ITEM 1. BUSINESS.
GENERAL
Central Illinois Public Service Company (AmerenCIPS or the Registrant) is a subsidiary of Ameren Corporation (Ameren), a holding company, registered under the Public Utility Holding Company Act of 1935. On December 31, 1997, CIPSCO Incorporated (CIPSCO) and Union Electric Company (AmerenUE) combined with the result that the common shareholders of CIPSCO and AmerenUE became the common shareholders of Ameren, and Ameren became the owner of 100% of the common stock of AmerenUE and CIPSCO's operating subsidiaries, the Registrant and CIPSCO Investment Company (the Merger). Since the Merger, Ameren has formed a number of other subsidiaries including AmerenEnergy, Inc. which serves as a power marketing agent for the Registrant and Ameren Services Company which provides shared support services to the Registrant. For additional information on the Registrant's business organization, see Note 1 to the "Notes to Financial Statements" under Item 8 herein.
In conjunction with the Illinois Electric Service Customer Choice and Rate Relief Law of 1997 (the Law), the Registrant has received regulatory approvals to transfer its generating facilities to Ameren Energy Generating Company (AEG), a nonregulated, indirectly wholly-owned subsidiary of Ameren. The transfer of the assets and liabilities (at historical net book value of approximately $600 million) is currently scheduled to occur in May 2000. Discussion below relating to "forward-looking" statements reflects information assuming that the transfer will occur as scheduled. For additional information on the Law, its impact on the Registrant, and the generating facilities transfer, see "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Note 2 to the "Notes to Financial Statements" under Item 8 herein.
The Registrant, an Illinois corporation, was organized in 1902. AmerenCIPS is a public utility operating company engaged in the sale of electricity and natural gas in portions of central and southern Illinois. The Registrant furnishes electric service in 557 incorporated and unincorporated communities and adjacent suburban and rural areas. The Registrant also furnishes natural gas service to retail customers in 267 incorporated and unincorporated communities and adjacent suburban and rural areas located in 41 counties of central and southern Illinois and provides gas transportation service to end-users.
The AmerenCIPS service territory is predominantly made up of small towns and rural areas. Of the communities served, only 5 have populations greater than 15,000. Customer density on the AmerenCIPS gas system is approximately 35 customers per mile of main. The Registrant furnishes both electric and natural gas service in 236 of the communities served by it.
The territory served by the Registrant, located in 66 counties in Illinois, has an estimated population of 820,000 and is devoted principally to agriculture and diversified industrial operations. Key industries include petroleum and petrochemical industries, food processing, metal fabrication and coal mining.
For the year 1999, 85% of total operating revenues was derived from the sale of electric energy and 15% from the sale of natural gas. Electric operating revenues as a percentage of total operating revenues in 1998 and 1997 were 85% and 82%, respectively.
The Registrant employed 1,759 persons at December 31, 1999. Approximately 70% of such employees are represented by local unions affiliated with the AFL-CIO. For information on labor agreements and other labor matters, see Note 11 to the "Notes to Financial Statements" under Item 8 herein. Approximately 45% of the Registrant's employees will transfer to AEG in conjunction with the generation facilities transfer discussed above.
sufficient under the test to support the issuance of additional preferred stock (assuming an annual dividend rate on such preferred stock of 6.75%) in an amount in excess of the maximum amount ($185 million) of authorized and unissued preferred stock under the Articles.
RATES
For the year 1999, approximately 78% of the Registrant's electric operating revenues were based on rates regulated by the Illinois Commerce Commission (ICC) and 22% were regulated by the Federal Energy Regulatory Commission (FERC) of the U. S. Department of Energy. The Registrant's gas operating revenues for the year 1999 were based on rates regulated exclusively by the ICC. For information on rate matters in these jurisdictions, see "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Note 2 to the "Notes to Financial Statements" under Item 8 herein.
FUEL SUPPLY
Over 99% of the net kilowatthour generation of the Registrant in 1999 was provided by coal-fired generating units and the remainder by an oil-fired unit. As discussed under "General" section above, the Registrant's generating facilities are scheduled to be transferred to AEG in the year 2000.
For additional information on the Registrant's "Fuel Supply", see "Results of Operations" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Note 11 to the "Notes to Financial Statements" under Item 8 herein.
REGULATION
Information contained in this section could be impacted by the transfer of the Registrant's generating facilities to AEG. See discussion in "General" section above for more information.
The Registrant is subject to regulation by the Securities and Exchange Commission and, as a subsidiary of Ameren, is subject to the provisions of the Public Utility Holding Company Act of 1935. The Registrant is subject to regulation by the ICC as to rates, service, accounts, issuance of equity securities, issuance of debt having a maturity of more than twelve months, mergers, and various other matters. The Registrant is also subject to regulation by the FERC as to rates and charges in connection with the transmission of electric energy in interstate commerce and the sale of such energy at wholesale in interstate commerce, mergers, and certain other matters. Authorization to issue debt having a maturity of twelve months or less is obtained from the Securities and Exchange Commission.
For information on regulatory matters in these jurisdictions, including the current status of electric utility restructuring in Illinois, see "Liquidity and Capital Resources" and "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Notes 1 and 2 to the "Notes to Financial Statements" under Item 8 herein.
The Registrant is regulated, in certain of its operations, by air and water pollution and hazardous waste regulations at the city, county, state and federal levels. The Registrant is in substantial compliance with such existing regulations.
Environmental Issues. On December 22, 1995, a complaint was filed in the Circuit Court for the Seventh Judicial Circuit, Sangamon County, Illinois against the Registrant and several other defendants. The complaint sought unspecified monetary damages and alleged that, as a result of exposure to carcinogens contained in coal tar at the AmerenCIPS Taylorville gas plant site, plaintiffs' children had suffered from a rare form of childhood cancer known as "neuroblastoma". In 1998, a jury awarded plaintiffs $3.2 million. In March 2000, the Illinois Appellate Court, on an appeal by AmerenCIPS, upheld the plaintiffs' verdict. The Registrant plans to seek an appeal of the court's decision to the Illinois Supreme Court. The Registrant believes that final disposition of this matter will not have a material adverse effect on the financial position, results of operations or liquidity of AmerenCIPS.
On August 2, 1996, the Illinois Attorney General filed a complaint with the Illinois Pollution Control Board alleging various violations of wastewater discharge permit conditions and ground water standards at AmerenCIPS' Hutsonville Power Station. The complaint seeks monetary penalties and the award of attorney fees. The Registrant, the Illinois Environmental Protection Agency and the Attorney General have reached a settlement in principle resolving the complaint which will require the Registrant to perform remedial actions at the site. Any final settlement of this matter must be approved by the Illinois Pollution Control Board. While the Registrant cannot predict the final outcome of this matter, it does not believe that the final resolution will have a material adverse effect on financial position, results of operations or liquidity of the Registrant.
See "Liquidity and Capital Resources" in "Management's Discussion and Analysis of Financial Conditions and Results of Operations" under Item 7 herein and Note 11 to the "Notes to Financial Statements" under Item 8 herein for a further discussion of environmental issues.
INDUSTRY ISSUES
The Registrant is facing issues common to the electric and gas utility industries which have emerged during the past several years. These issues include: the potential for more intense competition and for changing the structure of regulation; changes in the structure of the industry as a result of changes in federal and state laws, including the formation of unregulated generating entities; on-going consideration of additional changes of the industry by federal and state authorities; continually developing environmental laws, regulations and issues, including proposed new air quality standards; public concern about the siting of new facilities; proposals for demand side management programs; and global climate issues. The Registrant is monitoring these issues and is unable to predict at this time what impact, if any, these issues will have on its operations, financial condition, or liquidity.
For additional information on certain of these issues, see "Liquidity and Capital Resources" and "Electric Industry Restructuring" in Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Notes 2 and 11 to the "Notes to Financial Statements" under Item 8 herein.
Year 2000 Issue. The Year 2000 Issue relates to how dates are stored and used in computer systems, applications, and embedded systems. As the century date change occurred, certain date-sensitive systems had to recognize and properly treat the year as 2000 and not as 1900. This inability to recognize and properly treat the year as 2000 could have caused these systems to process critical financial and operational information incorrectly. The Registrant encountered no significant problems associated with the Year 2000 Issue at year-end. For information on this issue, see "Year 2000 Issue" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein.
ITEM 2.
ITEM 2. PROPERTIES.
Information contained in this section could be impacted by the transfer of the Registrant's generating facilities to AEG. See discussion in "General" section above for more information.
In planning its construction program, the Registrant is presently utilizing a forecast of kilowatthour sales growth of approximately 1.2% and peak load growth of 1.4%, each compounded annually, and is providing for a minimum reserve margin of approximately 15% above its anticipated peak load requirements.
The Registrant is a member of one of the ten regional electric reliability councils organized for coordinating the planning and operation of the nation's bulk power supply - MAIN (Mid-America Interconnected Network) operating primarily in Wisconsin, Illinois and Missouri. The Registrant's bulk power system is operated as an Ameren-wide control area and transmission system under the FERC approved Joint Dispatch Agreement between the Registrant and AmerenUE. Ameren has interconnections for transmission service and the exchange of electric energy, directly and through the facilities of others, with more than twenty power suppliers.
The Registrant has also received regulatory approvals to join the Midwest Independent System Operator (Midwest ISO) which will operate electric transmission systems and maintain system reliability and security for its members. For a discussion of the Midwest ISO which is expected to be operational in the year 2001, see "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Note 2 to the "Notes to Financial Statements" under Item 8 herein.
The Registrant owns 20% of the capital stock of Electric Energy, Inc. (EEI), and its affiliate, AmerenUE, owns 40% of such stock. The balance is held by two other sponsoring companies -- Kentucky Utilities Company (KU), and Illinova Generating (IG). EEI owns and operates a generating plant with a nominal capacity of 1,000 mW. 50% of the plant's output is committed to the Paducah Project of the U.S. Department of Energy, 20% to KU, 15% to AmerenUE and 7.5% each to IG and AmerenCIPS.
As of December 31, 1999, the Registrant owned approximately 4,700 circuit miles of electric transmission lines. The Registrant also owned 4,800 miles of natural gas transmission and distribution mains, four underground gas storage fields and one propane-air gas plant used to supplement the available pipeline supply of natural gas during periods of abnormally high demands. Other properties of the Registrant include distribution lines, underground cable, office buildings, warehouses, garages and repair shops.
AmerenCIPS has fee title to all principal plants and other important units of property, or to the real property on which such facilities are located (subject to mortgage liens securing outstanding indebtedness of the Registrant and to permitted liens and judgment liens, as defined).
Substantially all of AmerenCIPS' property and plant is subject to the direct first lien of an Indenture of Mortgage or Deed of Trust dated October 1, 1941, as amended and supplemented.
The following table sets forth information with respect to the Registrant's generating facilities and capability at the time of the expected 2000 peak. These facilities are part of the assets due to be transferred to AEG as discussed under "General" section above. As a part of this transfer, these facilities and the real property on which they are located will be released from the above referenced mortgage lien.
Energy Gross Kilowatt Source Plant Location Installed Capability ------ ----- -------- -------------------- Coal Newton Newton, IL 1,170,000 Coffeen Coffeen, IL 950,000 Grand Tower Grand Tower, IL 202,000 Hutsonville (Units 3 & 4) Hutsonville, IL 161,000 Meredosia (Units 1, 2 & 3) Meredosia, IL 359,000 ---------- Total Coal 2,842,000 Oil Hutsonville (Diesel) Hutsonville, IL 3,000 Meredosia (Unit 4) Meredosia, IL 182,000 ---------- Total Oil 185,000
TOTAL 3,027,000 =========
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Registrant is 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. Management believes that the final disposition of these proceedings will not have a material adverse effect on its financial position, results of operations or liquidity.
For additional information on legal and administrative proceedings, see "Regulation - Environmental Issues" under Item 1 herein, "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein, and Notes 2 and 11 to the "Notes to Financial Statements" under Item 8 herein.
___________________________
Statements made in this report which are not based on historical facts, are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, financial performance and the Year 2000 Issue. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Registrant is providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in subsequent securities filings, could cause results to differ materially from management expectations as suggested by such "forward-looking" statements: the effects of regulatory actions; changes in laws and other governmental actions; the impact on the Registrant of current regulations related to the phasing-in of the opportunity for some customers to choose alternative energy suppliers in Illinois; the effects of increased competition in the future due to, among other things, deregulation of certain aspects of the Registrant's business at both the state and Federal levels; future market prices for fuel and purchased power, electricity, and natural gas, including the use of financial instruments; average rates for electricity in the Midwest; business and economic conditions; interest rates; weather conditions; fuel prices and availability; generation plant performance; the impact of current environmental regulations on utilities and generating companies and the expectation that more stringent requirements will be introduced over time, which could potentially have a negative financial effect; monetary and fiscal policies; future wages and employee benefits costs; and legal and administrative proceedings.
INFORMATION REGARDING EXECUTIVE OFFICERS REQUIRED BY ITEM 401(b) OF REGULATION S-K:
Age At Date First Elected Name 12/31/99 Present Position or Appointed ---- -------- ---------------- ------------ G. L. Rainwater 53 President, Chief Executive Officer 1/1/98 and Director 12/31/97 T. R. Voss 52 Senior Vice President 6/1/99 W. L. Baxter 38 Vice President, 4/22/99 Controller and 12/31/97 Director 4/22/99 M. J. Montana 53 Vice President 4/28/98 G. W. Moorman 56 Vice President 6/1/88 C. D. Nelson 46 Vice President 4/28/98 J. L. Simpson 43 Vice President 6/1/99 S. R. Sullivan 39 Vice President, General Counsel and Secretary 11/7/98 J. E. Birdsong 45 Treasurer 12/31/97
All officers are elected or appointed annually by the Board of Directors following the election of such Board at the annual meeting of stockholders held in April. Except for Messrs. Baxter and Sullivan, each of the above-named executive officers has been employed by the Company or its affiliates for more than five years in executive or management positions. Mr. Baxter was previously employed by PricewaterhouseCoopers LLP. Mr. Sullivan was previously employed by Anheuser Busch Companies, Inc.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
There is no market for the Registrant's Common Stock since all shares are owned by its parent, Ameren.
ITEM 6. SELECTED FINANCIAL DATA.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Central Illinois Public Service Company (AmerenCIPS or the Registrant) is a subsidiary of Ameren Corporation (Ameren), a holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA). In December 1997, Union Electric Company (AmerenUE) and CIPSCO Incorporated (CIPSCO) combined to form Ameren, with AmerenUE and CIPSCO's subsidiaries, the Registrant and CIPSCO Investment Company (CIC), becoming subsidiaries of Ameren (the Merger).
In conjunction with the Illinois Electric Service Customer Choice and Rate Relief Law of 1997 (the Law), the Registrant has received regulatory approvals to transfer its generating facilities to Ameren Energy Generating Company (AEG), a nonregulated, indirectly wholly-owned subsidiary of Ameren. The transfer of the assets and liabilities (at historical net book value of approximately $600 million) is currently scheduled to occur in May 2000. Discussion below relating to "forward-looking" statements reflects information assuming that the transfer will occur as scheduled. For additional information on the Law, its impact on the Registrant, and the generating facilities transfer, see "Electric Industry Restructuring" below and Note 2 to the Notes to Financial Statements.
RESULTS OF OPERATIONS
Earnings Earnings for 1999, 1998 and 1997, were $50 million, $76 million and $35 million, respectively. Earnings fluctuated due to many conditions, primarily: sales growth, weather variations, credits to electric customers, electric rate reductions, gas rate increases, competitive market forces, fluctuating operating costs, charges for coal contract terminations, a targeted employee separation plan, merger-related expenses, changes in interest expense, changes in income and property taxes, and an extraordinary charge.
In the fourth quarter of 1999, the Registrant recorded a nonrecurring charge to earnings in connection with coal contract terminations with two coal suppliers. The charge reduced earnings $31 million, net of income taxes (see discussion below under "Electric Operations" and Note 11 - Commitments and Contingencies under Notes to Financial Statements for further information). In 1998, the Registrant also recorded a nonrecurring charge to earnings in connection with a targeted separation plan it offered to employees in July 1998. The charge reduced earnings $4 million, net of income taxes, (see Note 4 - Targeted Separation Plan under Notes to Financial Statements for further information). In addition, the Registrant recorded an extraordinary charge to earnings in the fourth quarter of 1997 for the write-off of generation-related regulatory assets and liabilities of the Registrant's retail electric business as a result of electric industry restructuring legislation enacted in Illinois in December 1997. The write-off reduced earnings $25 million, net of income taxes (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information).
The significant items affecting revenues, expenses and earnings for the years ended December 31, 1999, 1998 and 1997 are detailed in the following pages.
Electric Operations Electric Revenues Variations from Prior Year - -------------------------------------------------------------------------------- (In Millions) 1999 1998 1997 - -------------------------------------------------------------------------------- Rate variations $(7) $(5) $ - Effect of abnormal weather (16) 13 (1) Growth and other 9 14 5 Interchange sales 88 (1) (29) - -------------------------------------------------------------------------------- $74 $21 $(25) - --------------------------------------------------------------------------------
Electric revenues for 1999 increased $74 million, compared to 1998, primarily due to an 11% increase in total kilowatthour sales. This increase was primarily driven by a 37% increase in interchange sales, due to strong marketing efforts. This increase was partially offset by a residential rate decrease (see Note 2 - Regulatory Matters under notes to Financial Statements for further information). In addition, revenues were lower due to a 1% decrease in native sales, resulting from milder weather.
Electric revenues for 1998 increased $21 million, compared to 1997. Revenues increased primarily due to higher sales to retail customers within the Registrant's service territory, as a result of warm summer weather and economic growth in the service area. Weather-sensitive residential and commercial sales increased 6% and 4%, respectively, while industrial sales grew 4%. These increases were partially offset by a 5% rate decrease to residential customers beginning in August 1998 (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information).
Electric revenues for 1997 decreased primarily due to a 19% decrease in interchange sales due to market conditions and differences in the classification of certain interchange and purchased power transactions resulting from Federal Energy Regulatory Commission (FERC) Order 888, as well as a 3% decline in industrial sales. Residential sales remained constant with prior year levels, while commercial sales increased 2% over the same period.
Fuel and Purchased Power Variations from Prior Year - -------------------------------------------------------------------------------- (In Millions) 1999 1998 1997 - -------------------------------------------------------------------------------- Fuel: Generation $17 $(25) $ 7 Price (18) (2) (8) Generation efficiencies and other (7) (6) (4) Coal contract termination payments 52 - - Purchased power 40 21 (27) - -------------------------------------------------------------------------------- $84 $(12) $(32) - --------------------------------------------------------------------------------
The $84 million increase in fuel and purchased power costs for 1999, compared to 1998, was primarily due to increased generation and purchased power, resulting from higher sales volume and coal contract termination payments discussed below, partially offset by lower fuel costs.
In the fourth quarter of 1999, the Registrant and two of its coal suppliers executed agreements to terminate their existing coal supply contracts effective December 31, 1999. Under these agreements, the Registrant made termination payments to the suppliers totaling approximately $52 million. These termination payments were recorded as a nonrecurring charge in the fourth quarter of 1999. Total pretax fuel cost savings from these termination agreements are estimated to be $183 million (or $131 million net of the termination payments) through 2010, which is the maximum period that would have remained on any of the terminated coal supply contracts. Approximately $66 million of pretax fuel cost savings is expected to be realized over the next three years. See Note 11 - Commitments and Contingencies under Notes to Financial Statements for further information.
The $12 million decrease in fuel and purchased power costs for 1998, compared to 1997, was primarily driven by lower fuel costs due to lower fuel prices and utilizing joint dispatch generation. Upon consummation of the Merger, AmerenUE and AmerenCIPS began jointly dispatching generation, therefore allowing Ameren to utilize the most cost efficient plants of both operating companies to serve customers in either service territory. The decrease in 1997 fuel and purchased power costs was driven mainly by a decrease in interchange sales and lower fuel prices.
Gas Operations Gas revenues in 1999 increased $7 million, compared to 1998, primarily due to a gas rate increase which became effective in February 1999 (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information) and higher gas costs recovered through the Registrant's purchased gas adjustment clause. These increases were partially offset by a 10% decline in retail sales, resulting primarily from milder winter weather, as well as a decrease in off-system sales of gas to others. Gas revenues in 1998 decreased $26 million compared to 1997, primarily due to a 7% decline in retail sales resulting from milder winter weather and lower gas costs recovered through the Registrant's purchase gas adjustment clause. Gas revenues in 1997 decreased $4 million primarily due to a 10% decline in retail sales resulting from mild winter weather.
Gas costs in 1999 increased $4 million compared to 1999. This increase in gas costs was primarily due to higher gas prices, partially offset by lower total sales. Gas costs in 1998 declined $28 million compared to 1997. This decrease in gas costs was due to lower sales and lower gas prices. Gas costs for 1997 remained relatively flat when compared to 1996 costs.
Other Operating Expenses Other operating expense variations in 1997 through 1999 reflected recurring factors such as growth, inflation, labor and benefit increases, in addition to a charge for the targeted separation plan (TSP), as discussed below.
In 1998, Ameren announced plans to reduce its other operating expenses, including plans to eliminate approximately 400 employee positions by mid-1999 through a hiring freeze and the TSP. During the third quarter of 1998, a nonrecurring, pretax charge of $7 million was recorded, representing the Registrant's share of costs incurred to implement the TSP. The elimination of these positions, exclusive of the nonrecurring charge, reduced the Registrant's operating expenses approximately $4 million in 1998, and approximately $7 million in 1999, and is expected to reduce the Registrant's operating expenses by approximately $6 million to $7 million each year thereafter. See Note 4 - Targeted Separation Plan under Notes to Financial Statements for further information.
Other operating expenses increased $11 million, in 1999, compared to 1998, primarily due to increased postretirement expenses resulting from changes in actuarial assumptions, increased injuries and damages expenses based on claims experience, expenses associated with electric industry deregulation in Illinois and the Year 2000 project. These increases were partially offset by a reduced workforce, coupled with the fact that 1998 expenses included the charge for the TSP. The $19 million increase in other operating expenses in 1998, compared to 1997, were primarily due to the charge for the TSP and increased information system-related costs. In 1997, other operating expenses increased $15 million, primarily due to increases in labor, various equipment purchases and rentals and information system-related costs.
Maintenance expenses increased $32 million in 1999, compared to 1998. This increase was primarily due to increased power plant maintenance. In 1998, maintenance expenses decreased $4 million from the prior year, primarily due to less scheduled power plant maintenance. The 1997 maintenance expenses increase of $14 million from the prior year can be attributed to scheduled outages at three power plants.
Depreciation and amortization expense increased $6 million in 1999, compared to 1998. This increase was primarily due to increased depreciable property. In 1998, depreciation and amortization expense decreased $8 million from the prior year due to the write-off of generation-related regulatory assets in Illinois during the fourth quarter of 1997. The 1997 depreciation and amortization expense fluctuation relates primarily to property additions.
Taxes Income tax expense from operations decreased $15 million in 1999, compared to 1998, due to lower pretax income. Income tax expense from operations increased $12 million in 1998, compared to 1997, due to higher pretax income and a higher effective tax rate. Income tax expense from operations decreased $14 million in 1997, principally due to lower pretax income and a lower effective tax rate.
Other tax expense decreased $17 million in 1999, compared to 1998, primarily due to a decrease in gross receipts taxes. This decrease is the result of the restructuring of the Illinois public utility tax whereby gross receipts taxes are no longer recorded as electric revenue and gross receipts tax expense.
Other Income and Deductions In 1999, miscellaneous, net decreased $3 million, compared to 1998, primarily due to losses on the disposal of property realized in 1998. In 1998, miscellaneous, net decreased $3 million primarily due to higher merger-related expenses incurred in the prior year. Miscellaneous, net increased $2 million between 1997 and 1996 primarily due to increased merger-related expenses.
Interest Interest expense increased $3 million in 1999, compared to 1998, due to an increase in intercompany notes payable resulting from funds borrowed from the regulated money pool (see Note 7 - Short-Term Borrowings under Notes to Financial Statements for further information), partially offset by the redemption of short-term debt. Interest expense increased $3 million in 1998, compared to 1997, due to a higher amount of debt outstanding, partially offset by a decrease in other interest.
Balance Sheet The $27 million increase in trade accounts receivable and unbilled revenue was due primarily to higher sales and revenues in November and December 1999, compared to the same 1998 period.
The changes in accounts and wages payable, taxes accrued, other accounts and notes receivable, and other current assets resulted from the timing of various payments to taxing authorities and suppliers. The $133 million increase in intercompany notes payable was due to funds borrowed from a regulated money pool (see Note 7 - Short-Term Borrowings under Notes to Financial Statements for further information).
LIQUIDITY AND CAPITAL RESOURCES
Information contained in this section could be impacted by the transfer of the Registrant's generating facilities to AEG. See discussion in "Overview" section above for more information.
Cash provided by operating activities totaled $166 million for 1999, compared to $123 million for 1998 and $81 million in 1997, respectively.
Cash flows used in investing activities totaled $95 million, $68 million and $111 million, for the years ended December 31, 1999, 1998 and 1997, respectively. Expenditures in 1999 for constructing new or improving existing facilities and purchasing rail cars were $95 million.
Capital expenditures are expected to approximate $60 million in 2000. For the five-year period 2000-2004, construction expenditures are estimated at $264 million. This estimate assumes that the transfer of the Registrant's generating facilities to AEG will occur in 2000.
Title IV of the Clean Air Act Amendments of 1990 requires the Registrant to significantly reduce total annual sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions by the year 2000. By switching to low-sulfur coal, the Registrant is meeting these requirements.
In July 1997, the United States Environmental Protection Agency (EPA) issued regulations revising the National Ambient Air Quality Standards for ozone and particulate matter. In May 1999, the U.S. Court of Appeals for the District of Columbia remanded the regulations back to the EPA for review. Litigation regarding appeals of these regulations is ongoing. New ambient standards may result in significant additional reductions in SO2 and NOx emissions from the Registrant's power plants by 2007. At this time, the Registrant is unable to predict the ultimate impact of these revised air quality standards on its future financial condition, results of operations or liquidity.
In an attempt to lower ozone levels across the eastern United States, the EPA issued the implementation of regulations in September 1998 to reduce NOx emissions from coal-fired boilers and other sources in 22 states, including Illinois (where all of the Registrant's coal-fired power plant boilers are located). The proposed regulations mandate a 75% reduction from 1990 levels by the year 2003 and require states to develop plans to reduce NOx emissions to help alleviate ozone problem areas. The NOx emissions reductions already achieved on several of the Registrant's coal-fired power plants will help reduce the costs of compliance with these regulations. However, preliminary analysis of the regulations indicate that selective catalytic reduction technology may be required for some of the Registrant's units, as well as other additional controls.
In March 2000, the U.S. Court of Appeals for the District of Columbia substantially upheld the proposed NOx regulations but remanded portions of them to the EPA for further consideration. The implementation date of the regulations is uncertain and further legal challenge is possible. Assuming an implementation date of 2003, the Registrant currently estimates that its additional capital expenditures to comply with the final NOx regulations could range from $125 million to $150 million. Associated operations and maintenance expenditures could increase $5 million to $8 million annually, beginning in 2003. The Registrant is exploring alternatives to comply with these new regulations in order to minimize, to the extent possible, its capital costs and operating expenses. The Registrant is unable to predict the outcome of the litigation, the regulation implementation date or the ultimate impact of these standards on its future financial condition, results of operations or liquidity.
In November 1998, the United States signed an agreement with numerous other countries (the Kyoto Protocol) containing certain environmental provisions, which would require decreases in greenhouse gases in an effort to address the "global warming" issue. The Kyoto Protocol has not been ratified by the United States Senate. Implementation of the Kyoto Protocol in its present form would likely result in significantly higher capital costs and operations and maintenance expenses by the Registrant. At this time, the Registrant is unable to determine the impact of these proposals on the Registrant's future financial condition, results of operations or liquidity.
Cash flows used in financing activities were $68 million for 1999. This compares to cash flows used in financing activities of $74 million in 1998 and cash flows provided by financing activities of $48 million for 1997. The Registrant's financing activities during 1999 included the issuance of $133 million of intercompany notes payable, the redemption of $60 million of long-term debt, the redemption of $47 million of short-term debt, and the payment of dividends.
The Registrant plans to continue utilizing short-term debt to support normal operations and other temporary requirements. The Registrant is authorized by the Securities and Exchange Commission (SEC) under PUHCA to have up to $125 million of short-term unsecured debt instruments outstanding at any one time. Short-term borrowings consist of bank loans (maturities generally on an overnight basis) and commercial paper (maturities generally within 10 to 45 days). At December 31, 1999, the Registrant had committed bank lines of credit aggregating $30 million, all of which was unused and available at such date, which make available interim financing at various rates of interest based on LIBOR, the bank certificate of deposit rate or other options. The lines of credit are renewable annually at various dates throughout the year. At year-end, the Registrant had no outstanding short-term borrowings.
Also, the Registrant has the ability to borrow up to approximately $950 million from Ameren or AmerenUE through a regulated money pool agreement. The regulated money pool was established to coordinate and provide for certain short-term cash and working capital requirements and is administered by Ameren Services Company, another subsidiary of Ameren. Interest is calculated at varying rates of interest depending on the composition of internal and external funds in the regulated money pool. At December 31, 1999, the Registrant had $133 million of intercompany borrowings outstanding and $520 million available through the regulated money pool. See Note 7 - Short-Term Borrowings under Notes to Financial Statements for further information.
The Registrant, in the ordinary course of business, explores opportunities to reduce its costs in order to remain competitive in the marketplace. Areas where the Registrant focuses its review include, but are not limited to, labor costs and fuel supply costs. In the labor area, the Registrant has recently reached agreements with all of the Registrant's major collective bargaining units which will permit it to manage its labor costs and practices effectively in the future (see Note 11 - Commitments and Contingencies under Notes to Financial Statements for further discussion). The Registrant also explores alternatives to effectively manage the size of its workforce. These alternatives include utilizing hiring freezes, outsourcing and offering employee separation packages. In the fuel supply area, the Registrant explores alternatives to effectively manage its overall fuel costs. These alternatives include diversifying fuel sources for use at the Registrant's power plants (e.g. utilizing low-sulfur versus high- sulfur coal), as well as restructuring or terminating existing contracts with suppliers.
Certain of these reduction alternatives could result in additional investments being made at the Registrant's power plants in order to utilize different types of coal, or could require nonrecurring payments of employee separation benefits or nonrecurring payments to restructure or terminate existing fuel contracts with a supplier. Management is unable to predict which (if any), and to what extent, these alternatives to reduce its overall cost structure will be executed. Management is unable to determine the impact of these actions on the Registrant's future financial position, results of operations or liquidity.
RATE MATTERS
See Note 2 - Regulatory Matters under Notes to Financial Statements for a discussion of rate matters.
ELECTRIC INDUSTRY RESTRUCTURING
Steps taken and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation, and encourage increased competition. At the federal level, the Energy Policy Act of 1992 reduced various restrictions on the operation and ownership of independent power producers and gave the FERC the authority to order electric utilities to provide transmission access to third parties.
In April 1996, the FERC issued Order 888 and Order 889, which are intended to promote competition in the wholesale electric market. The FERC requires transmission-owning public utilities, such as AmerenCIPS, to provide transmission access and service to others in a manner similar and comparable to that which the utilities have by virtue of ownership. Order 888 requires that a single tariff be used by the utility in providing transmission service. Order 888 also provides for the recovery of strandable costs, under certain conditions, related to the wholesale business.
Order 889 established the standards of conduct and information requirements that transmission owners must adhere to in doing business under the open access rule. Under Order 889, utilities must obtain transmission service for their own use in the same manner their customers will obtain service, thus mitigating market power through control of transmission facilities. In addition, under Order 889, utilities must separate their merchant function (buying and selling wholesale power) from their transmission and reliability functions.
The Registrant believes that Order 888 and Order 889, which relate to its wholesale business, will not have a material adverse effect on its financial condition, results of operations or liquidity.
In 1998, the Registrant joined a group of companies that support the formation of the Midwest Independent System Operator (Midwest ISO). An ISO operates, but does not own, electric transmission systems and maintains system reliability and security, while alleviating pricing issues associated with the "pancaking" of rates. The Midwest ISO would be regulated by the FERC. Thirteen transmission-owning utilities have joined the Midwest ISO as of December 31, 1999. The FERC conditionally approved the formation of the Midwest ISO in September 1998, and it is expected to be operational during the year 2001. The Illinois Commerce Commission (ICC) has authorized the Registrant to join the Midwest ISO and to transfer control of its transmission facilities to the Midwest ISO. The Midwest ISO covers 14 states, represents portions of 60,000 miles of transmission line and controls $8 billion of assets. The Registrant believes that the operation of the Midwest ISO will not have a material adverse effect on its financial condition, results of operations or liquidity.
In December 1999, the FERC issued its Order 2000 relating to Regional Transmission Organizations (RTOs) that would meet certain characteristics such as size and independence. Order 2000 calls on all transmission owners to join RTOs. In particular, all public utilities that own, operate, or control interstate transmission facilities must file with the FERC by October 15, 2000, a proposal for an RTO, or alternatively a description of efforts by the utility to join an RTO. The Registrant expects that its participation in the Midwest ISO will satisfy the requirements of Order 2000.
Certain states are considering proposals or have adopted legislation that will promote competition at the retail level. In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Law) providing for electric utility restructuring in Illinois. This legislation introduces competition into the supply of electric energy at retail in Illinois.
Major provisions of the Law include the phasing-in through 2002 of retail direct access, which allows customers to choose their electric generation suppliers. The phase-in of retail direct access began on October 1, 1999, with large commercial and industrial customers principally comprising the initial group. The customers in this group represent approximately 24% of the Registrant's total sales. As of December 31, 1999, the impact of retail direct access on the Registrant's financial condition, results of operations or liquidity was immaterial. Retail direct access will be offered to the remaining commercial and industrial customers on December 31, 2000, and to residential customers on May 1, 2002.
In addition, the Law included a 5% rate decrease for residential customers that became effective in August 1998. This rate decrease is expected to reduce electric revenues by approximately $11 million annually, based on estimated levels of sales and assuming normal weather conditions. (See Note 2 - Regulatory Matters under Notes to Financial Statements for further information.) In 1998, the Registrant eliminated its Uniform Fuel Adjustment Clause (FAC) as allowed by the Law, which benefited shareholders in 1998 and 1999 and is expected to benefit shareholders in the future (see Note 1 - Summary of Significant Accounting Policies under Notes to Financial Statements for further information). The Law contains a provision allowing for the potential recovery of a portion of strandable costs, which represent costs that would not be recoverable in a restructured environment, through a transition charge collected from customers who choose an alternate electric supplier. In addition, the Law contains a provision requiring a portion of excess earnings (as defined under the Law) for the years 1998 through 2004 to be refunded to customers.
In December 1997, after evaluating the impact of the Law, the Registrant determined that it was necessary to write-off the generation-related regulatory assets and liabilities of its Illinois retail electric business. This extraordinary charge reduced 1997 earnings $25 million, net of income taxes. The Registrant has also concluded that its remaining net generation-related assets are not impaired for financial reporting purposes and that no plant writedowns are necessary at this time. See Note 2 - Regulatory Matters under Notes to Financial Statements for further information.
In conjunction with another provision of the Law, in July 1999, the Registrant filed a notice with the ICC that it intends to transfer its generating facilities (all in Illinois) to Ameren Energy Generating Company (AEG), a nonregulated, indirectly wholly-owned subsidiary of Ameren. The formation of the new generating subsidiary, as well as the transfer of the Registrant's generating assets and liabilities (at historical net book value of approximately $600 million) and certain power sales contracts, in exchange for an intercompany note receivable, was subject to regulatory approvals from the ICC, the FERC, and the Missouri Public Service Commission, all of which have been received as of March 10, 2000. An additional PUHCA-related determination that will permit the new generating
subsidiary to operate as an Exempt Wholesale Generator is being sought from the FERC. The generating subsidiary will include most of the new combustion turbine generators being acquired by Ameren, in addition to the Registrant's facilities. The new subsidiary is scheduled to be operational in May 2000. See Note 2 - Regulatory Matters under Notes to Financial Statements for further information.
Once the transfer is completed, a power sales agreement will be in place between the new generating subsidiary and a nonregulated marketing affiliate for all generation. The marketing affiliate will have a power sales agreement with the Registrant to supply it sufficient generation to meet native load requirements over the term of the agreement.
The proposed transfer of the Registrant's generating assets and liabilities had no effect on the Registrant's financial statements as of December 31, 1999.
In summary, the potential negative consequences associated with electric industry restructuring could be significant and could include the impairment and writedown of certain assets, including generation-related plant assets, lower revenues, reduced profit margins and increased costs of capital and operations expenses. Ameren and the Registrant are actively taking steps to mitigate these potential negative consequences. Most importantly, they will continue to focus on cost control to ensure that they maintain a competitive cost structure, which includes the recent termination of high-cost coal supply contracts (see Note 11 - - Commitments and Contingencies under Notes to Financial Statements for further information). Also, the actions of Ameren and the Registrant include establishing a nonregulated generating subsidiary and expanding its generation assets, strengthening the Registrant's trading and marketing operation to maintain current customers and obtain new customers, and enhancing information systems. The Registrant believes that these actions will position Ameren and the Registrant well in the competitive Illinois marketplace. The Registrant is also actively involved in shaping the policies of the Midwest ISO to protect its shareholders' interests. At this time, the Registrant is unable to predict the ultimate impact of electric industry restructuring on the Registrant's future financial condition, results of operations or liquidity.
YEAR 2000 ISSUE
The Year 2000 Issue relates to how dates are stored and used in computer systems, applications, and embedded systems. As the century date change occurred, certain date-sensitive systems had to recognize the year as 2000 and not as 1900. This inability to recognize and properly treat the year as 2000 could have caused these systems to process critical financial and operational information incorrectly. Management implemented a Year 2000 plan covering Ameren, including AmerenCIPS, and briefed Ameren's Board of Directors about the Year 2000 Issue and how it might have affected the Registrant. Ameren encountered no significant problems associated with the Year 2000 Issue at year-end. In addressing the Year 2000 Issue, Ameren incurred internal labor costs as well as external consulting and other expenses to prepare for the new century. As of December 31, 1999, Ameren had expended approximately $8 million in external costs (consulting fees and related costs). The impact of the Year 2000 Issue on the Registrant's financial condition, results of operations or liquidity was immaterial. Ameren will continue to monitor date-sensitive systems as certain key dates occur throughout the year.
CONTINGENCIES
See Note 2 - Regulatory Matters and Note 11 - Commitments and Contingencies under Notes to Financial Statements for material issues existing at December 31, 1999.
MARKET RISK RELATED TO FINANCIAL INSTRUMENTS AND COMMODITY INSTRUMENTS
Market risk represents the risk of changes in value of a financial instrument, derivative or non-derivative, caused by fluctuations in market variables (e.g., interest rates, equity prices, commodity prices, etc.). The following discussion of Ameren's, including AmerenCIPS', 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. Ameren handles market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, Ameren also faces risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, operational, and credit risk and are not represented in the following analysis.
Interest Rate Risk The Registrant is exposed to market risk through changes in interest rates through its issuance of both long-term and short-term variable-rate debt, fixed-rate debt, commercial paper and auction market preferred stock. The Registrant manages its interest rate exposure by controlling the amount of these instruments it holds within its total capitalization portfolio and by monitoring the effects of market changes in interest rates.
If interest rates increase one percentage point in 2000 as compared to 1999, the Registrant's interest expense would increase and net income would decrease by approximately $1 million. This amount has been determined using the assumptions that the Registrant's outstanding variable-rate debt, commercial paper and auction market preferred stock as of December 31, 1999, continued to be outstanding throughout 2000, and that the average interest rates for these instruments increased one percentage point over 1999. The model does not consider the effects of the reduced level of 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 its 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 the Registrant's financial structure.
Commodity Price Risk The Registrant is exposed to changes in market prices for natural gas, fuel and electricity. With regard to its natural gas utility business, the Registrant's exposure to changing market prices is in large part mitigated by the fact that the Registrant has a Purchased Gas Adjustment Clause (PGA) in place. The PGA allows the Registrant to pass on to its customers its prudently incurred costs of natural gas.
Since the Registrant does not have a provision similar to the PGA for its electric operations, the Registrant has entered into several long-term contracts with various suppliers to purchase coal to manage its exposure to fuel prices. (See Note 11 - Commitments and Contingencies under Notes to Financial Statements for further information). With regard to the Registrant's exposure to commodity price risk for purchased power and excess electricity sales, Ameren has established a subsidiary, AmerenEnergy, Inc. (AmerenEnergy), whose primary responsibility includes managing market risks associated with the changing market prices for electricity purchased and sold on behalf of the Registrant.
AmerenEnergy utilizes several techniques to mitigate its market risk for electricity, 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 AmerenEnergy is allowed to utilize (which include forward contracts, futures contracts, and option contracts) are dictated by a risk management policy, which has been reviewed with the Auditing Committee of Ameren's Board of Directors. Compliance with the risk management policy is the responsibility of a risk management steering committee, consisting of Ameren officers and an independent risk management officer at AmerenEnergy.
As of December 31, 1999, the fair value of derivative financial instruments exposed to commodity price risk was immaterial. AmerenEnergy's primary use of derivatives has been limited to transactions that are either risk-neutral or that reduce price risk exposure of the Registrant.
ACCOUNTING MATTERS
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities and requires recognition of all derivatives as either assets or liabilities on the balance sheet measured at fair value. The intended use of the derivatives and their designation as either a fair value hedge, a cash flow hedge, or a foreign currency hedge will determine when the gains or losses on the derivatives are to be reported in earnings and when they are to be reported as a component of other comprehensive income. In June 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133," which delayed the effective date of SFAS 133 to all fiscal quarters of all fiscal years, beginning after June 15, 2000. Earlier application is still encouraged. The Registrant expects to adopt SFAS 133 in the first quarter of 2001.
The Registrant is currently evaluating the impact of SFAS 133 on its financial position and results of operations upon adoption. The Registrant's evaluation includes reviewing existing derivative instruments to determine whether they fall within the scope of SFAS 133. At this time, management believes that adoption of SFAS 133 will not have
a material impact on the Registrant's financial position or results of operations upon adoption based on the derivative instruments which existed as of December 31, 1999. However, changing market conditions, the volume of future transactions which may fall within the scope of SFAS 133, and potential amendments to SFAS 133 could change management's current assessment. As a result, SFAS 133 could increase the volatility of the Registrant's future earnings and could be material to the Registrant's financial position and results of operations upon adoption.
EFFECTS OF INFLATION AND CHANGING PRICES
The Registrant's rates for retail electric and gas utility service are generally regulated by the ICC. Non-retail electric rates are regulated by the FERC.
The current replacement cost of the Registrant's utility plant substantially exceeds its recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical costs through depreciation might not be adequate to replace plants in future years. Regulatory practice has been modified for the Registrant's generation portion of its business (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). In addition, the impact on common stockholders is mitigated to the extent depreciable property is financed with debt that is repaid with dollars of less purchasing power.
The cost of fuel for electric generation, which was previously reflected in billings to customers through a Uniform Fuel Adjustment Clause, has been added to base rates as provided for in the Law (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). Changes in gas costs are generally reflected in billings to customers through a Purchased Gas Adjustment Clause.
Inflation continues to be a factor affecting operations, earnings, stockholders' equity and financial performance.
SAFE HARBOR STATEMENT
Statements made in this report which are not based on historical facts, are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, financial performance and the Year 2000 Issue. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Registrant is providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in subsequent securities filings, could cause results to differ materially from management expectations as suggested by such "forward-looking" statements: the effects of regulatory actions; changes in laws and other governmental actions; the impact on the Registrant of current regulations related to the phasing-in of the opportunity for some customers to choose alternative energy suppliers in Illinois; the effects of increased competition in the future due to, among other things, deregulation of certain aspects of the Registrant's business at both the state and Federal levels; future market prices for fuel and purchased power, electricity, and natural gas, including the use of financial instruments; average rates for electricity in the Midwest; business and economic conditions; interest rates; weather conditions; fuel prices and availability; generation plant performance; the impact of current environmental regulations on utilities and generating companies and the expectation that more stringent requirements will be introduced over time, which could potentially have a negative financial effect; monetary and fiscal policies; future wages and employee benefits costs; and legal and administrative proceedings.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information required to be reported by this item is included under "Market Risk Related to Financial Instruments and Commodity Instruments" in "Management's Discussion and Analysis of Financial Conditions and Results of Operations" under Item 7 herein.
REPORT OF INDEPENDENT ACCOUNTANTS ---------------------------------
To the Board of Directors and Shareholders of Central Illinois Public Service Company
In our opinion, the financial statements listed in the index appearing under Item 14(a)(1) on Page 37 present fairly, in all material respects, the financial position of Central Illinois Public Service Company at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. 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, 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 the opinion expressed above. The financial statements of Central Illinois Public Service Company for the year ended December 31, 1997 were audited by other independent accountants whose report dated January 31, 1997 expressed an unqualified opinion on those statements.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP St. Louis, Missouri February 2, 2000
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY BALANCE SHEET (Thousands of Dollars, Except Shares)
See Notes to Financial Statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY STATEMENT OF INCOME (Thousands of Dollars)
See Notes to Financial Statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY STATEMENT OF CASH FLOWS (Thousands of Dollars)
SUPPLEMENTAL DISCLOSURE OF NONCASH TRANSACTION: An extraordinary charge to earnings was recorded in the fourth quarter of 1997 for the write-off of generation-related regulatory assets and liabilities of the Registrant's retail electric business as a result of electric industry restructuring legislation enacted in Illinois in December 1997. The write-off reduced earnings $25 million, net of income taxes. See Note 2 - Regulatory Matters under Notes to Financial Statements for further information.
See Notes to Financial Statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY ---------------------------------------
STATEMENT OF RETAINED EARNINGS - ------------------------------ (Thousands of Dollars)
- ------------------------------------------------------------------------------- Year Ended December 31, 1999 1998 1997 - ------------------------------------------------------------------------------- Balance at Beginning of Period $455,337 $451,477 $459,942 - ------------------------------------------------------------------------------- Add: Net income 53,980 80,147 38,620 - ------------------------------------------------------------------------------- 509,317 531,624 498,562 - ------------------------------------------------------------------------------- Deduct: Common stock dividends 90,342 72,285 43,300 Preferred stock dividends 4,630 4,002 3,785 - ------------------------------------------------------------------------------- 94,972 76,287 47,085 - ------------------------------------------------------------------------------- Balance at End of Period $414,345 $455,337 $451,477 - -------------------------------------------------------------------------------
SELECTED QUARTERLY INFORMATION (Unaudited) - ------------------------------- (Thousands of Dollars)
- -------------------------------------------------------------------------------- Operating Operating Net Net Income Revenues Income Income (Loss) After Quarter Ended (Loss) (Loss) Preferred Stock Dividends - -------------------------------------------------------------------------------- March 31, 1999 207,772 24,709 14,315 13,347 March 31, 1998 199,515 21,732 12,118 11,134 June 30, 1999 221,929 29,981 20,680 19,763 June 30, 1998 214,829 28,429 19,349 18,468 September 30, 1999 279,327 53,845 43,283 42,326 September 30, 1998 (a) 246,675 50,623 39,672 38,736 December 31, 1999 (b) 219,094 (13,820) (24,298) (25,289) December 31, 1998 186,405 19,260 9,008 8,064 - --------------------------------------------------------------------------------
(a) The third quarter of 1998 included a nonrecurring charge related to the targeted separation plan that reduced net income $4 million. (See Note 4 - Targeted Separation Plan under Notes to Financial Statements for further information.) (b) The fourth quarter of 1999 included a charge for coal supply contract terminations that reduced net income $31 million. (See Note 11 - Commitments and Contingencies under Notes to Financial Statements for further information).
Other changes in quarterly earnings are due to the effect of weather on sales and other factors that are characteristic of public utility operations.
See Notes to Financial Statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 1999
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation
Central Illinois Public Service Company (AmerenCIPS or the Registrant) is a subsidiary of Ameren Corporation (Ameren), which is the parent company of two utility operating companies, the Registrant and Union Electric Company (AmerenUE). Ameren is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA) formed in December 1997 upon the merger of CIPSCO Incorporated (the Registrant's former parent) and AmerenUE (the Merger). Both Ameren and its subsidiaries are subject to the regulatory provisions of the PUHCA. The operating companies are engaged principally in the generation, transmission, distribution and sale of electric energy and the purchase, distribution, transportation and sale of natural gas in the states of Illinois and Missouri. Contracts among the companies--dealing with jointly-operated generating facilities, interconnecting transmission lines, and the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) or the Securities and Exchange Commission (SEC). Administrative support services are provided to the Registrant by a separate Ameren subsidiary, Ameren Services Company. The Registrant serves 400,000 electric and 175,000 gas customers in a 20,000 square-mile region of central and southern Illinois.
In conjunction with the Illinois Electric Service Customer Choice and Rate Relief Law of 1997 (the Law), the Registrant has received regulatory approvals to transfer its generating facilities to Ameren Energy Generating Company (AEG), a nonregulated, indirectly wholly-owned subsidiary of Ameren. The transfer of the assets and liabilities (at historical net book value of approximately $600 million) is currently scheduled to occur in May 2000. Discussion below relating to "forward-looking" statements reflects information assuming that the transfer will occur as scheduled. For additional information on the law, its impact on the Registrant, and the generating facilities transfer, see Note 2 - Regulatory Matters.
The Registrant also has a 20% interest in Electric Energy, Inc. (EEI), which is accounted for under the equity method of accounting. EEI owns and operates an electric generating and transmission facility in Illinois that supplies electric power primarily to a uranium enrichment plant located in Paducah, Kentucky.
Regulation In addition to the SEC, the Registrant is regulated by the Illinois Commerce Commission (ICC) and the FERC. The accounting policies of the Registrant conform to U.S. generally accepted accounting principles (GAAP). See Note 2 - Regulatory Matters for further information.
Property and Plant The cost of additions to, and betterments of, units of property and plant is capitalized. Cost includes labor, material, applicable taxes and overheads. An allowance for funds used during construction is also added for the Registrant's regulated assets, and interest incurred during construction is added for nonregulated assets. Maintenance expenditures and the renewal of items not considered units of property are charged to income, as incurred. When units of depreciable property are retired, the original cost and removal cost, less salvage value, are charged to accumulated depreciation.
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 in 1999, 1998, and 1997 was approximately 3% of the average depreciable cost.
Fuel and Gas Costs The cost of fuel for electric generation is reflected in base rates with no provision for changes to be made through a fuel adjustment clause. (See Note 2 - Regulatory Matters for further information.) In 1997, changes in fuel costs were generally reflected in billings to electric customers through a fuel adjustment clause. Changes in gas costs are generally reflected in billings to gas customers through a purchased gas adjustment clause.
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.
Income Taxes The Registrant is included in the consolidated federal income tax return filed by Ameren. Income taxes are allocated to the individual companies based on their respective taxable income or loss. 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.
Allowance for Funds Used During Construction Allowance for funds used during construction (AFC) is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds (preferred and common stockholders' equity) applicable to the Registrant's regulated construction program are capitalized as a cost of construction. AFC 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 AFC, as well as other construction costs, occurs when completed projects are placed in service and reflected in customer rates. The AFC rates used were 5% during 1999, 6% during 1998 and 8% during 1997.
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 The Registrant accrues an estimate of electric and gas revenues for service rendered, but unbilled, at the end of each accounting period.
Energy Contracts The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) Issue 98-10, "Accounting for Energy Trading and Risk Management Activities" became effective on January 1, 1999. EITF 98-10 provides guidance on the accounting for energy contracts entered into for the purchase or sale of electricity, natural gas, capacity and transportation. The EITF reached a consensus in EITF 98-10 that sales and purchase activities being performed need to be classified as either trading or nontrading. Furthermore, transactions that are determined to be trading activities would be recognized on the balance sheet measured at fair value, with gains and losses included in earnings. AmerenEnergy, Inc., an energy marketing subsidiary of Ameren, enters into contracts for the sale and purchase of energy on behalf of the Registrant and AmerenUE. Currently, virtually all of AmerenEnergy's transactions are considered nontrading activities and are accounted for using the accrual or settlement method, which represents industry practice. EITF 98-10 did not have a material impact on the Registrant's financial position or results of operations upon adoption.
Software Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use" became effective on January 1, 1999. SOP 98-1 provides guidance on accounting for the costs of computer software developed or obtained for internal use. Under SOP 98-1, certain costs may be capitalized and amortized over some future period. SOP 98-1 did not have a material impact on the Registrant's financial position or results of operations upon adoption.
Evaluation of Assets for Impairment Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" prescribes general standards for the recognition and measurement of impairment losses. The Registrant determines if long-lived assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount. An impairment loss is recognized if the undiscounted expected future cash flows are less than the carrying amount of the asset. SFAS 121 also requires that regulatory assets which are no longer probable of recovery through future revenues be charged to earnings (see Note 2 - Regulatory Matters for further information). As of December 31, 1999, no impairment was identified.
Use of Estimates 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 and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from those estimates.
Reclassifications Certain reclassifications have been made to prior-years' financial statements to conform with 1999 reporting.
NOTE 2 - Regulatory Matters
Illinois Electric Restructuring Certain states are considering proposals or have adopted legislation that will promote competition at the retail level. In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Law) providing for electric utility restructuring in Illinois. This legislation introduces competition into the supply of electric energy at retail in Illinois.
Under the Law, retail direct access, which allows customers to choose their electric generation suppliers, will be phased in over several years. Access for commercial and industrial customers will occur over a period from October 1999 to December 2000, and access for residential customers will occur after May 1, 2002.
As a requirement of the Law, in March 1999, the Registrant filed delivery service tariffs with the ICC. These tariffs would be used by electric customers who choose to purchase their power from alternate suppliers. On August 25, 1999, the ICC issued an order approving the delivery services tariffs, with an allowed rate of return on equity of 10.45%. The Registrant and AmerenUE filed a joint petition for rehearing of that order requesting the ICC to alter its conclusions on a number of issues. On October 13, 1999, the ICC granted a rehearing on certain issues. An order on this reopened proceeding was issued in 2000 resolving all outstanding issues.
The Law included a 5% residential electric rate decrease for the Registrant's electric customers, effective August 1, 1998. This rate decrease reduced electric revenues by approximately $7 million in 1999. The Registrant may be subject to additional 5% residential electric rate decreases in each of 2000 and 2002, to the extent its rates exceed the Midwest utility average at that time. The Registrant's rates are currently below the Midwest utility average.
As a result of the Law, the Registrant filed a proposal with the ICC to eliminate the electric fuel adjustment clause for Illinois retail customers, thereby including historical levels of fuel costs in base rates. The ICC approved the Registrant's filing in early 1998.
The Law also contains a provision requiring that one-half of excess earnings from the Illinois jurisdiction for the years 1998 through 2004 to be refunded to the Registrant's 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 an Index, as defined in the 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 30-year U.S. Treasury bonds, plus prescribed percentages ranging from 4% to 7%. Filings must be made with the ICC on, or before, March 31 of each year 2000 through 2005.
In conjunction with another provision of the Law, in July 1999, the Registrant filed a notice with the ICC that it intends to transfer its generating facilities (all in Illinois) to Ameren Energy Generating Company (AEG), a nonregulated, indirectly wholly-owned subsidiary of Ameren. The formation of the new generating subsidiary, as well as the transfer of the Registrant's generating assets and liabilities (at historical net book value of approximately $600 million) and certain power sales contracts in exchange for an intercompany note receivable, was subject to regulatory approvals from the ICC, the FERC, and the Missouri Public Service Commission, all of which have been received as of March 10, 2000. An additional PUHCA-related determination that will permit the new generating subsidiary to operate as an Exempt Wholesale Generator is being sought from the FERC. The generating subsidiary will include most of the new combustion turbine generators being acquired by Ameren in addition to the Registrant's facilities. The new generating subsidiary is scheduled to be operational in May 2000. The proposed transfer of the Registrant's generating assets and liabilities had no effect on the Registrant's financial statements as of December 31, 1999.
Once the transfer is completed, a power sales agreement will be in place between the new generating subsidiary and a nonregulated marketing affiliate for all generation. The marketing affiliate will have a power sales agreement with the Registrant to supply it sufficient generation to meet native load requirements over the term of the agreement.
Other provisions of the Law include (1) potential recovery of a portion of strandable costs, which represent costs which would not be recoverable in a restructured environment, through a transition charge collected from customers who choose another electric supplier; (2) a mechanism to securitize certain future revenues; and (3) a provision relieving the Registrant of the requirement to file electric rate cases or alternative regulatory plans, following the consummation of the Merger to reflect the effects of net merger savings.
The Registrant's accounting policies and financial statements conform to GAAP applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Such effects concern mainly the time at which various items enter into the determination of net income in order to follow the principle of matching costs and revenues. For example, SFAS 71 allows the Registrant to record certain assets and liabilities (regulatory assets and regulatory liabilities) that are expected to be recovered or settled in future rates and would not be recorded under GAAP for nonregulated entities. In addition, reporting under SFAS 71 allows companies whose service obligations and prices are regulated to maintain assets on their balance sheets representing costs they reasonably expect to recover from customers, through inclusion of such costs in future rates. SFAS 101, "Accounting for the Discontinuance of Application of FASB Statement No. 71," specifies how an enterprise that ceases to meet the criteria for application of SFAS 71 for all or part of its operations should report that event in its financial statements. In general, SFAS 101 requires that the enterprise report the discontinuance of SFAS 71 by eliminating from its balance sheet all regulatory assets and liabilities related to the applicable portion of the business that no longer meets SFAS 71 criteria. The EITF has concluded that application of SFAS 71 accounting should be discontinued once sufficiently detailed deregulation legislation is issued for a separable portion of a business for which a plan of deregulation has been established. However, the EITF further concluded that regulatory assets associated with the deregulated portion of the business, which will be recovered through tariffs charged to customers of a regulated portion of the business, should be associated with the regulated portion of the business from which future cash recovery is expected (not the portion of the business from which the costs originated). Those assets can therefore continue to be carried on the regulated entity's balance sheet to the extent such assets are recoverable. In addition, SFAS 121 establishes accounting standards for the impairment of long-lived assets.
Due to the enactment of the Law, prices for the retail supply of electric generation are expected to transition from cost-based, regulated rates to rates determined in large part by competitive market forces in the state of Illinois. As a result, the Registrant discontinued application of SFAS 71 for the retail portion of its generating business (i.e., the portion of the Registrant's business related to the supply of electric energy) in the fourth quarter of 1997. The Registrant evaluated the impact of the Law on the future recoverability of its regulatory assets and liabilities related to the generation portion of its business and determined that it was not probable that such assets and liabilities would be recovered through cash flows from the regulated portion of its business. Accordingly, the Registrant's generation-related regulatory assets and liabilities of its retail electric business were written off in the fourth quarter of 1997, resulting in an extraordinary charge to earnings of $25 million, net of income taxes. These regulatory assets and liabilities included previously incurred costs originally expected to be collected/refunded in future revenues, such as coal contract restructuring costs, costs associated with an abandoned scrubber at a generating plant, and income tax-related regulatory assets and liabilities. In addition, the Registrant has evaluated whether the recoverability of the costs associated with its remaining net generation-related assets has been impaired as defined under SFAS 121. The Registrant has concluded that impairment, as defined under SFAS 121, does not exist and that no plant writedowns are necessary at this time. At December 31, 1999, the Registrant's net investment in generation facilities related to its retail jurisdiction approximated $647 million and was included in electric plant in-service on the Registrant's balance sheet.
In August 1999, the Registrant filed a transmission system rate case with the FERC. This filing was primarily designed to implement, rates, terms and conditions for transmission service for those retail customers who choose other suppliers as allowed under the Law. On October 14, 1999, the FERC issued an order suspending the proposed rates until March 25, 2000. In January 2000, a settlement in principle was reached with the FERC trial staff and other interested parties. The settlement establishes the rates for transmission service that are to go into effect in the first quarter of 2000. The settlement is subject to approval by the FERC. The Registrant expects that the FERC will approve the settlement in 2000.
The provisions of the Law could also result in lower revenues, reduced profit margins and increased costs of capital and operations expense. At this time, the Registrant is unable to determine the impact of the Law on its future financial condition, results of operations or liquidity.
Gas In February 1999, the ICC approved an $8 million annual rate increase for natural gas service. The increase became effective in February 1999.
Midwest ISO In 1998, the Registrant joined a group of companies that support the formation of the Midwest Independent System Operator (Midwest ISO). An ISO operates, but does not own, electric transmission systems and maintains system reliability and security while alleviating pricing issues associated with the "pancaking" of rates. The Midwest ISO would be regulated by FERC. Thirteen transmission-owning utilities have joined the Midwest ISO, as of December 31, 1999. The FERC conditionally approved the formation of the Midwest ISO in September 1998, and it is expected to be operational during the year 2001. The ICC has authorized the Registrant to join the Midwest ISO and to transfer control of its transmission facilities to the Midwest ISO. The Midwest ISO covers 14 states, represents portions of 60,000 miles of transmission line and controls $8 billion in assets. The Registrant believes that the operation of the Midwest ISO will not have a material adverse effect on its financial condition, results of operations or liquidity.
In December 1999, the FERC issued its Order 2000 relating to Regional Transmission Organizations (RTOs) that would meet certain characteristics such as size and independence. Order 2000 calls on all transmission owners to join RTOs. In particular, all public utilities that own, operate, or control interstate transmission facilities must file with the FERC by October 15, 2000, a proposal for an RTO, or alternatively a description of efforts by the utility to join an RTO. The Registrant expects that its participation in the Midwest ISO will satisfy the requirements of Order 2000.
Regulatory Assets and Liabilities In accordance with SFAS 71, the Registrant has deferred certain costs pursuant to actions of its regulators, and is currently recovering such costs in electric rates charged to customers.
At December 31, the Registrant had recorded the following regulatory assets and regulatory liability: - ------------------------------------------------------------------------- (In Millions) 1999 1998 - ------------------------------------------------------------------------- Regulatory Assets: Income taxes $22 $25 Unamortized loss on reacquired debt 7 8 Other 13 15 - ------------------------------------------------------------------------- Regulatory Assets $42 $48 - ------------------------------------------------------------------------- Regulatory Liability: Income taxes $34 $40 - ------------------------------------------------------------------------- Regulatory Liability $34 $40 - -------------------------------------------------------------------------
Income Taxes: See Note 9 - Income Taxes. Unamortized Loss on Reacquired Debt: Represents losses related to refunded 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.
The Registrant continually assesses the recoverability of its 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.
NOTE 3 - Related Party Transactions
The Registrant has transactions in the normal course of business with other Ameren subsidiaries. These transactions are primarily comprised of power purchases and sales and services received or rendered. Intercompany receivables included in other accounts and notes receivable were approximately $12 million and $2 million, respectively, as of December 31, 1999 and 1998. Intercompany payables included in accounts and wages payable totaled approximately $35 million and $12 million, respectively, as of December 31, 1999 and 1998.
In addition, the Registrant has the ability to borrow funds from Ameren or AmerenUE or invest funds through a regulated money pool agreement. At December 31, 1999, the Registrant had outstanding intercompany borrowings of $133 million through the regulated money pool. See Note 7 - Short-Term Borrowings for further information.
NOTE 4 - Targeted Separation Plan
In July 1998, Ameren offered separation packages to employees whose positions were eliminated through a targeted separation plan (TSP). During the third quarter of 1998, a nonrecurring, pretax charge of $7 million was recorded, which reduced earnings $4 million, representing the Registrant's share of costs incurred to implement the TSP.
NOTE 5 - Concentration of Risk
Market Risk The Registrant engages in price risk management activities related to electricity and fuel. In addition to buying and selling these commodities, the Registrant uses derivative financial instruments to manage market risks and reduce exposure resulting from fluctuations in interest rates and the prices of electricity and fuel. Derivative instruments used include futures, forward contracts and options. The use of these types of contracts allows the Registrant to manage and hedge its contractual commitments and reduce exposure related to the volatility of commodity market prices.
Credit Risk Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. New York Mercantile Exchange (NYMEX) traded futures contracts are guaranteed by NYMEX and have nominal credit risk. On all other transactions, the Registrant is exposed to credit risk in the event of nonperformance by the counterparties in the transaction.
The Registrant's financial instruments subject to credit risk consist primarily of trade accounts receivable and forward contracts. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups comprising the Registrant's customer base. The Registrant's revenues are primarily derived from sales of electricity and natural gas to customers in Illinois. For each counterparty in forward contracts, the Registrant analyzes the counterparty's financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis through a credit risk management program.
NOTE 6 - Preferred Stock
At December 31, 1999 and 1998, AmerenCIPS had 4.6 million shares of authorized preferred stock. There were 2 million shares of cumulative preferred and 2.6 million shares of preferred without par value (aggregate stated value not to exceed $65 million) authorized.
Outstanding preferred stock is entitled to cumulative dividends and is redeemable at the prices shown in the following table: - --------------------------------------------------------------------------------
- -------------------------------------------------------------------------------- Preferred Stock Not Subject to Mandatory Redemption: ( Dollars in Millions) - -------------------------------------------------------------------------------- Redemption Price December 31, (per share) 1999 1998 Par value $100 Series-- 4.00% Series - 150,000 shares $101.00 $15 $15 4.25% Series - 50,000 shares 102.00 5 5 4.90% Series - 75,000 shares 102.00 8 8 4.92% Series - 50,000 shares 103.50 5 5 5.16% Series - 50,000 shares 102.00 5 5 1993 Auction - 300,000 shares 100.00 - note(a) 30 30 6.625% Series - 125,000 shares 100.00 12 12 - -------------------------------------------------------------------------------- TOTAL PREFERRED STOCK OUTSTANDING NOT SUBJECT TO MANDATORY REDEMPTION $80 $80 - --------------------------------------------------------------------------------
(a) Dividend rates, and periods during which such rates apply, vary depending on the Registrant's selection of certain defined dividend period lengths. The average dividend rate during 1999 was 3.89%.
- --------------------------------------------------------------------------------
NOTE 7 - Short-Term Borrowings
Short-term borrowings of the Registrant consist of bank loans (maturities generally on an overnight basis) and commercial paper (maturities generally within 10-45 days). No short-term borrowings were outstanding at December 31, 1999. At December 31, 1998, short-term borrowings of $47 million were outstanding with weighted average interest rates of 4.9%.
At December 31, 1999, the Registrant had committed bank lines of credit aggregating $30 million (all of which was unused and available at such date) which make available interim financing at various rates of interest based on LIBOR, the bank certificate of deposit rate, or other options. These lines of credit are renewable annually at various dates throughout the year.
Also, the Registrant has the ability to borrow up to approximately $950 million from Ameren or AmerenUE through a regulated money pool agreement. The regulated money pool was established to coordinate and provide for certain short-term cash and working capital requirements and is administered by Ameren Services Company. Interest is calculated at varying rates of interest depending on the composition of internal and external funds in the regulated money pool. At December 31, 1999, the Registrant had $133 million of intercompany borrowings outstanding and $520 million available through the regulated money pool.
NOTE 8 - Long-Term Debt
Long-term debt outstanding at December 31, was: - ------------------------------------------------------------------------------ (In Millions) 1999 1998 - ------------------------------------------------------------------------------ First Mortgage Bonds - note (a) - ------------------------------------------------------------------------------ 7 1/8% Series W paid in 1999 $ - 50 6.00% Series Z due 2000 25 25 6.73% Series 1997-2 due 2001 20 20 6 3/4% Series Y due 2002 23 23 6 3/8% Series Z due 2003 40 40 6.49% Series 1995-1 due 2005 20 20 7.05% Series 1997-2 due 2006 20 20 7 1/2% Series X due 2007 50 50 7.61% Series 1997-2 due 2017 40 40 6.125% Series due 2028 60 60 Other 5.375% - 6.99% due 2000 through 2008 50 60 - ------------------------------------------------------------------------------ 348 408 - ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ Pollution Control Loan Obligations - ------------------------------------------------------------------------------ 1990 Series B 7.60% due 2013 32 32 1990 Series A 7.60% due 2014 20 20 1993 Series C-1 due 2026 - note (b) 35 35 1993 Series C-2 5.70% due 2026 25 25 1993 Series A 6 3/8% due 2028 35 35 Other 5.40% - 5.90% due 2028 35 35 - ------------------------------------------------------------------------------ 182 182 - ------------------------------------------------------------------------------ Unamortized Discount and Premium on Debt (1) (2) - ------------------------------------------------------------------------------ Maturities Due Within One Year (35) (60) - ------------------------------------------------------------------------------ Total Long-Term Debt $494 $528 - ------------------------------------------------------------------------------ (a) At December 31, 1999, substantially all of the property and plant was mortgaged under, and subject to liens of, the respective indentures pursuant to which the bonds were issued. (b) The interest rate for the year 1999 was 3.34%. Since August 15, 1998, the actual interest rates vary since the bonds are currently in the weekly interest rate mode. Interest rate modes can be changed by the Registrant at the end of any interest rate mode period.
Maturities of long-term debt through 2004 are as follows: - ------------------------------------------------------------------------ (In Millions) Principal Amount - ------------------------------------------------------------------------ 2000 $35 2001 30 2002 33 2003 45 2004 - - ------------------------------------------------------------------------
NOTE 9 - Income Taxes
Total income tax expense for 1999 resulted in an effective tax rate of 36% on earnings before income taxes (36% in 1998 and 35% in 1997).
Principal reasons such rates differ from the statutory federal rate: - -------------------------------------------------------------------------------- 1999 1998 1997 - -------------------------------------------------------------------------------- Statutory federal income 35% 35% 35% tax rate Increases (decreases) from: Depreciation differences - (3) - Amortization of investment tax credit (3) (2) (3) State income tax 5 5 5 Other (1) 1 (2) - -------------------------------------------------------------------------------- Effective income tax rate 36% 36% 35% - --------------------------------------------------------------------------------
Income tax expense components: - -------------------------------------------------------------------------------- (In Millions) 1999 1998 1997 - -------------------------------------------------------------------------------- Taxes currently payable (principally federal): Included in operating expenses $52 $60 $39 - -------------------------------------------------------------------------------- $52 $60 $39 - --------------------------------------------------------------------------------
Deferred taxes (principally federal): Included in operating expenses-- Depreciation differences $ (7) $(10) $(4) Other (12) (1) 2 - -------------------------------------------------------------------------------- $(19) $(11) $(2) - --------------------------------------------------------------------------------
Deferred investment tax credits, Amortization Included in operating expenses $ (2) $ (3) $ (3) - -------------------------------------------------------------------------------- Total income tax expense $ 31 $46 $34 - --------------------------------------------------------------------------------
In accordance with SFAS 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.
The Registrant adjusts its 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.
Temporary differences gave rise to the following deferred tax assets and deferred tax liabilities at December 31: - -------------------------------------------------------------------------------- (In Millions) 1999 1998 - -------------------------------------------------------------------------------- Accumulated Deferred Income Taxes: Accelerated depreciation $216 $228 Capitalized taxes and expenses 78 87 Regulatory liabilities, net (29) (32) Prepayments (15) (27) Deferred benefit costs (11) - - -------------------------------------------------------------------------------- Total net accumulated deferred income tax liabilities $239 $256 - --------------------------------------------------------------------------------
NOTE 10 - Retirement Benefits
On January 1, 1999, the AmerenUE and the AmerenCIPS defined-benefit pension plans combined to form the Ameren Retirement Plan. The Ameren plan covers qualified employees of the Registrant. Benefits are based on the employees' years of service and compensation. The Ameren plan is funded in compliance with income tax regulations and federal funding requirements. The Registrant, along with other subsidiaries of Ameren, is a participant in the Ameren plan and is responsible for its proportional share of the costs and the assets or liabilities. The Registrant's share of the pension costs in 1999 was $6 million, of which approximately 20% was charged to construction accounts. The AmerenCIPS pension plan information for 1998 and 1997 is presented separately.
Pension costs for the years 1998 and 1997 were $9 million and $5 million, respectively, of which approximately 19% in 1998 and 15% in 1997 was charged to construction accounts.
In 1998, the Registrant changed its measurement date for valuation of plan assets and liabilities to December 31.
Funded Status of Pension Plan: - ------------------------------------------------------------------------ (In Millions) 1998 - ------------------------------------------------------------------------ Change in benefit obligation Net benefit obligation at beginning of year $249 Service cost 8 Interest cost 17 Amendments 5 Actuarial loss 8 Special termination benefit charge 5 Benefits paid (31) - ------------------------------------------------------------------------ Net benefit obligation at end of year 261
Change in plan assets * Fair value of plan assets at beginning of year 319 Actual return on plan assets 38 Employer contributions 5 Benefits paid (31) - ------------------------------------------------------------------------ Fair value of plan assets at end of year 331
Funded status - excess (70) Unrecognized net actuarial gain 73 Unrecognized prior service cost (13) Unrecognized net transition asset 2 - ------------------------------------------------------------------------ Prepaid pension cost at December 31 $ (8) - ------------------------------------------------------------------------ * Plan assets consist principally of common and preferred stocks, bonds, money market instruments and real estate.
Components of Net Periodic Benefit Cost: - ------------------------------------------------------------------------ (In Millions) 1998 1997 - ------------------------------------------------------------------------ Service cost $ 8 $ 7 Interest cost 17 16 Expected return on plan assets (22) (19) Amortization of prior service cost 1 1 Special termination benefit charge 5 - - ------------------------------------------------------------------------ Net periodic benefit cost $ 9 $ 5 - ------------------------------------------------------------------------
Weighted-average Assumptions for Actuarial Present Value of Projected Benefit Obligations: - ------------------------------------------------------ - ------------------------------------------------------ Discount rate at measurement date 6.75% Expected return on plan assets 8.5% Increase in future compensation 4% - ------------------------------------------------------
In addition to providing pension benefits, the Registrant provides certain health care and life insurance benefits for retired employees. The Registrant's postretirement benefit plans cover substantially all employees of AmerenCIPS as well as certain employees of Ameren Services Company. The Registrant accrues the expected postretirement
benefit costs during employees' years of service. The following is information related to the Registrant's postretirement benefit plans as of December 31.
The Registrant's funding policy is to fund two Voluntary Employee Beneficiary Association trusts (VEBAs) and the 401(h) account established within the Registrant's retirement income trust with the lesser of the net periodic cost or the amount deductible for federal income tax purposes. In 1998, the Registrant changed its measurement date for valuation of plan assets and liabilities to December 31. Postretirement benefit costs were $3 million for 1999, $6 million for 1998 and $12 million for 1997, of which approximately 10% was charged to construction accounts in 1999, 20% in 1998 and 17% in 1997. AmerenCIPS' transition obligation at December 31, 1999 is being amortized over the next 13 years.
The ICC allows the recovery of postretirement benefit costs in rates to the extent that such costs are funded.
Funded Status of Postretirement Benefit Plans: - ----------------------------------------------------------------------------- (In Millions) 1999 1998 - ----------------------------------------------------------------------------- Change in benefit obligation Net benefit obligation at beginning of year $152 $140 Service cost 3 3 Interest cost 9 10 Actuarial (gain)/loss (22) 4 Benefits paid (4) (5) - ----------------------------------------------------------------------------- Net benefit obligation at end of year 138 152
Change in plan assets * Fair value of plan assets at beginning of year 128 115 Actual return on plan assets 10 16 Employer contributions 1 4 401(h) transfer - (2) Benefits paid (4) (5) - ----------------------------------------------------------------------------- Fair value of plan assets at end of year 135 128
Funded status - deficiency 3 24 Unrecognized net actuarial gain 75 58 Unrecognized net transition obligation (71) (76) - ----------------------------------------------------------------------------- Postretirement benefit liability at December 31 $ 7 $ 6 - ----------------------------------------------------------------------------- * Plan assets consist principally of common and preferred stocks, bonds, money market instruments and real estate.
Components of Net Periodic Benefit Cost: - ------------------------------------------------------------------------------ (In Millions) 1999 1998 1997 - ------------------------------------------------------------------------------ Service cost $3 $3 $4 Interest cost 9 10 10 Expected return on plan assets (9) (8) (5) Amortization of: Transition obligation 6 5 5 Actuarial gain (6) (4) (2) - ------------------------------------------------------------------------------ Net periodic benefit cost $3 $6 $12 - ------------------------------------------------------------------------------
Assumptions for the Obligation Measurements: - ------------------------------------------------------------------------------ 1999 1998 - ------------------------------------------------------------------------------ Discount rate at measurement date 7.75% 6.75% Expected return on plan assets 8.5% 8.5% Medical cost trend rate - initial - 5.75% - ultimate 5.25% 4.75% Ultimate medical cost trend rate expected in year 2000 2000 - ------------------------------------------------------------------------------
A one percentage point increase in the medical cost trend rate is estimated to increase the net periodic cost and the accumulated postretirement benefit obligation approximately $2 million and $20 million, respectively. A one
percentage point decrease in the medical cost trend rate is estimated to decrease the net periodic cost and the accumulated postretirement benefit obligation approximately $2 million and $20 million, respectively.
NOTE 11 - Commitments and Contingencies
Information contained in this section could be impacted by the transfer of the Registrant's generating facilities to AEG. See discussion in Note 1 - Summary of Significant Accounting Policies for more information.
The Registrant is engaged in a capital program under which expenditures averaging approximately $62 million, including AFC, are anticipated during each of the next five years. This estimate assumes the transfer of the Registrant's generating facilities to AEG will occur in 2000.
The Registrant has commitments for the purchase of coal under long-term contracts. Coal contract commitments, including transportation costs, for 2000 through 2004 are estimated to total $761 million. Total coal purchases, including transportation costs, for 1999, 1998 and 1997 were $216 million, $189 million and $209, respectively. The Registrant also has existing contracts with pipeline and natural gas suppliers to provide, transport and store natural gas for distribution and electric generation. Gas-related contract cost commitments for 2000 through 2004 are estimated to total $54 million. Total delivered natural gas costs were $73 million for 1999, $69 million for 1998, and $97 million for 1997.
In the fourth quarter of 1999, the Registrant and two of its coal suppliers executed agreements to terminate their existing coal supply contracts, effective December 31, 1999. Under these agreements, the Registrant has made termination payments to the suppliers totaling approximately $52 million. These termination payments were recorded as a nonrecurring charge in the fourth quarter of 1999, equivalent to $31 million, after income taxes. Total pretax fuel cost savings from these termination agreements are estimated to be $183 million (or $131 million net of the termination payments) through 2010, which is the maximum period that would have remained on any of the terminated coal supply contracts. Approximately $66 million of pretax fuel cost savings is expected to be realized over the next three years.
During 1996, the Registrant restructured its contract with one of its major coal suppliers. In 1997, the Registrant paid a $70 million restructuring payment to the supplier, which allowed it to purchase at market prices low-sulfur, non-Illinois coal through the supplier (in substitution for the high-sulfur Illinois coal the Registrant was obligated to purchase under the original contract). Under the restructuring, the Registrant received options for future purchases of low-sulfur, non-Illinois coal from the supplier through 1999 at set negotiated prices.
By switching to low-sulfur coal, the Registrant was able to discontinue operating a generating plant scrubber. The benefits of the restructuring include lower cost coal, avoidance of significant capital expenditures to renovate the scrubber, and elimination of scrubber operating and maintenance costs (offset by scrubber retirement expenses). The net benefits of restructuring are expected to exceed $100 million through 2007. In December 1996, the ICC entered an order approving the switch to non-Illinois coal, recovery of the restructuring payment plus associated carrying costs (Restructuring Charges) through the retail Fuel Adjustment Clause (FAC) over six years, and continued recovery in rates of the undepreciated scrubber investment, plus costs of removal. Additionally, in May 1997 the FERC approved recovery of the wholesale portion of the Restructuring Charges through the wholesale FAC. As a result of the ICC and FERC orders, the Registrant classified the $72 million of the Restructuring Charges as a regulatory asset and, through December 1997, recovered approximately $10 million of the Restructuring Charges through the retail FAC and from wholesale customers. In November 1997, the ICC order was reversed on appeal by the Illinois Third District Appellate Court. The Illinois Supreme Court issued a final decision in December 1998 reversing the Appellate Court's opinion and affirming the ICC's order allowing the recovery of the Restructuring Charges through the retail FAC.
The recoverability of the Restructuring Charges under the retail FAC in Illinois was impacted by the Law. Among other things, the Law provides utilities with the option to eliminate the retail FAC and limits the ability of utilities to file a full rate case for its aggregate revenue requirements. After evaluating the impact of the Law on the future recoverability of the Registrant's Restructuring Charges through future rates, the Registrant wrote off the unamortized balance of the Illinois retail portion of its Restructuring Charges as of December 31, 1997 ($34 million, net of income taxes). See Note 2 - Regulatory Matters for further information.
Under Title IV of the Clean Air Act Amendments of 1990, the Registrant is required to significantly reduce total annual sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions by the year 2000. By switching to low-sulfur coal, the Registrant is meeting these requirements.
In July 1997, the United States Environmental Protection Agency (EPA) issued regulations revising the National Ambient Air Quality Standards for ozone and particulate matter. In May 1999, the U.S. Court of Appeals for the District of Columbia remanded the regulations back to the EPA for review. Litigation regarding appeals of these regulations is ongoing. New ambient standards may result in additional significant reductions in SO2 and NOx emissions from the Registrant's power plants by 2007. At this time, the Registrant is unable to predict the ultimate impact of these revised air quality standards on its future financial condition, results of operations or liquidity.
In an attempt to lower ozone levels across the eastern United States, the EPA issued the implementation of regulations in September 1998 to reduce NOx emissions from coal-fired boilers and other sources in 22 states, including Illinois (where all of the Registrant's coal-fired power plant boilers are located). The proposed regulations mandate a 75% reduction from 1990 levels by the year 2003 and require states to develop plans to reduce NOx emissions to help alleviate ozone problem areas. The NOx emissions reductions already achieved on several of the Registrant's coal-fired power plants will help to reduce the costs of compliance with this regulation. However, preliminary analysis of the regulations indicate that selective catalytic reduction technology will be required for some of the Registrant's units, as well as other additional controls.
In March 2000, the U.S. Court of Appeals for the District of Columbia substantially upheld the proposed NOx regulations but remanded portions of them to the EPA for further consideration. The implementation date of the regulations is uncertain and further legal challenge is possible. Assuming an implementation date of 2003, the Registrant currently estimates that its additional capital expenditures to comply with the final NOx could range from $125 million to $150 million. Associated operations and maintenance expenditures could increase $5 million to $8 million annually, beginning in 2003. The Registrant will explore alternatives to comply with these new regulations in order to minimize, to the extent possible, its capital costs and operating expenses. The Registrant is unable to predict the outcome of the litigation, the regulation implementation date or the ultimate impact of these standards on its future financial condition, results of operations or liquidity.
In November 1998, the United States signed an agreement with numerous other countries (the Kyoto Protocol) containing certain environmental provisions, which would require decreases in greenhouse gases in an effort to address the "global warming" issue. The Kyoto Protocol has not been ratified by the United States Senate. Implementation of the Kyoto Protocol in its present form would likely result in significantly higher capital costs and operations and maintenance expenses by the Registrant. At this time, the Registrant is unable to determine the impact of these proposals on the Registrant's future financial condition, results of operations or liquidity.
As of December 31, 1999, the Registrant was designated as a potentially responsible party (PRP) by federal and state environmental protection agencies at five hazardous waste sites. Other hazardous waste sites have been identified for which the Registrant may be responsible but has not been designated a PRP.
Costs relating to studies and remediation and associated legal and litigation expenses at the former manufactured gas plant sites located in Illinois are being accrued and deferred rather than expensed currently, pending recovery through environmental adjustment clause rate riders approved by the ICC. Through December 31, 1999, the total of the costs deferred, net of recoveries from insurers and through environmental adjustment clause rate riders, was $13 million.
The ICC has instituted reconciliation proceedings to review the Registrant's environmental remediation activities to determine whether the revenues collected from customers under its environmental adjustment clause rate riders were consistent with the amount of remediation costs prudently and properly incurred. Amounts found to have been incorrectly included under the riders would be subject to refund. Rulings from the ICC are pending with respect to these proceedings applicable to the years 1993 through 1998. The reconciliation proceedings relating to the Registrant's 1999 environmental remediation activities will commence by the ICC in 2000.
The Registrant continually reviews remediation costs that may be required for all of these sites. Any unrecovered environmental costs are not expected to have a material adverse effect on the Registrant's financial position, results of operations or liquidity.
The International Union of Operating Engineers Local 148 and the International Brotherhood of Electrical Workers Local 702 filed unfair labor practice charges with the National Labor Relations Board (NLRB), relating to the legality of the 1993 lockout of both unions by the Registrant. The NLRB issued complaints against the Registrant concerning its lockout. Both unions sought, among other things, back pay and other benefits for the period of the lockout. At that time, the Registrant estimated the amount of back pay and other benefits for both unions to be
approximately $17 million. In August 1998, a three-member panel of the NLRB reversed the May 1996 decision of its administrative law judge and ruled in favor of the Registrant holding that the lockout was lawful. In April 1999, the unions filed petitions for review with the U.S. Court of Appeals for the District of Columbia Circuit of the NLRB's August 1998 decision. This appeal is pending. The Registrant continues to believe that the lockout was both lawful and reasonable and that the final resolution of the dispute will not have a material adverse effect on its financial position, results of operations or liquidity.
Certain employees of the Registrant and its affiliated companies are represented by the International Brotherhood of Electrical Workers (IBEW) and the International Union of Operating Engineers. These employees comprise approximately 70% of Ameren's workforce. Labor agreements covering substantially all represented employees of the Registrant expired in 1999 and were renewed for a term expiring in 2002. Labor agreements which expired in 1999 have not been renewed with IBEW Locals 1439, 309, 649 and 1455, who collectively represent approximately 2,000 AmerenUE and Ameren Services Company employees. Negotiations with Local 1455 are still ongoing. However, after engaging in extensive good-faith bargaining with IBEW Locals 1439, 309 and 649, AmerenUE submitted a last, best and final offer to these collective bargaining units on February 2, 2000. The offer was rejected and AmerenUE informed these locals that it would implement the noneconomic portion of its offer effective March 6, 2000. The employees are currently working under the noneconomic portion of AmerenUE's last, best and final offer. The Registrant is unable to predict what further action, if any, these collective bargaining units will take or the response of the Registrant's union represented employees to any action by its affiliates' employees. The Registrant is unable to determine what, if any, impact these labor matters could have on its future financial condition, results of operations or cash flows.
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, the Registrant is unable to predict the impact of these changes on the Registrant's future financial condition, results of operations or liquidity. See Note 2 - Regulatory Matters for further information.
The Registrant is involved in other 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. The Registrant believes that the final disposition of these proceedings will not have a material adverse effect on its financial position, results of operations or liquidity.
NOTE 12 - 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 and Temporary Investments/Short-Term Borrowings The carrying amounts approximate fair value because of the short-term maturity of these instruments.
Preferred Stock 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 the Registrant 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.
Carrying amounts and estimated fair values of the Registrant's financial instruments at December 31:
1999 1998 - -------------------------------------------------------------------------------- (In Millions) Carrying Fair Carrying Fair Amount Value Amount Value - -------------------------------------------------------------------------------- Preferred stock $ 80 $ 66 $ 80 $ 75 Long-term debt (including current portion) 529 528 588 636 - --------------------------------------------------------------------------------
NOTE 13 - Segment Information
In 1998, the Registrant adopted SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." AmerenCIPS' business segments provide electric and gas service in portions of Illinois.
The accounting policies of the segments are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data includes a charge allocating costs of administrative support services to each of the segments. These costs are accumulated in a separate Ameren subsidiary, Ameren Services Company, which provides a variety of support services to the Registrant. The Registrant evaluates the performance of its segments and allocates resources to them, based on revenues and operating income.
The table below presents information about the reported revenues and operating income of the Registrant for the years ended December 31:
- -------------------------------------------------------------------- (In Millions) Electric Gas Total - --------------------------------------------------------------------
- -------------------------------------------------------------------- - -------------------------------------------------------------------- Revenues $ 795 $133 $ 928 Operating income 86 9 95 - --------------------------------------------------------------------
- -------------------------------------------------------------------- - -------------------------------------------------------------------- Revenues $ 722 $125 $ 847 Operating income 115 5 120 - --------------------------------------------------------------------
- -------------------------------------------------------------------- - -------------------------------------------------------------------- Revenues $ 700 $152 $ 852 Operating income 95 7 102 - --------------------------------------------------------------------
Specified items included in segment profit/loss for the year ended December 31:
- ------------------------------------------------------------------------------ (In Millions) Electric Gas Total - ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ Depreciation, depletion and amortization expense $ 73 $ 8 $ 81 - ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ Depreciation, depletion and amortization expense $ 66 $ 8 $ 74 - ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ Depreciation, depletion and amortization expense $ 76 $ 7 $ 83 Extraordinary items (25) - (25) - ------------------------------------------------------------------------------
Specified item related to segment assets as of December 31:
- ----------------------------------------------------------------------------- (In Electric Gas Total Millions) - -----------------------------------------------------------------------------
- ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- Expenditures for additions to long-lived assets $ 86 $ 9 $ 95 - -----------------------------------------------------------------------------
- ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- Expenditures for additions to long-lived assets $ 60 $ 9 $ 69 - -----------------------------------------------------------------------------
- ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- Expenditures for additions To long-lived assets $ 105 $ 11 $ 116 - -----------------------------------------------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
On June 12, 1998, the Board of Directors of the Registrant's parent, Ameren, approved the recommendation of the Board's Auditing Committee and appointed PricewaterhouseCoopers LLP as auditors for the year 1998. Ameren's appointment of PricewaterhouseCoopers LLP also covered auditing services for Ameren's subsidiaries, which meant that Registrant's previous certifying accountant, Arthur Andersen LLP (Andersen), was, in effect, dismissed.
Andersen's report of the Registrant's financial statements for the year 1997 did not contain an adverse opinion or a disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope, or accounting principles. Further, during such period, and through the date of dismissal, there were no disagreements with Andersen on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure. Also, there was no occurrence of any kind of event set out in paragraphs (a) (1) (v) (A) through (D) of Item 304 of Regulation S-K.
PricewaterhouseCoopers LLP was also appointed as auditors for the year 1999.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Any information concerning directors required to be reported by this item is included under "Item (1): Election of Directors" in the AmerenCIPS' 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference.
Information concerning executive officers required by this item is reported in Part I of this Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION.
Any information required to be reported by this item is included under "Compensation" in AmerenCIPS' 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Any information required to be reported by this item is included under "Security Ownership of Management" in AmerenCIPS' 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Any information required to be reported by this item is included under "Item (1): Election of Directors" in AmerenCIPS' 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements and Financial Statement Schedule Covered by Report of Independent Accountants
Pages Herein
Report of Independent Accountants.................................17 Balance Sheet - December 31, 1999 and 1998........................18 Statement of Income - Years 1999, 1998, and 1997..................19 Statement of Cash Flows - Years 1999, 1998, and 1997..............20 Statement of Retained Earnings - Years 1999, 1998, and 1997.......21 Notes to Financial Statements.....................................22 Valuation and Qualifying Accounts (Schedule II) Years 1999, 1998, and 1997......................................38
2. Exhibits: See EXHIBITS beginning on Page 40
(b) Reports on Form 8-K. The Registrant filed a report on Form 8-K dated December 20, 1999 reporting the termination of coal supply contracts, the resulting estimated pretax fuel cost savings and the recording of a nonrecurring charge.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
Note: Uncollectible accounts charged off, less recoveries.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY (Registrant)
G. L. RAINWATER President and Chief Executive Officer
Date March 29, 2000 By /s/ Steven R. Sullivan -------------- ------------------------------------ (Steven R. Sullivan, Attorney-in-Fact)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title
/s/ G. L. Rainwater President, Chief Executive Officer and Director - ------------------------------ (Principal Executive Offcer) G. L. RAINWATER
/s/ Jerre E. Birdsong Treasurer - ------------------------------ (Principal Financial Officer) JERRE E. BIRDSONG
/s/ Warner L. Baxter Vice President, Controller and Director - ------------------------------ (Principal Accounting Officer) WARNER L. BAXTER
/s/ Paul A. Agathen Director - ------------------------------ PAUL A. AGATHEN
/s/ Donald E. Brandt Director - ------------------------------ DONALD E. BRANDT
/s/ Charles W. Mueller Director - ------------------------------ CHARLES W. MUELLER
By /s/ Steven R. Sullivan March 29, 2000 --------------------------- (Steven R. Sullivan, Attorney-in Fact)
EXHIBITS
Exhibits Filed Herewith
Exhibit No. Description
12 - Statement re Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements.
23 - Consent of Independent Accountants.
24 - Powers of Attorney.
27 - Financial Data Schedule.
Exhibits Incorporated By Reference
The following exhibits heretofore have been filed with the Securities and Exchange Commission pursuant to requirements of the Acts administered by the Commission. Such exhibits are identified by the references following the listing of each such exhibit, and they are hereby incorporated herein by reference.
Exhibit No. Description - ----------- ------------ 2 - Agreement and Plan of Merger, dated as of August 11, 1995, by and among CIPSCO Incorporated, Union Electric Company, Ameren Corporation and Arch Merger Inc. (Exhibit 2(a) filed with CIPSCO's and CIPS' Form 10-Q/A (Amendment No. 1) for the quarter ended June 30, 1995.)
3.01 - Restated Articles of Incorporation of CIPS. (Exhibit 3(b) filed with CIPS' Form 10-Q for the quarter ended March 31, 1994.)
3.02 - By-Laws of the Company as amended effective August 26, 1999. (September 30, 1999 Form 10-Q, Exhibit 3(ii).)
4 - Indenture of Mortgage or Deed of Trust dated October 1, 1941, from CIPS to Continental Illinois National Bank and Trust Company of Chicago and Edmond B. Stofft, as Trustees. (Exhibit 2.01 in File No. 2-60232.) Supplemental Indentures dated, respectively September 1, 1947, January 1, 1949, February 1, 1952, September 1, 1952, June 1, 1954, February 1, 1958 , January 1, 1959, May 1, 1963, May 1, 1964, June 1, 1965, May 1, 1967, April 1, 1970, April 1, 1971, September 1, 1971, May 1, 1972, December 1, 1973, March 1, 1974, April 1, 1975, October 1, 1976, November 1, 1976, October 1, 1978, August 1, 1979, February 1, 1980, February 1, 1986, May 15, 1992, July 1, 1992, September 15, 1992, April 1, 1993, and June 1, 1995 between CIPS and the Trustees under the Indenture of Mortgage or Deed of Trust referred to above (Amended Exhibit 7(b) in File No. 2-7341; Second Amended Exhibit 7.03 in File No. 2-7795; Second Amended Exhibit 4.07 in File No.2-9353; Amended Exhibit 4.05 in file No. 2-9802; Amended Exhibit 4.02 in File No. 2-10944; Amended Exhibit 2.02 in File No. 2-13866; Amended Exhibit 2.02 in File No. 2-14656; Amended Exhibit 2.02 in File No.2-21345; Amended Exhibit 2.02 in File No. 2-22326; Amended Exhibit 2.02 in File No. 2-23569; Amended Exhibit 2.02 in File No. 2-26284; Amended Exhibit 2.02 in File No. 2-36388; Amended Exhibit 2.02 in File No. 2-39587; Amended Exhibit 2.02 in File No. 2-41468; Amended Exhibit 2.02 in File No. 2-43912; Exhibit 2.03 in File No. 2-60232; Amended Exhibit 2.02 in File No. 2-50146; Amended Exhibit 2.02 in File No. 2-52886; Second Amended Exhibit 2.04 in File No. 2-57141; Amended Exhibit 2.04 in File No. 2-57557; Amended Exhibit 2.06 in File No. 2- 62564; Exhibit 2.02(a) in File No. 2-65914; Amended Exhibit 2.02(a) in File No. 2-66380; and Amended Exhibit 4.02 in File No. 33-3188; Exhibit 4.02 to Form 8-K dated May 15, 1992; Exhibit 4.02 to Form 8-K dated July 1, 1992; Exhibit 4.02 to Form 8-K dated September 15, 1992; Exhibit 4.02 to Form 8-K dated March 30, 1993; Exhibit 4.03 to Form 8-K dated June 5, 1995; Exhibit 4.03 to Form 8-K dated March 15, 1997; Exhibit 4.03 to Form 8-K dated June 1, 1997; and Exhibit 4.02, Post-Effective Amendment No. 1 in File No. 333-18473.)
4.01 - Indenture dated as of December 1, 1998 from CIPS to the Bank of New York relating to CIPS' Senior Notes, 5.375% due 2008 and 6.125% due 2028. (Exhibit 4.03, Post-Effective Amendment No. 1 to File No. 333-18473.)
Exhibit No. Description
10.01- Form of Director's Retirement Income Plan. (Exhibit 10.04 filed with 1990 Annual Report on Form 10-K.)
10.02- Form of Excess Benefit Plan. (Exhibit 10.10 filed with CIPSCO's and CIPS' 1994 Annual Report on Form 10-K.)
10.03- Amendment to Form of Excess Benefit Plan. (Exhibit 10.07 filed with CIPSCO's and CIPS' 1995 Annual Report on Form 10-K.)
10.04- Form of Special Executive Retirement Plan. (Exhibit 10.11 filed with CIPSCO's and CIPS' 1994 Annual Report on Form 10-K.)
10.05- Amendment to Form of Special Executive Retirement Plan. (Exhibit 10.09 filed with CIPSCO's and CIPS' 1995 Annual Report on Form 10-K.)
10.06- Ameren Long-Term Incentive Plan of 1998. (Ameren's 1998 Form 10-K, Exhibit 10.1.)
10.07- Ameren Change of Control Severance Plan. ((Ameren's 1998 Form 10-K, Exhibit 10.2.)
10.08- Ameren Deferred Compensation Plan for Members of the Ameren Leadership Team. (Ameren's 1998 Form 10-K, Exhibit 10.3.)
10.09- Ameren Deferred Compensation Plan for Members of the Board of Directors. (Ameren's 1998 Form 10-K, Exhibit 10.4.)
Note: Reports of the Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-3672.
Reports of Ameren on Form 10-K are on file with the SEC under File Number 1-14756.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
There is no market for the Registrant's Common Stock since all shares are owned by its parent, Ameren.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Central Illinois Public Service Company (AmerenCIPS or the Registrant) is a subsidiary of Ameren Corporation (Ameren), a holding company registered under the Public Utility Holding Company Act of 1935 (PUHCA). In December 1997, Union Electric Company (AmerenUE) and CIPSCO Incorporated (CIPSCO) combined to form Ameren, with AmerenUE and CIPSCO's subsidiaries, the Registrant and CIPSCO Investment Company (CIC), becoming subsidiaries of Ameren (the Merger).
In conjunction with the Illinois Electric Service Customer Choice and Rate Relief Law of 1997 (the Law), the Registrant has received regulatory approvals to transfer its generating facilities to Ameren Energy Generating Company (AEG), a nonregulated, indirectly wholly-owned subsidiary of Ameren. The transfer of the assets and liabilities (at historical net book value of approximately $600 million) is currently scheduled to occur in May 2000. Discussion below relating to "forward-looking" statements reflects information assuming that the transfer will occur as scheduled. For additional information on the Law, its impact on the Registrant, and the generating facilities transfer, see "Electric Industry Restructuring" below and Note 2 to the Notes to Financial Statements.
RESULTS OF OPERATIONS
Earnings Earnings for 1999, 1998 and 1997, were $50 million, $76 million and $35 million, respectively. Earnings fluctuated due to many conditions, primarily: sales growth, weather variations, credits to electric customers, electric rate reductions, gas rate increases, competitive market forces, fluctuating operating costs, charges for coal contract terminations, a targeted employee separation plan, merger-related expenses, changes in interest expense, changes in income and property taxes, and an extraordinary charge.
In the fourth quarter of 1999, the Registrant recorded a nonrecurring charge to earnings in connection with coal contract terminations with two coal suppliers. The charge reduced earnings $31 million, net of income taxes (see discussion below under "Electric Operations" and Note 11 - Commitments and Contingencies under Notes to Financial Statements for further information). In 1998, the Registrant also recorded a nonrecurring charge to earnings in connection with a targeted separation plan it offered to employees in July 1998. The charge reduced earnings $4 million, net of income taxes, (see Note 4 - Targeted Separation Plan under Notes to Financial Statements for further information). In addition, the Registrant recorded an extraordinary charge to earnings in the fourth quarter of 1997 for the write-off of generation-related regulatory assets and liabilities of the Registrant's retail electric business as a result of electric industry restructuring legislation enacted in Illinois in December 1997. The write-off reduced earnings $25 million, net of income taxes (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information).
The significant items affecting revenues, expenses and earnings for the years ended December 31, 1999, 1998 and 1997 are detailed in the following pages.
Electric Operations Electric Revenues Variations from Prior Year - -------------------------------------------------------------------------------- (In Millions) 1999 1998 1997 - -------------------------------------------------------------------------------- Rate variations $(7) $(5) $ - Effect of abnormal weather (16) 13 (1) Growth and other 9 14 5 Interchange sales 88 (1) (29) - -------------------------------------------------------------------------------- $74 $21 $(25) - --------------------------------------------------------------------------------
Electric revenues for 1999 increased $74 million, compared to 1998, primarily due to an 11% increase in total kilowatthour sales. This increase was primarily driven by a 37% increase in interchange sales, due to strong marketing efforts. This increase was partially offset by a residential rate decrease (see Note 2 - Regulatory Matters under notes to Financial Statements for further information). In addition, revenues were lower due to a 1% decrease in native sales, resulting from milder weather.
Electric revenues for 1998 increased $21 million, compared to 1997. Revenues increased primarily due to higher sales to retail customers within the Registrant's service territory, as a result of warm summer weather and economic growth in the service area. Weather-sensitive residential and commercial sales increased 6% and 4%, respectively, while industrial sales grew 4%. These increases were partially offset by a 5% rate decrease to residential customers beginning in August 1998 (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information).
Electric revenues for 1997 decreased primarily due to a 19% decrease in interchange sales due to market conditions and differences in the classification of certain interchange and purchased power transactions resulting from Federal Energy Regulatory Commission (FERC) Order 888, as well as a 3% decline in industrial sales. Residential sales remained constant with prior year levels, while commercial sales increased 2% over the same period.
Fuel and Purchased Power Variations from Prior Year - -------------------------------------------------------------------------------- (In Millions) 1999 1998 1997 - -------------------------------------------------------------------------------- Fuel: Generation $17 $(25) $ 7 Price (18) (2) (8) Generation efficiencies and other (7) (6) (4) Coal contract termination payments 52 - - Purchased power 40 21 (27) - -------------------------------------------------------------------------------- $84 $(12) $(32) - --------------------------------------------------------------------------------
The $84 million increase in fuel and purchased power costs for 1999, compared to 1998, was primarily due to increased generation and purchased power, resulting from higher sales volume and coal contract termination payments discussed below, partially offset by lower fuel costs.
In the fourth quarter of 1999, the Registrant and two of its coal suppliers executed agreements to terminate their existing coal supply contracts effective December 31, 1999. Under these agreements, the Registrant made termination payments to the suppliers totaling approximately $52 million. These termination payments were recorded as a nonrecurring charge in the fourth quarter of 1999. Total pretax fuel cost savings from these termination agreements are estimated to be $183 million (or $131 million net of the termination payments) through 2010, which is the maximum period that would have remained on any of the terminated coal supply contracts. Approximately $66 million of pretax fuel cost savings is expected to be realized over the next three years. See Note 11 - Commitments and Contingencies under Notes to Financial Statements for further information.
The $12 million decrease in fuel and purchased power costs for 1998, compared to 1997, was primarily driven by lower fuel costs due to lower fuel prices and utilizing joint dispatch generation. Upon consummation of the Merger, AmerenUE and AmerenCIPS began jointly dispatching generation, therefore allowing Ameren to utilize the most cost efficient plants of both operating companies to serve customers in either service territory. The decrease in 1997 fuel and purchased power costs was driven mainly by a decrease in interchange sales and lower fuel prices.
Gas Operations Gas revenues in 1999 increased $7 million, compared to 1998, primarily due to a gas rate increase which became effective in February 1999 (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information) and higher gas costs recovered through the Registrant's purchased gas adjustment clause. These increases were partially offset by a 10% decline in retail sales, resulting primarily from milder winter weather, as well as a decrease in off-system sales of gas to others. Gas revenues in 1998 decreased $26 million compared to 1997, primarily due to a 7% decline in retail sales resulting from milder winter weather and lower gas costs recovered through the Registrant's purchase gas adjustment clause. Gas revenues in 1997 decreased $4 million primarily due to a 10% decline in retail sales resulting from mild winter weather.
Gas costs in 1999 increased $4 million compared to 1999. This increase in gas costs was primarily due to higher gas prices, partially offset by lower total sales. Gas costs in 1998 declined $28 million compared to 1997. This decrease in gas costs was due to lower sales and lower gas prices. Gas costs for 1997 remained relatively flat when compared to 1996 costs.
Other Operating Expenses Other operating expense variations in 1997 through 1999 reflected recurring factors such as growth, inflation, labor and benefit increases, in addition to a charge for the targeted separation plan (TSP), as discussed below.
In 1998, Ameren announced plans to reduce its other operating expenses, including plans to eliminate approximately 400 employee positions by mid-1999 through a hiring freeze and the TSP. During the third quarter of 1998, a nonrecurring, pretax charge of $7 million was recorded, representing the Registrant's share of costs incurred to implement the TSP. The elimination of these positions, exclusive of the nonrecurring charge, reduced the Registrant's operating expenses approximately $4 million in 1998, and approximately $7 million in 1999, and is expected to reduce the Registrant's operating expenses by approximately $6 million to $7 million each year thereafter. See Note 4 - Targeted Separation Plan under Notes to Financial Statements for further information.
Other operating expenses increased $11 million, in 1999, compared to 1998, primarily due to increased postretirement expenses resulting from changes in actuarial assumptions, increased injuries and damages expenses based on claims experience, expenses associated with electric industry deregulation in Illinois and the Year 2000 project. These increases were partially offset by a reduced workforce, coupled with the fact that 1998 expenses included the charge for the TSP. The $19 million increase in other operating expenses in 1998, compared to 1997, were primarily due to the charge for the TSP and increased information system-related costs. In 1997, other operating expenses increased $15 million, primarily due to increases in labor, various equipment purchases and rentals and information system-related costs.
Maintenance expenses increased $32 million in 1999, compared to 1998. This increase was primarily due to increased power plant maintenance. In 1998, maintenance expenses decreased $4 million from the prior year, primarily due to less scheduled power plant maintenance. The 1997 maintenance expenses increase of $14 million from the prior year can be attributed to scheduled outages at three power plants.
Depreciation and amortization expense increased $6 million in 1999, compared to 1998. This increase was primarily due to increased depreciable property. In 1998, depreciation and amortization expense decreased $8 million from the prior year due to the write-off of generation-related regulatory assets in Illinois during the fourth quarter of 1997. The 1997 depreciation and amortization expense fluctuation relates primarily to property additions.
Taxes Income tax expense from operations decreased $15 million in 1999, compared to 1998, due to lower pretax income. Income tax expense from operations increased $12 million in 1998, compared to 1997, due to higher pretax income and a higher effective tax rate. Income tax expense from operations decreased $14 million in 1997, principally due to lower pretax income and a lower effective tax rate.
Other tax expense decreased $17 million in 1999, compared to 1998, primarily due to a decrease in gross receipts taxes. This decrease is the result of the restructuring of the Illinois public utility tax whereby gross receipts taxes are no longer recorded as electric revenue and gross receipts tax expense.
Other Income and Deductions In 1999, miscellaneous, net decreased $3 million, compared to 1998, primarily due to losses on the disposal of property realized in 1998. In 1998, miscellaneous, net decreased $3 million primarily due to higher merger-related expenses incurred in the prior year. Miscellaneous, net increased $2 million between 1997 and 1996 primarily due to increased merger-related expenses.
Interest Interest expense increased $3 million in 1999, compared to 1998, due to an increase in intercompany notes payable resulting from funds borrowed from the regulated money pool (see Note 7 - Short-Term Borrowings under Notes to Financial Statements for further information), partially offset by the redemption of short-term debt. Interest expense increased $3 million in 1998, compared to 1997, due to a higher amount of debt outstanding, partially offset by a decrease in other interest.
Balance Sheet The $27 million increase in trade accounts receivable and unbilled revenue was due primarily to higher sales and revenues in November and December 1999, compared to the same 1998 period.
The changes in accounts and wages payable, taxes accrued, other accounts and notes receivable, and other current assets resulted from the timing of various payments to taxing authorities and suppliers. The $133 million increase in intercompany notes payable was due to funds borrowed from a regulated money pool (see Note 7 - Short-Term Borrowings under Notes to Financial Statements for further information).
LIQUIDITY AND CAPITAL RESOURCES
Information contained in this section could be impacted by the transfer of the Registrant's generating facilities to AEG. See discussion in "Overview" section above for more information.
Cash provided by operating activities totaled $166 million for 1999, compared to $123 million for 1998 and $81 million in 1997, respectively.
Cash flows used in investing activities totaled $95 million, $68 million and $111 million, for the years ended December 31, 1999, 1998 and 1997, respectively. Expenditures in 1999 for constructing new or improving existing facilities and purchasing rail cars were $95 million.
Capital expenditures are expected to approximate $60 million in 2000. For the five-year period 2000-2004, construction expenditures are estimated at $264 million. This estimate assumes that the transfer of the Registrant's generating facilities to AEG will occur in 2000.
Title IV of the Clean Air Act Amendments of 1990 requires the Registrant to significantly reduce total annual sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions by the year 2000. By switching to low-sulfur coal, the Registrant is meeting these requirements.
In July 1997, the United States Environmental Protection Agency (EPA) issued regulations revising the National Ambient Air Quality Standards for ozone and particulate matter. In May 1999, the U.S. Court of Appeals for the District of Columbia remanded the regulations back to the EPA for review. Litigation regarding appeals of these regulations is ongoing. New ambient standards may result in significant additional reductions in SO2 and NOx emissions from the Registrant's power plants by 2007. At this time, the Registrant is unable to predict the ultimate impact of these revised air quality standards on its future financial condition, results of operations or liquidity.
In an attempt to lower ozone levels across the eastern United States, the EPA issued the implementation of regulations in September 1998 to reduce NOx emissions from coal-fired boilers and other sources in 22 states, including Illinois (where all of the Registrant's coal-fired power plant boilers are located). The proposed regulations mandate a 75% reduction from 1990 levels by the year 2003 and require states to develop plans to reduce NOx emissions to help alleviate ozone problem areas. The NOx emissions reductions already achieved on several of the Registrant's coal-fired power plants will help reduce the costs of compliance with these regulations. However, preliminary analysis of the regulations indicate that selective catalytic reduction technology may be required for some of the Registrant's units, as well as other additional controls.
In March 2000, the U.S. Court of Appeals for the District of Columbia substantially upheld the proposed NOx regulations but remanded portions of them to the EPA for further consideration. The implementation date of the regulations is uncertain and further legal challenge is possible. Assuming an implementation date of 2003, the Registrant currently estimates that its additional capital expenditures to comply with the final NOx regulations could range from $125 million to $150 million. Associated operations and maintenance expenditures could increase $5 million to $8 million annually, beginning in 2003. The Registrant is exploring alternatives to comply with these new regulations in order to minimize, to the extent possible, its capital costs and operating expenses. The Registrant is unable to predict the outcome of the litigation, the regulation implementation date or the ultimate impact of these standards on its future financial condition, results of operations or liquidity.
In November 1998, the United States signed an agreement with numerous other countries (the Kyoto Protocol) containing certain environmental provisions, which would require decreases in greenhouse gases in an effort to address the "global warming" issue. The Kyoto Protocol has not been ratified by the United States Senate. Implementation of the Kyoto Protocol in its present form would likely result in significantly higher capital costs and operations and maintenance expenses by the Registrant. At this time, the Registrant is unable to determine the impact of these proposals on the Registrant's future financial condition, results of operations or liquidity.
Cash flows used in financing activities were $68 million for 1999. This compares to cash flows used in financing activities of $74 million in 1998 and cash flows provided by financing activities of $48 million for 1997. The Registrant's financing activities during 1999 included the issuance of $133 million of intercompany notes payable, the redemption of $60 million of long-term debt, the redemption of $47 million of short-term debt, and the payment of dividends.
The Registrant plans to continue utilizing short-term debt to support normal operations and other temporary requirements. The Registrant is authorized by the Securities and Exchange Commission (SEC) under PUHCA to have up to $125 million of short-term unsecured debt instruments outstanding at any one time. Short-term borrowings consist of bank loans (maturities generally on an overnight basis) and commercial paper (maturities generally within 10 to 45 days). At December 31, 1999, the Registrant had committed bank lines of credit aggregating $30 million, all of which was unused and available at such date, which make available interim financing at various rates of interest based on LIBOR, the bank certificate of deposit rate or other options. The lines of credit are renewable annually at various dates throughout the year. At year-end, the Registrant had no outstanding short-term borrowings.
Also, the Registrant has the ability to borrow up to approximately $950 million from Ameren or AmerenUE through a regulated money pool agreement. The regulated money pool was established to coordinate and provide for certain short-term cash and working capital requirements and is administered by Ameren Services Company, another subsidiary of Ameren. Interest is calculated at varying rates of interest depending on the composition of internal and external funds in the regulated money pool. At December 31, 1999, the Registrant had $133 million of intercompany borrowings outstanding and $520 million available through the regulated money pool. See Note 7 - Short-Term Borrowings under Notes to Financial Statements for further information.
The Registrant, in the ordinary course of business, explores opportunities to reduce its costs in order to remain competitive in the marketplace. Areas where the Registrant focuses its review include, but are not limited to, labor costs and fuel supply costs. In the labor area, the Registrant has recently reached agreements with all of the Registrant's major collective bargaining units which will permit it to manage its labor costs and practices effectively in the future (see Note 11 - Commitments and Contingencies under Notes to Financial Statements for further discussion). The Registrant also explores alternatives to effectively manage the size of its workforce. These alternatives include utilizing hiring freezes, outsourcing and offering employee separation packages. In the fuel supply area, the Registrant explores alternatives to effectively manage its overall fuel costs. These alternatives include diversifying fuel sources for use at the Registrant's power plants (e.g. utilizing low-sulfur versus high- sulfur coal), as well as restructuring or terminating existing contracts with suppliers.
Certain of these reduction alternatives could result in additional investments being made at the Registrant's power plants in order to utilize different types of coal, or could require nonrecurring payments of employee separation benefits or nonrecurring payments to restructure or terminate existing fuel contracts with a supplier. Management is unable to predict which (if any), and to what extent, these alternatives to reduce its overall cost structure will be executed. Management is unable to determine the impact of these actions on the Registrant's future financial position, results of operations or liquidity.
RATE MATTERS
See Note 2 - Regulatory Matters under Notes to Financial Statements for a discussion of rate matters.
ELECTRIC INDUSTRY RESTRUCTURING
Steps taken and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation, and encourage increased competition. At the federal level, the Energy Policy Act of 1992 reduced various restrictions on the operation and ownership of independent power producers and gave the FERC the authority to order electric utilities to provide transmission access to third parties.
In April 1996, the FERC issued Order 888 and Order 889, which are intended to promote competition in the wholesale electric market. The FERC requires transmission-owning public utilities, such as AmerenCIPS, to provide transmission access and service to others in a manner similar and comparable to that which the utilities have by virtue of ownership. Order 888 requires that a single tariff be used by the utility in providing transmission service. Order 888 also provides for the recovery of strandable costs, under certain conditions, related to the wholesale business.
Order 889 established the standards of conduct and information requirements that transmission owners must adhere to in doing business under the open access rule. Under Order 889, utilities must obtain transmission service for their own use in the same manner their customers will obtain service, thus mitigating market power through control of transmission facilities. In addition, under Order 889, utilities must separate their merchant function (buying and selling wholesale power) from their transmission and reliability functions.
The Registrant believes that Order 888 and Order 889, which relate to its wholesale business, will not have a material adverse effect on its financial condition, results of operations or liquidity.
In 1998, the Registrant joined a group of companies that support the formation of the Midwest Independent System Operator (Midwest ISO). An ISO operates, but does not own, electric transmission systems and maintains system reliability and security, while alleviating pricing issues associated with the "pancaking" of rates. The Midwest ISO would be regulated by the FERC. Thirteen transmission-owning utilities have joined the Midwest ISO as of December 31, 1999. The FERC conditionally approved the formation of the Midwest ISO in September 1998, and it is expected to be operational during the year 2001. The Illinois Commerce Commission (ICC) has authorized the Registrant to join the Midwest ISO and to transfer control of its transmission facilities to the Midwest ISO. The Midwest ISO covers 14 states, represents portions of 60,000 miles of transmission line and controls $8 billion of assets. The Registrant believes that the operation of the Midwest ISO will not have a material adverse effect on its financial condition, results of operations or liquidity.
In December 1999, the FERC issued its Order 2000 relating to Regional Transmission Organizations (RTOs) that would meet certain characteristics such as size and independence. Order 2000 calls on all transmission owners to join RTOs. In particular, all public utilities that own, operate, or control interstate transmission facilities must file with the FERC by October 15, 2000, a proposal for an RTO, or alternatively a description of efforts by the utility to join an RTO. The Registrant expects that its participation in the Midwest ISO will satisfy the requirements of Order 2000.
Certain states are considering proposals or have adopted legislation that will promote competition at the retail level. In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Law) providing for electric utility restructuring in Illinois. This legislation introduces competition into the supply of electric energy at retail in Illinois.
Major provisions of the Law include the phasing-in through 2002 of retail direct access, which allows customers to choose their electric generation suppliers. The phase-in of retail direct access began on October 1, 1999, with large commercial and industrial customers principally comprising the initial group. The customers in this group represent approximately 24% of the Registrant's total sales. As of December 31, 1999, the impact of retail direct access on the Registrant's financial condition, results of operations or liquidity was immaterial. Retail direct access will be offered to the remaining commercial and industrial customers on December 31, 2000, and to residential customers on May 1, 2002.
In addition, the Law included a 5% rate decrease for residential customers that became effective in August 1998. This rate decrease is expected to reduce electric revenues by approximately $11 million annually, based on estimated levels of sales and assuming normal weather conditions. (See Note 2 - Regulatory Matters under Notes to Financial Statements for further information.) In 1998, the Registrant eliminated its Uniform Fuel Adjustment Clause (FAC) as allowed by the Law, which benefited shareholders in 1998 and 1999 and is expected to benefit shareholders in the future (see Note 1 - Summary of Significant Accounting Policies under Notes to Financial Statements for further information). The Law contains a provision allowing for the potential recovery of a portion of strandable costs, which represent costs that would not be recoverable in a restructured environment, through a transition charge collected from customers who choose an alternate electric supplier. In addition, the Law contains a provision requiring a portion of excess earnings (as defined under the Law) for the years 1998 through 2004 to be refunded to customers.
In December 1997, after evaluating the impact of the Law, the Registrant determined that it was necessary to write-off the generation-related regulatory assets and liabilities of its Illinois retail electric business. This extraordinary charge reduced 1997 earnings $25 million, net of income taxes. The Registrant has also concluded that its remaining net generation-related assets are not impaired for financial reporting purposes and that no plant writedowns are necessary at this time. See Note 2 - Regulatory Matters under Notes to Financial Statements for further information.
In conjunction with another provision of the Law, in July 1999, the Registrant filed a notice with the ICC that it intends to transfer its generating facilities (all in Illinois) to Ameren Energy Generating Company (AEG), a nonregulated, indirectly wholly-owned subsidiary of Ameren. The formation of the new generating subsidiary, as well as the transfer of the Registrant's generating assets and liabilities (at historical net book value of approximately $600 million) and certain power sales contracts, in exchange for an intercompany note receivable, was subject to regulatory approvals from the ICC, the FERC, and the Missouri Public Service Commission, all of which have been received as of March 10, 2000. An additional PUHCA-related determination that will permit the new generating
subsidiary to operate as an Exempt Wholesale Generator is being sought from the FERC. The generating subsidiary will include most of the new combustion turbine generators being acquired by Ameren, in addition to the Registrant's facilities. The new subsidiary is scheduled to be operational in May 2000. See Note 2 - Regulatory Matters under Notes to Financial Statements for further information.
Once the transfer is completed, a power sales agreement will be in place between the new generating subsidiary and a nonregulated marketing affiliate for all generation. The marketing affiliate will have a power sales agreement with the Registrant to supply it sufficient generation to meet native load requirements over the term of the agreement.
The proposed transfer of the Registrant's generating assets and liabilities had no effect on the Registrant's financial statements as of December 31, 1999.
In summary, the potential negative consequences associated with electric industry restructuring could be significant and could include the impairment and writedown of certain assets, including generation-related plant assets, lower revenues, reduced profit margins and increased costs of capital and operations expenses. Ameren and the Registrant are actively taking steps to mitigate these potential negative consequences. Most importantly, they will continue to focus on cost control to ensure that they maintain a competitive cost structure, which includes the recent termination of high-cost coal supply contracts (see Note 11 - - Commitments and Contingencies under Notes to Financial Statements for further information). Also, the actions of Ameren and the Registrant include establishing a nonregulated generating subsidiary and expanding its generation assets, strengthening the Registrant's trading and marketing operation to maintain current customers and obtain new customers, and enhancing information systems. The Registrant believes that these actions will position Ameren and the Registrant well in the competitive Illinois marketplace. The Registrant is also actively involved in shaping the policies of the Midwest ISO to protect its shareholders' interests. At this time, the Registrant is unable to predict the ultimate impact of electric industry restructuring on the Registrant's future financial condition, results of operations or liquidity.
YEAR 2000 ISSUE
The Year 2000 Issue relates to how dates are stored and used in computer systems, applications, and embedded systems. As the century date change occurred, certain date-sensitive systems had to recognize the year as 2000 and not as 1900. This inability to recognize and properly treat the year as 2000 could have caused these systems to process critical financial and operational information incorrectly. Management implemented a Year 2000 plan covering Ameren, including AmerenCIPS, and briefed Ameren's Board of Directors about the Year 2000 Issue and how it might have affected the Registrant. Ameren encountered no significant problems associated with the Year 2000 Issue at year-end. In addressing the Year 2000 Issue, Ameren incurred internal labor costs as well as external consulting and other expenses to prepare for the new century. As of December 31, 1999, Ameren had expended approximately $8 million in external costs (consulting fees and related costs). The impact of the Year 2000 Issue on the Registrant's financial condition, results of operations or liquidity was immaterial. Ameren will continue to monitor date-sensitive systems as certain key dates occur throughout the year.
CONTINGENCIES
See Note 2 - Regulatory Matters and Note 11 - Commitments and Contingencies under Notes to Financial Statements for material issues existing at December 31, 1999.
MARKET RISK RELATED TO FINANCIAL INSTRUMENTS AND COMMODITY INSTRUMENTS
Market risk represents the risk of changes in value of a financial instrument, derivative or non-derivative, caused by fluctuations in market variables (e.g., interest rates, equity prices, commodity prices, etc.). The following discussion of Ameren's, including AmerenCIPS', 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. Ameren handles market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, Ameren also faces risks that are either non-financial or non-quantifiable. Such risks principally include business, legal, operational, and credit risk and are not represented in the following analysis.
Interest Rate Risk The Registrant is exposed to market risk through changes in interest rates through its issuance of both long-term and short-term variable-rate debt, fixed-rate debt, commercial paper and auction market preferred stock. The Registrant manages its interest rate exposure by controlling the amount of these instruments it holds within its total capitalization portfolio and by monitoring the effects of market changes in interest rates.
If interest rates increase one percentage point in 2000 as compared to 1999, the Registrant's interest expense would increase and net income would decrease by approximately $1 million. This amount has been determined using the assumptions that the Registrant's outstanding variable-rate debt, commercial paper and auction market preferred stock as of December 31, 1999, continued to be outstanding throughout 2000, and that the average interest rates for these instruments increased one percentage point over 1999. The model does not consider the effects of the reduced level of 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 its 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 the Registrant's financial structure.
Commodity Price Risk The Registrant is exposed to changes in market prices for natural gas, fuel and electricity. With regard to its natural gas utility business, the Registrant's exposure to changing market prices is in large part mitigated by the fact that the Registrant has a Purchased Gas Adjustment Clause (PGA) in place. The PGA allows the Registrant to pass on to its customers its prudently incurred costs of natural gas.
Since the Registrant does not have a provision similar to the PGA for its electric operations, the Registrant has entered into several long-term contracts with various suppliers to purchase coal to manage its exposure to fuel prices. (See Note 11 - Commitments and Contingencies under Notes to Financial Statements for further information). With regard to the Registrant's exposure to commodity price risk for purchased power and excess electricity sales, Ameren has established a subsidiary, AmerenEnergy, Inc. (AmerenEnergy), whose primary responsibility includes managing market risks associated with the changing market prices for electricity purchased and sold on behalf of the Registrant.
AmerenEnergy utilizes several techniques to mitigate its market risk for electricity, 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 AmerenEnergy is allowed to utilize (which include forward contracts, futures contracts, and option contracts) are dictated by a risk management policy, which has been reviewed with the Auditing Committee of Ameren's Board of Directors. Compliance with the risk management policy is the responsibility of a risk management steering committee, consisting of Ameren officers and an independent risk management officer at AmerenEnergy.
As of December 31, 1999, the fair value of derivative financial instruments exposed to commodity price risk was immaterial. AmerenEnergy's primary use of derivatives has been limited to transactions that are either risk-neutral or that reduce price risk exposure of the Registrant.
ACCOUNTING MATTERS
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities and requires recognition of all derivatives as either assets or liabilities on the balance sheet measured at fair value. The intended use of the derivatives and their designation as either a fair value hedge, a cash flow hedge, or a foreign currency hedge will determine when the gains or losses on the derivatives are to be reported in earnings and when they are to be reported as a component of other comprehensive income. In June 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133," which delayed the effective date of SFAS 133 to all fiscal quarters of all fiscal years, beginning after June 15, 2000. Earlier application is still encouraged. The Registrant expects to adopt SFAS 133 in the first quarter of 2001.
The Registrant is currently evaluating the impact of SFAS 133 on its financial position and results of operations upon adoption. The Registrant's evaluation includes reviewing existing derivative instruments to determine whether they fall within the scope of SFAS 133. At this time, management believes that adoption of SFAS 133 will not have
a material impact on the Registrant's financial position or results of operations upon adoption based on the derivative instruments which existed as of December 31, 1999. However, changing market conditions, the volume of future transactions which may fall within the scope of SFAS 133, and potential amendments to SFAS 133 could change management's current assessment. As a result, SFAS 133 could increase the volatility of the Registrant's future earnings and could be material to the Registrant's financial position and results of operations upon adoption.
EFFECTS OF INFLATION AND CHANGING PRICES
The Registrant's rates for retail electric and gas utility service are generally regulated by the ICC. Non-retail electric rates are regulated by the FERC.
The current replacement cost of the Registrant's utility plant substantially exceeds its recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical costs through depreciation might not be adequate to replace plants in future years. Regulatory practice has been modified for the Registrant's generation portion of its business (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). In addition, the impact on common stockholders is mitigated to the extent depreciable property is financed with debt that is repaid with dollars of less purchasing power.
The cost of fuel for electric generation, which was previously reflected in billings to customers through a Uniform Fuel Adjustment Clause, has been added to base rates as provided for in the Law (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). Changes in gas costs are generally reflected in billings to customers through a Purchased Gas Adjustment Clause.
Inflation continues to be a factor affecting operations, earnings, stockholders' equity and financial performance.
SAFE HARBOR STATEMENT
Statements made in this report which are not based on historical facts, are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, financial performance and the Year 2000 Issue. In connection with the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Registrant is providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in subsequent securities filings, could cause results to differ materially from management expectations as suggested by such "forward-looking" statements: the effects of regulatory actions; changes in laws and other governmental actions; the impact on the Registrant of current regulations related to the phasing-in of the opportunity for some customers to choose alternative energy suppliers in Illinois; the effects of increased competition in the future due to, among other things, deregulation of certain aspects of the Registrant's business at both the state and Federal levels; future market prices for fuel and purchased power, electricity, and natural gas, including the use of financial instruments; average rates for electricity in the Midwest; business and economic conditions; interest rates; weather conditions; fuel prices and availability; generation plant performance; the impact of current environmental regulations on utilities and generating companies and the expectation that more stringent requirements will be introduced over time, which could potentially have a negative financial effect; monetary and fiscal policies; future wages and employee benefits costs; and legal and administrative proceedings.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information required to be reported by this item is included under "Market Risk Related to Financial Instruments and Commodity Instruments" in "Management's Discussion and Analysis of Financial Conditions and Results of Operations" under Item 7 herein.
REPORT OF INDEPENDENT ACCOUNTANTS ---------------------------------
To the Board of Directors and Shareholders of Central Illinois Public Service Company
In our opinion, the financial statements listed in the index appearing under Item 14(a)(1) on Page 37 present fairly, in all material respects, the financial position of Central Illinois Public Service Company at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. 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, 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 the opinion expressed above. The financial statements of Central Illinois Public Service Company for the year ended December 31, 1997 were audited by other independent accountants whose report dated January 31, 1997 expressed an unqualified opinion on those statements.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP St. Louis, Missouri February 2, 2000
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY BALANCE SHEET (Thousands of Dollars, Except Shares)
See Notes to Financial Statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY STATEMENT OF INCOME (Thousands of Dollars)
See Notes to Financial Statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY STATEMENT OF CASH FLOWS (Thousands of Dollars)
SUPPLEMENTAL DISCLOSURE OF NONCASH TRANSACTION: An extraordinary charge to earnings was recorded in the fourth quarter of 1997 for the write-off of generation-related regulatory assets and liabilities of the Registrant's retail electric business as a result of electric industry restructuring legislation enacted in Illinois in December 1997. The write-off reduced earnings $25 million, net of income taxes. See Note 2 - Regulatory Matters under Notes to Financial Statements for further information.
See Notes to Financial Statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY ---------------------------------------
STATEMENT OF RETAINED EARNINGS - ------------------------------ (Thousands of Dollars)
- ------------------------------------------------------------------------------- Year Ended December 31, 1999 1998 1997 - ------------------------------------------------------------------------------- Balance at Beginning of Period $455,337 $451,477 $459,942 - ------------------------------------------------------------------------------- Add: Net income 53,980 80,147 38,620 - ------------------------------------------------------------------------------- 509,317 531,624 498,562 - ------------------------------------------------------------------------------- Deduct: Common stock dividends 90,342 72,285 43,300 Preferred stock dividends 4,630 4,002 3,785 - ------------------------------------------------------------------------------- 94,972 76,287 47,085 - ------------------------------------------------------------------------------- Balance at End of Period $414,345 $455,337 $451,477 - -------------------------------------------------------------------------------
SELECTED QUARTERLY INFORMATION (Unaudited) - ------------------------------- (Thousands of Dollars)
- -------------------------------------------------------------------------------- Operating Operating Net Net Income Revenues Income Income (Loss) After Quarter Ended (Loss) (Loss) Preferred Stock Dividends - -------------------------------------------------------------------------------- March 31, 1999 207,772 24,709 14,315 13,347 March 31, 1998 199,515 21,732 12,118 11,134 June 30, 1999 221,929 29,981 20,680 19,763 June 30, 1998 214,829 28,429 19,349 18,468 September 30, 1999 279,327 53,845 43,283 42,326 September 30, 1998 (a) 246,675 50,623 39,672 38,736 December 31, 1999 (b) 219,094 (13,820) (24,298) (25,289) December 31, 1998 186,405 19,260 9,008 8,064 - --------------------------------------------------------------------------------
(a) The third quarter of 1998 included a nonrecurring charge related to the targeted separation plan that reduced net income $4 million. (See Note 4 - Targeted Separation Plan under Notes to Financial Statements for further information.) (b) The fourth quarter of 1999 included a charge for coal supply contract terminations that reduced net income $31 million. (See Note 11 - Commitments and Contingencies under Notes to Financial Statements for further information).
Other changes in quarterly earnings are due to the effect of weather on sales and other factors that are characteristic of public utility operations.
See Notes to Financial Statements.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 1999
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation
Central Illinois Public Service Company (AmerenCIPS or the Registrant) is a subsidiary of Ameren Corporation (Ameren), which is the parent company of two utility operating companies, the Registrant and Union Electric Company (AmerenUE). Ameren is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA) formed in December 1997 upon the merger of CIPSCO Incorporated (the Registrant's former parent) and AmerenUE (the Merger). Both Ameren and its subsidiaries are subject to the regulatory provisions of the PUHCA. The operating companies are engaged principally in the generation, transmission, distribution and sale of electric energy and the purchase, distribution, transportation and sale of natural gas in the states of Illinois and Missouri. Contracts among the companies--dealing with jointly-operated generating facilities, interconnecting transmission lines, and the exchange of electric power--are regulated by the Federal Energy Regulatory Commission (FERC) or the Securities and Exchange Commission (SEC). Administrative support services are provided to the Registrant by a separate Ameren subsidiary, Ameren Services Company. The Registrant serves 400,000 electric and 175,000 gas customers in a 20,000 square-mile region of central and southern Illinois.
In conjunction with the Illinois Electric Service Customer Choice and Rate Relief Law of 1997 (the Law), the Registrant has received regulatory approvals to transfer its generating facilities to Ameren Energy Generating Company (AEG), a nonregulated, indirectly wholly-owned subsidiary of Ameren. The transfer of the assets and liabilities (at historical net book value of approximately $600 million) is currently scheduled to occur in May 2000. Discussion below relating to "forward-looking" statements reflects information assuming that the transfer will occur as scheduled. For additional information on the law, its impact on the Registrant, and the generating facilities transfer, see Note 2 - Regulatory Matters.
The Registrant also has a 20% interest in Electric Energy, Inc. (EEI), which is accounted for under the equity method of accounting. EEI owns and operates an electric generating and transmission facility in Illinois that supplies electric power primarily to a uranium enrichment plant located in Paducah, Kentucky.
Regulation In addition to the SEC, the Registrant is regulated by the Illinois Commerce Commission (ICC) and the FERC. The accounting policies of the Registrant conform to U.S. generally accepted accounting principles (GAAP). See Note 2 - Regulatory Matters for further information.
Property and Plant The cost of additions to, and betterments of, units of property and plant is capitalized. Cost includes labor, material, applicable taxes and overheads. An allowance for funds used during construction is also added for the Registrant's regulated assets, and interest incurred during construction is added for nonregulated assets. Maintenance expenditures and the renewal of items not considered units of property are charged to income, as incurred. When units of depreciable property are retired, the original cost and removal cost, less salvage value, are charged to accumulated depreciation.
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 in 1999, 1998, and 1997 was approximately 3% of the average depreciable cost.
Fuel and Gas Costs The cost of fuel for electric generation is reflected in base rates with no provision for changes to be made through a fuel adjustment clause. (See Note 2 - Regulatory Matters for further information.) In 1997, changes in fuel costs were generally reflected in billings to electric customers through a fuel adjustment clause. Changes in gas costs are generally reflected in billings to gas customers through a purchased gas adjustment clause.
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.
Income Taxes The Registrant is included in the consolidated federal income tax return filed by Ameren. Income taxes are allocated to the individual companies based on their respective taxable income or loss. 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.
Allowance for Funds Used During Construction Allowance for funds used during construction (AFC) is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds (preferred and common stockholders' equity) applicable to the Registrant's regulated construction program are capitalized as a cost of construction. AFC 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 AFC, as well as other construction costs, occurs when completed projects are placed in service and reflected in customer rates. The AFC rates used were 5% during 1999, 6% during 1998 and 8% during 1997.
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 The Registrant accrues an estimate of electric and gas revenues for service rendered, but unbilled, at the end of each accounting period.
Energy Contracts The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) Issue 98-10, "Accounting for Energy Trading and Risk Management Activities" became effective on January 1, 1999. EITF 98-10 provides guidance on the accounting for energy contracts entered into for the purchase or sale of electricity, natural gas, capacity and transportation. The EITF reached a consensus in EITF 98-10 that sales and purchase activities being performed need to be classified as either trading or nontrading. Furthermore, transactions that are determined to be trading activities would be recognized on the balance sheet measured at fair value, with gains and losses included in earnings. AmerenEnergy, Inc., an energy marketing subsidiary of Ameren, enters into contracts for the sale and purchase of energy on behalf of the Registrant and AmerenUE. Currently, virtually all of AmerenEnergy's transactions are considered nontrading activities and are accounted for using the accrual or settlement method, which represents industry practice. EITF 98-10 did not have a material impact on the Registrant's financial position or results of operations upon adoption.
Software Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use" became effective on January 1, 1999. SOP 98-1 provides guidance on accounting for the costs of computer software developed or obtained for internal use. Under SOP 98-1, certain costs may be capitalized and amortized over some future period. SOP 98-1 did not have a material impact on the Registrant's financial position or results of operations upon adoption.
Evaluation of Assets for Impairment Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" prescribes general standards for the recognition and measurement of impairment losses. The Registrant determines if long-lived assets are impaired by comparing their undiscounted expected future cash flows to their carrying amount. An impairment loss is recognized if the undiscounted expected future cash flows are less than the carrying amount of the asset. SFAS 121 also requires that regulatory assets which are no longer probable of recovery through future revenues be charged to earnings (see Note 2 - Regulatory Matters for further information). As of December 31, 1999, no impairment was identified.
Use of Estimates 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 and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from those estimates.
Reclassifications Certain reclassifications have been made to prior-years' financial statements to conform with 1999 reporting.
NOTE 2 - Regulatory Matters
Illinois Electric Restructuring Certain states are considering proposals or have adopted legislation that will promote competition at the retail level. In December 1997, the Governor of Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997 (the Law) providing for electric utility restructuring in Illinois. This legislation introduces competition into the supply of electric energy at retail in Illinois.
Under the Law, retail direct access, which allows customers to choose their electric generation suppliers, will be phased in over several years. Access for commercial and industrial customers will occur over a period from October 1999 to December 2000, and access for residential customers will occur after May 1, 2002.
As a requirement of the Law, in March 1999, the Registrant filed delivery service tariffs with the ICC. These tariffs would be used by electric customers who choose to purchase their power from alternate suppliers. On August 25, 1999, the ICC issued an order approving the delivery services tariffs, with an allowed rate of return on equity of 10.45%. The Registrant and AmerenUE filed a joint petition for rehearing of that order requesting the ICC to alter its conclusions on a number of issues. On October 13, 1999, the ICC granted a rehearing on certain issues. An order on this reopened proceeding was issued in 2000 resolving all outstanding issues.
The Law included a 5% residential electric rate decrease for the Registrant's electric customers, effective August 1, 1998. This rate decrease reduced electric revenues by approximately $7 million in 1999. The Registrant may be subject to additional 5% residential electric rate decreases in each of 2000 and 2002, to the extent its rates exceed the Midwest utility average at that time. The Registrant's rates are currently below the Midwest utility average.
As a result of the Law, the Registrant filed a proposal with the ICC to eliminate the electric fuel adjustment clause for Illinois retail customers, thereby including historical levels of fuel costs in base rates. The ICC approved the Registrant's filing in early 1998.
The Law also contains a provision requiring that one-half of excess earnings from the Illinois jurisdiction for the years 1998 through 2004 to be refunded to the Registrant's 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 an Index, as defined in the 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 30-year U.S. Treasury bonds, plus prescribed percentages ranging from 4% to 7%. Filings must be made with the ICC on, or before, March 31 of each year 2000 through 2005.
In conjunction with another provision of the Law, in July 1999, the Registrant filed a notice with the ICC that it intends to transfer its generating facilities (all in Illinois) to Ameren Energy Generating Company (AEG), a nonregulated, indirectly wholly-owned subsidiary of Ameren. The formation of the new generating subsidiary, as well as the transfer of the Registrant's generating assets and liabilities (at historical net book value of approximately $600 million) and certain power sales contracts in exchange for an intercompany note receivable, was subject to regulatory approvals from the ICC, the FERC, and the Missouri Public Service Commission, all of which have been received as of March 10, 2000. An additional PUHCA-related determination that will permit the new generating subsidiary to operate as an Exempt Wholesale Generator is being sought from the FERC. The generating subsidiary will include most of the new combustion turbine generators being acquired by Ameren in addition to the Registrant's facilities. The new generating subsidiary is scheduled to be operational in May 2000. The proposed transfer of the Registrant's generating assets and liabilities had no effect on the Registrant's financial statements as of December 31, 1999.
Once the transfer is completed, a power sales agreement will be in place between the new generating subsidiary and a nonregulated marketing affiliate for all generation. The marketing affiliate will have a power sales agreement with the Registrant to supply it sufficient generation to meet native load requirements over the term of the agreement.
Other provisions of the Law include (1) potential recovery of a portion of strandable costs, which represent costs which would not be recoverable in a restructured environment, through a transition charge collected from customers who choose another electric supplier; (2) a mechanism to securitize certain future revenues; and (3) a provision relieving the Registrant of the requirement to file electric rate cases or alternative regulatory plans, following the consummation of the Merger to reflect the effects of net merger savings.
The Registrant's accounting policies and financial statements conform to GAAP applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Such effects concern mainly the time at which various items enter into the determination of net income in order to follow the principle of matching costs and revenues. For example, SFAS 71 allows the Registrant to record certain assets and liabilities (regulatory assets and regulatory liabilities) that are expected to be recovered or settled in future rates and would not be recorded under GAAP for nonregulated entities. In addition, reporting under SFAS 71 allows companies whose service obligations and prices are regulated to maintain assets on their balance sheets representing costs they reasonably expect to recover from customers, through inclusion of such costs in future rates. SFAS 101, "Accounting for the Discontinuance of Application of FASB Statement No. 71," specifies how an enterprise that ceases to meet the criteria for application of SFAS 71 for all or part of its operations should report that event in its financial statements. In general, SFAS 101 requires that the enterprise report the discontinuance of SFAS 71 by eliminating from its balance sheet all regulatory assets and liabilities related to the applicable portion of the business that no longer meets SFAS 71 criteria. The EITF has concluded that application of SFAS 71 accounting should be discontinued once sufficiently detailed deregulation legislation is issued for a separable portion of a business for which a plan of deregulation has been established. However, the EITF further concluded that regulatory assets associated with the deregulated portion of the business, which will be recovered through tariffs charged to customers of a regulated portion of the business, should be associated with the regulated portion of the business from which future cash recovery is expected (not the portion of the business from which the costs originated). Those assets can therefore continue to be carried on the regulated entity's balance sheet to the extent such assets are recoverable. In addition, SFAS 121 establishes accounting standards for the impairment of long-lived assets.
Due to the enactment of the Law, prices for the retail supply of electric generation are expected to transition from cost-based, regulated rates to rates determined in large part by competitive market forces in the state of Illinois. As a result, the Registrant discontinued application of SFAS 71 for the retail portion of its generating business (i.e., the portion of the Registrant's business related to the supply of electric energy) in the fourth quarter of 1997. The Registrant evaluated the impact of the Law on the future recoverability of its regulatory assets and liabilities related to the generation portion of its business and determined that it was not probable that such assets and liabilities would be recovered through cash flows from the regulated portion of its business. Accordingly, the Registrant's generation-related regulatory assets and liabilities of its retail electric business were written off in the fourth quarter of 1997, resulting in an extraordinary charge to earnings of $25 million, net of income taxes. These regulatory assets and liabilities included previously incurred costs originally expected to be collected/refunded in future revenues, such as coal contract restructuring costs, costs associated with an abandoned scrubber at a generating plant, and income tax-related regulatory assets and liabilities. In addition, the Registrant has evaluated whether the recoverability of the costs associated with its remaining net generation-related assets has been impaired as defined under SFAS 121. The Registrant has concluded that impairment, as defined under SFAS 121, does not exist and that no plant writedowns are necessary at this time. At December 31, 1999, the Registrant's net investment in generation facilities related to its retail jurisdiction approximated $647 million and was included in electric plant in-service on the Registrant's balance sheet.
In August 1999, the Registrant filed a transmission system rate case with the FERC. This filing was primarily designed to implement, rates, terms and conditions for transmission service for those retail customers who choose other suppliers as allowed under the Law. On October 14, 1999, the FERC issued an order suspending the proposed rates until March 25, 2000. In January 2000, a settlement in principle was reached with the FERC trial staff and other interested parties. The settlement establishes the rates for transmission service that are to go into effect in the first quarter of 2000. The settlement is subject to approval by the FERC. The Registrant expects that the FERC will approve the settlement in 2000.
The provisions of the Law could also result in lower revenues, reduced profit margins and increased costs of capital and operations expense. At this time, the Registrant is unable to determine the impact of the Law on its future financial condition, results of operations or liquidity.
Gas In February 1999, the ICC approved an $8 million annual rate increase for natural gas service. The increase became effective in February 1999.
Midwest ISO In 1998, the Registrant joined a group of companies that support the formation of the Midwest Independent System Operator (Midwest ISO). An ISO operates, but does not own, electric transmission systems and maintains system reliability and security while alleviating pricing issues associated with the "pancaking" of rates. The Midwest ISO would be regulated by FERC. Thirteen transmission-owning utilities have joined the Midwest ISO, as of December 31, 1999. The FERC conditionally approved the formation of the Midwest ISO in September 1998, and it is expected to be operational during the year 2001. The ICC has authorized the Registrant to join the Midwest ISO and to transfer control of its transmission facilities to the Midwest ISO. The Midwest ISO covers 14 states, represents portions of 60,000 miles of transmission line and controls $8 billion in assets. The Registrant believes that the operation of the Midwest ISO will not have a material adverse effect on its financial condition, results of operations or liquidity.
In December 1999, the FERC issued its Order 2000 relating to Regional Transmission Organizations (RTOs) that would meet certain characteristics such as size and independence. Order 2000 calls on all transmission owners to join RTOs. In particular, all public utilities that own, operate, or control interstate transmission facilities must file with the FERC by October 15, 2000, a proposal for an RTO, or alternatively a description of efforts by the utility to join an RTO. The Registrant expects that its participation in the Midwest ISO will satisfy the requirements of Order 2000.
Regulatory Assets and Liabilities In accordance with SFAS 71, the Registrant has deferred certain costs pursuant to actions of its regulators, and is currently recovering such costs in electric rates charged to customers.
At December 31, the Registrant had recorded the following regulatory assets and regulatory liability: - ------------------------------------------------------------------------- (In Millions) 1999 1998 - ------------------------------------------------------------------------- Regulatory Assets: Income taxes $22 $25 Unamortized loss on reacquired debt 7 8 Other 13 15 - ------------------------------------------------------------------------- Regulatory Assets $42 $48 - ------------------------------------------------------------------------- Regulatory Liability: Income taxes $34 $40 - ------------------------------------------------------------------------- Regulatory Liability $34 $40 - -------------------------------------------------------------------------
Income Taxes: See Note 9 - Income Taxes. Unamortized Loss on Reacquired Debt: Represents losses related to refunded 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.
The Registrant continually assesses the recoverability of its 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.
NOTE 3 - Related Party Transactions
The Registrant has transactions in the normal course of business with other Ameren subsidiaries. These transactions are primarily comprised of power purchases and sales and services received or rendered. Intercompany receivables included in other accounts and notes receivable were approximately $12 million and $2 million, respectively, as of December 31, 1999 and 1998. Intercompany payables included in accounts and wages payable totaled approximately $35 million and $12 million, respectively, as of December 31, 1999 and 1998.
In addition, the Registrant has the ability to borrow funds from Ameren or AmerenUE or invest funds through a regulated money pool agreement. At December 31, 1999, the Registrant had outstanding intercompany borrowings of $133 million through the regulated money pool. See Note 7 - Short-Term Borrowings for further information.
NOTE 4 - Targeted Separation Plan
In July 1998, Ameren offered separation packages to employees whose positions were eliminated through a targeted separation plan (TSP). During the third quarter of 1998, a nonrecurring, pretax charge of $7 million was recorded, which reduced earnings $4 million, representing the Registrant's share of costs incurred to implement the TSP.
NOTE 5 - Concentration of Risk
Market Risk The Registrant engages in price risk management activities related to electricity and fuel. In addition to buying and selling these commodities, the Registrant uses derivative financial instruments to manage market risks and reduce exposure resulting from fluctuations in interest rates and the prices of electricity and fuel. Derivative instruments used include futures, forward contracts and options. The use of these types of contracts allows the Registrant to manage and hedge its contractual commitments and reduce exposure related to the volatility of commodity market prices.
Credit Risk Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. New York Mercantile Exchange (NYMEX) traded futures contracts are guaranteed by NYMEX and have nominal credit risk. On all other transactions, the Registrant is exposed to credit risk in the event of nonperformance by the counterparties in the transaction.
The Registrant's financial instruments subject to credit risk consist primarily of trade accounts receivable and forward contracts. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups comprising the Registrant's customer base. The Registrant's revenues are primarily derived from sales of electricity and natural gas to customers in Illinois. For each counterparty in forward contracts, the Registrant analyzes the counterparty's financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis through a credit risk management program.
NOTE 6 - Preferred Stock
At December 31, 1999 and 1998, AmerenCIPS had 4.6 million shares of authorized preferred stock. There were 2 million shares of cumulative preferred and 2.6 million shares of preferred without par value (aggregate stated value not to exceed $65 million) authorized.
Outstanding preferred stock is entitled to cumulative dividends and is redeemable at the prices shown in the following table: - --------------------------------------------------------------------------------
- -------------------------------------------------------------------------------- Preferred Stock Not Subject to Mandatory Redemption: ( Dollars in Millions) - -------------------------------------------------------------------------------- Redemption Price December 31, (per share) 1999 1998 Par value $100 Series-- 4.00% Series - 150,000 shares $101.00 $15 $15 4.25% Series - 50,000 shares 102.00 5 5 4.90% Series - 75,000 shares 102.00 8 8 4.92% Series - 50,000 shares 103.50 5 5 5.16% Series - 50,000 shares 102.00 5 5 1993 Auction - 300,000 shares 100.00 - note(a) 30 30 6.625% Series - 125,000 shares 100.00 12 12 - -------------------------------------------------------------------------------- TOTAL PREFERRED STOCK OUTSTANDING NOT SUBJECT TO MANDATORY REDEMPTION $80 $80 - --------------------------------------------------------------------------------
(a) Dividend rates, and periods during which such rates apply, vary depending on the Registrant's selection of certain defined dividend period lengths. The average dividend rate during 1999 was 3.89%.
- --------------------------------------------------------------------------------
NOTE 7 - Short-Term Borrowings
Short-term borrowings of the Registrant consist of bank loans (maturities generally on an overnight basis) and commercial paper (maturities generally within 10-45 days). No short-term borrowings were outstanding at December 31, 1999. At December 31, 1998, short-term borrowings of $47 million were outstanding with weighted average interest rates of 4.9%.
At December 31, 1999, the Registrant had committed bank lines of credit aggregating $30 million (all of which was unused and available at such date) which make available interim financing at various rates of interest based on LIBOR, the bank certificate of deposit rate, or other options. These lines of credit are renewable annually at various dates throughout the year.
Also, the Registrant has the ability to borrow up to approximately $950 million from Ameren or AmerenUE through a regulated money pool agreement. The regulated money pool was established to coordinate and provide for certain short-term cash and working capital requirements and is administered by Ameren Services Company. Interest is calculated at varying rates of interest depending on the composition of internal and external funds in the regulated money pool. At December 31, 1999, the Registrant had $133 million of intercompany borrowings outstanding and $520 million available through the regulated money pool.
NOTE 8 - Long-Term Debt
Long-term debt outstanding at December 31, was: - ------------------------------------------------------------------------------ (In Millions) 1999 1998 - ------------------------------------------------------------------------------ First Mortgage Bonds - note (a) - ------------------------------------------------------------------------------ 7 1/8% Series W paid in 1999 $ - 50 6.00% Series Z due 2000 25 25 6.73% Series 1997-2 due 2001 20 20 6 3/4% Series Y due 2002 23 23 6 3/8% Series Z due 2003 40 40 6.49% Series 1995-1 due 2005 20 20 7.05% Series 1997-2 due 2006 20 20 7 1/2% Series X due 2007 50 50 7.61% Series 1997-2 due 2017 40 40 6.125% Series due 2028 60 60 Other 5.375% - 6.99% due 2000 through 2008 50 60 - ------------------------------------------------------------------------------ 348 408 - ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ Pollution Control Loan Obligations - ------------------------------------------------------------------------------ 1990 Series B 7.60% due 2013 32 32 1990 Series A 7.60% due 2014 20 20 1993 Series C-1 due 2026 - note (b) 35 35 1993 Series C-2 5.70% due 2026 25 25 1993 Series A 6 3/8% due 2028 35 35 Other 5.40% - 5.90% due 2028 35 35 - ------------------------------------------------------------------------------ 182 182 - ------------------------------------------------------------------------------ Unamortized Discount and Premium on Debt (1) (2) - ------------------------------------------------------------------------------ Maturities Due Within One Year (35) (60) - ------------------------------------------------------------------------------ Total Long-Term Debt $494 $528 - ------------------------------------------------------------------------------ (a) At December 31, 1999, substantially all of the property and plant was mortgaged under, and subject to liens of, the respective indentures pursuant to which the bonds were issued. (b) The interest rate for the year 1999 was 3.34%. Since August 15, 1998, the actual interest rates vary since the bonds are currently in the weekly interest rate mode. Interest rate modes can be changed by the Registrant at the end of any interest rate mode period.
Maturities of long-term debt through 2004 are as follows: - ------------------------------------------------------------------------ (In Millions) Principal Amount - ------------------------------------------------------------------------ 2000 $35 2001 30 2002 33 2003 45 2004 - - ------------------------------------------------------------------------
NOTE 9 - Income Taxes
Total income tax expense for 1999 resulted in an effective tax rate of 36% on earnings before income taxes (36% in 1998 and 35% in 1997).
Principal reasons such rates differ from the statutory federal rate: - -------------------------------------------------------------------------------- 1999 1998 1997 - -------------------------------------------------------------------------------- Statutory federal income 35% 35% 35% tax rate Increases (decreases) from: Depreciation differences - (3) - Amortization of investment tax credit (3) (2) (3) State income tax 5 5 5 Other (1) 1 (2) - -------------------------------------------------------------------------------- Effective income tax rate 36% 36% 35% - --------------------------------------------------------------------------------
Income tax expense components: - -------------------------------------------------------------------------------- (In Millions) 1999 1998 1997 - -------------------------------------------------------------------------------- Taxes currently payable (principally federal): Included in operating expenses $52 $60 $39 - -------------------------------------------------------------------------------- $52 $60 $39 - --------------------------------------------------------------------------------
Deferred taxes (principally federal): Included in operating expenses-- Depreciation differences $ (7) $(10) $(4) Other (12) (1) 2 - -------------------------------------------------------------------------------- $(19) $(11) $(2) - --------------------------------------------------------------------------------
Deferred investment tax credits, Amortization Included in operating expenses $ (2) $ (3) $ (3) - -------------------------------------------------------------------------------- Total income tax expense $ 31 $46 $34 - --------------------------------------------------------------------------------
In accordance with SFAS 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.
The Registrant adjusts its 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.
Temporary differences gave rise to the following deferred tax assets and deferred tax liabilities at December 31: - -------------------------------------------------------------------------------- (In Millions) 1999 1998 - -------------------------------------------------------------------------------- Accumulated Deferred Income Taxes: Accelerated depreciation $216 $228 Capitalized taxes and expenses 78 87 Regulatory liabilities, net (29) (32) Prepayments (15) (27) Deferred benefit costs (11) - - -------------------------------------------------------------------------------- Total net accumulated deferred income tax liabilities $239 $256 - --------------------------------------------------------------------------------
NOTE 10 - Retirement Benefits
On January 1, 1999, the AmerenUE and the AmerenCIPS defined-benefit pension plans combined to form the Ameren Retirement Plan. The Ameren plan covers qualified employees of the Registrant. Benefits are based on the employees' years of service and compensation. The Ameren plan is funded in compliance with income tax regulations and federal funding requirements. The Registrant, along with other subsidiaries of Ameren, is a participant in the Ameren plan and is responsible for its proportional share of the costs and the assets or liabilities. The Registrant's share of the pension costs in 1999 was $6 million, of which approximately 20% was charged to construction accounts. The AmerenCIPS pension plan information for 1998 and 1997 is presented separately.
Pension costs for the years 1998 and 1997 were $9 million and $5 million, respectively, of which approximately 19% in 1998 and 15% in 1997 was charged to construction accounts.
In 1998, the Registrant changed its measurement date for valuation of plan assets and liabilities to December 31.
Funded Status of Pension Plan: - ------------------------------------------------------------------------ (In Millions) 1998 - ------------------------------------------------------------------------ Change in benefit obligation Net benefit obligation at beginning of year $249 Service cost 8 Interest cost 17 Amendments 5 Actuarial loss 8 Special termination benefit charge 5 Benefits paid (31) - ------------------------------------------------------------------------ Net benefit obligation at end of year 261
Change in plan assets * Fair value of plan assets at beginning of year 319 Actual return on plan assets 38 Employer contributions 5 Benefits paid (31) - ------------------------------------------------------------------------ Fair value of plan assets at end of year 331
Funded status - excess (70) Unrecognized net actuarial gain 73 Unrecognized prior service cost (13) Unrecognized net transition asset 2 - ------------------------------------------------------------------------ Prepaid pension cost at December 31 $ (8) - ------------------------------------------------------------------------ * Plan assets consist principally of common and preferred stocks, bonds, money market instruments and real estate.
Components of Net Periodic Benefit Cost: - ------------------------------------------------------------------------ (In Millions) 1998 1997 - ------------------------------------------------------------------------ Service cost $ 8 $ 7 Interest cost 17 16 Expected return on plan assets (22) (19) Amortization of prior service cost 1 1 Special termination benefit charge 5 - - ------------------------------------------------------------------------ Net periodic benefit cost $ 9 $ 5 - ------------------------------------------------------------------------
Weighted-average Assumptions for Actuarial Present Value of Projected Benefit Obligations: - ------------------------------------------------------ - ------------------------------------------------------ Discount rate at measurement date 6.75% Expected return on plan assets 8.5% Increase in future compensation 4% - ------------------------------------------------------
In addition to providing pension benefits, the Registrant provides certain health care and life insurance benefits for retired employees. The Registrant's postretirement benefit plans cover substantially all employees of AmerenCIPS as well as certain employees of Ameren Services Company. The Registrant accrues the expected postretirement
benefit costs during employees' years of service. The following is information related to the Registrant's postretirement benefit plans as of December 31.
The Registrant's funding policy is to fund two Voluntary Employee Beneficiary Association trusts (VEBAs) and the 401(h) account established within the Registrant's retirement income trust with the lesser of the net periodic cost or the amount deductible for federal income tax purposes. In 1998, the Registrant changed its measurement date for valuation of plan assets and liabilities to December 31. Postretirement benefit costs were $3 million for 1999, $6 million for 1998 and $12 million for 1997, of which approximately 10% was charged to construction accounts in 1999, 20% in 1998 and 17% in 1997. AmerenCIPS' transition obligation at December 31, 1999 is being amortized over the next 13 years.
The ICC allows the recovery of postretirement benefit costs in rates to the extent that such costs are funded.
Funded Status of Postretirement Benefit Plans: - ----------------------------------------------------------------------------- (In Millions) 1999 1998 - ----------------------------------------------------------------------------- Change in benefit obligation Net benefit obligation at beginning of year $152 $140 Service cost 3 3 Interest cost 9 10 Actuarial (gain)/loss (22) 4 Benefits paid (4) (5) - ----------------------------------------------------------------------------- Net benefit obligation at end of year 138 152
Change in plan assets * Fair value of plan assets at beginning of year 128 115 Actual return on plan assets 10 16 Employer contributions 1 4 401(h) transfer - (2) Benefits paid (4) (5) - ----------------------------------------------------------------------------- Fair value of plan assets at end of year 135 128
Funded status - deficiency 3 24 Unrecognized net actuarial gain 75 58 Unrecognized net transition obligation (71) (76) - ----------------------------------------------------------------------------- Postretirement benefit liability at December 31 $ 7 $ 6 - ----------------------------------------------------------------------------- * Plan assets consist principally of common and preferred stocks, bonds, money market instruments and real estate.
Components of Net Periodic Benefit Cost: - ------------------------------------------------------------------------------ (In Millions) 1999 1998 1997 - ------------------------------------------------------------------------------ Service cost $3 $3 $4 Interest cost 9 10 10 Expected return on plan assets (9) (8) (5) Amortization of: Transition obligation 6 5 5 Actuarial gain (6) (4) (2) - ------------------------------------------------------------------------------ Net periodic benefit cost $3 $6 $12 - ------------------------------------------------------------------------------
Assumptions for the Obligation Measurements: - ------------------------------------------------------------------------------ 1999 1998 - ------------------------------------------------------------------------------ Discount rate at measurement date 7.75% 6.75% Expected return on plan assets 8.5% 8.5% Medical cost trend rate - initial - 5.75% - ultimate 5.25% 4.75% Ultimate medical cost trend rate expected in year 2000 2000 - ------------------------------------------------------------------------------
A one percentage point increase in the medical cost trend rate is estimated to increase the net periodic cost and the accumulated postretirement benefit obligation approximately $2 million and $20 million, respectively. A one
percentage point decrease in the medical cost trend rate is estimated to decrease the net periodic cost and the accumulated postretirement benefit obligation approximately $2 million and $20 million, respectively.
NOTE 11 - Commitments and Contingencies
Information contained in this section could be impacted by the transfer of the Registrant's generating facilities to AEG. See discussion in Note 1 - Summary of Significant Accounting Policies for more information.
The Registrant is engaged in a capital program under which expenditures averaging approximately $62 million, including AFC, are anticipated during each of the next five years. This estimate assumes the transfer of the Registrant's generating facilities to AEG will occur in 2000.
The Registrant has commitments for the purchase of coal under long-term contracts. Coal contract commitments, including transportation costs, for 2000 through 2004 are estimated to total $761 million. Total coal purchases, including transportation costs, for 1999, 1998 and 1997 were $216 million, $189 million and $209, respectively. The Registrant also has existing contracts with pipeline and natural gas suppliers to provide, transport and store natural gas for distribution and electric generation. Gas-related contract cost commitments for 2000 through 2004 are estimated to total $54 million. Total delivered natural gas costs were $73 million for 1999, $69 million for 1998, and $97 million for 1997.
In the fourth quarter of 1999, the Registrant and two of its coal suppliers executed agreements to terminate their existing coal supply contracts, effective December 31, 1999. Under these agreements, the Registrant has made termination payments to the suppliers totaling approximately $52 million. These termination payments were recorded as a nonrecurring charge in the fourth quarter of 1999, equivalent to $31 million, after income taxes. Total pretax fuel cost savings from these termination agreements are estimated to be $183 million (or $131 million net of the termination payments) through 2010, which is the maximum period that would have remained on any of the terminated coal supply contracts. Approximately $66 million of pretax fuel cost savings is expected to be realized over the next three years.
During 1996, the Registrant restructured its contract with one of its major coal suppliers. In 1997, the Registrant paid a $70 million restructuring payment to the supplier, which allowed it to purchase at market prices low-sulfur, non-Illinois coal through the supplier (in substitution for the high-sulfur Illinois coal the Registrant was obligated to purchase under the original contract). Under the restructuring, the Registrant received options for future purchases of low-sulfur, non-Illinois coal from the supplier through 1999 at set negotiated prices.
By switching to low-sulfur coal, the Registrant was able to discontinue operating a generating plant scrubber. The benefits of the restructuring include lower cost coal, avoidance of significant capital expenditures to renovate the scrubber, and elimination of scrubber operating and maintenance costs (offset by scrubber retirement expenses). The net benefits of restructuring are expected to exceed $100 million through 2007. In December 1996, the ICC entered an order approving the switch to non-Illinois coal, recovery of the restructuring payment plus associated carrying costs (Restructuring Charges) through the retail Fuel Adjustment Clause (FAC) over six years, and continued recovery in rates of the undepreciated scrubber investment, plus costs of removal. Additionally, in May 1997 the FERC approved recovery of the wholesale portion of the Restructuring Charges through the wholesale FAC. As a result of the ICC and FERC orders, the Registrant classified the $72 million of the Restructuring Charges as a regulatory asset and, through December 1997, recovered approximately $10 million of the Restructuring Charges through the retail FAC and from wholesale customers. In November 1997, the ICC order was reversed on appeal by the Illinois Third District Appellate Court. The Illinois Supreme Court issued a final decision in December 1998 reversing the Appellate Court's opinion and affirming the ICC's order allowing the recovery of the Restructuring Charges through the retail FAC.
The recoverability of the Restructuring Charges under the retail FAC in Illinois was impacted by the Law. Among other things, the Law provides utilities with the option to eliminate the retail FAC and limits the ability of utilities to file a full rate case for its aggregate revenue requirements. After evaluating the impact of the Law on the future recoverability of the Registrant's Restructuring Charges through future rates, the Registrant wrote off the unamortized balance of the Illinois retail portion of its Restructuring Charges as of December 31, 1997 ($34 million, net of income taxes). See Note 2 - Regulatory Matters for further information.
Under Title IV of the Clean Air Act Amendments of 1990, the Registrant is required to significantly reduce total annual sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions by the year 2000. By switching to low-sulfur coal, the Registrant is meeting these requirements.
In July 1997, the United States Environmental Protection Agency (EPA) issued regulations revising the National Ambient Air Quality Standards for ozone and particulate matter. In May 1999, the U.S. Court of Appeals for the District of Columbia remanded the regulations back to the EPA for review. Litigation regarding appeals of these regulations is ongoing. New ambient standards may result in additional significant reductions in SO2 and NOx emissions from the Registrant's power plants by 2007. At this time, the Registrant is unable to predict the ultimate impact of these revised air quality standards on its future financial condition, results of operations or liquidity.
In an attempt to lower ozone levels across the eastern United States, the EPA issued the implementation of regulations in September 1998 to reduce NOx emissions from coal-fired boilers and other sources in 22 states, including Illinois (where all of the Registrant's coal-fired power plant boilers are located). The proposed regulations mandate a 75% reduction from 1990 levels by the year 2003 and require states to develop plans to reduce NOx emissions to help alleviate ozone problem areas. The NOx emissions reductions already achieved on several of the Registrant's coal-fired power plants will help to reduce the costs of compliance with this regulation. However, preliminary analysis of the regulations indicate that selective catalytic reduction technology will be required for some of the Registrant's units, as well as other additional controls.
In March 2000, the U.S. Court of Appeals for the District of Columbia substantially upheld the proposed NOx regulations but remanded portions of them to the EPA for further consideration. The implementation date of the regulations is uncertain and further legal challenge is possible. Assuming an implementation date of 2003, the Registrant currently estimates that its additional capital expenditures to comply with the final NOx could range from $125 million to $150 million. Associated operations and maintenance expenditures could increase $5 million to $8 million annually, beginning in 2003. The Registrant will explore alternatives to comply with these new regulations in order to minimize, to the extent possible, its capital costs and operating expenses. The Registrant is unable to predict the outcome of the litigation, the regulation implementation date or the ultimate impact of these standards on its future financial condition, results of operations or liquidity.
In November 1998, the United States signed an agreement with numerous other countries (the Kyoto Protocol) containing certain environmental provisions, which would require decreases in greenhouse gases in an effort to address the "global warming" issue. The Kyoto Protocol has not been ratified by the United States Senate. Implementation of the Kyoto Protocol in its present form would likely result in significantly higher capital costs and operations and maintenance expenses by the Registrant. At this time, the Registrant is unable to determine the impact of these proposals on the Registrant's future financial condition, results of operations or liquidity.
As of December 31, 1999, the Registrant was designated as a potentially responsible party (PRP) by federal and state environmental protection agencies at five hazardous waste sites. Other hazardous waste sites have been identified for which the Registrant may be responsible but has not been designated a PRP.
Costs relating to studies and remediation and associated legal and litigation expenses at the former manufactured gas plant sites located in Illinois are being accrued and deferred rather than expensed currently, pending recovery through environmental adjustment clause rate riders approved by the ICC. Through December 31, 1999, the total of the costs deferred, net of recoveries from insurers and through environmental adjustment clause rate riders, was $13 million.
The ICC has instituted reconciliation proceedings to review the Registrant's environmental remediation activities to determine whether the revenues collected from customers under its environmental adjustment clause rate riders were consistent with the amount of remediation costs prudently and properly incurred. Amounts found to have been incorrectly included under the riders would be subject to refund. Rulings from the ICC are pending with respect to these proceedings applicable to the years 1993 through 1998. The reconciliation proceedings relating to the Registrant's 1999 environmental remediation activities will commence by the ICC in 2000.
The Registrant continually reviews remediation costs that may be required for all of these sites. Any unrecovered environmental costs are not expected to have a material adverse effect on the Registrant's financial position, results of operations or liquidity.
The International Union of Operating Engineers Local 148 and the International Brotherhood of Electrical Workers Local 702 filed unfair labor practice charges with the National Labor Relations Board (NLRB), relating to the legality of the 1993 lockout of both unions by the Registrant. The NLRB issued complaints against the Registrant concerning its lockout. Both unions sought, among other things, back pay and other benefits for the period of the lockout. At that time, the Registrant estimated the amount of back pay and other benefits for both unions to be
approximately $17 million. In August 1998, a three-member panel of the NLRB reversed the May 1996 decision of its administrative law judge and ruled in favor of the Registrant holding that the lockout was lawful. In April 1999, the unions filed petitions for review with the U.S. Court of Appeals for the District of Columbia Circuit of the NLRB's August 1998 decision. This appeal is pending. The Registrant continues to believe that the lockout was both lawful and reasonable and that the final resolution of the dispute will not have a material adverse effect on its financial position, results of operations or liquidity.
Certain employees of the Registrant and its affiliated companies are represented by the International Brotherhood of Electrical Workers (IBEW) and the International Union of Operating Engineers. These employees comprise approximately 70% of Ameren's workforce. Labor agreements covering substantially all represented employees of the Registrant expired in 1999 and were renewed for a term expiring in 2002. Labor agreements which expired in 1999 have not been renewed with IBEW Locals 1439, 309, 649 and 1455, who collectively represent approximately 2,000 AmerenUE and Ameren Services Company employees. Negotiations with Local 1455 are still ongoing. However, after engaging in extensive good-faith bargaining with IBEW Locals 1439, 309 and 649, AmerenUE submitted a last, best and final offer to these collective bargaining units on February 2, 2000. The offer was rejected and AmerenUE informed these locals that it would implement the noneconomic portion of its offer effective March 6, 2000. The employees are currently working under the noneconomic portion of AmerenUE's last, best and final offer. The Registrant is unable to predict what further action, if any, these collective bargaining units will take or the response of the Registrant's union represented employees to any action by its affiliates' employees. The Registrant is unable to determine what, if any, impact these labor matters could have on its future financial condition, results of operations or cash flows.
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, the Registrant is unable to predict the impact of these changes on the Registrant's future financial condition, results of operations or liquidity. See Note 2 - Regulatory Matters for further information.
The Registrant is involved in other 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. The Registrant believes that the final disposition of these proceedings will not have a material adverse effect on its financial position, results of operations or liquidity.
NOTE 12 - 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 and Temporary Investments/Short-Term Borrowings The carrying amounts approximate fair value because of the short-term maturity of these instruments.
Preferred Stock 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 the Registrant 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.
Carrying amounts and estimated fair values of the Registrant's financial instruments at December 31:
1999 1998 - -------------------------------------------------------------------------------- (In Millions) Carrying Fair Carrying Fair Amount Value Amount Value - -------------------------------------------------------------------------------- Preferred stock $ 80 $ 66 $ 80 $ 75 Long-term debt (including current portion) 529 528 588 636 - --------------------------------------------------------------------------------
NOTE 13 - Segment Information
In 1998, the Registrant adopted SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." AmerenCIPS' business segments provide electric and gas service in portions of Illinois.
The accounting policies of the segments are the same as those described in Note 1 - Summary of Significant Accounting Policies. Segment data includes a charge allocating costs of administrative support services to each of the segments. These costs are accumulated in a separate Ameren subsidiary, Ameren Services Company, which provides a variety of support services to the Registrant. The Registrant evaluates the performance of its segments and allocates resources to them, based on revenues and operating income.
The table below presents information about the reported revenues and operating income of the Registrant for the years ended December 31:
- -------------------------------------------------------------------- (In Millions) Electric Gas Total - --------------------------------------------------------------------
- -------------------------------------------------------------------- - -------------------------------------------------------------------- Revenues $ 795 $133 $ 928 Operating income 86 9 95 - --------------------------------------------------------------------
- -------------------------------------------------------------------- - -------------------------------------------------------------------- Revenues $ 722 $125 $ 847 Operating income 115 5 120 - --------------------------------------------------------------------
- -------------------------------------------------------------------- - -------------------------------------------------------------------- Revenues $ 700 $152 $ 852 Operating income 95 7 102 - --------------------------------------------------------------------
Specified items included in segment profit/loss for the year ended December 31:
- ------------------------------------------------------------------------------ (In Millions) Electric Gas Total - ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ Depreciation, depletion and amortization expense $ 73 $ 8 $ 81 - ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ Depreciation, depletion and amortization expense $ 66 $ 8 $ 74 - ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ Depreciation, depletion and amortization expense $ 76 $ 7 $ 83 Extraordinary items (25) - (25) - ------------------------------------------------------------------------------
Specified item related to segment assets as of December 31:
- ----------------------------------------------------------------------------- (In Electric Gas Total Millions) - -----------------------------------------------------------------------------
- ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- Expenditures for additions to long-lived assets $ 86 $ 9 $ 95 - -----------------------------------------------------------------------------
- ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- Expenditures for additions to long-lived assets $ 60 $ 9 $ 69 - -----------------------------------------------------------------------------
- ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- Expenditures for additions To long-lived assets $ 105 $ 11 $ 116 - -----------------------------------------------------------------------------
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
On June 12, 1998, the Board of Directors of the Registrant's parent, Ameren, approved the recommendation of the Board's Auditing Committee and appointed PricewaterhouseCoopers LLP as auditors for the year 1998. Ameren's appointment of PricewaterhouseCoopers LLP also covered auditing services for Ameren's subsidiaries, which meant that Registrant's previous certifying accountant, Arthur Andersen LLP (Andersen), was, in effect, dismissed.
Andersen's report of the Registrant's financial statements for the year 1997 did not contain an adverse opinion or a disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope, or accounting principles. Further, during such period, and through the date of dismissal, there were no disagreements with Andersen on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure. Also, there was no occurrence of any kind of event set out in paragraphs (a) (1) (v) (A) through (D) of Item 304 of Regulation S-K.
PricewaterhouseCoopers LLP was also appointed as auditors for the year 1999.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Any information concerning directors required to be reported by this item is included under "Item (1): Election of Directors" in the AmerenCIPS' 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference.
Information concerning executive officers required by this item is reported in Part I of this Form 10-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Any information required to be reported by this item is included under "Compensation" in AmerenCIPS' 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Any information required to be reported by this item is included under "Security Ownership of Management" in AmerenCIPS' 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Any information required to be reported by this item is included under "Item (1): Election of Directors" in AmerenCIPS' 2000 definitive proxy statement filed pursuant to Regulation 14A and is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements and Financial Statement Schedule Covered by Report of Independent Accountants
Pages Herein
Report of Independent Accountants.................................17 Balance Sheet - December 31, 1999 and 1998........................18 Statement of Income - Years 1999, 1998, and 1997..................19 Statement of Cash Flows - Years 1999, 1998, and 1997..............20 Statement of Retained Earnings - Years 1999, 1998, and 1997.......21 Notes to Financial Statements.....................................22 Valuation and Qualifying Accounts (Schedule II) Years 1999, 1998, and 1997......................................38
2. Exhibits: See EXHIBITS beginning on Page 40
(b) Reports on Form 8-K. The Registrant filed a report on Form 8-K dated December 20, 1999 reporting the termination of coal supply contracts, the resulting estimated pretax fuel cost savings and the recording of a nonrecurring charge.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
Note: Uncollectible accounts charged off, less recoveries.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY (Registrant)
G. L. RAINWATER President and Chief Executive Officer
Date March 29, 2000 By /s/ Steven R. Sullivan -------------- ------------------------------------ (Steven R. Sullivan, Attorney-in-Fact)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title
/s/ G. L. Rainwater President, Chief Executive Officer and Director - ------------------------------ (Principal Executive Offcer) G. L. RAINWATER
/s/ Jerre E. Birdsong Treasurer - ------------------------------ (Principal Financial Officer) JERRE E. BIRDSONG
/s/ Warner L. Baxter Vice President, Controller and Director - ------------------------------ (Principal Accounting Officer) WARNER L. BAXTER
/s/ Paul A. Agathen Director - ------------------------------ PAUL A. AGATHEN
/s/ Donald E. Brandt Director - ------------------------------ DONALD E. BRANDT
/s/ Charles W. Mueller Director - ------------------------------ CHARLES W. MUELLER
By /s/ Steven R. Sullivan March 29, 2000 --------------------------- (Steven R. Sullivan, Attorney-in Fact)
EXHIBITS
Exhibits Filed Herewith
Exhibit No. Description
12 - Statement re Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements.
23 - Consent of Independent Accountants.
24 - Powers of Attorney.
27 - Financial Data Schedule.
Exhibits Incorporated By Reference
The following exhibits heretofore have been filed with the Securities and Exchange Commission pursuant to requirements of the Acts administered by the Commission. Such exhibits are identified by the references following the listing of each such exhibit, and they are hereby incorporated herein by reference.
Exhibit No. Description - ----------- ------------ 2 - Agreement and Plan of Merger, dated as of August 11, 1995, by and among CIPSCO Incorporated, Union Electric Company, Ameren Corporation and Arch Merger Inc. (Exhibit 2(a) filed with CIPSCO's and CIPS' Form 10-Q/A (Amendment No. 1) for the quarter ended June 30, 1995.)
3.01 - Restated Articles of Incorporation of CIPS. (Exhibit 3(b) filed with CIPS' Form 10-Q for the quarter ended March 31, 1994.)
3.02 - By-Laws of the Company as amended effective August 26, 1999. (September 30, 1999 Form 10-Q, Exhibit 3(ii).)
4 - Indenture of Mortgage or Deed of Trust dated October 1, 1941, from CIPS to Continental Illinois National Bank and Trust Company of Chicago and Edmond B. Stofft, as Trustees. (Exhibit 2.01 in File No. 2-60232.) Supplemental Indentures dated, respectively September 1, 1947, January 1, 1949, February 1, 1952, September 1, 1952, June 1, 1954, February 1, 1958 , January 1, 1959, May 1, 1963, May 1, 1964, June 1, 1965, May 1, 1967, April 1, 1970, April 1, 1971, September 1, 1971, May 1, 1972, December 1, 1973, March 1, 1974, April 1, 1975, October 1, 1976, November 1, 1976, October 1, 1978, August 1, 1979, February 1, 1980, February 1, 1986, May 15, 1992, July 1, 1992, September 15, 1992, April 1, 1993, and June 1, 1995 between CIPS and the Trustees under the Indenture of Mortgage or Deed of Trust referred to above (Amended Exhibit 7(b) in File No. 2-7341; Second Amended Exhibit 7.03 in File No. 2-7795; Second Amended Exhibit 4.07 in File No.2-9353; Amended Exhibit 4.05 in file No. 2-9802; Amended Exhibit 4.02 in File No. 2-10944; Amended Exhibit 2.02 in File No. 2-13866; Amended Exhibit 2.02 in File No. 2-14656; Amended Exhibit 2.02 in File No.2-21345; Amended Exhibit 2.02 in File No. 2-22326; Amended Exhibit 2.02 in File No. 2-23569; Amended Exhibit 2.02 in File No. 2-26284; Amended Exhibit 2.02 in File No. 2-36388; Amended Exhibit 2.02 in File No. 2-39587; Amended Exhibit 2.02 in File No. 2-41468; Amended Exhibit 2.02 in File No. 2-43912; Exhibit 2.03 in File No. 2-60232; Amended Exhibit 2.02 in File No. 2-50146; Amended Exhibit 2.02 in File No. 2-52886; Second Amended Exhibit 2.04 in File No. 2-57141; Amended Exhibit 2.04 in File No. 2-57557; Amended Exhibit 2.06 in File No. 2- 62564; Exhibit 2.02(a) in File No. 2-65914; Amended Exhibit 2.02(a) in File No. 2-66380; and Amended Exhibit 4.02 in File No. 33-3188; Exhibit 4.02 to Form 8-K dated May 15, 1992; Exhibit 4.02 to Form 8-K dated July 1, 1992; Exhibit 4.02 to Form 8-K dated September 15, 1992; Exhibit 4.02 to Form 8-K dated March 30, 1993; Exhibit 4.03 to Form 8-K dated June 5, 1995; Exhibit 4.03 to Form 8-K dated March 15, 1997; Exhibit 4.03 to Form 8-K dated June 1, 1997; and Exhibit 4.02, Post-Effective Amendment No. 1 in File No. 333-18473.)
4.01 - Indenture dated as of December 1, 1998 from CIPS to the Bank of New York relating to CIPS' Senior Notes, 5.375% due 2008 and 6.125% due 2028. (Exhibit 4.03, Post-Effective Amendment No. 1 to File No. 333-18473.)
Exhibit No. Description
10.01- Form of Director's Retirement Income Plan. (Exhibit 10.04 filed with 1990 Annual Report on Form 10-K.)
10.02- Form of Excess Benefit Plan. (Exhibit 10.10 filed with CIPSCO's and CIPS' 1994 Annual Report on Form 10-K.)
10.03- Amendment to Form of Excess Benefit Plan. (Exhibit 10.07 filed with CIPSCO's and CIPS' 1995 Annual Report on Form 10-K.)
10.04- Form of Special Executive Retirement Plan. (Exhibit 10.11 filed with CIPSCO's and CIPS' 1994 Annual Report on Form 10-K.)
10.05- Amendment to Form of Special Executive Retirement Plan. (Exhibit 10.09 filed with CIPSCO's and CIPS' 1995 Annual Report on Form 10-K.)
10.06- Ameren Long-Term Incentive Plan of 1998. (Ameren's 1998 Form 10-K, Exhibit 10.1.)
10.07- Ameren Change of Control Severance Plan. ((Ameren's 1998 Form 10-K, Exhibit 10.2.)
10.08- Ameren Deferred Compensation Plan for Members of the Ameren Leadership Team. (Ameren's 1998 Form 10-K, Exhibit 10.3.)
10.09- Ameren Deferred Compensation Plan for Members of the Board of Directors. (Ameren's 1998 Form 10-K, Exhibit 10.4.)
Note: Reports of the Company on Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-3672.
Reports of Ameren on Form 10-K are on file with the SEC under File Number 1-14756.