accounting adjustment associated with investment assets being amortized over useful lives ranging from 6 - 16 years; a purchase accounting accrual for severance liabilities; and a purchase accounting accrual for abandoned CILCO software. (b) The impact on interest of the amortization of purchase accounting adjustments is due to CILCORP's 9.375% senior notes due 2029 and 8.70% senior notes due 2009 being written up to fair value with the adjustment being amortized over the average remaining life of the debt. See Note 6 - Long-term Debt and Equity Financings to our financial statements for additional information. (c) Included in fuel and purchased power are the amortization of emission allowance assets amortized over 28 years and the amortization of purchase accounting liabilities associated with coal contracts being amortized over the remaining life of 2 years. (d) The impact on depreciation and amortization of the amortization of purchase accounting adjustments is due to the plant assets at Duck Creek, E. D. Edwards, and Sterling Avenue being written up to fair value with the adjustment being amortized over the remaining useful lives of the plants (Duck Creek - 34 years; E. D. Edwards - 27 years; and Sterling Avenue - 15 years). (e) Tax effect of the above amortization adjustments.
Illinois Power
On February 2, 2004, we entered into an agreement with Dynegy to purchase the stock of Decatur, Illinois-based Illinois Power and Dynegy's 20% ownership interest in EEI. Illinois Power operates a rate-regulated electric and natural gas transmission and distribution business serving approximately 590,000 electric and 415,000 gas customers in areas contiguous to our existing Illinois utility service territories. The total transaction value is approximately $2.3 billion, including the assumption of approximately $1.8 billion of Illinois Power debt and preferred stock, with the balance of the purchase price to be paid in cash at closing. Ameren will place $100 million of the cash portion of the purchase price in a six-year escrow pending resolution of certain contingent environmental obligations of Illinois Power and other Dynegy affiliates for which Ameren has been provided indemnification by Dynegy.
Ameren's financing plan for this transaction includes the issuance of new Ameren common stock, which in total, is expected to equal at least 50% of the transaction value. In February 2004, Ameren issued 19.1 million common shares that generated net proceeds of $853 million. Proceeds from this sale and future offerings are expected to be used to finance the cash portion of the purchase price, to reduce Illinois Power debt assumed as part of this transaction, to pay any related premiums and possibly to reduce present or future indebtedness and/or repurchase securities of Ameren or our subsidiaries.
Upon completion of the acquisition, expected by the end of 2004, Illinois Power will become an Ameren subsidiary operating as AmerenIP. The transaction is subject to the approval of the ICC, the SEC, the FERC, the Federal Communications Commission, the expiration of the waiting period under the Hart-Scott-Rodino Act and other customary closing conditions.
In addition, this transaction includes a firm capacity power supply contract for Illinois Power's annual purchase of 2,800 megawatts of electricity from a subsidiary of Dynegy. This contract will extend through 2006 and is expected to supply about 75% of Illinois Power's customer requirements.
For the nine months ended September 30, 2003, Illinois Power had revenues of $1.2 billion, operating income of $130 million, and net income applicable to common shareholder of $88 million, and at September 30, 2003, had total assets of $2.6 billion, excluding an intercompany note receivable from its parent company of approximately $2.3 billion. For the year ended December 31, 2002, Illinois Power had revenues of $1.5 billion, operating income of $164 million, and net income applicable to common shareholder of $158 million, and at December 31, 2002, had total assets of $2.6 billion, excluding an intercompany note receivable from its parent company of approximately $2.3 billion. Illinois Power also files quarterly and annual reports with the SEC.
NOTE 3 - Rate and Regulatory Matters
Intercompany Transfer of Electric Generating Facilities and Illinois Service Territory
As a part of the settlement of the Missouri electric rate case in 2002, UE committed to making certain infrastructure investments from January 1, 2002 through June 30, 2006, including the addition of 700 megawatts of generation capacity. The new capacity requirement is expected to be satisfied by the additions in 2002 of 240 megawatts and the proposed transfer from Genco to UE, at net book value (approximately $250 million), of approximately 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois. The transfer is subject to receipt of FERC and SEC approval. Approval by the MoPSC is not required in order for this transfer to occur. However, the MoPSC has jurisdiction over UE's ability to recover the cost of the transferred generating facilities from its electric customers in its rates. As part of the settlement
of the Missouri electric rate case in 2002, UE is subject to a rate moratorium providing for no changes in its electric ratesbefore June 30, 2006, subject to certain statutory and other exceptions. Approval of the ICC is not required contingent upon prior approval and execution of UE's transfer of its Illinois public utility operations to CIPS as discussed below.
In February 2003, UE sought approval from the FERC to transfer approximately 550 megawatts of generating assets from Genco to UE. Certain independent power producers objected to UE's request based on a claim that the transfer may harm competition for the sale of electricity at wholesale and the FERC set the matter for hearing. In February 2004, the Administrative Law Judge hearing the case issued a preliminary order supporting the transfer. However, the full commission must approve the order for it to become effective.
In May 2003, UE announced its plan to limit its public utility operations to the state of Missouri and to discontinue operating as a public utility subject to ICC regulation. UE intends to accomplish this plan by transferring its Illinois-based electric and natural gas businesses, including its Illinois-based distribution assets and certain of its transmission assets, to CIPS. In 2003, UE's Illinois electric and gas service territory generated revenues of $155 million and had a net book value of $122 million at December 31, 2003. UE's electric generating facilities and a certain minor amount of its electric transmission facilities in Illinois would not be part of the transfer. The transfer was approved by the FERC in December 2003. The transfer of UE's Illinois-based utility businesses will also require the approval of the ICC, the MoPSC and the SEC under the provisions of the PUHCA. In August 2003, UE filed with the MoPSC, and in October and November 2003, filed with the ICC and the SEC for authority to transfer UE's Illinois-based utility businesses, at net book value, to CIPS. The filing with the ICC seeks approval to transfer only UE's Illinois-based natural gas utility business since the ICC authorized the transfer of UE's Illinois-based electric utility business to CIPS in 2000. UE proposes to transfer approximately one-half of the assets directly to CIPS in consideration for a CIPS promissory note, and approximately one-half of the assets by means of a dividend in kind to Ameren followed by a capital contribution by Ameren to CIPS.
A filing seeking approval of both the transfer of UE's Illinois-based utility business and Genco's CTs was made with the SEC in October 2003. If completed, the transfers will be accounted for at book value with no gain or loss recognition, which is appropriate treatment for transactions of this type by two entities under common control. In January 2004, the MoPSC staff and the Missouri Office of Public Counsel filed rebuttal testimony with the MoPSC expressing concerns that the transfer may be detrimental to the public in Missouri and recommended that the transfer be denied. On March 1, 2004, UE filed surrebuttal testimony, which responded to these concerns. Hearings are scheduled to occur in March 2004.
We are unable to predict the ultimate outcome of these regulatory proceedings or the timing of the final decisions of the various agencies.
Missouri Electric
MoPSC Rate Case
From July 1, 1995 through June 30, 2001, UE operated under experimental alternative regulation plans in Missouri that provided for the sharing of earnings with customers if its regulatory return on equity exceeded defined threshold levels. After UE's experimental alternative regulation plan for its Missouri retail electric customers expired, the MoPSC Staff and others sought to reduce UE's annual Missouri electric revenues by over $300 million through a complaint case proceeding. The MoPSC Staff's recommendation was based on a return to traditional cost of service ratemaking, a lowered return on equity, a reduction in UE's depreciation rates and other cost of service adjustments.
In August 2002, a stipulation and agreement resolving this case became effective following agreement by all parties to the case and approval by the MoPSC. The stipulation and agreement includes the following principal features:
o The phase-in of $110 million of electric rate reductions through April 2004, $50 million of which was retroactively effective as of April 1, 2002, $30 million of which became effective on April 1, 2003, and $30 million of which will become effective on April 1, 2004. o A rate moratorium providing for no changes in rates before July 1, 2006, subject to certain statutory and other exceptions.
o A commitment to contribute $14 million to programs for low income energy assistance and weatherization, promotion of energy efficiency and economic development in UE's service territory in 2002, with additional payments of $3 million made annually on June 30, 2003 through June 30, 2006. This entire obligation was expensed in 2002. o A commitment to make $2.25 billion to $2.75 billion in critical energy infrastructure investments from January 1, 2002 through June 30, 2006, including, among other things, the addition of more than 700 megawatts of new generation capacity and the replacement of steam generators at UE's Callaway Nuclear Plant. The 700 megawatts of new generation is expected to be satisfied by 240 megawatts that were added by UE in 2002 and the proposed transfer at net book value to UE of approximately 550 megawatts of generation assets from Genco, which is subject to receipt of necessary regulatory approvals. See Intercompany Transfer of Electric Generating Facilities and Illinois Service Territory within this Note for additional information on the proposed transfer. o An annual reduction in UE's depreciation rates by $20 million, retroactive to April 1, 2002, based on an updated analysis of asset values, service lives and accumulated depreciation levels. o A one-time credit of $40 million which was accrued during the plan period. The entire amount was paid to UE's Missouri retail electric customers in 2002 for settlement of the final sharing period under the alternative regulation plan that expired June 30, 2001.
Marketing Company - UE Power Supply Agreements
In order to satisfy UE's regulatory load requirements for 2001, UE purchased, under a one year contract, 450 megawatts of capacity and energy from Marketing Company. For 2002, UE similarly entered into a one year contract with Marketing Company for the purchase of 200 megawatts of capacity and energy. The MoPSC objected to these contracts before the SEC under the PUHCA and the FERC. In 2002 and 2003, respectively, the FERC approved a settlement modifying future procedures for entering into affiliate contracts and the MoPSC withdrew its complaint at the SEC. As a result, no additional action by the FERC or the SEC is expected in this matter.
Federal - Electric Transmission
Regional Transmission Organization
In December 1999, the FERC issued Order 2000 requiring all utilities subject to FERC jurisdiction to state their intentions for joining a RTO. Since April 2002, the GridAmerica Companies have participated in a number of filings at the FERC in an effort to form GridAmerica LLC, or GridAmerica, as an ITC. On December 19, 2002, the FERC issued an order conditionally approving the formation and operation of GridAmerica as an ITC within the Midwest ISO subject to further compliance filings, which were made by the GridAmerica Companies in early 2003. CILCO is already a member of the Midwest ISO and has transferred functional control of its transmission system to the Midwest ISO. Transmission service on the CILCO transmission system is provided pursuant to the terms and conditions of the Midwest ISO OATT on file with the FERC.
On April 30, 2003, the FERC issued an order authorizing the GridAmerica Companies' request to transfer functional control of their transmission assets to GridAmerica. The FERC also accepted the proposed rate amendments to the Midwest ISO OATT, filed in early 2003 by Midwest ISO and the GridAmerica Companies, effective upon the commencement of service over the GridAmerica transmission facilities under the Midwest ISO OATT, suspended the proposed rates for a nominal period, subject to refund, and established hearing and settlement judge procedures to determine the justness and reasonableness of the proposed rate amendments to the Midwest ISO OATT. In August 2003, the GridAmerica Companies filed acknowledgements with the FERC to permit GridAmerica to commence operations on October 1, 2003, on a phased basis, by assuming, with the Midwest ISO, functional control of the transmission systems of American Transmission Systems, Incorporated, a subsidiary of FirstEnergy Corp., and Northern Indiana Public Service Company, a subsidiary of NiSource Inc. Pursuant to this authorization, GridAmerica began operating on October 1, 2003.
Also beginning on October 1, 2003, the proposed rates filed by Midwest ISO and the GridAmerica Companies became effective, subject to refund for FirstEnergy Corp. and NiSource Inc. Since UE and CIPS have not transferred functional control of their transmission assets to Midwest ISO, the proposed rates are not effective for UE or CIPS. On December 18, 2003, the GridAmerica Companies, the Midwest ISO and the Midwest ISO transmission owners filed a Stipulation and Agreement with the FERC in an effort to settle the disputed rate issues for transmission service over the transmission assets of the GridAmerica Companies. On March 3, 2004, the FERC approved the Stipulation and Agreement.
UE also requires approval from the MoPSC to join the Midwest ISO. On February 26, 2004, the MoPSC issued an order conditionally approving a Stipulation and Agreement that was filed on February 6, 2004. The Order authorizes UE's participation in the Midwest ISO through GridAmerica for a five year period, but is conditioned on the FERC approving a Service Agreement that outlines the terms and conditions under which the Midwest ISO will provide transmission service to UE's bundled retail load. FERC approval of this Service Agreement is pending.
Upon the transfer of functional control by UE and CIPS of their transmission systems to GridAmerica, the FERC has ordered the return, with interest, of the $13 million exit fee paid by UE and the $5 million exit fee paid by CIPS when they previously left the Midwest ISO.
Genco does not own transmission assets, but pays UE and CIPS for the use of their transmission systems to transmit power from the Genco generating plants. Until the tariffs and other material terms of UE's and CIPS' participation in GridAmerica and GridAmerica's participation in the Midwest ISO are finalized and approved by the FERC and other regulatory authorities having jurisdiction, we are unable to predict the ultimate impact that ongoing RTO developments will have on our financial position, results of operations or liquidity. UE and CIPS expect to begin participating in the Midwest ISO in 2004.
On November 17, 2003, the FERC issued a final order upholding an earlier order issued in July 2003 (July Order), that will reduce UE's and CIPS', as well as other transmission-owning utilities', "through and out" transmission revenues effective April 1, 2004, subject to certain conditions (the April 1 effective date was changed to May 1, 2004, by subsequent order issued by the FERC). The revenues subject to elimination by this order are those revenues from transmission reservations that travel through or out of UE's and CIPS' transmission systems and are also used to provide electricity to load within the Midwest ISO or PJM Interconnection LLC systems. The magnitude of the potential net revenue reduction resulting from this order could be up to $20 to $25 million annually if UE and CIPS are not in a RTO. UE and CIPS would incur approximately 60% and 40%, respectively, of the potential net revenue reduction. While it is anticipated that UE's and CIPS' transmission revenues could be reduced by these orders, transmission expenses for Genco could be reduced. Moreover, the FERC's final Order explicitly permits companies to collect the lost "through and out" revenues through other transitional rate mechanisms. Until it is determined when, or if, UE and CIPS will join a RTO, or the magnitude of lost "through and out" transmission revenue recovery UE and CIPS will receive through other rate mechanisms, UE and CIPS are unable to predict the ultimate impact of these orders.
Standard Market Design Notice of Proposed Rulemaking
In July 2002, the FERC issued its Standard Market Design NOPR. The NOPR proposes a number of changes to the way the current wholesale transmission service and energy markets are operated. Specifically, the NOPR proposes that all jurisdictional transmission facilities be placed under the control of an independent transmission provider (similar to a RTO), proposes a new transmission service tariff that provides a single form of transmission service for all users of the transmission system including bundled retail load, and proposes a new energy market and congestion management system that uses locational marginal pricing as its basis. In our initial comments on the NOPR, which were filed at the FERC on November 15, 2002, we expressed our concern with the potential impact of the proposed rules in their current form on the cost and reliability of service to retail customers. We also proposed that certain modifications be made to the proposed rules in order to protect transmission owners from the possibility of trapped transmission costs that might not be recoverable from ratepayers as a result of inconsistent regulatory policies. We filed additional comments on the remaining sections of the NOPR during the first quarter of 2003.
In April 2003, the FERC issued a "white paper" reflecting comments received in response to the NOPR. More specifically, the white paper indicated that the FERC will not assert jurisdiction over the transmission rate component of bundled retail service and will insure that existing bundled retail customers retain their existing transmission rights and retain rights for future load growth in its final rule. Moreover, the white paper acknowledged that the final rule will provide the states with input on resource adequacy requirements, allocation of firm transmission rights, and transmission planning. The FERC also requested input on the flexibility and timing of the final rule's implementation.
Although issuance of the Standard Market Design final rule is uncertain and the implementation schedule is still unknown, the Midwest ISO is already in the process of implementing a separate market design similar to the proposed market design in the NOPR. In July 2003, the Midwest ISO filed with the FERC a revised OATT codifying the terms and conditions under which it would implement the new market design. Thereafter, on October 17, 2003, the Midwest ISO filed a motion for withdrawal of their revised OATT to ensure that effective reliability tools are in place and operating correctly before moving forward with the new market design. UE and CIPS will continue monitoring the status of the Midwest ISO's market design and the potential impact of the market design on the cost and reliability of
service to retail customers and providing guidance to be followed by the Midwest ISO in developing a new energy market design in the future. Until the FERC issues a final rule and the Midwest ISO finalizes its new market design, we are unable to predict the ultimate impact of the NOPR or the Midwest ISO new market design on our future financial position, results of operations or liquidity.
Federal - Hydroelectric
In February 2004, UE filed an application with the FERC to renew the license for its Osage hydroelectric plant for an additional 50 year term. The current FERC license expires on February 28, 2006. The license application proposes to continue operations at the Osage plant as a peaking facility, upgrade four turbine units and to maximize the hydroelectric capacity of the plant.
Illinois Electric
In 2002, all of the Illinois residential, commercial and industrial customers of UE, CIPS and CILCO had a choice in electric suppliers under the provisions of 1997 Illinois legislation related to the restructuring of the Illinois electric industry (the Illinois Customer Choice Law). Under the Illinois Customer Choice Law, UE, CIPS and CILCO rates initially were frozen through January 1, 2005, subject to residential electric rate decreases of up to 5% in 2002 to the extent rates exceeded the Midwest utility average. In 2002, the Illinois electric rates of UE, CIPS and CILCO were below the Midwest utility average.
As the result of an amendment to the Illinois Customer Choice Law, the rate freeze was extended through January 1, 2007. As a result of this extension, CIPS and Marketing Company expect to seek to renew or extend their power supply agreement and CILCO and AERG expect to seek to renew or extend their power supply agreement through January 1, 2007. A renewal or extension of the power supply agreements will depend on compliance with regulatory requirements in effect at the time.
The Illinois Customer Choice Law allows a utility to collect transition charges from customers that elect to move from bundled retail rates to market-based power and energy. Utilities have the right to collect applicable transition charges throughout the transition period that ends January 1, 2007, from customers that elect market-based power and energy. In the order authorizing the acquisition of CILCO by Ameren, the ICC required UE, CIPS and CILCO to eliminate transition charges in the period commencing June 2003 through at least May 2005. The non-recovery of transition charges is not expected to have a material impact on UE, CIPS or CILCO.
The Illinois Customer Choice Law also contains a provision requiring that one-half of excess earnings from the Illinois jurisdiction for the years 1998 through 2006 be refunded to UE, CIPS and CILCO's Illinois customers. Excess earnings are defined as the portion of the two-year average annual rate of return on common equity in excess of 1.5% of the two-year average of the Index, as defined in the Illinois Customer Choice Law. The Index is defined as the sum of the average for the twelve months ended September 30 of the average monthly yields of the Treasury long-term average (25 years and above), plus 7% for both UE's and CIPS' and 11% for CILCO. Estimated refunds totaling less than $1 million to UE's Illinois customers are expected to be made during the period from April 1, 2004, through March 31, 2005. No refunds to CIPS' or CILCO's Illinois customers are expected to be made during the period from April 1, 2004 through March 31, 2005, resulting from excess earnings during the year ended December 31, 2003. UE made excess earnings refunds of $2.1 million during the period April 1, 2000 through March 31, 2001, resulting from excess earnings during the year ended December 31, 1999. Additionally, UE made excess earnings refunds of $1.5 million during the period April 1, 2001 through March 31, 2002, resulting from excess earnings during the year ended December 31, 2000. These refunds were recorded as a reduction to Operating Revenues - Electric.
Illinois Gas
In October 2003, the ICC issued orders awarding CILCO, CIPS and UE increases in annual natural gas delivery rates of approximately $9 million, $7 million and $2 million, respectively. These new rates went into effect in November 2003.
Missouri Gas
In January 2004, a stipulation and agreement resolving a request by UE to increase annual natural gas rates became effective following agreement by all parties to the case and approval by the MoPSC. The stipulation and agreement authorized an increase in annual gas delivery rates of approximately $13 million, effective February 15, 2004. Other principal features of the stipulation and agreement include:
o A rate moratorium providing for no changes in gas delivery rates before July 1, 2006, absent the occurrence of a significant, unusual event that has a major impact on UE. o An agreement not to request a PGA increase prior to April 1, 2004. o A commitment to make $15 million to $25 million in infrastructure improvement investments from July 1, 2003 through December 31, 2006, including replacement of cast iron main and unprotected steel service lines. UE agreed not to propose rate adjustments to recover infrastructure costs through a statutory infrastructure system replacement surcharge prior to January 1, 2006. o Commitments to contribute an aggregate of $310,000 annually to programs for low income weatherization, energy assistance and energy efficient equipment in UE's service territory.
Regulatory Assets and Liabilities
In accordance with SFAS No. 71, UE, CIPS and CILCO defer certain costs pursuant to actions of regulators and are currently recovering such costs in rates charged to customers.
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) 2002 amounts represent predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. (c) Amount represents SFAS No. 109 deferred tax asset. See Note 13 - Income Taxes for amortization period.
(d) These assets do not earn a return. (e) Represents recoverable costs for asset retirement obligations at our rate-regulated operations. See SFAS No. 143 discussion in Note 1 - Summary of Significant Accounting Policies. (f) Represents UE's Callaway Nuclear Plant operations and maintenance expenses, property taxes and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the plant's current operating license through 2024. (g) Represents losses related to repaid debt. These amounts are being amortized over the lives of the related new debt issues or the remaining lives of the old debt issues if no new debt was issued. (h) Represents the recoverable portion of accrued environmental site liabilities which is primarily collected from electric and gas customers through ICC approved revenue riders in Illinois. (i) Represents Y2K expenses being amortized over 6 years starting in 2002 in conjunction with the settlement of UE's Missouri electric rate case and a DOE decommissioning assessment being amortized over 14 years through 2007. In addition, amount includes the portion of merger-related expenses applicable to the Missouri retail jurisdiction, which are being amortized through 2007 based on a MoPSC order. (j) Represents unamortized portion of investment tax credit and federal excess taxes. See Note 13 - Income Taxes for amortization period. (k) Represents estimated funds collected for the eventual dismantling and removing plant from service upon retirement related to our rate-regulated operations. See SFAS No. 143 discussion in Note 1 - Summary of Significant Accounting Policies.
UE, CIPS and CILCO continually assess the recoverability of their regulatory assets. Under current accounting standards, regulatory assets are written off to earnings when it is no longer probable that such amounts will be recovered through future revenues. Electric industry restructuring legislation may impact the recoverability of regulatory assets in the future.
NOTE 4 - Property and Plant, Net
(a) 2002 amounts exclude amounts for CILCORP and CILCO; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) 2002 amounts represent predecessor information.
NOTE 5 - Short-term Borrowings and Liquidity
Short-term borrowings consist of commercial paper and bank loans (maturities generally within 1 to 45 days). Short-term borrowings at Ameren and UE at December 31, 2003 were $161 million (2002 - $271 million) and $150 million (2002 - $250 million), respectively. CILCO had short-term borrowings of $10 million at December 31, 2002, with no amount outstanding at December 31, 2003. The average short-term borrowings at UE were $24 million for the year ended December 31, 2003, with a weighted-average interest rate of 1.1% (2002 - $65 million with a weighted-average interest rate of 1.8%). Peak short-term borrowings for UE were $228 million for the year ended December 31, 2003 with a weighted-average interest rate of 1.2% (2002 - $173 million with a weighted-average interest rate of 1.7%). CILCO's commercial paper outstanding at December 31, 2002 had a weighted-average interest rate of 2.05%.
At December 31, 2003, certain of the Ameren Companies had committed bank credit facilities totaling $829 million, excluding the EEI facilities and the nuclear fuel lease facility, which were available for use by UE, CIPS, CILCO and Ameren Services through a utility money pool arrangement. As of December 31, 2003, $679 million was available under these committed credit facilities, excluding the EEI facilities and the nuclear fuel lease. In addition, $600 million of the $829 million may be used by Ameren directly and most of the non rate-regulated affiliates including, but not limited to, Resources Company, Genco, Marketing Company, AFS, AERG and Ameren Energy through a non state-regulated subsidiary money pool agreement. CILCO received final regulatory approval to participate in the utility money pool arrangement in September 2003. CILCORP received funds through direct loans from Ameren since it was not part of the non state-regulated money pool agreement. The committed bank credit facilities are used to support our commercial paper programs under which $150 million was outstanding at December 31, 2003 (2002 - $250 million). Access to our credit facilities for all Ameren Companies is subject to reduction based on use by affiliates. AERG received final regulatory approval to participate in our non state-regulated subsidiary money pool arrangement and as a lender only in our utility money pool arrangement in October 2003. See Note 14 - Related Party Transactions report for a detailed explanation of the money pool arrangements.
In July 2003, Ameren entered into two new revolving credit facilities totaling $470 million to be used for general corporate purposes including support of our commercial paper programs. The $470 million in new facilities includes a $235 million 364-day revolving credit facility and a $235 million three-year revolving credit facility. These new credit facilities replaced Ameren's existing $270 million 364-day revolving credit facility, which matured in July 2003, and a $200 million facility, which would have matured in December 2003. In July 2003, Ameren also amended covenants in its $130 million multi-year credit facility.
In April 2003, UE entered into a 364-day committed credit facility totaling $75 million to be used for general corporate purposes including support of its commercial paper program. This facility makes borrowings available at various interest rates based on London Interbank Offered Rate, agreed rates and other options. CIPS and CILCO can access this facility through the utility money pool.
EEI also has two bank credit agreements totaling $45 million that extend through June 2004. At December 31, 2003, $37 million was available under these committed credit facilities.
UE also had a lease agreement that provided for the financing of nuclear fuel. At December 31, 2003, the maximum amount that could be financed under the agreement was $120 million. At December 31, 2003, $67 million was financed under the lease. UE terminated the nuclear lease agreement in February 2004.
We have money pool agreements with and among our subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained between rate-regulated and non rate-regulated businesses. See Note 14 - Related Party Transactions for a detailed explanation of the money pool arrangements.
Borrowings under Ameren's non state-regulated subsidiary money pool by Genco, Development Company and Medina Valley, each an "exempt wholesale generator," are considered investments for purposes of the 50% SEC aggregate investment limitation. Based on Ameren's aggregate investment in these "exempt wholesale generators" as of December 31, 2003, the maximum permissible borrowings under Ameren's non state-regulated subsidiary money pool pursuant to this limitation for these entities was $663 million in the aggregate.
Certain of the Ameren Companies' bank credit agreements contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets, merge with other entities and restrict and encumber upstream dividend payments of our subsidiaries. These credit agreements also contain a provision that limits Ameren's, UE's, CIPS' and CILCO's total indebtedness to 60% of total capitalization pursuant to a calculation defined in the related agreement. As of December 31, 2003, the ratio of total indebtedness to total capitalization (calculated in accordance with this provision) for Ameren, UE, CIPS and CILCO was 52%, 44%, 54% and 53%, respectively (2002 - 50%, 43%, 50%, - -%). These credit agreement provisions were not applicable in 2002 for CILCO, since CILCO was not a party to, nor subject to the provisions of, these facilities during 2002. In addition, the credit agreements contain indebtedness cross-default provisions and material adverse change clauses, which could trigger a default under these facilities in the event that any of Ameren's subsidiaries (subject to the definition in the underlying credit agreements), other than certain project finance subsidiaries, defaults in indebtedness in excess of $50 million. The credit agreements also require us to meet minimum ERISA funding rules.
None of the Ameren Companies' credit agreements or financing arrangements contain credit rating triggers with the exception of one of CILCO's financing arrangements. An event of default will occur under a $100 million CILCO bank
term loan if the credit rating on CILCO's first mortgage bonds falls below any two of the following: BBB- from S&P, Baa3 from Moody's or BBB- from Fitch. As of December 31, 2003, CILCO's current ratings on its first mortgage bonds were A-, A2 and A, respectively. This term loan was repaid in February 2004.
At December 31, 2003, Ameren and its subsidiaries were in compliance with their credit agreement provisions and covenants.
NOTE 6 - Long-term Debt and Equity Financings
The following table presents long-term debt outstanding for the Ameren Companies and EEI as of December 31, 2003 and 2002:
(a) At December 31, 2003, a majority of property and plant was mortgaged under, and subject to liens of, the respective indentures pursuant to which the bonds were issued. CILCO's long-term debt is secured by a lien on substantially all of its property and franchises. (b) Environmental Improvement or Pollution Control Series secured by first mortgage bonds. (c) Interest rates, and the periods during which such rates apply, vary depending on our selection of certain defined rate modes. The average interest rates for the years 2003 and 2002 were as follows: 2003 2002 ---- ---- 1991 Series 1.60% 1.64% 1992 Series 1.64% 1.60% 1998 Series A 1.75% 1.53% 1998 Series B 1.75% 1.53% 1998 Series C 1.77% 1.53% 2000 Series A 1.80% 1.56% 2000 Series B 1.77% 1.52% 2000 Series C 1.75% 1.56% (d) Under the terms of the subordinated debentures, UE may, under certain circumstances, defer the payment of interest for up to five years. Upon the election to defer interest payments, UE dividend payments to Ameren are prohibited. (e) Variable rate tax-exempt pollution control indebtedness that was converted to long-term fixed rates. (f) CILCORP's long-term debt is secured by a pledge of all of the common stock of CILCO. The amount of debt outstanding at CILCORP includes a purchase accounting fair market value adjustment of approximately $96 million.
The following table presents the aggregate stated maturities of long-term debt for the Ameren Companies and EEI at December 31, 2003:
All the Ameren Companies expect to fund maturities of long-term debt and contractual obligations through a combination of cash flow from operations and external financing.
Ameren
Pursuant to an August 2002 shelf registration statement, Ameren issued approximately $338 million of common stock in 2002 and issued approximately $256 million of common stock in 2003. Net proceeds from the issuances were used to fund the cash portion of the purchase price for its acquisition of CILCORP and for general corporate purposes. In February 2004, Ameren issued, pursuant to the August 2002 shelf registration statement, 19.1 million shares of its
common stock at $45.90 per share. Ameren received net proceeds of $853 million, which are expected to provide funds required to pay the cash portion of the purchase price for our acquisition of Illinois Power and Dynegy's 20% interest in EEI and to reduce Illinois Power debt assumed as part of this transaction and pay related premiums. Pending such use, and/or if the acquisition is not completed, we plan to use the net proceeds to reduce present or future indebtedness and/or repurchase securities of Ameren or its subsidiaries. A portion of the net proceeds may also be temporarily invested in short-term instruments. As substantially all of the capacity under the August 2002 shelf registration was used, we expect to make a new shelf registration statement filing with the SEC in early 2004. See Note 2 - Acquisitions for further information.
The acquisitions of CILCORP on January 31, 2003, and Medina Valley on February 4, 2003, included the assumption by Ameren of CILCORP and Medina Valley debt and preferred stock at closing of $895 million. The assumed debt and preferred stock consisted of $250 million 9.375% senior notes due 2029, $225 million 8.70% senior notes due 2009, a $100 million secured floating rate term loan due 2004, other secured indebtedness totaling $279 million and preferred stock of $41 million.
In December 2003, Ameren repaid its 2001 Floating Rate Notes totaling $150 million. These notes were repaid with available cash on hand.
In March 2002, Ameren issued $345 million of adjustable conversion-rate equity security units and $227 million of common stock (five million shares at $39.50 per share and 750,000 shares, pursuant to the exercise of an option granted to the underwriters, at $38.865 per share). The $25 adjustable conversion-rate equity security units each consisted of an Ameren senior unsecured note with a principal amount of $25 and a contract to purchase, for $25, a fraction of a share of Ameren common stock on May 15, 2005. The senior unsecured notes were recorded at their fair value of $345 million and will mature on May 15, 2007. Total distributions on the equity security units will be at an annual rate of 9.75%, consisting of quarterly interest payments on the senior unsecured notes at the initial annual rate of 5.20% and adjustment payments under the stock purchase contracts at the annual rate of 4.55%. The stock purchase contracts require holders to purchase between 8.7 million and 7.4 million shares of Ameren common stock on May 15, 2005, at the market price at that time, subject to a minimum share purchase price of $39.50 and a maximum of $46.61. The stock purchase contracts include a pledge of the related senior unsecured notes as collateral for the stock purchase obligation. The interest rate on the outstanding senior unsecured notes is subject to being reset by a remarketing agent for quarterly payments after May 15, 2005, until maturity. We recorded the net present value of the contracted stock purchase payments of $46 million as an increase in Other Deferred Credits and Liabilities to reflect our obligation and a decrease in Other Paid-in Capital to reflect the fair value of the stock purchase contract. The liability for the contracted stock purchase adjustment payments (December 31, 2003 - $21 million) will be reduced as such payments are made through May 15, 2005. We used the net proceeds from these offerings to repay short-term indebtedness and for general corporate purposes.
In September 2001, we began issuing new shares of common stock to satisfy dividend reinvestments and direct purchases under our DRPlus plan and in December 2001, we began issuing new shares of common stock in connection with our 401(k) plans. Previously, these requirements were met by purchasing outstanding shares. Under these plans, we issued 2.5 million, 2.3 million and 0.8 million shares of common stock in 2003, 2002 and 2001, respectively, that were valued at $105 million, $93 million and $33 million for the respective years.
UE
In August 2002, a shelf registration statement filed by UE and its subsidiary trust with the SEC was declared effective. This registration statement permitted the offering from time to time of up to $750 million of various forms of long-term debt and trust preferred securities to refinance existing debt and preferred stock, and for general corporate purposes, including the repayment of short-term debt incurred to finance construction expenditures and other working capital needs. In 2002, UE issued $173 million of 5.25% senior secured notes due September 1, 2012, under the shelf registration statement.
In March 2003, UE issued, pursuant to the August 2002 shelf registration statement, $184 million of 5.50% senior secured notes due March 15, 2034, with interest payable semi-annually on March 15 and September 15 of each year beginning in September 2003. UE received net proceeds of $180 million, which along with other funds were used in April 2003, to redeem $104 million principal amount of outstanding 8 1/4% first mortgage bonds due October 15, 2022,
at a redemption price of 103.61% of par, plus accrued interest, and to repay short-term debt incurred to pay at maturity $75 million principal amount of 8.33% first mortgage bonds that matured in December 2002.
In April 2003, UE issued, pursuant to the August 2002 shelf registration statement, $114 million of 4.75% senior secured notes due April 1, 2015, with interest payable semi-annually on April 1 and October 1 of each year beginning in October 2003. UE received net proceeds of $113 million, which along with other funds were used in May 2003, to redeem $85 million principal amount of outstanding 8.00% first mortgage bonds due December 15, 2022, at a redemption price of 103.38% of par, plus accrued interest, and to reduce short-term debt.
In July 2003, UE issued, pursuant to the August 2002 shelf registration statement, $200 million of 5.10% senior secured notes due August 1, 2018, with interest payable semi-annually on August 1 and February 1 of each year beginning in February 2004. UE received net proceeds of $198 million, which along with other funds were used to repay short-term debt incurred to fund the maturity of $100 million principal amount 7.65% first mortgage bonds due July 15, 2003, and to repay $21 million of short-term debt. The remaining proceeds were used in August 2003, to redeem $75 million principal amount of outstanding 7.15% first mortgage bonds due August 1, 2023, at a redemption price of 103.01% of par, plus accrued interest. The amount of securities remaining available for issuance pursuant to the 2002 shelf registration statement was $79 million as of August 2003.
In September 2003, the SEC declared effective another shelf registration statement filed by UE and its subsidiary trust in August 2003, covering the offering from time to time of up to $1 billion of various forms of long-term debt and trust preferred securities. The $79 million of securities which remained available for issuance under the August 2002 shelf registration is included in the $1 billion of securities available to be issued under this shelf registration statement. In October 2003, UE issued, pursuant to the September 2003 shelf registration statement, $200 million of 4.65% senior secured notes due October 1, 2013, with interest payable semi-annually on April 1 and October 1 of each year beginning in April 2004. UE received net proceeds of $198 million, which were used to repay outstanding short-term debt. The amount of securities remaining available for issuance totaled $800 million as of December 31, 2003. UE may sell all, or a portion of, the currently remaining securities registered under the September 2003 shelf registration statement if warranted by market conditions and capital requirements. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
In December 2002, upon receipt of all necessary federal and state regulatory approvals, UE, pursuant to Missouri economic development statutes, conveyed most of its Peno Creek CT facility to the City of Bowling Green, Missouri in exchange for the issuance by the City of a taxable industrial development revenue bond in the amount of $103 million. Concurrently, the City leased back the facility to UE for a term of 20 years. The lease term is the same as the final maturity of the bond purchased by UE. While the lease is a capital lease, no capital was raised in the transaction. UE is responsible for making rental payments under the lease in an amount sufficient to pay the debt service of the bond. The City's ownership of the facility during the term of the bond and the lease is expected to result in property tax savings to UE. Under the terms of the lease, UE retains all operation and maintenance responsibilities for the facility and ownership of the facility is returned to UE at the expiration of the lease.
Nuclear Fuel Lease
UE had a lease agreement, which was scheduled to expire on August 31, 2031, that provided for the financing of a portion of its nuclear fuel that was processed for use or was consumed at UE's Callaway Nuclear Plant. The lease agreement had variable interest rates based on short-term commercial paper interest rates. In February 2004, UE terminated this lease.
UE capitalized the cost of the leased nuclear fuel incurred by the lessor, plus certain interest costs, and recorded the related lease obligation. Total interest charges under the lease were $2 million in 2003, $2 million in 2002 and $4 million in 2001. Interest charges for these years were based on average interest rates of approximately 2% for 2003, 2% for 2002 and 5% for 2001. Interest charges of $1 million in 2003, $2 million in 2002 and $4 million in 2001 were capitalized.
CIPS
In March 2003, CIPS repaid its $5 million principal amount 6.99% Series 97-1 first mortgage bonds on their maturity date. In April 2003, CIPS repaid its $40 million principal amount 6 3/8% Series Z first mortgage bonds on their maturity date and also redeemed prior to maturity and at par, its $50 million 7 1/2% Series X first mortgage bonds due July 1, 2007. In December 2003, CIPS redeemed its $30 million auction preferred stock at par. All redemptions and repayments were made with available cash and borrowings from the utility money pool.
In May 2001, a shelf registration statement filed by CIPS with the SEC was declared effective. This registration statement enables CIPS to offer from time to time senior notes in one or more series with an offering price not to exceed $250 million. In June 2001, CIPS issued, under the shelf registration statement, $150 million of senior notes due in June 2011, with an interest rate of 6.625%. Until the release date as described in the senior secured note indenture, the senior notes will be secured by a related series of CIPS' first mortgage bonds. The proceeds of these senior notes were used to repay short-term debt and first mortgage bonds maturing in June 2001. At December 31, 2003, the amount of securities remaining available for issuance pursuant to the shelf registration statement was $100 million. CIPS may sell all, or a portion of, the currently remaining securities registered under the May 2001 shelf registration statement if warranted by market conditions and capital requirements. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
Genco
In January 2003, all holders completed an exchange of Genco's $275 million 7.95% Series E senior notes, due 2032, originally issued under private placement to qualified investors under Rule 144A, for new Series F senior notes. The Series F senior notes are identical in all material respects to the Series E senior notes, except that the new series of notes were registered with the SEC and do not contain transfer restrictions. Interest is payable semi-annually on June 1 and December 1 of each year, beginning December 1, 2002. Genco received net proceeds of $271 million from the original issuance of the Series E senior notes in June 2002 that were used to reduce short-term borrowings incurred to finance previous generating capacity additions and for general corporate purposes.
CILCORP
In conjunction with Ameren's acquisition of CILCORP, CILCORP's long-term debt was recorded at fair value. This resulted in recognition of fair value related adjustment increases of $71 million related to CILCORP's 9.375% senior bonds due 2029 and $40 million related to its 8.70% senior notes due 2009. Amortization related to these fair value adjustments was approximately $7 million for the year ended December 31, 2003, and was included in interest expense in the Consolidated Statements of Income for Ameren and CILCORP.
In September 2003, CILCORP repurchased, prior to maturity, $13 million in principal amount of its 9.375% senior bonds and $27 million in principal amount of its 8.70% senior notes. Premiums paid to repurchase these bonds, and bonds retired by CILCO as described below, resulted in an aggregate reduction of the fair value adjustments recorded upon acquisition of $8 million. CILCORP repurchased these senior bonds and notes through a direct loan from Ameren.
CILCO
In February 2003, CILCO repaid $25 million in principal amount of its 6.82% Series medium-term notes on their maturity date. In April 2003, three series of CILCO's first mortgage bonds were redeemed prior to maturity. These redemptions included CILCO's $65 million principal amount 8 1/5% Series due January 15, 2022, at a redemption price of 103.29%, and two 7.80% Series totaling $10 million in principal amount due February 9, 2023, at a redemption price of 103.90%. In August 2003, CILCO repaid two bank loans totaling $5 million prior to their scheduled maturity dates. In July 2003, a series of CILCO preferred stock was reduced by $1 million as a result of a mandatory sinking fund provision. CILCO repaid its $100 million term loan facility in February 2004. All redemptions and repayments were made with available cash, direct borrowings from Ameren, and borrowings from the utility money pool.
Medina Valley
In June 2003, Medina Valley repaid, prior to maturity, with funds borrowed from the non state-regulated subsidiary money pool, a $36 million secured term loan with an effective interest rate of 7.65% and terminated two related interest rate swaps at a total redemption cost of $44 million. This repayment eliminated the outstanding bank debt at Medina Valley.
Amortization of Debt Issuance Costs and Associated Premiums and Discounts
The following table presents the amortization of debt issuance costs and any premium or discounts included in interest expense for the Ameren Companies for the three years ended December 31, 2003, 2002, and 2001, respectively:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) 2002 and 2001 amounts represent predecessor information. January 2003 predecessor amounts were zero. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. (c) CILCO's financial statements are presented on a historical basis of accounting for all periods presented. See Note 1 - Summary of Significant Accounting Policies for further information.
Indenture Provisions and Other Covenants
UE
UE's indenture agreements and Articles of Incorporation include covenants and provisions which must be complied with in order to issue first mortgage bonds and preferred stock. UE must comply with earnings tests contained in its respective mortgage indenture and Articles of Incorporation. For the issuance of additional first mortgage bonds, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required. At December 31, 2003, UE had a coverage ratio of 9.1 times the annual interest charges on the first mortgage bonds outstanding, which would permit UE to issue an additional $4.2 billion of first mortgage bonds. For the issuance of additional preferred stock, earnings coverage of at least 2.5 times the annual dividend on preferred stock outstanding and to be issued is required under UE's Articles of Incorporation. As of December 31, 2003, UE had a coverage ratio of 74.2 times the annual dividend on preferred stock outstanding which would permit UE to issue an additional $2.4 billion in preferred stock. The ability to issue such securities in the future will depend on such tests at that time.
In addition, UE's mortgage indenture contains certain provisions which restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those payable in common stock, leaving $1.6 billion of free and unrestricted retained earnings at December 31, 2003.
CIPS
CIPS' indenture agreements and Articles of Incorporation include covenants which must be complied with in order to issue first mortgage bonds and preferred stock. CIPS must comply with earnings tests contained in its respective mortgage indenture and Articles of Incorporation. For the issuance of additional first mortgage bonds, earnings coverage of twice the annual interest charges on first mortgage bonds outstanding and to be issued is required. As of December 31, 2003, CIPS had a coverage ratio of 2.5 times the annual interest charges for one year on the aggregate amount of bonds outstanding, and subsequently, had the availability to issue an additional $66 million of first mortgage bonds. For the issuance of additional preferred stock, earnings coverage of 1.5 times annual interest charges on all long-term debt and preferred stock dividends is required under CIPS' Articles of Incorporation. As of December 31, 2003, CIPS had a coverage ratio of 1.8 times the sum of the annual interest charges and dividend requirements on all long-term debt and
preferred stock outstanding as of December 31, 2003, and consequently had the availability to issue an additional $109 million of preferred stock. The ability to issue such securities in the future will depend on coverage ratios at that time.
Genco
Genco's senior note indenture includes provisions that require it to maintain a senior debt service coverage ratio of at least 1.8 to 1 (for both the prior four fiscal quarters and for the next succeeding four six-month periods) in order to pay dividends to Ameren or to make payments of principal or interest under certain subordinated indebtedness excluding amounts payable under its intercompany note payable with CIPS. For the four quarters ended December 31, 2003, this ratio was 3.8 to 1. In addition, the indenture also restricts Genco from incurring any additional indebtedness, with the exception of certain permitted indebtedness as defined in the indenture, unless its senior debt service coverage ratio equals at least 2.5 to 1 for the most recently ended four fiscal quarters and its senior debt to total capital ratio would not exceed 60%, both after giving effect to the additional indebtedness on a pro-forma basis. This debt incurrence requirement is disregarded in the event certain rating agencies reaffirm the ratings of Genco after considering the additional indebtedness. As of December 31, 2003, Genco's senior debt to total capital was 53%.
CILCORP
Covenants in CILCORP's indenture governing its $475 million (original issuance amount) senior notes and bonds require CILCORP to maintain a debt to capital ratio of no greater than 0.67 to 1 and an interest coverage ratio of at least 2.2 to 1 in order to make any payment of dividends or intercompany loans to affiliates other than to its direct and indirect subsidiaries including CILCO. However, in the event CILCORP is not in compliance with these tests, CILCORP may make such payments of dividends or intercompany loans if its senior long-term debt rating is at least BB+ from S&P, Baa2 from Moody's and BBB from Fitch. At December 31, 2003, CILCORP's debt to capital ratio was 0.6 to 1 and its interest coverage ratio was 3.0 to 1, calculated in accordance with related provisions in this indenture. The common stock of CILCO is pledged as security to the holders of these senior notes and bonds.
CILCO
CILCO must maintain investment grade ratings for its first mortgage bonds from at least two of S&P, Moody's and Fitch. CILCO's current senior secured debt ratings from these rating agencies is A-, A2 and A, respectively. CILCO had restrictions on the payment of dividends and its ability to otherwise make distributions with respect to its common stock as a result of its $100 million bank term loan. This loan was repaid in February 2004.
Off-Balance Sheet Arrangements
At December 31, 2003, neither Ameren nor any of its subsidiaries had any off-balance sheet financing arrangements, other than operating leases entered into in the ordinary course of business. Neither Ameren nor any of its subsidiaries expects to engage in any significant off-balance sheet financing arrangements in the near future.
NOTE 7 - Restructuring Charges and Other Special Items
Ameren and UE recorded a pre-tax coal contract settlement gain of $51 million in 2003. This gain represented a return of coal costs plus accrued interest accumulated by a coal supplier for reclamation of a coal mine that supplied a UE power plant. UE entered into a settlement agreement with the coal supplier to return the accumulated reclamation funds, which will be paid to UE ratably through December 2004. Ameren's and UE's accounts receivable balance related to this settlement at December 31, 2003 was $36 million.
CILCO recorded $21 million in acquisition integration costs in 2003. These costs represented write-offs of software deemed of no ongoing benefit as of the acquisition date ($13 million), severance and relocation costs ($5 million), and an increase in the bad debt reserve ($3 million) related to one customer for which there was significant concern from a collection standpoint at the acquisition date. These amounts were offset against goodwill at CILCORP through purchase accounting and, therefore, there was no impact to Ameren's Consolidated Statement of Income.
Ameren recorded voluntary employee retirement and other restructuring charges of $92 million in 2002. These charges included a voluntary retirement program charge of $75 million based on voluntary retirements of approximately 550 employees. Of the $75 million charge, UE recorded $51 million, CIPS recorded $14 million, Genco recorded $8 million and other Ameren companies recorded $2 million. These charges primarily related to special termination benefits associated with our pension and postretirement benefit plans. Most of the employees who voluntarily retired accepted retirement in 2002 and left Ameren in early 2003.
In addition, in 2002, Ameren recorded a charge of approximately $17 million primarily associated with the retirement of 343 megawatts of rate-regulated generating capacity at UE's Venice, Illinois plant and temporary suspension of operations of two coal-fired generating units (126 megawatts) at Genco's Meredosia, Illinois plant.
NOTE 8 - Other Income and Deductions
The following table presents Other Income and Deductions for each of the Ameren Companies for the years ended December 31, 2003, 2002, and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) 2002 amounts represent predecessor information. January 2003 predecessor amounts were zero. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. (c) CILCO's financial statements are presented on a historical basis of accounting for all periods presented. See Note 1 - Summary of Significant Accounting Policies for further information.
NOTE 9 - Derivative Financial Instruments
We utilize derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity and emission credits. Price fluctuations in natural gas, fuel and electricity cause:
o an unrealized appreciation or depreciation of our firm commitments to purchase or sell when purchase or sales prices under the firm commitment are compared with current commodity prices; o market values of fuel and natural gas inventories or purchased power to differ from the cost of those commodities in inventory under firm commitment; and o actual cash outlays for the purchase of these commodities to differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are dictated by risk management policies and include forward contracts, futures contracts, options and swaps. We continually assess our supply and delivery commitment positions against forward market prices and internally forecast forward prices and modify our exposure to market, credit and operational risk by entering into various offsetting transactions. In general, we believe these transactions serve to reduce our price risk.
In addition, we may purchase additional power, again within risk management guidelines, in anticipation of power requirements and future price changes. Certain derivative contracts we enter into on a regular basis as part of our power risk management program do not qualify for hedge accounting or the normal purchase and sale exceptions under SFAS No. 133. Accordingly, these contracts are recorded at fair value with changes in the fair value charged or credited to the income statement in the period in which the change occurred. Contracts we enter into as part of our power risk management program may be settled by either physical delivery or net settled with the counterparty.
Cash Flow Hedges
We routinely enter into forward purchase and sales contracts for electricity based on forecasted levels of economic generation and customer requirements. The relative balance between customer requirements and economic generation varies throughout the year. The contracts typically cover a period of 12 months or less. The purpose of these contracts is to hedge against possible price fluctuations in the spot market for the period covered under the contracts. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objective and strategy for undertaking various hedge transactions. The mark-to-market value of cash flow hedges will continue to fluctuate with changes in market prices up to contract expiration.
The following table presents balances in certain accounts for cash flow hedges as of December 31, 2003 and 2002:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) Represents the mark-to-market value for the hedged portion of electricity price exposure for periods generally less than one year. Certain contracts designated as hedges of electricity price exposure have terms up to five years. (c) Represents a gain associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity and the gain in OCI is amortized over a 10-year period that began in June 2002. (d) Represents a gain associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through October 2006. CILCORP and CILCO amounts represent a gain associated with a partial hedge of natural gas requirements through March 2007. (e) Represents the mark-to-market gain of two call options accounted for as cash flow hedges for coal held with two suppliers. One of these options to purchase coal expired in October 2003 and the other option expires in July 2005. The final value of the options will be recognized as a reduction in fuel costs as the hedged coal is burned.
The pre-tax net gain or loss on power forward derivative instruments included in Other Income and Deductions at UE and Genco, which represented the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, as well as the reversal of amounts previously recorded in OCI due to transactions going to delivery or settlement, was less than a $1 million loss for both UE and Genco for the year ended December 31, 2003 (2002 - $2 million loss for UE, $1 million loss for Genco).
Other Derivatives
The following table represents the net change in market value of option transactions, which are used to manage our positions in SO2 allowances, coal, heating oil and electricity or power. Certain of these transactions are treated as non-hedge transactions under SFAS No. 133. The net change in the market value of SO2 options is recorded in Operating Revenues - Electric, while the net change in the market value of coal, heating oil and electricity or power options is recorded as Operating Expenses - Fuel and Purchased Power.
(a) Heating oil option gains and losses were less than $1 million for all periods shown above. (b) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (c) 2002 and 2001 amounts represent predecessor information. January 2003 predecessor amounts were zero. (d) CILCO's financial statements are presented on a historical basis of accounting for all periods presented. See Note 1 - Summary of Significant Accounting Policies for further information.
NOTE 10 - Stockholder Rights Plan and Preferred Stock
Stockholder Rights Plan
In October 1998, Ameren's Board of Directors approved a share purchase rights plan designed to assure stockholders of fair and equal treatment in the event of a proposed takeover. The rights will be exercisable only if a person or group acquires 15% or more of Ameren's common stock or announces a tender offer, the consummation of which would result in ownership by a person or group of 15% or more of the common stock. Each right will entitle the holder to purchase one one-hundredth of a newly issued preferred stock at an exercise price of $180. If a person or group acquires 15% or more of Ameren's outstanding common stock, each right will entitle its holder (other than such person or members of such group) to purchase, at the right's then-current exercise price, a number of Ameren's common shares having a market value of twice such price. In addition, if Ameren is acquired in a merger or other business combination transaction after a person or group has acquired 15% or more of our outstanding common stock, each right will entitle its holder to purchase, at the right's then-current exercise price, a number of the acquiring company's common shares having a market value of twice such price. The acquiring person or group will not be entitled to exercise these rights. The SEC approved the plan under the PUHCA in December 1998. The rights were issued as a dividend payable January 8, 1999, to stockholders of record on that date. These rights expire in 2008. One right will accompany each new share of Ameren common stock issued prior to such expiration date.
Preferred Stock
All classes of UE's, CIPS' and CILCO's preferred stock are entitled to cumulative dividends and have voting rights. Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no shares outstanding. CIPS has 2.6 million shares of no par value preferred stock authorized, with no shares outstanding. UE has 7.5 million shares authorized of $1 par value preference stock and CILCO has 2.0 million shares authorized of no par value preference stock. No shares of preference stock have been issued.
The following table presents the outstanding preferred stock of UE, CIPS and CILCO that is not subject to mandatory redemption and is entitled to cumulative dividends and is redeemable, at the option of the issuer, at the prices presented as of December 31, 2003 and 2002:
(a) Beginning February 15, 2003, declining to $100 per share in 2012. (b) In the event of voluntary liquidation, $105.50. (c) Prior to the acquisition date of CILCORP on January 31, 2003, the 4.50% Series was $11 million and the 4.64% Series was $8 million.
The following table presents the outstanding preferred stock of CILCO that is subject to mandatory redemption, is entitled to cumulative dividends and is redeemable, at a determinable price on a fixed date or dates, at the prices presented as of December 31, 2003 and 2002, respectively:
(a) Beginning July 1, 2003, this preferred stock became redeemable, at the option of CILCO, at $100 per share. A mandatory redemption fund was established on July 1, 2003. The fund provides for the redemption of 11,000 shares for $1.1 million on July 1 of each year through July 1, 2007. On July 1, 2008, the remaining shares outstanding will be retired for $16.5 million. (b) Prior to the acquisition of CILCORP on January 31, 2003, the 5.85% Series was $22 million. (c) In the event of voluntary or involuntary liquidation, the stockholder receives $100 per share plus accrued dividends.
NOTE 11 - Retirement Benefits
We have defined benefit and postretirement benefit plans covering substantially all employees of UE, CIPS, CILCORP, CILCO and Ameren Services and certain employees of Resources Company and its subsidiaries, including Genco. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans.
Investment Strategy and Return on Asset Assumption
The primary objective of the Ameren Retirement Plan and postretirement benefit plans is to provide eligible employees with pension and postretirement healthcare benefits. Ameren manages plan assets in accordance with the "prudent investor" guidelines contained in the ERISA. Ameren's goal is to earn the highest possible return on plan assets consistent with its tolerance for risk. Ameren delegates investment management to specialists in each asset class and where appropriate, provides the investment manager with specific guidelines which include allowable and/or prohibited investment types. Ameren regularly monitors manager performance and compliance with investment guidelines.
The expected return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns and volatility of the various asset classes. Based on the target asset allocation for each asset class, the overall expected rate of return for the portfolio was developed and adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.
Pension
Pension benefits are based on the employees' years of service and compensation. Our plans are funded in compliance with income tax regulations and federal funding requirements.
The following table presents the cash contributions made to our defined benefit retirement plan qualified trusts during 2003 and 2002.
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries. (b) 2002 amounts represent predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
A minimum pension liability was recorded at December 31, 2002, which resulted in an after-tax charge to OCI and a reduction in stockholders' equity of $102 million. At December 31, 2003, the minimum pension liability was reduced, resulting in OCI of $46 million and an increase in stockholders' equity. The following table presents the minimum pension liability amounts, after taxes, as of December 31, 2003 and 2002:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries. (b) 2002 amounts represent predecessor information. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances. CILCORP's 2002 minimum pension liability was reduced to zero in 2003 as a result of purchase accounting adjustments.
The following tables present the funded status of our pension plans for the years ended December 31, 2003 and 2002:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003.
(b) Excludes amounts paid from company funds. (c) Represents predecessor information. (d) Special termination benefits for 2002 represent the enhanced improvement in benefits provided to the approximate 550 employees who voluntarily retired in 2002. See also Note 7 - Restructuring Charges and Other Special Items for further information.
The following table presents the assumptions used to determine benefit obligations at December 31, 2003 and 2002:
(a) Represents predecessor information for 2002.
Based on our assumptions at December 31, 2003, and in order to maintain minimum funding levels for our pension plan, we expect to be required under ERISA to fund an average of approximately $115 million annually from 2005 through 2008 assuming the passage of a law which would be retroactive to January 1, 2004, to extend the temporary interest rate relief. We expect UE's, CIPS', Genco's and CILCO's portion of the 2005 to 2008 funding requirements to be approximately 65%, 10%, 10% and 15%, respectively. These amounts are estimates and may change based on actual stock market performance, changes in interest rates, any pertinent changes in government regulations and any prior voluntary contributions.
The following tables present the amounts recorded in the Consolidated Balance Sheets as of December 31, 2003 and 2002:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) Represents predecessor information.
The following table presents our pension plan asset categories as of December 31, 2003 and 2002 and our target allocations for 2004:
The following table presents the projected benefit obligation, the accumulated benefit obligation and the fair value of plan assets for plans that have a projected benefit obligation and an accumulated benefit obligation in excess of plan assets at December 31, 2003 and 2002:
The following table presents the components of the net periodic pension benefit cost during 2003, 2002 and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) Represents predecessor information.
Prior service cost is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan. The net actuarial (gain) loss subject to amortization is amortized on a straight-line basis over ten years.
UE, CIPS, Genco, CILCORP and CILCO are participants in Ameren's plans and are responsible for their proportional share of the costs. The following table presents the pension costs incurred for the years ended December 31, 2003, 2002, and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries. (b) Includes predecessor information for periods prior to the acquisition date of January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
The expected pension benefit payments from qualified trust and company funds, which reflect expected future service, are as follows:
The following table presents the assumptions used to determine net periodic benefit cost for the years ended December 31, 2003, 2002, and 2001:
(a) Represents predecessor information for 2002 and 2001.
Postretirement
Our funding policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association trusts (VEBA) to match the annual postretirement expense.
The following table presents the cash contributions made to our postretirement plan during 2003. We made cash contributions of $74 million in 2002. We expect to make contributions of approximately $80 million during 2004.
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries. (b) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
The following tables present the funded status of Ameren's postretirement benefit plans at December 31, 2003 and 2002:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) Excludes amounts paid from company funds. (c) Ameren's transition obligation at December 31, 2003, is being amortized over the next 11 years. (d) Represents predecessor information. (e) Plan amendments represent a favorable change to our net benefit obligation and relate to increasing retiree premiums and placing limits on healthcare benefits. (f) Special termination benefits for 2002 represent the enhanced improvement in benefits provided to the approximate 550 employees who voluntarily retired in 2002. See also Note 7 - Restructuring Charges and Other Special Items for further information.
The following table presents the assumptions used to determine the benefit obligations at December 31, 2003 and 2002:
(a) 2002 amounts represent predecessor information.
The following table presents the accumulated postretirement benefit obligation and the fair value of plan assets which have an accumulated postretirement benefit obligation in excess of plan assets at December 31, 2003 and 2002:
The following tables present the components of Ameren's net periodic postretirement benefit cost as of December 31, 2003, 2002, and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) Represents predecessor information.
Prior service cost is amortized on a straight-line basis over the average future service of active plan participants benefiting under the postretirement plans. The net actuarial loss subject to amortization is amortized on a straight-line basis over ten years.
UE, CIPS, Genco, CILCORP and CILCO are responsible for their proportional share of the postretirement benefit costs. The following table presents the postretirement benefit costs for the years ended December 31, 2003, 2002, and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries. (b) Includes predecessor information for periods prior to the acquisition date of January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
The following expected postretirement benefit payments, which reflect expected future service, are as follows:
The following table presents our postretirement plan asset categories as of December 31, 2003 and 2002 and our target allocations for 2004:
The following table presents the assumptions used to determine net periodic benefit cost for the years ended December 31, 2003, 2002, and 2001:
(a) 2002 and 2001 amounts represent predecessor information.
Assumed healthcare cost trend rates have a significant effect on the amounts reported for healthcare plans. In addition, we have plan limits on the amount Ameren will contribute to future postretirement benefits. The following table presents the effects of a one percent change in assumed healthcare cost trend rates:
Other
Ameren, CIPS and CILCO sponsor 401(k) plans for eligible employees. The plans allow employees to contribute a portion of their base pay in accordance with specific guidelines. Ameren, CIPS and CILCO match a percentage of the employee contributions up to certain limits. Ameren's and CILCO's matching contributions to the 401(k) plans totaled $14 million and $1 million, respectively, in 2003, and $14 million and $1 million, respectively, in 2002, and $13 million and $1 million, respectively, in 2001. CIPS' matching contributions to the 401(k) plan were less than $1 million in 2003, 2002 and 2001.
NOTE 12 - Stock-based Compensation
Ameren has a long-term incentive plan for eligible employees called the Long-term Incentive Plan of 1998, which provides for the grant of options, performance awards, restricted stock, dividend equivalents and stock appreciation rights. Restricted stock awards were granted in 2003, 2002 and 2001 as a component of our compensation programs. We applied APB Opinion No. 25 in accounting for our stock-based compensation for years prior to 2003. There have not been any stock options granted since December 31, 2000. Effective January 1, 2003, we adopted SFAS No. 123. See Note 1 - Summary of Significant Accounting Policies for further information.
Restricted Stock
Restricted stock awards may be granted under our long-term incentive plan. Upon the achievement of certain performance levels, the restricted stock award vests over a period of seven years, beginning at the date of grant, and includes provisions requiring certain stock ownership levels based on position and salary. An accelerated vesting provision is also included in this plan which reduces the vesting period from seven years to three years. During 2003, 2002 and 2001, respectively, 152,956, 154,678 and 141,788 restricted stock awards were granted. The weighted-average fair value for restricted stock awards granted in 2003, 2002 and 2001 was $39.74, $42.50 and $39.60 per share, respectively. We record unearned compensation (as a component of stockholders' equity) equal to the market value of the restricted stock on the date of grant and charge the unearned compensation to expense over the vesting period. In accordance with SFAS No. 123, we recorded compensation expense relating to restricted stock awards of approximately $5 million in 2003 (which included accelerated expense of approximately $1 million related to employee retirements), $2 million in 2002 (which included accelerated expense of approximately $1 million related to our voluntary retirement program offered in 2002) and approximately $1 million in 2001.
Stock Options
Ameren
Options may be granted under our long-term incentive plan at a price not less than the fair market value of the common shares at the date of grant. Granted options vest over a period of five years, beginning at the date of grant, and provide for accelerated exercising upon the occurrence of certain events, including retirement. Outstanding options expire on various dates through 2010. Subject to adjustment, four million shares have been authorized to be issued or delivered under our long-term incentive plan. In accordance with APB Opinion No. 25, no compensation expense was recognized related to our stock options for 2002 and 2001. The pre-tax cost of weighted-average grant-date fair value of options granted would have been approximately $2 million in each of the years ended 2002 and 2001 had the fair value method under SFAS No. 123 been used for options. The fair value method was used prospectively beginning January 1, 2003. See Note 1 - Summary of Significant Accounting Policies for further information.
The following table presents Ameren stock option activity during 2003, 2002 and 2001:
The following table presents additional information about stock options outstanding at December 31, 2003:
The fair values of stock options were estimated using a binomial option-pricing model with the following assumptions:
CILCORP
Prior to Ameren's acquisition of CILCORP, employees of CILCORP and CILCO participated in the AES Stock Option Plan that provided for grants of stock options to eligible participants. Under the terms of the plan, options were issued to purchase shares of AES common stock at a price equal to 100% of the market price at the date the option was granted. The options became eligible for exercise under various schedules. The following table presents CILCORP stock option activity during 2002 and 2001:
Provisions of CILCORP bonus programs allowed for the cash-out of certain AES stock options in the event of an acquisition of CILCORP. CILCO paid $3 million during 2003 for the cash-out of the entire 73,502 shares which were eligible under these provisions. All other outstanding options under the AES Stock Option Plan remain the sole obligation of AES.
No compensation expense was recognized in connection with the issuance of options as all options have an exercise price equal to the market price of AES common stock on the date of grant. The following table presents the assumptions that were used in the Black-Scholes valuation method for shares granted:
Had compensation expense been recognized using the fair value based method under SFAS No. 123, pre-tax cost would have decreased by $3 million and $1 million in 2002 and 2001, respectively.
NOTE 13 - Income Taxes
The following table presents the effective tax rates on income before income taxes as a result of total income tax expense for each of the companies for 2003, 2002 and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) Represents predecessor information for 2002 and 2001.
The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2003, 2002, and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) Represents predecessor information for 2002 and 2001. (c) CILCORP Other primarily includes affordable housing tax credits and company-owned life insurance.
The following table presents the components of income tax expense for the years ended December 31, 2003, 2002, and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003. (b) Represents predecessor information for 2002 and 2001.
With respect to UE, CIPS and CILCO, in accordance with SFAS No. 109, "Accounting for Income Taxes," a regulatory asset, representing the probable recovery from customers of future income taxes, which is expected to occur when temporary differences reverse, was recorded along with a corresponding deferred tax liability. Also, a regulatory
liability, recognizing the lower expected revenue resulting from reduced income taxes associated with amortizing accumulated deferred investment tax credits was recorded. Investment tax credits have been deferred and will continue to be credited to income over the lives of the related property.
We adjust our deferred tax liabilities for changes enacted in tax laws or rates. Recognizing that regulators will probably reduce future revenues for deferred tax liabilities initially recorded at rates in excess of the current statutory rate, reductions in the deferred tax liability were credited to the regulatory liability.
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2003 and 2002:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) 2002 amounts represent predecessor information. CILCORP consolidates CILCO and therefore includes CILCO in its balances.
NOTE 14 - Related Party Transactions
The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren's financial statements. Below are the material related party agreements.
Electric Power Supply Agreements
Under two electric power supply agreements, Genco is obligated to supply to Marketing Company, and Marketing Company, in turn, is obligated to supply to CIPS, all of the energy and capacity needed by CIPS to offer service for resale to its native load customers at rates specified by the ICC and to fulfill CIPS' other obligations under all applicable federal and state tariffs or contracts. Any power not used by CIPS is sold by Marketing Company under various long-
term wholesale and retail contracts. For native load, CIPS pays an annual capacity charge per megawatt (the greater of its forecasted peak demand or actual demand), plus an energy charge per megawatthour to Marketing Company. For fixed-price retail customers outside of the tariff, CIPS pays Marketing Company the price it receives under these contracts. The fees paid by CIPS to Marketing Company for native load and fixed-price retail customers and any other sales by Marketing Company under various long-term wholesale and retail contracts are passed through to Genco. In addition, under the power supply agreement between Genco and Marketing Company, Genco bears all generation-related operating risks, including plant performance, operations, maintenance, efficiency, employee retention and other matters. There are no guarantees, bargain purchase options or other terms that may convey to CIPS the right to use the property and plant of Genco. The agreement between CIPS and Marketing Company expires on December 31, 2004. The agreement between Genco and Marketing Company can be terminated by either party upon at least one year's notice, but may not be terminated prior to December 31, 2004. CIPS and Marketing Company plan to pursue a renewal or extension of their agreement through December 31, 2006. A renewal or extension of this agreement will depend on compliance with regulatory requirements in effect at the time. This extension was required by the ICC in its order approving Ameren's acquisition of CILCORP and CILCO.
In October 2003, in conjunction with CILCO's transfer to AERG of substantially all of its generating assets, AERG entered into an electric power supply agreement with CILCO to supply CILCO with sufficient power to meet its native load requirements. CILCO pays a monthly capacity charge per megawatt based on CILCO's system capacity requirements, plus an energy charge per megawatthour. This agreement expires on December 31, 2004. AERG and CILCO plan to pursue an extension of the power supply agreement through December 31, 2006. A renewal or extension of this agreement will depend on compliance with regulatory requirements in effect at the time. The ICC required this extension in its order approving Ameren's acquisition of CILCORP and CILCO. Also in conjunction with CILCO's generating asset transfer, a bilateral power supply agreement was entered into between AERG and Marketing Company. This agreement provides for AERG to sell excess power to Marketing Company for sales outside the CILCO control area, and also allows Marketing Company to sell power to AERG to fulfill CILCO's native load requirements.
CILCO had a power purchase agreement with CIPS for the purchase of 100 megawatts of capacity and firm energy for the months of January and June through September under a contract which commenced in January 2000 and expired in September 2003. This power was supplied by Genco through the Marketing Company, CIPS and Genco electric power supply agreements discussed above.
UE and CIPS are parties to a power supply agreement with EEI to purchase and sell capacity and energy. This agreement expires on December 31, 2005. Under a separate agreement which expires on December 31, 2005, CIPS resold its entitlements under the power supply agreement with EEI to Marketing Company.
UE has a 150 megawatt power supply agreement with Marketing Company which expires December 31, 2005. UE also had a one year 450 megawatt power supply agreement with Marketing Company which expired in May 2002 and another one year 200 megawatt power supply agreement with Marketing Company which expired in May 2003. Power supplied by Marketing Company to UE through these agreements is being obtained from Genco.
Joint Dispatch Agreement
UE and Genco jointly dispatch electric generation under an amended joint dispatch agreement. Under the agreement, each affiliate is required to serve their load requirements from their own generation first, and then allow access to any available generation to their affiliate. The joint dispatch agreement can be terminated by either party by giving one year's notice on or after January 1, 2004. UE is currently in discussions with the MoPSC regarding possible amendments to the joint dispatch agreement. Modifications to this agreement could have a material adverse effect on UE or Genco.
Agency Agreements
Agency Agreements Any excess generation not used by UE or Genco through the joint dispatch agreement is sold to third parties through Ameren Energy, serving as each affiliate's agent. Ameren Energy also acts as agent on behalf of UE and Genco to purchase power when they require it.
In December 2003, the SEC approved an agency agreement between AERG and Marketing Company that authorizes Marketing Company, on behalf of AERG, to sell AERG's excess generation, or purchase power when needed to supply AERG customers.
Executory Tolling, Gas Sales and Transportation Agreements
Under an executory tolling agreement, CILCO purchases steam, chilled water and electricity from Medina Valley. In connection with this agreement, Medina Valley purchases gas to fuel its generating facility from AFS under a fuel supply and services agreement. Prior to September 2003, Medina Valley purchased gas from CILCORP Energy Services, Inc., a subsidiary of CILCORP which operates gas management services that include commodity procurement and re-delivery to retail customers, and gas transportation from CILCO.
Under a gas transportation agreement, Genco acquires gas transportation service from UE for its Columbia, Missouri CTs. This agreement expires in February 2016.
Support Services Agreements
Costs of support services provided by Ameren Services, Ameren Energy and AFS to their affiliates, including wages, employee benefits, professional services and other expenses are based on, or are an allocation of, actual costs incurred.
Money Pools
Utility
UE, CIPS and CILCO have the ability to borrow from Ameren and each other through a utility money pool agreement. In September 2003, CILCO received the final required regulatory approval necessary for its participation in the utility money pool. In October 2003, AERG also received the required regulatory approval necessary to participate in the utility money pool. Ameren Services administers the utility money pool and tracks internal and external funds separately. Ameren Services also participates in the utility money pool. Ameren and AERG may only participate in the utility money pool as lenders. Internal funds are surplus funds contributed to the utility money pool from participants. The primary source of external funds for the utility money pool is the UE commercial paper program. Through the utility money pool, the pool participants can access committed credit facilities at Ameren which totaled $600 million at December 31, 2003. These facilities are in addition to UE's $154 million, CIPS' $15 million and CILCO's $60 million in committed credit facilities which are also available to the utility money pool participants. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent the pool participants have surplus funds or other external sources are used to increase the available amounts. The availability of funds is also determined by funding requirement limits established by the SEC under the PUHCA. UE, CIPS, CILCO and Ameren Services rely on the utility money pool to coordinate and provide for certain short-term cash and working capital requirements. Borrowers receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 2003 was 1.14% (2002 - 1.68%).
Non state-regulated
Genco and other non state-regulated Ameren subsidiaries have the ability to borrow up to $600 million in total from Ameren through a non state-regulated subsidiary money pool agreement. However, the total amount available to the pool participants at any time is reduced by the amount of borrowings from Ameren by its subsidiaries and is increased to the extent other pool participants advance surplus funds to the non state-regulated subsidiary money pool, or external sources are used to increase the available amounts. At December 31, 2003, $600 million was available through the non state-regulated subsidiary money pool, excluding additional funds available through excess cash balances. The non state-regulated subsidiary money pool was established to coordinate and provide for short-term cash and working capital requirements of Ameren's non state-regulated activities and is administered by Ameren Services. Borrowers receiving a loan under the non state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non
state-regulated subsidiary money pool. These rates are based on the cost of funds used to fund money pool advances. Ameren and CILCORP are authorized to act only as lenders to the non state-regulated subsidiary money pool. In October 2003, AERG received the required regulatory approval necessary to participate in the non state-regulated subsidiary money pool. The average interest rate for borrowing under the non state-regulated subsidiary money pool for year ended December 31, 2003 was 8.84% (2002 - 7.60%).
CILCORP has been granted authority by the SEC under the PUHCA to borrow up to $250 million directly from Ameren in a separate arrangement unrelated to the money pools.
Intercompany Promissory Notes
Genco has subordinated intercompany promissory notes payable to CIPS and Ameren that were issued in connection with the transfer of CIPS' generating plants to Genco as part of deregulation in Illinois. The two subordinated intercompany notes each have a term of five years, bear interest at 7% based on a 10-year amortization schedule and are due May 1, 2005. Partial principal payments are payable annually and interest expense is payable quarterly. The maturities associated with the subordinated intercompany notes payable are $53 million for 2004 and $358 million for 2005.
Operating Lease
Under an operating lease agreement, Genco is leasing certain CTs at a Joppa, Illinois site to its parent, Development Company. Under an electric power supply agreement with Marketing Company, Development Company supplies the capacity and energy from these leased units to Marketing Company, which in turn supplies the energy to Genco.
UE
The following tables present the impact of related party transactions on UE's Consolidated Statement of Income for the years ended December 31, 2003, 2002, and 2001, and on the Consolidated Balance Sheet as of December 31, 2003 and 2002, based primarily on the agreements discussed above:
CIPS
The following tables present the impact of related party transactions on CIPS' Statement of Income for the years ended December 31, 2003, 2002, and 2001, and on the Balance Sheet as of December 31, 2003 and 2002, based primarily on the agreements discussed above:
(a) Amount includes current portion of $49 million as of December 31, 2003 (December 31, 2002 - $46 million).
Genco
The following tables present the impact of related party transactions on Genco's Statement of Income for the years ended December 31, 2003, 2002, and 2001, and on the Balance Sheet as of December 31, 2003 and 2002, based primarily on the agreements discussed above.
(a) Amount includes current portion of $49 million as of December 31, 2003 (December 31, 2002 - $46 million). (b) Amount includes current portion of $4 million as of December 31, 2003 (December 31, 2002 - $4 million).
CILCORP
The following tables present the impact of related party transactions on CILCORP's Consolidated Statement of Income for the years ended December 31, 2003, 2002, and 2001, and on the Consolidated Balance Sheet as of December 31, 2003 and 2002, based primarily on the agreements discussed above.
(a) 2002 and 2001 amounts represent predecessor information. 2003 amounts include January 2003 predecessor information which included $2 million in operating revenues and $3 million in purchased power associated with the executory tolling agreement with Medina Valley. (b) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(a) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
CILCO
The following tables present the impact of related party transactions on CILCO's Consolidated Statement of Income for the years ended December 31, 2003, 2002, and 2001, and on the Consolidated Balance Sheet as of December 31, 2003 and 2002, based primarily on the various agreements discussed above:
(a) 2002 and 2001 amounts represent predecessor information. 2003 amounts include January 2003 predecessor information which included $2 million in operating revenues and $3 million in purchased power associated with the agreement with Medina Valley.
NOTE 15 - Commitments and Contingencies
As a result of issues generated in the course of daily business, we are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have an adverse material effect on our financial position, results of operations or liquidity.
Capital Expenditures
See Note 3 - Rate and Regulatory Matters for information regarding Ameren's and UE's capital expenditure commitments, which were agreed upon in relation to UE's 2002 Missouri electric rate case settlement and UE's 2003 Missouri gas rate case settlement. Additionally, UE's future estimated capital expenditures include the addition of new CTs with approximately 330 megawatts of capacity at its Venice, Illinois location by the end of 2005. Total costs expected to be incurred for these units approximate $140 million of which approximately $77 million was committed as of December 31, 2003.
Fuel Purchase Commitments
To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. In addition, we have entered into various long-term commitments for the purchase of electricity. The following table presents the total estimated fuel purchase commitments at December 31, 2003:
(a) Includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) Commitments for coal, natural gas, nuclear fuel and the purchase of electricity are until 2010, 2012, 2009 and 2010, respectively.
Nuclear Plant Insurance Coverage
The following table presents insurance coverage at UE's Callaway Nuclear Plant at December 31, 2003:
(a) Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended (Price-Anderson). This is subject to retrospective assessment with respect to loss from an incident at any U.S. reactor, payable at $10 million per year. Price-Anderson expired in August 2002 and the temporary extension expired December 31, 2003. Renewal legislation is pending before Congress. Until Price-Anderson is renewed, its provisions continue to apply to existing nuclear plants. (b) Limit of liability for each incident under Price-Anderson. (c) Industry limit for potential liability from workers claiming exposure to the hazards of nuclear radiation. (d) Includes premature decommissioning costs. (e) Weekly indemnity of $3.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $2.8 million per week for 110 weeks thereafter.
Price-Anderson limits the liability for claims from an incident involving any licensed U.S. nuclear facility. The limit is based on the number of licensed reactors and is adjusted at least every five years based on the Consumer Price Index. Utilities owning a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.
If losses from a nuclear incident at the Callaway Nuclear Plant exceed the limits of, or are not subject to, insurance, or if coverage is not available, we self-insure the risk. Although we have no reason to anticipate a serious nuclear incident, if one did occur, it could have a material, but indeterminable, adverse effect on our financial position, results of operations or liquidity.
Leases
The following table presents our lease obligations at December 31, 2003:
(a) Includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) See Note 6 - Long-term Debt and Equity Financings for further discussion. (c) Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The amounts for these items are included in the less than 1 year, 1-3 years and 3-5 years columns. Amounts for after 5 years are not included in the total amount due to the indefinite periods. The estimated obligation for after 5 years is $2 million annually for both the real estate leases and the railroad licenses.
We lease various facilities, office equipment, plant equipment and railcars under operating leases. We also have a capital lease relating to UE's Peno Creek CT facility. We had a capital lease relating to nuclear fuel for UE's Callaway Nuclear Plant which was terminated early in February 2004. See Note 6 - Long-term Debt and Equity Financings for further information on this nuclear fuel lease. The following table presents total rental expense, included in Other Operations and Maintenance expenses, as of December 31, 2003, 2002, and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) 2002 and 2001 amounts represent predecessor information.
Environmental Matters
We are subject to various environmental regulations by federal, state and local authorities. From the beginning phases of siting and development, to the ongoing operation of existing or new electric generating, transmission and distribution facilities, our activities involve compliance with diverse laws and regulations that address emissions and impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological/historical resources), chemical and waste handling and noise impacts. Our activities require complex and
often lengthy processes to obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or their operations, as required. The more significant matters are discussed below.
Clean Air Act
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act creates a marketable commodity called an SO2 "allowance." Each allowance gives the owner the right to emit one ton of SO2. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. If additional allowances are needed for new generating facilities, they can be purchased from facilities having excess allowances or from SO2 allowance banks. Our generating facilities comply with the SO2 allowance caps through the purchase of allowances, the use of low sulfur fuels or through the application of pollution control technology.
The EPA issued a rule in October 1998 requiring 22 eastern states and the District of Columbia to reduce emissions of NOx in order to reduce ozone in the eastern United States. Among other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NOx emission budget for each state, including Illinois. The EPA rule requires states to implement controls sufficient to meet their NOx budget by May 31, 2004. In February 2002, the EPA proposed similar rules for Missouri. These rules are expected to be issued as final rules in the spring of 2004. The compliance date for the Missouri rules is expected to be May 1, 2007.
As a result of these requirements, we have installed a variety of NOx control technologies on our power plant boilers over the past several years. The following table presents our future estimated capital expenditures to comply with the final NOx regulations in Missouri and Illinois between 2004 and 2008:
These estimates include the assumption that the regulations will require the installation of selective catalytic reduction technology on some of our units, as well as additional controls.
In 2004, we are seeking regulatory approval to transfer at net book value approximately 550 megawatts (approximately $250 million) of generating capacity from Genco to UE, to satisfy the requirements of UE's 2002 Missouri electric rate case settlement and to meet future UE generating capacity needs. See Note 3 - - Rate and Regulatory Matters to our financial statements for further information.
On December 31, 2002, the EPA published in the Federal Register revisions to the NSR programs under the Clean Air Act, governing pollution control requirements for new fossil-fueled generating plants and major modifications to existing plants. On October 27, 2003, the EPA published a set of associated rules governing the routine maintenance, repair and replacement of equipment at power plants. Various northeastern states, the state of Illinois and others, have filed a petition with the United States District Court for the District of Columbia challenging the legality of the revisions to these NSR programs. Other states, various industries and environmental groups have filed to intervene in this challenge. At this time, we are unable to predict the impact if this challenge is successful on our future financial position, results of operations or liquidity.
In mid-December 2003, the EPA issued proposed regulations with respect to SO2 and NOx emissions (the "Interstate Air Quality Rule") and mercury emissions from coal-fired power plants. These new rules, if adopted, will require significant additional reductions in these emissions from our power plants in phases, beginning in 2010. The rules are currently under a public review and comment period and may change before being issued as final late in 2004 or early
2005. The following table presents preliminary estimated capital costs based on current technology on the Ameren systems to comply with the SO2 and NOx rules, as proposed:
(a) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
The proposed mercury regulations contain a number of options and the final control requirements are highly uncertain. Ameren anticipates additional capital costs to comply with the mercury rules could be up to $100 million by 2010, with UE incurring approximately two-thirds of the costs and Genco incurring most of the remaining costs. Depending upon the final mercury rules, similar additional costs would be incurred between 2010 and 2018.
Multi-Pollutant Legislation
The United States Congress has been working on legislation to consolidate the numerous air pollution regulations facing the utility industry. Continued deliberation on this "multi-pollutant" legislation is expected in 2004. The cost to comply with such legislation, if enacted, is expected to be covered by the modifications to our facilities required by combined Mercury and Interstate Air Quality Rules described above.
Global Climate
Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. The related Kyoto Protocol was signed by the United States but has since been rejected by the President, who instead has asked for an 18% decrease in carbon intensity on a voluntary basis. Future initiatives on this issue and the ultimate effects of the Kyoto Protocol and the President's initiatives on us are unknown. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies. Coal-fired power plants, however, are significant sources of carbon dioxide emissions, a principal greenhouse gas. Therefore, our compliance costs with any mandated federal greenhouse gas reductions in the future could have a material impact on our future financial position, results of operations or liquidity.
Clean Water Act
In April 2002, the EPA proposed rules under the Clean Water Act that require that cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts. These rules pertain to existing generating facilities that currently employ a cooling water intake structure whose flow exceeds 50 million gallons per day. The proposed rule may require us to install additional intake screens or other protective measures, as well as extensive site specific study and monitoring requirements. There is also the possibility that the proposed rules may lead to the installation of cooling towers on some of our facilities. Final rules are expected by March 2004. Our compliance costs associated with the final rules are unknown, but are not expected to be material.
Remediation
We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of fault, legality of original disposal, or ownership of a disposal site. UE and CIPS have been identified by the federal or state governments as a potentially responsible party at several contaminated sites. Several of these sites involve facilities which were transferred by CIPS to Genco in May 2000 and were transferred by CILCO to AERG in October 2003. As part of each transfer, the transferor (CIPS or CILCO) has contractually agreed to indemnify the transferee (Genco or AERG) for remediation costs associated with pre-existing environmental contamination at the transferred sites.
CIPS, CILCO and UE own or are otherwise responsible for 13, four and one former MGP sites in Illinois, respectively. All of these sites are in various stages of investigation, evaluation and remediation. Under its current schedule, Ameren anticipates that remediation at these sites should be completed by 2010. The ICC permits each company to recover remediation and litigation costs associated with their former MGP sites located in Illinois from their Illinois electric and natural gas utility customers through environmental riders. To be recoverable, such costs must be prudently and properly incurred and are subject to annual reconciliation review by the ICC. The total costs deferred, net of recoveries from insurers and through environmental adjustment rate riders, at December 31, 2003, were $26 million, $4 million and $1 million for CIPS, CILCO and UE, respectively.
In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. Unlike in Illinois, UE does not have in effect in Missouri a rate rider mechanism which permits remediation costs associated with MGP sites to be recovered from utility customers, and UE does not have any retail utility operations in Iowa. Because of the unknown and unique characteristics of each site (such as amount and type of residues present, physical characteristics of the site and the environmental risk), and uncertain regulatory requirements, we are not able to determine the maximum liability for the remediation of these sites. UE has recorded a $12 million liability as of December 31, 2003, representing its estimated minimum obligation. At this time, we are unable to determine what portion of these costs, if any, will be eligible for recovery from insurance carriers.
In June 2000, the EPA notified UE and numerous other companies that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 1 and Sauget Area 2. From approximately 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2 and currently owns and operates electric transmission and distribution facilities in or near Sauget Areas 1 and 2.
In September 2000, the DOJ was granted leave by the United States District Court - Southern District of Illinois to add numerous additional parties, including UE, to a pre-existing lawsuit between the government and others. The government seeks recovery of response costs under CERCLA (Superfund), incurred in connection with the remediation of Sauget Area 1. In October 2003, the government dismissed UE as a party to the lawsuit and UE considers the Sauget Area 1 litigation closed.
In September 2001, the EPA proposed in the Federal Register that Sauget Area 1 and Sauget Area 2 be listed on the National Priorities List. The inclusion of a site on this list allows the EPA to access Superfund trust monies to fund site remediations. With respect to Sauget Area 2, UE has joined with other potentially responsible parties to evaluate the extent of potential contamination. We are unable to predict the ultimate impact of the Sauget Area 2 site on our financial position, results of operations or liquidity.
In October 2002, UE was included in a Unilateral Administrative Order list of potentially liable parties for groundwater contamination for a portion of the Sauget Area 2 site. The Unilateral Administrative Order encompasses the groundwater contamination releasing to the Mississippi River adjacent to Monsanto Chemical Company's (now known as Solutia's) former chemical waste landfill and the resulting impact area in the Mississippi River. UE is being asked to participate in response activities that involve the installation of a barrier wall around a chemical waste site with three recovery wells to divert groundwater flow. The projected cost for this remedy method is approximately $26 million. In November 2002, UE sent a letter to the EPA asserting its defenses to the Unilateral Administrative Order and requested its removal from the list of potentially responsible parties under the Unilateral Administrative Order. Solutia agreed to comply with the Unilateral Administrative Order. However, in December 2003, Solutia filed for bankruptcy protection and is seeking to discharge its environmental liabilities. As the status of future remediation at Sauget Area 2 or compliance with the Unilateral Administrative Order is uncertain, we are unable to predict the ultimate impact of the Sauget Area 2 site on our financial position, results of operations or liquidity.
In October 2002, CILCO submitted a corrective action plan to the Illinois Environmental Protection Agency (Illinois EPA) in accordance with permit conditions to address ground water issues associated with the recycle pond and ash ponds at the Duck Creek power plant facility. In January 2003, the Illinois EPA accepted portions of the plan but rejected other portions. Additional discussions with the Illinois EPA will be necessary to develop an acceptable plan. CILCORP and CILCO both have a liability of $8 million at December 31, 2003, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort to treat and discharge the recycle system water in order to address these ground water issues. Future CILCO capital expenditures at Duck Creek will entail installation of a bypass water
line and construction of a landfill and a new pond. CILCO estimates future capital expenditures for the indicated activities could range from $19 million to $30 million by 2008.
In addition, our operations, or that of our predecessor companies, involve the use, disposal and, in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine the impact these actions may have on our financial position, results of operations or liquidity.
Waste Disposal
On July 30, 2002, the Illinois Attorney General's Office advised us that it would be commencing an enforcement action concerning an inactive waste disposal site near Coffeen, Illinois, which is the location of a disposal facility permitted by the Illinois EPA to receive fly ash from Genco's Coffeen power plant. The Illinois Attorney General also notified the disposal facility's current and former owners as to the proposed enforcement action. The Attorney General advised that it may initiate an action under CERCLA (Superfund) to recover past costs incurred at the site (approximately $0.3 million) and to obtain a declaratory judgment as to liability for future costs. Neither Genco, the current owner of the Coffeen power plant, nor CIPS, the prior owner of the Coffeen power plant, owned or operated the disposal facility. We believe that this matter will not have a material adverse effect on Ameren's, CIPS or Genco's financial position, results of operations or liquidity.
Noise-related Matters
On July 8, 2003, Genco and its parent company, Development Company, as well as U.S. Can Company, filed a complaint in the Circuit Court of Cook County, Illinois, Chancery Division, against the Village of Bartlett, Illinois, the Village Trustees, and Realen Homes, L.P., a Pennsylvania limited partnership, seeking a declaratory judgment and/or writ of certiorari to invalidate decisions by the Village of Bartlett on June 3, 2003, to annex and rezone properties for a proposed project to be developed by Realen Homes. The project would consist of approximately 210 single family and 119 townhouse units on land located across from Genco's CTs, U.S. Can Company's plant and other industrial facilities in Elgin, Illinois. The proposed residential project could impact, among other things, Genco's ability to meet certain state and local noise standards. On March 3, 2004, Genco, Development Company, the Village of Bartlett and Realen Homes, L.P., agreed to a settlement of the lawsuit by the terms of which the parties, among other things, agreed to a dismissal of the complaint, as then amended, and entered into an easement and restrictive covenant agreement pertaining to the transmissioin of noise and light from the property where Genco's CTs are located. In a related matter, on October 28, 2003, Genco filed a rulemaking proceeding before the Illinois Pollution Control Board seeking site specific noise limitations for its CTs in Elgin, Illinois. The new limitations, if adopted by the Illinois Pollution Control Board, would allow Genco to meet Illinois noise requirements in a newly proposed residential area. The Illinois Pollution Control Board held a hearing on this rulemaking proceeding on January 22, 2004. A ruling is anticipated in May 2004.
Asbestos-Related Litigation
Ameren, UE, CIPS, Genco and CILCO have been named, along with numerous other parties, in a number of lawsuits which have been filed by certain plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The number of total defendants named in each case is significant with as many as 110 parties named in a case to as few as six. However, the average number of parties is 60 in the cases that were pending as of December 31, 2003.
The claims filed against Ameren, UE, CIPS, Genco and CILCO allege injury from asbestos exposure during the plaintiffs' activities at our electric generating plants. In the case of CIPS, its former plants are now owned by Genco, and in the case of CILCO, most of its former plants are now owned by AERG. As a part of the transfer of ownership of the generating plants, the transferor (CIPS or CILCO) has contractually agreed to indemnify the transferee (Genco or AERG) for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages in excess of $50,000, which, if proved, typically would be shared among the named defendants.
The following table presents the status of the asbestos-related lawsuits that have been filed against the Ameren Companies as of December 31, 2003:
(a) Addition of the numbers in the individual columns does not equal the total column because some of the lawsuits name multiple Ameren entities as defendants.
Ameren, UE, CIPS, Genco and CILCO believe that the final disposition of these proceedings will not have a material adverse effect on their financial position, results of operations or liquidity.
Other Matters
On May 11, 2001, CILCO and Enron Power Marketing, Inc. (EPMI), a subsidiary of Enron Corp. (Enron), entered into a Master Agreement for electric purchases and sales, which covered energy transactions scheduled for deliveries during the period of 2001 to 2003. On November 28, 200l, EPMI demanded that CILCO post $28 million in collateral based on mark-to-market exposure of open transactions. On November 30, 2001, CILCO notified EPMI that events of default had occurred under the Master Agreement and pursuant to the termination provisions of the Master Agreement declared the Master Agreement terminated effective December 20, 2001. Due to contractual provisions and EPMI's and Enron's actions, we do not believe that it is probable that CILCO will be required to pay any amount to Enron or its affiliates and has therefore recorded no liability for undelivered electric purchases. Enron and EPMI filed Chapter 11 bankruptcy petitions on December 2, 2001, in the U. S. Bankruptcy Court for the Southern District of New York. Thereafter, CILCO purchased replacement power to serve its retail customers which had previously been partially supported by the EPMI transactions. While the ultimate outcome is unpredictable, we do not believe that EPMI's defaults under the Master Agreement, its filing for bankruptcy protection, CILCO's termination of the Master Agreement, or CILCO's purchase of replacement electricity will have a material adverse effect on CILCO's financial position or results of operations or liquidity.
On December 10, 2002, EPMI filed a complaint against AES, Constellation New Energy, Inc., formerly known as AES New Energy Inc., and CILCO in the U.S. Bankruptcy Court for the Southern District of New York. With respect to CILCO, EPMI alleges that it is owed $31.2 million under the Master Agreement. CILCO disputes that any amount is owed EPMI based on the clear language of the Master Agreement, Section 553 of the Bankruptcy Code and EPMI's misconduct prior to entering into the Master Agreement and continuing through the date of its bankruptcy filing. EPMI's complaint against CILCO and others is part of a large class of claims that have been stayed pending mandatory court ordered mediation. Mediation sessions are ongoing and the parties are continuing to discuss potential settlement. AES has agreed to undertake CILCO's defense in this proceeding and intends to vigorously contest these claims. Due to CILCO's contractual and other defenses to EPMI's claims, as well as certain provisions related to the sale of CILCO to Ameren, we do not believe the results of this litigation will have a material adverse effect on CILCO's financial position, results of operations or liquidity.
On May 4, 2001, CILCO and Enron subsidiary Enron North America Corp. (ENA) entered into a natural gas transaction for daily deliveries not to exceed 10,000 MMBtu per day during calendar year 2002. CILCO received no natural gas deliveries pursuant to this transaction in 2002. On October 24, 2001, CILCO and ENA entered into a short-term natural gas transaction giving CILCO the right to call upon ENA for the delivery of 10,000 MMBtu per day during the period from November 1, 2001 through March 31, 2002. Since late November 2001, ENA has been unable to deliver natural gas when called upon by CILCO. ENA's failure to deliver natural gas is an event of default under the Master Firm Sales Agreement governing the October transaction. On December 2, 2001, ENA filed a Chapter 11 bankruptcy petition in the U. S. Bankruptcy Court for the Southern District of New York. To the extent that it has been necessary, CILCO has purchased replacement natural gas. Because these transactions are part of a larger and more diversified natural gas supply portfolio and are subject to the PGA clause, management does not believe ENA's failure to supply natural gas or its subsequent bankruptcy filing will have a material adverse effect on CILCO's financial position, results of operations or liquidity.
On June 18, 2003, 20 retirees and surviving spouses of retirees of various Ameren companies (the plaintiffs) filed a complaint in the U.S. District Court, Southern District of Illinois, against Ameren, UE, CIPS, Genco and Ameren Services, and against our Retiree Medical Plan (the defendants). The retirees were members of various local labor unions of the IBEW and the IUOE. The complaint, referred to as Barnett, et al. vs Ameren Corporation, et al., alleges the following:
o the labor organizations which represented the plaintiffs have historically negotiated retiree medical benefits with the defendants and that pursuant to the negotiated collective bargaining agreements and other negotiated documents, the plaintiffs are guaranteed medical benefits at no cost or at a fixed maximum cost during their retirement; o Ameren has unilaterally announced that, beginning in 2004, retirees must pay a portion of their own healthcare premiums and either an increasing portion of their dependents' premiums or newly imposed dependents' premiums, and that surviving spouses will be paying increased amounts for their medical benefits; o the defendants' actions deprive the plaintiffs of vested benefits and thus violate ERISA and the Labor Management Relations Act of 1947, and constitute a breach of the defendants' fiduciary duties; and o the defendants are estopped from changing the plan benefits. (This allegation was subsequently dropped from the amended complaints)
The plaintiffs filed the complaint on behalf of themselves, other similarly situated former non-management employees and their surviving spouses who retired from January 1, 1992 through October 1, 2002, and on behalf of all subsequent non-management retirees and their surviving spouses whose medical benefits are reduced or are threatened with reduction. The plaintiffs seek to have this lawsuit certified as a class action, seek injunctive relief and declaratory relief, seek actual damages for any amounts they are made to pay as a result of the defendants' actions, and seek payment of attorney fees and costs. An amended complaint that added three plaintiffs was filed July 15, 2003. In response to the Court's ruling on the defendants' motions to dismiss various counts of the complaint, a second amended complaint was filed on December 15, 2003, clarifying some of the allegations, adding two and dropping two plaintiffs, and adding the Ameren Group Medical Plan as a defendant. We are unable to predict the outcome of this lawsuit or the impact of the outcome on our financial position, results of operations or liquidity.
Regulation
Regulatory changes enacted and being considered at the federal and state levels continue to change the structure of the utility industry and utility regulation, as well as encourage increased competition. At this time, we are unable to predict the impact of these changes on our future financial position, results of operations or liquidity. See Note 3 - Rate and Regulatory Matters for further information.
NOTE 16 - Callaway Nuclear Plant
Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or 1/10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this Act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates from its Callaway Nuclear Plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. UE has sufficient storage capacity at its Callaway Nuclear Plant until 2019 and has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE's disposal facility is not expected to adversely affect the continued operation of the Callaway Nuclear Plant through its currently licensed life.
Electric utility rates charged to customers provide for the recovery of the Callaway Nuclear Plant's decommissioning costs over the life of the plant, based on an assumed 40-year life, ending with expiration of the plant's operating license in 2024. The Callaway Nuclear Plant site is assumed to be decommissioned based on immediate dismantlement method and removal from service. Decommissioning costs, including decontamination, dismantling and site restoration, are estimated to be $536 million in current year dollars and are expected to escalate approximately 3.5% per year through the end of decommissioning activity in 2033. Decommissioning costs are charged to cost of services used to establish electric rates for UE's customers and amounted to approximately $7 million in each of the years 2003, 2002 and 2001. Every three years, the MoPSC and ICC require UE to file updated cost studies for decommissioning its
Callaway Nuclear Plant, and electric rates may be adjusted at such times to reflect changed estimates. The latest studies were filed in 2002. Costs collected from customers are deposited in an external trust fund to provide for the Callaway Nuclear Plant's decommissioning. Fund earnings are expected to average approximately 8.6% annually through the date of decommissioning. If the assumed return on trust assets is not earned, we believe it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for UE's Callaway Nuclear Plant is reported in Nuclear Decommissioning Trust Fund in Ameren's and UE's Consolidated Balance Sheets. This amount is legally restricted to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to the regulatory asset recorded in connection with the adoption of SFAS No. 143. Upon the completion of UE's transfer of its Illinois electric and gas utility businesses to CIPS, which is subject to the receipt of regulatory approvals, the assets and liabilities related to the Illinois portion of the decommissioning trust fund will be transferred to Missouri. See Note 3 - Rate and Regulatory Matters for further information.
NOTE 17 - Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash, Temporary Investments and Short-term Borrowings
The carrying amounts approximate fair value because of the short-term maturity of these instruments.
Marketable Securities
The fair value is based on quoted market prices obtained from dealers or investment managers.
Nuclear Decommissioning Trust Fund
The fair value is estimated based on quoted market prices for securities.
Preferred Stock of UE, CIPS and CILCO
The fair value is estimated based on the quoted market prices for the same or similar issues.
Long-term Debt
The fair value is estimated based on the quoted market prices for same or similar issues or on the current rates offered to Ameren and its subsidiaries for debt of comparable maturities.
Derivative Financial Instruments
Market prices used to determine fair value are based on management's estimates, which take into consideration factors like closing exchange prices, over-the-counter prices, time value of money and volatility factors. All derivative financial instruments are carried at fair value.
The following table presents the carrying amounts and estimated fair values of our financial instruments at December 31, 2003 and 2002:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003 and includes amounts for non-registrant Ameren subsidiaries. (b) Includes predecessor information for periods prior to January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
UE has investments in debt and equity securities that are held in trust funds for the purpose of funding the nuclear decommissioning of its Callaway Nuclear Plant. See Note 16 - Callaway Nuclear Plant for further information. We have classified these investments in debt and equity securities as available for sale and have recorded all such investments at their fair market value at December 31, 2003 and 2002. Investments by the nuclear decommissioning trust funds are allocated 60% to 70% to equity securities with the balance invested in fixed income securities. Fixed income investments are limited to U.S. government or agency securities, municipal bonds or investment-grade corporate securities. The proceeds from the sale of investments were $123 million in 2003 (2002 - $141 million; 2001 - $230 million). Using the specific identification method to determine cost, the gross realized gains on those sales were approximately $1 million for 2003 (2002 - less than $1 million; 2001 - $4 million). Net realized and unrealized gains and losses are reflected in regulatory assets on Ameren's and UE's Consolidated Balance Sheets, which is consistent with the method we use to account for the decommissioning costs recovered in rates. Gains or losses on assets in the trusts could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in electric rates paid by UE's customers.
The following table presents the costs and fair values of investments in debt and equity securities in the nuclear decommissioning trust fund at December 31, 2003 and 2002:
The following table presents the costs and fair values of investments in debt securities according to their contractual maturities at December 31, 2003:
NOTE 18 - Segment Information
Ameren
Ameren's reportable segment, Utility Operations, is comprised of its electric generation and electric and gas transmission and distribution operations. Ameren's reportable segment, Other, is comprised of the parent holding company, Ameren Corporation. As a result of the CILCORP acquisition, we modified our segment presentation in 2003 and have made reclassifications to prior periods to conform to current period presentation.
The accounting policies for segment data are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data includes intersegment revenues, as well as a charge for allocating costs of administrative support services to each of the operating companies, which, in each case, is eliminated upon consolidation. Ameren Services allocates administrative support services based on various factors, such as headcount, number of customers and total assets.
The table below presents information about the reported revenues, net income and total assets of Ameren for the years ended December 31, 2003, 2002, and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) Elimination of intercompany revenues.
The following table presents specified items included in Ameren's segment profit (loss) for the years ended December 31, 2003, 2002, and 2001:
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for non-registrant Ameren subsidiaries as well as intercompany eliminations. (b) Elimination of intercompany interest charges. (c) Does not include income tax expense related to the cumulative effect gain recognized upon adoption of SFAS No. 143. (d) Does not include tax benefit related to the cumulative effect loss recognized upon adoption of SFAS No. 133.
All construction expenditures for the years ended December 31, 2003, 2002, and 2001, were in the Utility Operations segment.
(a) Includes amounts for CILCORP since the acquisition date of January 31, 2003. (b) For 2002, revenues were netted with costs upon adoption of EITF No. 02-3 and the rescission of EITF No. 98-10. See Note 1 - Summary of Significant Accounting Policies to our financial statements for further information. The amount netted for each quarter is as follows: 2002 - $241 million in first quarter, $133 million in second quarter, $189 million in third quarter and $175 million in fourth quarter.
(a) For 2002, revenues were netted with costs upon adoption of EITF No. 02-3 and the rescission of EITF No. 98-10. See Note 1 - Summary of Significant Accounting Policies to our financial statements for further information. The amount netted for each quarter is as follows: 2002 - $150 million in first quarter, $78 million in second quarter, $117 million in third quarter and $113 million in fourth quarter.
(a) For 2002, revenues were netted with costs upon adoption of EITF No. 02-3 and the rescission of EITF No. 98-10. See Note 1 - Summary of Significant Accounting Policies to our financial statements for further information. The amount netted for each quarter is as follows: 2002 - $87 million in first quarter, $44 million in second quarter, $60 million in third quarter and $62 million in fourth quarter.
(a) Includes predecessor information for periods prior to January 31, 2003.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
PricewaterhouseCoopers LLP served as independent accountants for Ameren, UE, CIPS and Genco for the two fiscal years ended December 31, 2003 and 2002 and the subsequent interim period through the date of this report and for CILCORP and CILCO for the fiscal year ended December 31, 2003, and the subsequent interim period through the date of this report. During these periods, PricewaterhouseCoopers LLP did not resign, decline to stand for re-election or was dismissed.
During the fiscal year ended December 31, 2002, and the subsequent interim period through March 14, 2003, Deloitte & Touche LLP served as independent public accountants for CILCORP and CILCO. The following text was filed by CILCORP and CILCO by Form 8-K on March 20, 2003, regarding a change in their certifying accountant:
On March 14, 2003, the Auditing Committees of CILCORP Inc. and Central Illinois Light Company (the "Registrants") dismissed Deloitte & Touche LLP ("Deloitte & Touche") as the Registrants' independent public accountants subject to completion of its services related to the audits of the fiscal year 2002 and engaged PricewaterhouseCoopers LLP ("PricewaterhouseCoopers") to serve as the Registrants' independent auditors for the fiscal year 2003. The Registrants' Auditing Committees made this replacement because PricewaterhouseCoopers is serving as the independent auditors for the Registrants' parent company, Ameren Corporation, for the fiscal year 2003.
Deloitte & Touche's reports on the Registrants' consolidated financial statements for the fiscal years ended December 31, 2001 and 2000 did not contain an adverse opinion or a disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles.
During the Registrants' two fiscal years ended December 31, 2001 and 2000 and the subsequent interim period through March 14, 2003, there were no disagreements with Deloitte & Touche on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure which, if not resolved to Deloitte & Touche's satisfaction, would have caused it to make reference to the subject matter in connection with its reports on the Registrants' consolidated financial statements for such years, and there were no reportable events, as listed in Item 304(a)(1)(v) of Regulation S-K.
The Registrants have provided Deloitte & Touche with a copy of the foregoing disclosures. Attached as Exhibit 16.1 is a copy of Deloitte & Touche's letter, dated March 20, 2003, stating its agreement with such statements.
During the Registrants' two fiscal years ended December 31, 2002 and 2001 and the subsequent interim period through March 14, 2003, the Registrants did not consult PricewaterhouseCoopers regarding the application of accounting principles to a specified transaction, either contemplated or proposed, or the type of audit opinion that might be rendered on the Registrants' consolidated financial statements, or any other matter or reportable event that would be required to be reported in this Current Report on Form 8-K.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES.
(a) Evaluation of Disclosure Controls and Procedures
As of December 31, 2003, the principal executive officer and principal financial officer of each Registrant have evaluated the effectiveness of the design and operation of such Registrant's disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act). Based upon that evaluation, the principal executive officer and principal financial officer of each such Registrant have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to such Registrant, which is required to be included in such Registrant's reports filed or submitted with the SEC under the Exchange Act.
(b) Change in Internal Controls
There has been no change in the Registrants' internal control over financial reporting that occurred during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS.
Information required by Item 401and 405 of SEC Regulation S-K for Ameren, UE, CIPS and CILCO will be included in each company's definitive proxy statement for their 2004 annual meetings of shareholders filed pursuant to SEC Regulation 14A and is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I(2) of Form 10-K.
Information concerning executive officers required by this item is reported under a separate caption in Part I of this report.
The Boards of Directors of the Ameren Companies have determined that they have one Audit Committee financial expert serving on each of their Audit Committees. His name is Douglas R. Oberhelman and he has been determined by the Ameren Companies' Boards of Directors to be "independent" as that term is used in SEC Regulation 14A.
To provide for ethical conduct in its financial management and reporting, Ameren has adopted a Code of Ethics that applies to the principal executive officer, the principal financial officer, the principal accounting officer or controller, and the treasurer of the Ameren Companies. Ameren has also adopted a Code of Business Conduct that applies to the directors, officers and employees of the Ameren Companies, referred to as the Corporate Compliance Policy. The Ameren Companies make available free of charge through Ameren's Internet website (http://www.ameren.com) the Code of Ethics and Corporate Compliance Policy. These documents are also available without charge in print upon written request to Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri 63166-6149. Any amendment to, or waiver of, the Code of Ethics and Corporate Compliance Policy will be posted on Ameren's Internet website within five business dates following the date of the amendment or waiver.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Information required by Item 402 of SEC Regulation S-K for Ameren, UE, CIPS and CILCO will be included in each company's definitive proxy statement for their 2004 annual meetings of shareholders filed pursuant to SEC Regulation 14A and is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I(2) of Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
Equity Compensation Plan Information
The following table presents information as of December 31, 2003, with respect to the shares of Ameren's common stock that may be issued under its existing equity compensation plan.
(a) Consists of the Ameren Corporation Long-term Incentive Plan of 1998 which was approved by stockholders in April 1998 and expires on April 1, 2008. (b) Excludes an aggregate of 584,762 restricted shares of Ameren common stock issued under the Ameren Corporation Long-term Incentive Plan of 1998 in 2001, 2002, 2003 and 2004.
UE, CIPS, Genco, CILCORP and CILCO do not have separate equity compensation plans.
The information required by Item 403 of SEC Regulation S-K for Ameren, UE, CIPS and CILCO will be included in each company's definitive proxy statement for their 2004 annual meetings of shareholders filed pursuant to SEC Regulation 14A and is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I(2) of Form 10-K.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information required by Item 404 of SEC Regulation S-K for Ameren, UE, CIPS and CILCO will be included in each company's definitive proxy statement for their 2004 annual meetings of shareholders filed pursuant to SEC Regulation 14A and is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I(2) of Form 10-K.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies will be included in the definitive proxy statements of Ameren, UE, CIPS and CILCO for their 2004 annual meetings of shareholders filed pursuant to SEC Regulation 14A and is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
The above schedule should be read in conjunction with the aforementioned financial statements. Schedules not included have been omitted because they are not applicable or the required data is shown in the aforementioned financial statements.
(a)(3) Exhibits.
Reference is made to the Exhibit Index commencing on page 189.
(b) Reports on Form 8-K. The Ameren Companies filed the following reports on Form 8-K during the quarterly period ended December 31, 2003:
(c) Exhibits are listed in the Exhibit Index commencing on page 189.
(a) Amount includes $2 million related to CILCO balance at the date of acquisition on January 31, 2003. (b) Uncollectible accounts charged off, less recoveries.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
*The file number references for the Combined Ameren Companies' filings with the SEC are: Ameren, 1-14756; UE, 1-2967; CIPS, 1-3672; Genco, 333-56594; CILCORP, 2-95569; and CILCO, 1-2732. **Management compensatory plan or arrangement.
Each Registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above.