ITEM 1. BUSINESS.
GENERAL
Union Electric Company (AmerenUE or the Registrant) is a subsidiary of Ameren Corporation (Ameren), a holding company which is registered under the Public Utility Holding Company Act of 1935. On December 31, 1997, the Registrant and CIPSCO Incorporated (CIPSCO) combined with the result that the common shareholders of the Registrant and CIPSCO became the common shareholders of Ameren, and Ameren became the owner of 100% of the common stock of the Registrant and CIPSCO's operating subsidiaries, Central Illinois Public Service Company (AmerenCIPS) 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.
The Registrant, incorporated in Missouri in 1922, is successor to a number of companies, the oldest of which was organized in 1881. The Registrant is the largest electric utility in the State of Missouri and supplies electric service in territories in Missouri and Illinois having an estimated population of 2,600,000 within an area of approximately 24,500 square miles, including the greater St. Louis area. Retail gas service is supplied in 90 Missouri communities and in the City of Alton, Illinois and vicinity.
For the year 1999, 96% of total operating revenues was derived from the sale of electric energy and 4% from the sale of natural gas. Electric operating revenues as a percentage of total operating revenues in both 1998 and 1997 were also 96%.
The Registrant employed 4,184 persons at December 31, 1999. Approximately 77% of such employees are represented by local unions affiliated with the AFL-CIO. For information on the status of labor agreements with these unions, see Note 12 to the "Notes to Financial Statements" under Item 8 herein.
CAPITAL PROGRAM AND FINANCING
The Registrant is engaged in a capital program under which construction expenditures are expected to approximate $297 million in 2000. For the five-year period 2000-2004, construction expenditures are estimated at $1.6 billion. This estimate includes capital expenditures which will be incurred by the Registrant to meet new air quality standards for ozone and particulate matter.
During the five-year period ended 1999, gross additions to the property of the Registrant, including allowance for funds used during construction and excluding nuclear fuel, were approximately $1.3 billion (including $228 million in 1999) and property retirements were $347 million.
In addition to the funds required for construction during the 2000-2004 period, $611 million will be required to repay long-term debt as follows: $11 million in 2000; $227 million in 2002; $100 million in 2003; and $273 million in 2004. Amounts for years subsequent to 2000 do not include the Registrant's nuclear fuel lease payments since the amounts of such payments are not currently determinable.
The Registrant has transactions in the normal course of business with other Ameren subsidiaries and has the ability to borrow funds from Ameren or AmerenCIPS or invest funds through a regulated money pool agreement. At December 31, 1999, the Registrant had outstanding intercompany receivables of $166 million through the regulated money pool.
For information on the Registrant's capital program, external cash sources and intercompany borrowings, see "Liquidity and Capital Resources" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Notes 3, 6, 8 and 12 to the "Notes to Financial Statements" under Item 8 herein.
Financing Restrictions. Under the most restrictive earnings test contained in the Registrant's Indenture of Mortgage and Deed of Trust (Mortgage) relating to its First Mortgage Bonds (Bonds), no Bonds may be issued (except in certain refunding operations) unless the Registrant's net earnings available for interest after depreciation for 12 consecutive months within the 15 months preceding such issuance are at least two times annual interest charges on all Bonds and prior lien bonds then outstanding and to be issued (all calculated as provided in the Mortgage). Such ratio for the 12 months ended December 31, 1999 was 7.8, which would permit the Registrant to issue an additional $3.2 billion of Bonds (8% annual interest rate assumed). Additionally, the Mortgage permits issuance of new bonds up to (a) 60% of defined property additions, or (b) the amount of previous bonds retired or to be retired, or (c) the amount of cash put up for such purpose. At December 31, 1999, the aggregate amount of Bonds issuable under (a) and (b) above was approximately $2.4 billion.
The Registrant's Restated Articles of Incorporation restrict the Registrant from selling Preferred Stock unless its net earnings for a period of 12 consecutive months within 15 months preceding such sale are at least two and one-half times the annual dividend requirements on its Preferred Stock then outstanding and to be issued. Such ratio for the 12 months ended December 31, 1999 was 39.5, which would permit the Registrant to issue an additional $1.6 billion stated value of Preferred Stock (8% annual dividend rate assumed). Certain other financing arrangements require the Registrant to obtain prior consents to various actions by the Registrant, including any future borrowings, except for permitted financings such as borrowings under revolving credit agreements, the nuclear fuel lease, unsecured short-term borrowings (subject to certain conditions), and the issuance of additional Bonds.
RATES
For the year 1999, approximately 83%, 6%, and 11% of the Registrant's electric operating revenues were based on rates regulated by the Missouri Public Service Commission (MoPSC), the Illinois Commerce Commission (ICC), and the Federal Energy Regulatory Commission (FERC) of the U. S. Department of Energy, respectively. 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.
In February 2000, the Registrant filed a request with the MoPSC to increase rates approximately $12 million annually for natural gas service in its Missouri jurisdiction. The MoPSC has until January 2001 to render a decision.
FUEL SUPPLY
Oil and Gas. The actual and prospective use of such fuels for utility electric generation purposes is minimal, and the Registrant has not experienced and does not expect to experience difficulty in obtaining adequate supplies.
Coal. Because of uncertainties of supply due to potential work stoppages, equipment breakdowns and other factors, the Registrant has a policy of maintaining a coal inventory consistent with its expected burn practices.
Nuclear. The components of the nuclear fuel cycle required for nuclear generating units are as follows: (1) uranium; (2) conversion of uranium into uranium hexafluoride; (3) enrichment of uranium hexafluoride; (4) conversion of enriched uranium hexafluoride into uranium dioxide and the fabrication into nuclear fuel assemblies; and (5) disposal and/or reprocessing of spent nuclear fuel.
The Registrant has agreements and/or inventories to fulfill its Callaway Nuclear Plant needs for uranium, enrichment, fabrication and conversion services through 2002. Additional contracts will have to be entered into in order to supply nuclear fuel during the remainder of the life of the Plant, at prices which cannot now be accurately predicted. The Callaway Plant normally requires refueling at 18-month intervals, with the next regular refueling presently scheduled for the spring of 2001.
Under the Nuclear Waste Policy Act of 1982, the U. S. Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel. DOE currently charges one mill per nuclear generated kilowatt-hour sold for future disposal of spent fuel. Electric rates charged to customers provide for recovery of such costs. DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. The Registrant has sufficient storage capacity at the Callaway site until 2020 and has the capability for additional storage capacity through the licensed life of the plant in 2024. The delayed availability of the DOE's disposal facility is not expected to adversely affect the continued operation of Callaway Plant.
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 Notes 12 and 13 to the "Notes to Financial Statements" under Item 8 herein.
REGULATION
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 MoPSC and 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 and Missouri, 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.
Operation of the Callaway Plant is subject to regulation by the Nuclear Regulatory Commission. The Registrant's Facility Operating License for the Callaway Plant expires on October 18, 2024. The Registrant's Osage hydroelectric plant and its Taum Sauk pumped-storage hydro plant, as licensed projects under the Federal Power Act, are subject to certain federal regulations affecting, among other things, the general operation and maintenance of the projects. The Registrant's license for the Osage Plant expires on February 28, 2006, and its license for the Taum Sauk Plant expires on June 30, 2010. The Registrant's Keokuk Plant and dam located in the Mississippi River between Hamilton, Illinois and Keokuk, Iowa, are operated under authority, unlimited in time, granted by an Act of Congress in 1905.
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. See "Liquidity and Capital Resources" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Note 12 to the "Notes to Financial Statements" under Item 8 herein for a 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; public concerns about nuclear decommissioning and the disposal of nuclear wastes; 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, 12 and 13 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.
In planning its construction program, the Registrant is presently utilizing a forecast of kilowatthour sales growth of approximately 2.0% 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 AmerenCIPS. 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 40% of the capital stock of Electric Energy, Inc. ("EEI"), and its affiliate, AmerenCIPS, owns 20% of such stock. The balance is held by two other sponsoring com- panies -- 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 DOE, 20% to KU, 15% to AmerenUE, and 7.5% each to IG and AmerenCIPS.
As of December 31, 1999, the Registrant owned approximately 3,300 circuit miles of electric transmission lines. The Registrant also owned 2,800 miles of gas mains and three propane-air gas plants 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, steam distribution facilities in Jefferson City, Missouri and office buildings, warehouses, garages and repair shops.
The Registrant 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), except that (i) a portion of the Osage Plant reservoir, certain facilities at the Sioux Plant, certain of the Registrant's substations and most of its transmission and distribution lines and gas mains are situated on lands occupied under leases, easements, franchises, licenses or permits; (ii) the United States and/or the State of Missouri own, or have or may have, paramount rights to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River, on which certain generating and other properties of the Registrant are located; and (iii) the United States and/or State of Illinois and/or State of Iowa and/or City of Keokuk, Iowa own, or have or may have, paramount rights with respect to, certain lands lying in the bed of the Mississippi River on which a portion of the Registrant's Keokuk Plant is located.
Substantially all of the Registrant's property and plant is subject to the direct first lien of an Indenture of Mortgage and Deed of Trust dated June 15, 1937, 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.
Energy Gross Kilowatt Source Plant Location Installed Capability ------ ----- -------- -------------------- Coal Labadie Franklin County, MO 2,400,000 Rush Island Jefferson County, MO 1,224,000 Sioux St. Charles County, MO 1,006,000 Meramec St. Louis County, MO 859,000 ------------ Total Coal 5,489,000 Nuclear Callaway Callaway County, MO 1,181,000 Hydro Osage Lakeside, MO 212,000 Keokuk Keokuk, IA 126,000 ------------ Total Hydro 338,000 Oil and Venice Venice, IL 441,000 Natural Other Various 424,000* ------------ Gas Total Oil and Natural Gas 865,000 Pumped- storage Taum Sauk Reynolds County, MO 440,000 ------------ TOTAL 8,313,000 ===========
* Includes 48,000 gross kilowatt installed capability of a new combustion turbine generator scheduled for service before the expected 2000 peak.
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 "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Notes 2 and 12 to the "Notes to Financial Statements" under Item 8 herein.
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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
Charles W. Mueller 61 President, 7/1/93 Chief Executive Officer 1/1/94 and Director 6/11/93 Donald E. Brandt 45 Senior Vice President 7/1/88 and Director 4/28/98 Daniel F. Cole 46 Senior Vice President 7/12/99 Thomas F. Voss 52 Senior Vice President 6/1/99 Warner L. Baxter 38 Vice President, 5/1/98 Controller and 8/1/96 Director 4/22/99 William J. Carr 62 Vice President 10/1/88 Michael J. Montana 53 Vice President 7/1/88 Charles D. Naslund 47 Vice President 2/1/99 Garry L. Randolph 51 Vice President 3/1/91 William C. Shores 61 Vice President 7/1/88 Steven R. Sullivan 39 Vice President, General Counsel 7/1/98 and Secretary 9/1/98 Jerre E. Birdsong 45 Treasurer 7/1/93
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 Registrant 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
Union Electric Company (AmerenUE 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, AmerenUE and CIPSCO Incorporated (CIPSCO) combined to form Ameren, with AmerenUE and CIPSCO's subsidiaries, Central Illinois Public Service Company (AmerenCIPS) and CIPSCO Investment Company (CIC), becoming subsidiaries of Ameren (the Merger).
RESULTS OF OPERATIONS
Earnings Earnings for 1999, 1998, and 1997 were $340 million, $311 million, and $293 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 (including Callaway Nuclear Plant refueling outages), merger-related expenses, changes in interest expense, changes in income and property taxes, a targeted employee separation plan and an extraordinary charge.
In 1998, the Registrant recorded a nonrecurring charge to earnings in connection with a targeted separation plan it offered to employees in July 1998. That charge reduced earnings $11 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 Illinois retail electric business as a result of electric industry restructuring legislation enacted in Illinois in December 1997. The write-off reduced earnings $27 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 - ---------------------------------------------------------------------- (Millions of Dollars) 1999 1998 1997 - ---------------------------------------------------------------------- Rate variations $ (9) $ (8) $-- Credit to customers 7 (24) 28 Effect of abnormal weather (37) 48 4 Growth and other 47 48 1 Interchange sales 136 38 (5) - ---------------------------------------------------------------------- $ 144 $ 102 $ 28 - ----------------------------------------------------------------------
Electric revenues for 1999 increased $144 million, compared to 1998, primarily due to a 5% increase in total kilowatthour sales. This increase was primarily driven by a 75% increase in interchange sales, due to strong marketing efforts. Also contributing to the revenue increase was a decrease in the credit to Missouri electric customers (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). Partially offsetting these increases, weather-sensitive residential sales decreased 2%, commercial sales remained flat, while industrial sales decreased 2%.
Electric revenues for 1998 increased $102 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 growth in the service area, and increased interchange revenues, primarily due to favorable market conditions. These increases were partially offset by a rate decrease and an increase in estimated credits to Missouri electric customers, as well as a 5% rate decrease for Illinois electric customers (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). Weather-sensitive residential and commercial sales increased 6% and 4%, respectively, while industrial sales grew 1%. Interchange sales increased 7%, primarily from AmerenCIPS.
The increase in 1997 electric revenues was primarily due to a lower Missouri customer credit recorded in 1997. Residential sales remained flat while interchange sales decreased 5%. Commercial and industrial sales were 1% and 3% higher, respectively.
Fuel and Purchased Power Variations from Prior Year - -------------------------------------------------------------------------------- (Millions of Dollars) 1999 1998 1997 - -------------------------------------------------------------------------------- Fuel: Generation $ (2) $ 24 $ 17 Price (2) (10) (15) Generation efficiencies and other (2) 5 (1) Purchased power 132 11 (14) - -------------------------------------------------------------------------------- $ 126 $ 30 $ (13) - --------------------------------------------------------------------------------
The $126 million increase in fuel and purchased power costs for 1999, compared to 1998, was primarily driven by increased power purchases resulting from higher sales volume.
The $30 million increase in fuel and purchased power costs for 1998, compared to 1997, was primarily driven by increased generation due to higher sales volume, joint dispatch, and higher purchased power prices, partially offset by lower fuel prices. 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. Fuel and purchased power costs decreased in 1997 primarily due to reduced purchased power costs, resulting from relatively flat native load sales coupled with greater generation, as well as lower fuel prices.
Gas Operations Gas revenues in 1998 decreased $7 million compared to 1997, primarily due to an 8% decline in retail sales resulting from mild weather and lower gas costs reflected in the Company's purchased gas adjustment clause. Weather-sensitive residential and commercial sales decreased 10% and 6%, respectively, and industrial sales declined 2%. These decreases were partially offset by benefits realized from an annual $12 million Missouri gas rate increase effective February 1998 (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information).
Gas costs in 1999 increased $5 million compared to 1998, primarily due to higher gas prices partially offset by lower total sales. Gas costs in 1998 declined $14 million compared to 1997, primarily due to lower sales and lower gas prices.
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 the capitalization of certain costs as a result of a Missouri Public Service Commission (MoPSC) Order and 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, the Registrant recorded a nonrecurring, pretax charge of $18 million representing its 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 $11 million in 1998, and approximately $15 million in 1999, and is expected to reduce the Registrant's operating expenses by approximately $14 million to $18 million each year thereafter. See Note 4 - Targeted Separation Plan under Notes to Financial Statements for further information.
The $28 million decrease in other operating expenses in 1999, compared to 1998, was primarily due to the 1998 charge for the TSP and related reduced workforce, decreases in injuries and damages expense (due to claims experience) and information system-related costs and the capitalization of certain costs (including computer software costs) that had previously been expensed for the Registrant's Missouri electric operations (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information).
The $57 million increase in other operating expenses in 1998, compared to 1997, was primarily due to the charge for the TSP and increases in injuries and damages expense and information system-related costs. In 1997, other operating expense increased $26 million primarily due to increased information system-related expenses.
Maintenance expenses increased $25 million in 1999, compared to 1998 primarily due to increased power plant maintenance and tree trimming activity. The expenses incurred for the 35-day refueling outage in the fall of 1999 at the Callaway Nuclear Plant were comparable to those for the 31-day spring 1998 refueling outage. No refueling outage is scheduled for 2000. In 1998, maintenance expenses increased $5 million due to the scheduled spring refueling outage at the Callaway Nuclear Plant; partially offset by less scheduled fossil plant maintenance. In 1997, maintenance expenses decreased $6 million, primarily a result of reduced Callaway Plant expenses due to the absence of a refueling outage in 1997, offset in part by increased scheduled fossil plant maintenance.
Depreciation and amortization expense increased $12 million in 1998 and $7 million in 1997, due to increased depreciable property and amortization of the Missouri portion of merger-related costs which were recorded as a regulatory asset upon Merger close under the conditions of the Missouri Public Service Commission (MoPSC) order approving the Merger.
Taxes Income tax expense from operations increased $13 million in 1999, compared to 1998, due to higher pretax income. Income tax expense from operations increased $25 million in 1998, compared to 1997, due to higher pretax income and a higher effective tax rate. Income tax expense from operations decreased $5 million in 1997 primarily due to a lower effective tax rate.
Other tax expense decreased $8 million in 1999, compared to 1998, primarily due to a decrease in gross receipts taxes related to the Registrant's Illinois jurisdiction. This decrease is the result of the restructuring of the Illinois public utility tax whereby gross receipts taxes are no longer recorded as electric revenues and gross receipts tax expense.
Other Income and Deductions Miscellaneous, net increased $4 million for 1998, compared to 1997, due to increased interest income and gains on the sale of property. Miscellaneous, net increased $12 million for 1997, primarily due to the capitalization of certain merger-related costs in 1997.
Interest Interest expense decreased $10 million in 1999, compared to 1998, primarily due to lower debt outstanding during the year and a decrease in other interest expense. Interest expense decreased $9 million for 1998, compared to 1997, due to lower interest rates and a decrease in other interest expense. Interest expense increased $6 million for 1997 primarily due to higher debt outstanding during the year at higher interest rates.
Balance Sheet The $12 million decrease in trade accounts receivable and unbilled revenue at December 31, 1999, compared to 1998, was due to lower sales and revenues in November and early December 1999, compared to the comparable time period in 1998. The $166 million increase in intercompany notes receivable was due to funds invested in a regulated money pool (see Note 3 - Related Party Transactions under Notes to Financial Statements for further information.)
The $54 million increase in other current liabilities was primarily due to the timing of credit payments to electric customers in the Registrant's Missouri and Illinois jurisdictions, as well as an increase in a liability for an estimated rate reduction for Missouri electric customers retroactive to September 1, 1998 (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). The remaining variance is the result of the timing of various payments to suppliers.
The $37 million increase in other deferred credits and liabilities was primarily due to Callaway Plant decommissioning costs.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $725 million for 1999, compared to $651 million and $602 million in 1998 and 1997, respectively.
Cash flows used in investing activities totaled $419 million, $231 million, and $284 million for the years ended December 31, 1999, 1998 and 1997, respectively. Expenditures in 1999 for constructing new or to improve existing facilities and purchasing rail cars were $246 million. In addition, the Company spent $22 million to acquire nuclear fuel.
Capital expenditures are expected to approximate $297 million in 2000. For the five-year period 2000-2004, construction expenditures are estimated at $1.6 billion. This estimate includes capital expenditures that will be incurred by the Registrant to meet new air quality standards for ozone and particulate matter, as discussed below.
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, early banking of emission credits and installing advanced NOx reduction combustion technology, 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 Missouri (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 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 and 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.
See Note 13 - Callaway Nuclear Plant under Notes to Financial Statements for a discussion of Callaway Plant decommissioning costs.
Cash flows used in financing activities were $236 million for 1999, compared to $376 million and $320 million for 1998 and 1997, respectively. The Registrant's principal financing activities during 1999 included the redemption of $100 million of long-term debt, the issuance of $152 million of long-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 $1 billion 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 $150 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.
The Registrant also has a bank credit agreement due 2002, which permits the borrowing of up to $300 million on a long-term basis, all of which was unused, and $148 million was available at December 31, 1999. In addition, the Registrant has the ability to borrow up to approximately $530 million from Ameren or AmerenCIPS 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 no intercompany borrowings outstanding and $402 million available through the regulated money pool. See Note 8 - Short-Term Borrowings under Notes to Financial Statements for further discussion.
Additionally, the Registrant has a lease agreement that provides for the financing of nuclear fuel. At December 31, 1999, the maximum amount that could be financed under the agreement was $120 million. Cash used in financing for 1999 included issuances under the lease for nuclear fuel of $65 million, offset in part by $15 million of redemptions. At December 31, 1999, $116 million was financed under the lease. See Note 6 - Nuclear Fuel Lease 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 some of the Registrant's collective bargaining units which will permit it to manage its labor costs and practices effectively in the future (see Note 12 - 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 fossil power plants, 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 Federal Energy Regulatory Commission (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 the Registrant, 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 MoPSC and the Illinois Commerce Commission (ICC) have 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 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.
Illinois 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 Illinois Law) providing for electric utility restructuring in Illinois, where approximately 6% of the Registrant's retail electric revenues are derived. This legislation introduces competition into the supply of electric energy at retail in Illinois.
Major provisions of the Illinois 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 6% 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 Illinois Law included a 5% rate decrease for residential customers that became effective in August 1998. This rate decrease reduced electric revenues $1 million in 1999 compared to 1998 and is expected to impact electric revenues by approximately $3 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 Illinois 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 Illinois 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 Illinois Law contains a provision requiring a portion of excess earnings (as defined under the Illinois Law) for the years 1998 through 2004 to be refunded to customers.
In December 1997, after evaluating the impact of the Illinois 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 $27 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.
Missouri In Missouri, where approximately 94% of the Registrant's retail electric revenues are derived, a task force appointed by the MoPSC investigated electric industry restructuring and competition. In 1998 the task force issued a report to the MoPSC that addressed many of the restructuring issues, but did not provide a specific recommendation or approach to restructure the industry. In addition, in 1998, the MoPSC staff issued a proposed plan for restructuring Missouri's electric industry. The staff's plan addressed a number of issues of concern if the industry is restructured in Missouri. It also included a proposal for less than full recovery of strandable costs. The staff's plan has not been addressed by the MoPSC. A joint committee of the Missouri legislature is also conducting hearings on these issues. Several restructuring bills were introduced by the Missouri legislature in 1999 and 2000. The Registrant is unable to predict the timing or ultimate outcome of electric industry restructuring in the state of Missouri.
Summary 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 and net regulatory assets, lower revenues, reduced profit margins and increased costs of capital and operations expenses. The Registrant is actively taking steps to mitigate these potential negative consequences. Most importantly, the Registrant will continue to focus on cost control to ensure that it maintains a competitive cost structure. In Missouri, the Registrant is actively involved in all major deliberations taking place surrounding electric industry restructuring in an effort to ensure that restructuring legislation, if any, contains an orderly transition and is equitable to the Registrant's shareholders. 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 AmerenUE, 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, Note 12 - Commitments and Contingencies and Note 13 - Callaway Nuclear Plant 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 the Registrant's 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. The Registrant handles market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, the Registrant 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 and commercial paper. 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 by approximately $6 million, and net income would decrease by approximately $4 million. This amount has been determined using the assumptions that the Registrant's outstanding variable-rate debt and commercial paper, 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 potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate 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 in both its Missouri and Illinois jurisdictions. The PGA allows the Registrant to pass on to its customers its prudently incurred costs of natural gas. With approval of the MoPSC, the Registrant participated in an experimental program to control the volatility of gas prices paid by its Missouri customers in the 1998-1999 winter months through the purchase of financial instruments. This program concluded in April 1999.
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 and nuclear fuel to manage its exposure to fuel prices. (See Note 12 - 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 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.
Equity Price Risk The Registrant maintains trust funds, as required by the Nuclear Regulatory Commission and Missouri and Illinois state laws, to fund certain costs of nuclear decommissioning (see Note 13 - Callaway Nuclear Plant under Notes to Financial Statements for further information). As of December 31, 1999, these funds were invested primarily in domestic equity securities, fixed-rate, fixed-income securities, and cash and cash equivalents. By maintaining a portfolio that includes long-term equity investments, the Registrant is seeking to maximize the returns to be utilized to fund nuclear decommissioning costs. However, the equity securities included in the Registrant's portfolio are exposed to price fluctuations in equity markets, and the fixed-rate, fixed-income securities are exposed to changes in interest rates. The Registrant actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, established target allocation percentages of the assets of its trusts to various investment options. The Registrant's exposure to equity price market risk is in large part mitigated due to the fact that the Registrant is currently allowed to recover its decommissioning costs in its rates.
ACCOUNTING MATTERS
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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 and contracts to determine the appropriate accounting for these items under 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 MoPSC and 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 in its Illinois jurisdiction and may be modified in the future for the Registrant's Missouri jurisdiction (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.
In the Illinois retail jurisdiction, 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 Illinois Law (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). In the Missouri retail jurisdiction, 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. In Illinois and Missouri, changes in gas costs are generally reflected in billings to customers through Purchased Gas Adjustment Clauses.
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 Union Electric Company
In our opinion, the financial statements listed in the index appearing under Item 14(a)(1) on Page 38 present fairly, in all material respects, the financial position of Union Electric Company at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 in conformity with auditing standards 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 accounting principles 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.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP St. Louis, Missouri February 2, 2000
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
UNION ELECTRIC COMPANY BALANCE SHEET (Thousands of Dollars, Except Shares)
See Notes to Financial Statements.
UNION ELECTRIC COMPANY STATEMENT OF INCOME (Thousands of Dollars)
See Notes to Financial Statements.
UNION ELECTRIC 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 Company's Illinois retail electric business as a result of electric industry restructuring legislation enacted in Illinois in December 1997. The write-off reduced earnings $27 million, net of income taxes. See Note 2 - Regulatory Matters under Notes to Financial Statements for further information.
See Notes to Financial Statements.
UNION ELECTRIC COMPANY
STATEMENT OF RETAINED EARNINGS - ------------------------------ (Thousands of Dollars)
- -------------------------------------------------------------------------------- Year Ended December 31, 1999 1998 1997 Balance at Beginning of Period $1,211,610 $1,159,956 $1,126,513 - -------------------------------------------------------------------------------- Add: Net income 349,252 320,070 301,655 - -------------------------------------------------------------------------------- 1,560,862 1,480,026 1,428,168 - -------------------------------------------------------------------------------- Deduct: Common stock dividends 328,674 259,599 259,395 Preferred stock dividends 11,021 8,817 8,817 - -------------------------------------------------------------------------------- 339,695 268,416 268,212 - -------------------------------------------------------------------------------- Balance at End of Period $1,221,167 $1,211,610 $1,159,956 - -------------------------------------------------------------------------------- Under the mortgage indenture, as amended, $31,305 of total retained earnings was restricted against payment of common dividends - except those payable in common stock, leaving $1,189,862 of free and unrestricted retained earnings at December 31, 1999.
SELECTED QUARTERLY INFORMATION (Unaudited) - -------------------------------- (Thousands of Dollars)
- -------------------------------------------------------------------------------- Operating Operating Net Net Income Revenues Income Income After Quarter Ended Preferred Stock Dividends - -------------------------------------------------------------------------------- March 31, 1999 (a) $506,071 $68,887 $43,743 $41,539 March 31, 1998 (a) $478,585 $62,120 $30,302 $28,098 June 30, 1999 621,367 96,292 70,669 68,464 June 30, 1998 (b) 588,676 92,827 66,251 64,046 September 30, 1999 905,850 235,707 208,727 206,523 September 30, 1998 (c) 846,437 233,738 206,551 204,347 December 31, 1999 (d) 493,878 42,382 26,113 23,909 December 31, 1998 468,373 39,498 16,966 14,762 - --------------------------------------------------------------------------------
(a) The first quarter of 1999 and 1998 included credits to Missouri electric customers that reduced net income approximately $11 million and $6 million, respectively. (b) The second quarter of 1998 included credits to Missouri electric customers that reduced net income approximately $18 million. Callaway Plant refueling expenses, which decreased net income approximately $18 million, were also included in the second quarter of 1998. (c) The third quarter of 1998 included a nonrecurring charge related to the targeted employee separation plan that reduced net income $11 million. (See Note 4 - Targeted Separation Plan under Notes to Financial Statements for further information.) (d) The fourth quarter of 1999 included adjustments that increased earnings $9 million as a result of a Report and Order received from the Missouri Public Service Commission relating to the Registrant's electric alternative regulation plan. (See Note 2 - Regulatory Matters under Notes to Financial Statements for further information). In addition, Callaway Plant refueling expenses, which decreased net income approximately $22 million were included in the fourth quarter of 1999.
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.
UNION ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 1999
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation Union Electric Company (AmerenUE or the Registrant) is a subsidiary of Ameren Corporation (Ameren), which is the parent company of two utility operating companies, the Registrant and Central Illinois Public Service Company (AmerenCIPS). Ameren is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA) formed in December 1997 upon the merger of AmerenUE and CIPSCO Incorporated (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 Missouri and Illinois. Contracts among the companies--dealing with jointly-owned 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 1.1 million electric and 125,000 gas customers in a 24,500 square-mile area of Missouri and Illinois, including Metropolitan St. Louis.
The Registrant also has a 40% 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 Missouri Public Service Commission (MoPSC), 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 In the Missouri and Illinois retail electric jurisdictions, the cost of fuel for electric generation is reflected in base rates with no provision for changes to be made through fuel adjustment clauses. (See Note 2 - Regulatory Matters for further information.) In the Illinois jurisdiction in 1997, changes in fuel costs were generally reflected in billings to electric customers through a fuel adjustment clause. In the Illinois and Missouri retail gas jurisdictions, changes in gas costs are generally reflected in billings to gas customers through purchased gas adjustment clauses.
Nuclear Fuel The cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is charged to expense based on net kilowatthours generated and sold.
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 liabili-
ties 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 10% during 1999 and 9% during 1998 and 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 AmerenUE and AmerenCIPS. 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
Missouri Electric In July 1995, the MoPSC approved an agreement establishing contractual obligations involving the Registrant's Missouri retail electric rates. Included was a three-year experimental alternative regulation plan (the Original Plan) that ran from July 1, 1995, through June 30, 1998, which provided that earnings in those years in excess of a 12.61% regulatory return on equity (ROE) be shared equally between customers and stockholders, and earnings above a 14% ROE be credited to customers. The formula for computing the credit used twelve-month results ending June 30, rather than calendar year earnings. In 1996, the Registrant recorded a $47 million credit for the first year of the Original Plan, which reduced earnings $28 million. During 1997, the Registrant recorded a $20 million credit for the second year of the Original Plan, which reduced earnings $11 million. In 1998, the Registrant recorded an estimated $43 million credit for the final year of the Original Plan, which reduced earnings $26 million.
Included in the joint agreement approved by the MoPSC in its February 1997 order authorizing the Merger, was a new three-year experimental alternative regulation plan (the New Plan) that runs from July 1, 1998, through June 30, 2001. Like the Original Plan, the New Plan requires that earnings over a 12.61% ROE up to a 14% ROE be shared equally between customers and shareholders. The New Plan also returns to customers 90% of all earnings above a 14% ROE up to a 16% ROE. Earnings above a 16% ROE are credited entirely to customers. In addition, the joint agreement provides for a Missouri electric rate decrease, retroactive to September 1, 1998, based on the weather-adjusted average annual credits to customers under the Original Plan. The Registrant estimated that its Missouri electric rate decrease should approximate $20 million on an annualized basis and reduced revenues accordingly since September 1998.
In November 1998, the MoPSC Staff proposed adjustments to the customer credit for the third year of the Original Plan. In addition, the MoPSC Staff proposed adjustments to the Registrant's estimated Missouri electric rate decrease based upon their methodology of calculating the weather-adjusted credits. The determination of the credit for the third year of the Original Plan, as well as the determination of the Missouri electric rate decrease, were subject to regulatory proceedings before the MoPSC in 1999.
On December 23, 1999, the MoPSC issued a Report and Order (Order) related to the customer credit for the third year of the Original Plan. Certain of the MoPSC staff's proposed adjustments were accepted by the MoPSC in the Order. In addition, the Order requires the Registrant to capitalize and amortize certain costs (including computer software costs) that had previously been expensed for its Missouri electric operations.
Based on the provisions of the Order, the Registrant estimates that the credit for the third year of the Original Plan will approximate $31 million. In addition, with regard to the Missouri electric rate decrease, the Registrant, the MoPSC staff, and other parties reached a settlement related to the calculation of the weather-adjusted credits. As a result, the Registrant estimates that the annualized Missouri electric rate decrease will approximate $17 million. On February 24, 2000, the Registrant filed a Petition for Writ of Review with the Circuit Court of Cole County, Missouri, asking that the Order be reversed. The Registrant has also requested that the court issue a stay of the MoPSC's Order. While it is unable to predict the ultimate outcome of the judicial appeal of the MoPSC's Order, the Registrant believes that the final decision will not have a material adverse effect on its financial position, results of operations or liquidity.
The provisions of the Order also have an impact on the estimated credit to electric customers recorded by the Registrant for the first year of the New Plan. As a result, the Registrant recorded an estimated credit of $25 million for the plan year ended June 30, 1999. In addition, the Registrant recorded an estimated $20 million credit for the 1999 portion of the second year of the New Plan. Also, the provision of the Order which requires the Registrant to capitalize and amortize certain costs (including computer software costs) that had been previously expensed resulted in the capitalization of approximately $20 million of costs in the fourth quarter of 1999.
In summary, the provisions of the Order and the resulting changes in the Registrant's estimates of credits and Missouri electric rate decrease for the open years under the Original Plan and the New Plan resulted in an increase in earnings of approximately $9 million in the fourth quarter of 1999.
On December 30, 1999, the Registrant filed a request for rehearing with the MoPSC, asking that it reconsider its decision to adopt certain of the MoPSC staff's adjustments. On January 25, 2000, the MoPSC denied the Registrant's request. The Registrant plans to file an appeal with the courts.
Gas In December 1997, the MoPSC approved a $12 million annual rate increase for natural gas service in the Registrant's Missouri jurisdiction. The rate increase became effective in February 1998.
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 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 MoPSC and the ICC have 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.
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 Illinois Law) providing for electric utility restructuring in Illinois, where approximately 6% of the Registrant's retail electric revenues are derived. This legislation introduces competition into the supply of electric energy at retail in Illinois.
Under the Illinois 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 Illinois 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 AmerenCIPS 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 Illinois Law included a 5% residential electric rate decrease for the Registrant's Illinois electric customers, effective August 1, 1998. This rate decrease reduced electric revenues approximately $1 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 Illinois Law, the Registrant filed a proposal with the ICC to eliminate their electric fuel adjustment clause for Illinois retail customers, thereby including a historical levels of fuel costs in base rates. The ICC approved the Registrant's filing in early 1998.
The Illinois Law also contains a provision requiring that one-half of excess earnings from the Illinois jurisdiction for the years 1998 through 2004 be refunded to the Registrant's Illinois customers. Excess earnings are defined as the portion of the two-year average annual rate of return on common equity in excess of 1.5% of the two-year average of an Index, as defined in the Illinois 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 US 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.
Other provisions of the Illinois 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 in Illinois, 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 portion of the business that no longer meets the 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 Illinois 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 Illinois retail portion of its generating business (i.e., the portion of the Registrant's business related to the supply of electric energy in Illinois) in the fourth quarter of 1997. The Registrant evaluated the impact of the Illinois 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 the cash flows from the regulated portion of its business. Accordingly, the Registrant's generation-related regulatory assets and liabilities of its Illinois retail electric business were written off in the fourth quarter of 1997, resulting in an extraordinary charge to earnings of $27 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 deferred charges related to 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.
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 in Illinois who choose other suppliers as allowed under the Illinois 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 Illinois 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 Illinois Law on the Registrant's future financial condition, results of operations or liquidity.
Missouri Electric Restructuring In Missouri, where approximately 94% of the Registrant's retail electric revenues are derived, a task force appointed by the MoPSC investigated electric industry restructuring and competition. In 1998, the task force issued a report to the MoPSC that addressed many of the restructuring issues but did not provide a specific recommendation or approach to restructure the industry. In addition, in 1998, the MoPSC staff issued a proposed plan for restructuring Missouri's electric industry. The staff's plan addressed a number of issues of concern if the industry is restructured in Missouri. It also included a proposal for less than full recovery of strandable costs. The staff's plan has not been
addressed by the MoPSC. A joint committee of the Missouri legislature is also conducting hearings on these issues. Several restructuring bills were introduced by the Missouri legislature in 1999 and 2000.
The Registrant is unable to predict the timing or ultimate outcome of electric industry restructuring in the state of Missouri, as well as the impact of potential electric industry restructuring matters on the Registrant's future financial condition, results of operations or liquidity. The potential negative consequences of electric industry restructuring could be significant and include the impairment and write-down of certain assets, including generation-related plant and net regulatory assets, lower revenues, reduced profit margins and increased costs of capital and operations expense. At December 31, 1999, the Registrant's net investment in generation facilities related to its Missouri jurisdiction approximated $2.6 billion and was included in electric plant in-service on the Registrant's balance sheet. In addition, at December 31, 1999, the Registrant's Missouri net generation-related regulatory assets approximated $454 million.
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 $601 $608 Callaway costs 92 95 Unamortized loss on reacquired debt 24 26 Merger costs 22 24 Other 18 20 - ----------------------------------------------------------------------- Regulatory Assets $757 $773 - ----------------------------------------------------------------------- Regulatory Liability: Income taxes $154 $159 - ----------------------------------------------------------------------- Regulatory Liability $154 $159 - -----------------------------------------------------------------------
Income Taxes: See Note 10 - Income Taxes. Callaway Costs: Represents Callaway Nuclear Plant operations and maintenance expenses, property taxes and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the plant (through 2024). 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. Merger Costs: Represents the portion of merger-related expenses applicable to the Missouri retail jurisdiction. These costs are being amortized within 10 years, based on a MoPSC order.
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. However, as noted in the above paragraphs, electric industry restructuring legislation may impact the recoverability of regulatory assets in the future.
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 $15 million and $6 million, respectively, as of December 31, 1999 and 1998. Intercompany payables included in accounts and wages payable totaled approximately $25 million and $17 million, respectively, as of December 31, 1999 and 1998.
In addition, the Registrant has the ability to borrow funds from Ameren or AmerenCIPS or invest funds through a regulated money pool agreement. At December 31, 1999, the Registrant had outstanding intercompany receivables of $166 million through the regulated money pool. See Note 8 - 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 $18 million was recorded, which reduced earnings $11 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 receivables 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 Missouri and 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 - Nuclear Fuel Lease
The Registrant has a lease agreement that provides for the financing of nuclear fuel. At December 31, 1999, the maximum amount that could be financed under the agreement was $120 million. Pursuant to the terms of the lease, the Registrant has assigned to the lessor certain contracts for purchase of nuclear fuel. The lessor obtains, through the issuance of commercial paper or from direct loans under a committed revolving credit agreement from commercial banks, the necessary funds to purchase the fuel and make interest payments when due.
The Registrant is obligated to reimburse the lessor for all expenditures for nuclear fuel, interest and related costs. Obligations under this lease become due as the nuclear fuel is consumed at the Registrant's Callaway Nuclear Plant. The Registrant reimbursed the lessor $16 million in 1999, $23 million during 1998 and $31 million during 1997.
The Registrant has capitalized the cost, including certain interest costs, of the leased nuclear fuel and has recorded the related lease obligation. Total interest charges under the lease were $5 million in 1999 and 1998 and $6 million in 1997. Interest charges for these years were based on average interest rates of approximately 6%. Interest charges of $4 million were capitalized in 1999 and $3 million were capitalized in 1998 and 1997.
NOTE 7 - Preferred Stock
At December 31, 1999 and 1998, the Registrant had 25 million shares of authorized preferred stock.
Outstanding preferred stock is entitled to cumulative dividends and is redeemable at the redemption prices shown below: - --------------------------------------------------------------------------------
- -------------------------------------------------------------------------------- Preferred Stock Not Subject to Mandatory Redemption: (in millions) - -------------------------------------------------------------------------------- Redemption Price December 31, (per share) 1999 1998 Without par value and stated value of $100 per share-- $7.64 Series - 330,000 shares $103.82 - note (a) $33 $33 $5.50 Series A - 14,000 shares 110.00 1 1 $4.75 Series - 20,000 shares 102.176 2 2 $4.56 Series - 200,000 shares 102.47 20 20 $4.50 Series - 213,595 shares 110.00 - note (b) 21 21 $4.30 Series - 40,000 shares 105.00 4 4 $4.00 Series - 150,000 shares 105.625 15 15 $3.70 Series - 40,000 shares 104.75 4 4 $3.50 Series - 130,000 shares 110.00 13 13
Without par value and stated value of $25 per share-- $1.735 Series - 1,657,500 shares 25.00 42 42 - --------------------------------------------------------------------------------
TOTAL PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION $155 $155 - --------------------------------------------------------------------------------
(a) Beginning February 15, 2003, eventually declining to $100 per share. (b) In the event of voluntary liquidation, $105.50.
- --------------------------------------------------------------------------------
NOTE 8 - 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). At December 31, 1999 and 1998 the Registrant had no outstanding short-term borrowings.
At December 31, 1999, the Registrant had committed bank lines of credit aggregating $150 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 $530 million from Ameren or AmerenCIPS 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 no intercompany borrowings outstanding and $402 million available through the regulated money pool.
NOTE 9 - Long-Term Debt
- -------------------------------------------------------------------------------- (in millions) 1999 1998 - -------------------------------------------------------------------------------- First Mortgage Bonds - note (a) - -------------------------------------------------------------------------------- 6 3/4% Series paid in 1999 $ - $100 8.33% Series due 2002 75 75 7.65% Series due 2003 100 100 6 7/8% Series due 2004 188 188 7 3/8% Series due 2004 85 85 6 3/4% Series due 2008 148 148 7.40% Series due 2020 - note (b) 60 60 8 3/4% Series due 2021 125 125 8% Series due 2022 85 85 8 1/4% Series due 2022 104 104 7.15% Series due 2023 75 75 7% Series due 2024 100 100 5.45% Series due 2028 - note (b) 44 44 - -------------------------------------------------------------------------------- 1,189 1,289 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Missouri Environmental Improvement Revenues Bonds - -------------------------------------------------------------------------------- 1985 Series A due 2015 - note (c) 70 70 1985 Series B due 2015 - note (c) 57 57 1991 Series due 2020 - note (c) 43 43 1992 Series due 2022 - note (c) 47 47 1998 Series A due 2033 - note (c) 60 60 1998 Series B due 2033 - note (c) 50 50 1998 Series C due 2033 - note (c) 50 50 - -------------------------------------------------------------------------------- 377 377 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Subordinated Deferrable Interest Debentures - -------------------------------------------------------------------------------- 7.69% Series A due 2036 - note (d) 66 66 - ------------------------------------------------------------------------------- Commercial Paper - note (e) 152 -- - ------------------------------------------------------------------------------- Nuclear Fuel Lease 116 66 - ------------------------------------------------------------------------------- Unamortized Discount and Premium on Debt (6) (7) - ------------------------------------------------------------------------------- Maturities Due Within One Year (11) (117) ------------------------------------------------------------------------------ Total Long-Term Debt $1,883 $1,674 - -------------------------------------------------------------------------------
(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) Environmental Improvement Series. (c) Interest rates, and the periods during which such rates apply, vary depending on the Registrant's selection of certain defined rate modes. The average interest rates for the year 1999 are as follows: 1985 Series A 3.21% 1985 Series B 3.29% 1991 Series 3.65% 1992 Series 3.55% 1998 Series A 3.49% 1998 Series B 3.48% 1998 Series C 3.46% (d) During the terms of the debentures, the Registrant may, under certain circumstances, defer the payment of interest for up to five years. (e) A bank credit agreement, due 2002, permits the Registrant to borrow or to support commercial paper borrowings up to $300 million. Interest rates will vary depending on market conditions. At December 31, 1999, no such borrowings were outstanding.
Maturities of long-term debt through 2004 are as follows: - ---------------------------------------- (in millions) Principal Amount - ---------------------------------------- 2000 $ 11 2001 -- 2002 227 2003 100 2004 273 - ----------------------------------------
Amounts for years subsequent to 2000 do not include nuclear fuel lease payments since the amounts of such payments are not currently determinable.
NOTE 10 - Income Taxes
Total income tax expense for 1999 resulted in an effective tax rate of 40% on earnings before income taxes (40% in 1998 and 38% in 1997).
Principal reasons such rates differ from the statutory federal rate: - ------------------------------------------------------------------------ 1999 1998 1997 - ------------------------------------------------------------------------ Statutory federal income tax rate 35% 35% 35% Increases (Decreases) from: Depreciation differences 2 2 2 State income tax 4 4 4 Other (1) (1) (3) - ------------------------------------------------------------------------ Effective income tax rate 40% 40% 38% - ------------------------------------------------------------------------
Income tax expense components: - ------------------------------------------------------------------------ (in millions) 1999 1998 1997 - ------------------------------------------------------------------------ Taxes currently payable (principally federal): Included in operating expenses $236 $237 $216 Included in other income-- Miscellaneous, net (4) (5) (3) - ------------------------------------------------------------------------ 232 232 213 Deferred taxes (principally federal): Included in operating expenses-- Depreciation differences 9 (1) (7) Other (9) (14) (10) Included in other income-- Depreciation differences -- -- 1 Other -- -- 9 - ------------------------------------------------------------------------ -- (15) (7) Deferred investment tax credits, Amortization Included in operating expenses (5) (5) (6) - ------------------------------------------------------------------------ Total income tax expense $227 $212 $200 - ------------------------------------------------------------------------
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: Depreciation $822 $814 Regulatory assets, net 462 465 Capitalized taxes and expenses 60 68 Deferred benefit costs (47) (48) - ------------------------------------------------------------------------------ Total net accumulated deferred income tax liabilities $1,297 $1,299 - ------------------------------------------------------------------------------
NOTE 11 - 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 for 1999 were $18 million, of which approximately 18% was charged to construction accounts. The AmerenUE pension plan information for 1998 and 1997 is presented separately.
Pension costs for the years 1998 and 1997 were $28 million and $24 million, respectively, of which approximately 19% and 17%, respectively, was charged to construction accounts.
Funded Status of Pension Plans: - ------------------------------------------------------------------------ (in millions) 1998 - ------------------------------------------------------------------------ Change in benefit obligation Net benefit obligation at beginning of year $999 Service cost 24 Interest cost 70 Amendments 10 Actuarial loss 38 Special termination benefit charge 7 Benefits paid (88) - ------------------------------------------------------------------------ Net benefit obligation at end of year 1,060
Change in plan assets * Fair value of plan assets at beginning of year 1,006 Actual return on plan assets 122 Employer contributions 1 Benefits paid (88) - ------------------------------------------------------------------------ Fair value of plan assets at end of year 1,041
Funded status - deficiency 19 Unrecognized net actuarial gain 121 Unrecognized prior service cost (73) Unrecognized net transition asset 6 - ------------------------------------------------------------------------ Accrued pension cost at December 31 $73 - ------------------------------------------------------------------------ * Plan assets consist principally of common stocks and fixed income securities.
Components of Net Periodic Benefit Cost: - -------------------------------------------------------------------------------- (in millions) 1998 1997 - -------------------------------------------------------------------------------- Service cost $24 $22 Interest cost 70 69 Expected return on plan assets (75) (71) Amortization of: Transition asset (1) (1) Prior service cost 6 7 Actuarial gain (3) (2) Special termination benefit charge 7 -- - -------------------------------------------------------------------------------- Net periodic benefit cost $28 $24 - --------------------------------------------------------------------------------
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 accrues the expected postretirement benefit costs during employees' years of service.
The Registrant's funding policy is to annually contribute the net periodic cost to a Voluntary Employee Beneficiary Association trust (VEBA). Postretirement benefit costs were $46 million in 1999, $43 million for 1998 and $44 million in 1997, of which approximately 18% in 1999 and 17% in 1998 and 1997 were charged to construction accounts. The Registrant's transition obligation at December 31, 1999 is being amortized over the next 13 years.
The MoPSC and the ICC allow the recovery of postretirement benefit costs in rates to the extent that such costs are funded. In December 1995, the Registrant established two external trust funds for retiree health care and life insurance benefits. In 1998, 1997 and 1996, claims were paid out of the plan trust funds.
Funded Status of the Plans: - -------------------------------------------------------------------------------- (in millions) 1999 1998 - -------------------------------------------------------------------------------- Change in benefit obligation Net benefit obligation at beginning of year $360 $333 Service cost 15 14 Interest cost 25 24 Actuarial (gain)/loss (20) 9 Benefits paid (26) (20) - -------------------------------------------------------------------------------- Net benefit obligation at end of year 354 360
Change in plan assets * Fair value of plan assets at beginning of year 110 81 Actual return on plan assets 4 8 Employer contributions 46 44 Unincorporated business income tax -- (3) Benefits paid (26) (20) - -------------------------------------------------------------------------------- Fair value of plan assets at end of year 134 110
Funded status - deficiency 220 250 Unrecognized net actuarial gain 29 11 Unrecognized prior service cost (3) (3) Unrecognized net transition obligation (162) (175) - -------------------------------------------------------------------------------- Postretirement benefit liability at December 31 $84 $83 - -------------------------------------------------------------------------------- * Plan assets consist principally of common stocks and fixed income securities.
Components of Net Periodic Benefit Cost: - -------------------------------------------------------------------------------- (in millions) 1999 1998 1997 - -------------------------------------------------------------------------------- Service cost $15 $14 $12 Interest cost 25 24 23 Expected return on plan assets (6) (5) (2) Amortization of: Transition obligation 12 12 12 Actuarial gain -- (2) (1) - -------------------------------------------------------------------------------- Net periodic benefit cost $46 $43 $44 - --------------------------------------------------------------------------------
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 $4 million and $31 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 $4 million and $31 million, respectively.
NOTE 12 - Commitments and Contingencies
The Registrant is engaged in a capital program under which expenditures averaging approximately $317 million, including AFC, are anticipated during each of the next five years. This estimate includes capital expenditures that will be incurred by the Registrant to meet new air quality standards for ozone and particulate matter, as discussed later in this Note.
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 $1.0 billion. Total coal purchases, including transportation costs, for 1999, 1998 and 1997 were $312 million, $304 million, and $267 million, 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 $54 million for 1999, $50 million for 1998, and $64 million for 1997. The Registrant's nuclear fuel commitments for 2000 through 2004, including uranium concentrates, conversion, enrichment and fabrication, are expected to total $73 million, and are expected to be financed under the nuclear fuel lease. Nuclear fuel expenditures for 1999, 1998 and 1997 were $22 million, $20 million and $35 million, respectively. Additionally, the Registrant has long-term contracts with other utilities to purchase electric capacity. These commitments for 2000 through 2004 are estimated to total $200 million. During 1999, 1998 and 1997, electric capacity purchases were $38 million, $35 million, and $34 million, respectively.
The Registrant's insurance coverage for Callaway Nuclear Plant at December 31, 1999, was as follows:
Type and Source of Coverage - ------------------------------------------------------------------------------- (in millions) Maximum Maximum Coverages Assessments For Single Incidents - ------------------------------------------------------------------------------- Public Liability: American Nuclear Insurers $ 200 $-- Pool Participation 9,338 88 (a) - ------------------------------------------------------------------------------- $ 9,538 (b) $ 88 - ------------------------------------------------------------------------------- Nuclear Worker Liability: American Nuclear Insurers $ 200 (c) $ 3 - ------------------------------------------------------------------------------- Property Damage: Nuclear Electric Insurance Ltd. $ 2,750 (d) $ 11 - ------------------------------------------------------------------------------- Replacement Power: Nuclear Electric Insurance Ltd. $ 490 (e) $2 - ------------------------------------------------------------------------------- (a) Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended, (Price- Anderson). Subject to retrospective assessment with respect to loss from an incident at any U.S. reactor, payable at $10 million per year. Price-Anderson expires in 2002. (b) Limit of liability for each incident under Price-Anderson. (c) Industry limit for potential liability from workers claiming exposure to the hazard of nuclear radiation. (d) Includes premature decommissioning costs. (e) Weekly indemnity of $3.5 million, for 52 weeks which commences after the first 12 weeks of an outage, plus $2.8 million per week for 110 weeks thereafter. - --------------------------------------------------------------------------------
Price-Anderson limits the liability for claims from an incident involving any licensed U.S. nuclear facility. The limit is based on the number of licensed reactors and is adjusted at least every five years based on the Consumer Price Index. Utilities owning a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by Price-Anderson.
If losses from a nuclear incident at Callaway exceed the limits of, or are not subject to, insurance, or if coverage is not available, the Registrant will self-insure the risk. Although the Registrant has no reason to anticipate a serious nuclear incident, if one did occur it could have a material, but indeterminable, adverse effect on the Registrant's financial position, results of operations or liquidity.
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, early banking of emission credits and installing advanced NOx reduction combustion technology, 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 Missouri (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 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.
As of December 31, 1999, the Registrant was designated as a potentially responsible party (PRP) by federal and state environmental protection agencies at four 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 at a former manufactured gas plant site located in Illinois are being accrued and deferred rather than expensed currently, pending recovery through environmental adjustment clause rate riders approved by the ICC. 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 1997 and 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 its hazardous waste 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.
Certain employees of the Registrant are represented by the International Brotherhood of Electrical Workers (IBEW) and the International Union of Operating Engineers. These employees comprise approximately 77% of the Registrant's workforce. New contracts with collective bargaining units representing approximately 46% of these employees were ratified in 1999 with terms 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 employees of the Registrant and Ameren Services Company. Negotiations with Local 1455 are still ongoing. However, after engaging in extensive good-faith bargaining with IBEW Locals 1439, 309 and 649, the Registrant submitted a last, best and final offer to these collective bargaining units on February 2, 2000. The offer was rejected and the Registrant 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 the Registrant'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 other union represented employees to any action by its employees. The Registrant is also unable to determine what, if any, impact these labor matters could have on its future financial condition, results of operations or liquidity.
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 13 - Callaway Nuclear Plant
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill per nuclear-generated kilowatthour sold for future disposal of spent fuel. Electric rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. The Registrant has sufficient storage capacity at the Callaway Plant site until 2020 and has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE's disposal facility is not expected to adversely affect the continued operation of the Callaway Plant.
Electric rates charged to customers provide for recovery of Callaway Plant decommissioning costs over the life of the plant, based on an assumed 40-year life, ending with expiration of the plant's operating license in 2024. The Callaway site is assumed to be decommissioned using the DECON (immediate dismantlement) method. Decommissioning costs, including decontamination, dismantling and site restoration, are estimated to be $509 million in current year dollars and are expected to escalate approximately 4% per year through the end of decommissioning activity in 2033. Decommissioning costs are charged to depreciation expense over Callaway's service life and amounted to approximately $7 million in each of the years 1999, 1998 and 1997. Every three years, the MoPSC and ICC require the Registrant to file updated cost studies for decommissioning Callaway, and electric rates may be adjusted at such times to reflect changed estimates. The latest studies were filed in 1999. Costs collected from customers are deposited in an external trust fund to provide for Callaway's decommissioning. Fund earnings are expected to average approximately 9% annually through the date of decommissioning. If the assumed return on trust assets is not earned, the Registrant believes it is probable that any such earnings deficiency will be recovered in rates. Trust fund earnings, net of expenses, appear on the balance sheet as increases in the nuclear decommissioning trust fund and in the accumulated provision for nuclear decommissioning.
The staff of the SEC has questioned certain current accounting practices of the electric utility industry, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In response to these questions, the Financial Accounting Standards Board has agreed to review the accounting for removal costs, including decommissioning. The Registrant does not expect that changes in the accounting for nuclear decommissioning costs will have a material effect on its financial position, results of operations or liquidity.
NOTE 14 - 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.
Nuclear Decommissioning Trust Fund The fair value is estimated based on quoted market prices for securities.
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 $155 $126 $155 $160 Long-term debt (including current portion) 1,894 1,872 1,791 1,919 - --------------------------------------------------------------------------------
The Registrant has investments in debt and equity securities that are held in trust funds for the purpose of funding the nuclear decommissioning of Callaway Nuclear Plant (see Note 13 - Callaway Nuclear Plant). The Registrant has classified these investments in debt and equity securities as available for sale and has recorded all such investments at their fair market value at December 31, 1999 and 1998. In 1999, 1998 and 1997, the proceeds from the sale of investments were $83 million, $29 million and $24 million, respectively. Using the specific identification method to determine cost, the gross realized gains on those sales were approximately $11 million for 1999, and $2 million for both 1998 and 1997. Net realized and unrealized gains and losses are reflected in the accumulated provision for nuclear decommissioning on the balance sheet, which is consistent with the method used by the Registrant to account for the decommissioning costs recovered in rates.
Costs and fair values of investments in debt and equity securities in the nuclear decommissioning trust fund at December 31 were as follows: - ------------------------------------------------------------------------------- 1999 (in millions) Gross Unrealized Security Type Cost Gain (Loss) Fair Value - ------------------------------------------------------------------------------- Debt Securities $67 $-- $-- $67 Equity Securities 45 73 -- 118 Cash equivalents 2 -- -- 2 - ------------------------------------------------------------------------------- $114 $73 $-- $187 - -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------- 1998 (in millions) Gross Unrealized Security Type Cost Gain (Loss) Fair Value - -------------------------------------------------------------------------------- Debt Securities $48 $4 $-- $52 Equity Securities 46 62 -- 108 Cash equivalents 2 -- -- 2 - -------------------------------------------------------------------------------- $96 $66 $-- $162 - --------------------------------------------------------------------------------
The contractual maturities of investments in debt securities at December 31, 1999, were as follows: - --------------------------------------------------------------------------- (in millions) Cost Fair Value - --------------------------------------------------------------------------- 1 year to 5 years $6 $6 5 years to 10 years 30 30 Due after 10 years 31 31 - --------------------------------------------------------------------------- $67 $67 - ---------------------------------------------------------------------------
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 AmerenUE's 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 AmerenUE's 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 AmerenUE's 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 AmerenUE's 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..................................... 39
Schedules not included have been omitted because they are not applicable or the required data is shown in the aforementioned financial statements.
2. Exhibits: See EXHIBITS beginning on Page 41
(b) Reports on Form 8-K. The Registrant filed a report on Form 8-K dated January 20, 2000 reporting the issuance of a Report and Order dated December 23, 1999 by the Missouri Public Service Commission regarding the Registrant's electric alternative regulation plans.
UNION ELECTRIC 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.
UNION ELECTRIC COMPANY (Registrant)
CHARLES W. MUELLER 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/ C. W. Mueller President, Chief Executive Officer and Director - --------------------------- (Principal Executive Officer) CHARLES W. MUELLER
/s/ Donald E. Brandt Senior Vice President and Director - --------------------------- (Principal Financial Officer) DONALD E. BRANDT
/s/ Warner L. Baxter Vice President, Controller and Director - --------------------------- (Principal Accounting Officer) WARNER L. BAXTER
/s/ Paul A. Agathen Director - --------------------------- PAUL A. AGATHEN
/s/ Gary L. Rainwater Director - --------------------------- GARY L. RAINWATER
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.
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 Union Electric Company, CIPSCO Incorporated, Ameren Corporation, and Arch Merger Inc. (June 30, 1995 Form 10-Q/A (Amendment No. 1), Exhibit 2(a).)
3(i) - Restated Articles of Incorporation of the Company, as filed with the Secretary of State of the State of Missouri. (1993 Form 10-K, Exhibit 3(i).)
3(ii)- By-Laws of the Company as amended to August 26, 1999. (September 30, 1999 Form 10-Q, Exhibit 3(ii).)
4.1 - Order of the Securities and Exchange Commission dated October 16, 1945 in File No. 70-1154 permitting the issue of Preferred Stock, $3.70 Series. (Registration No. 2-27474, Exhibit 3-E.)
4.2 - Order of the Securities and Exchange Commission dated April 30, 1946 in File No. 70-1259 permitting the issue of Preferred Stock, $3.50 Series. (Registration No. 2-27474, Exhibit 3-F.)
4.3 - Order of the Securities and Exchange Commission dated October 20, 1949 in File No. 70-2227 permitting the issue of Preferred Stock, $4.00 Series. (Registration No. 2-27474, Exhibit 3-G.)
4.4 - Indenture of Mortgage and Deed of Trust of the Company dated June 15, 1937, as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941. (Registration No. 2-4940, Exhibit B-1.)
4.5 - Supplemental Indentures to Mortgage
Dated as of File Reference Exhibit No. ----------- -------------- ----------- March 1, 1967 2-58274 2.9 April 1, 1971 Form 8-K, April 1971 6 February 1, 1974 Form 8-K, February 1974 3 July 7, 1980 2-69821 4.6 May 1, 1990 Form 10-K, 1990 4.6 December 1, 1991 33-45008 4.4 December 4, 1991 33-45008 4.5 January 1, 1992 Form 10-K, 1991 4.6 October 1, 1992 Form 10-K, 1992 4.6 December 1, 1992 Form 10-K, 1992 4.7 February 1, 1993 Form 10-K, 1992 4.8 May 1, 1993 Form 10-K, 1993 4.6 August 1, 1993 Form 10-K, 1993 4.7 October 1, 1993 Form 10-K, 1993 4.8 January 1, 1994 Form 10-K, 1993 4.9 December 1, 1996 Form 10-K, 1996 4.36
Exhibit No. Description
4.6 - Series A Agreement of Sale dated as of June 1, 1984 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Letter of Credit and Reimbursement Agreement dated as of June 1, 1984 between Citibank, N.A. and the Company and Series A Trust Indenture dated as of June 1, 1984 between the Authority and Mercantile Trust Company National Association, as trustee. (Registration No. 2-96198, Exhibit 4.25.)
4.7 - Reimbursement Agreement dated as of April 21, 1992 among Swiss Bank Corporation, various financial institutions, and the Company, providing for an alternate letter of credit to serve as a source of payment for bonds issued under the Series A Trust Indenture dated as of June 1, 1984. (1992 Form 10-K, Exhibit 4.23.)
4.8 - Series B Agreement of Sale dated as of June 1, 1984 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Reimbursement Agreement dated as of June 1, 1984 between Chemical Bank and the Company and Series B Trust Indenture dated as of June 1, 1984 between the Authority and Mercantile Trust Company National Association, as trustee. (Registration No. 2-96198, Exhibit 4.26.)
4.9 - Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company, providing for an alternate letter of credit to serve as a source of payment for bonds issued under the Series B Trust Indenture dated as of June 1, 1984. (June 30, 1988 Form 10-Q, Exhibit 4.2.)
4.10 - Amendment and Extension Agreement dated as of June 1, 1990 to the Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company. (1990 Form 10-K, Exhibit 4.29.)
4.11 - Amendment and Extension Agreement dated as of June 1, 1991 to the amended Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.27.)
4.12 - Amendment Agreement dated as of June 1, 1992 to the amended Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.28.)
4.13 - Series 1985 A Reaffirmation Agreement and Second Supplement to Agreement of Sale dated as of June 1, 1985 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Series 1985 A Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company and Series 1985 A Trust Indenture dated as of June 1, 1985 between the Authority and Mercantile Trust Company National Association, as trustee and Texas Commerce Bank National Association, as co-trustee. (June 30, 1985 Form 10-Q, Exhibit 4.1.)
4.14 - Amendment and Extension Agreement dated as of June 1, 1988 revising the Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company. (June 30, 1988 Form 10-Q, Exhibit 4.4.)
4.15 - Amendment and Extension Agreement dated as of June 1, 1990 revising the Reimbursement Agreement dated as of June 1, 1985, as amended, between Union Bank of Switzerland and the Company. (1990 Form 10-K, Exhibit 4.37.)
Exhibit No. Description
4.16 - Amendment and Extension Agreement dated as of June 1, 1991 to the amended Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.32.)
4.17 - Amendment Agreement dated as of June 1, 1992 to the amended Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.33.)
4.18 - Series 1985 B Reaffirmation Agreement and Third Supplement to Agreement of Sale dated as of June 1, 1985 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Series 1985 B Reimbursement Agreement dated as of June 1, 1985 between The Long-term Credit Bank of Japan, Limited and the Company and Series 1985 B Trust Indenture dated as of June 1, 1985 between the Authority and Mercantile Trust Company National Association, as trustee and Texas Commerce Bank National Association, as co-trustee. (June 30, 1985 Form 10-Q, Exhibit 4.2.)
4.19 - Reimbursement Agreement dated as of February 1, 1993 between Westdeutsche Landesbank Girozentrale and the Company, providing for an alternate letter of credit to serve as a source of payment for bonds issued under the Series 1985 B Trust Indenture dated as of June 1, 1985. (1992 Form 10-K, Exhibit 4.35.)
4.20 - Loan Agreement dated as of May 1, 1990 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Indenture of Trust dated as of May 1, 1990 between the Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1990 Form 10-K, Exhibit 4.40.)
4.21 - Loan Agreement dated as of December 1, 1991 between the State Environmental Improvement and Energy Resources Authority and the Company, together with Indenture of Trust dated as of December 1, 1991 between the Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1992 Form 10-K, Exhibit 4.37.)
4.22 - Loan Agreement dated as of December 1, 1992, between the State Environmental Improvement and Energy Resources Authority and the Company, together with Indenture of Trust dated as of December 1, 1992 between the Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1992 Form 10-K, Exhibit 4.38.)
4.23 - Fuel Lease dated as of February 24, 1981 between the Company, as lessee, and Gateway Fuel Company, as lessor, covering nuclear fuel. (1980 Form 10-K, Exhibit 10.20.)
4.24 - Amendments to Fuel Lease dated as of May 8, 1984 and October 15, 1984, respectively, between the Company, as lessee, and Gateway Fuel Company, as lessor, covering nuclear fuel. (Registration No. 2-96198, Exhibit 4.28.)
4.25 - Amendment to Fuel Lease dated as of October 15, 1986 between the Company, as lessee, and Gateway Fuel Company, as lessor, covering nuclear fuel. (September 30, 1986 Form 10-Q, Exhibit 4.3.)
4.26 - Credit Agreement dated as of August 15, 1989 among the Company, Certain Lenders, The First National Bank of Chicago, as Agent and Swiss Bank Corporation, Chicago Branch, as Co-Agent. (September 30, 1989 Form 10-Q, Exhibit 4.)
Exhibit No. Description
4.27 - Series 1998A Loan Agreement dated as of September 1, 1998 between The State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.28.)
4.28 - Series 1998B Loan Agreement dated as of September 1, 1998 between The State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.29.)
4.29 - Series 1998C Loan Agreement dated as of September 1, 1998 between The State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.30.)
10.1 - Ameren Long-Term Incentive Plan of 1998. (Ameren's 1998 Form 10-K, Exhibit 10.1.)
10.2 - Ameren Change of Control Severance Plan. (Ameren's 1998 Form 10-K, Exhibit 10.2.)
10.3 - Ameren Deferred Compensation Plan for Members of the Ameren Leadership Team. (Ameren's 1998 Form 10-K, Exhibit 10.3.)
10.4 - 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 1-2967.
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
Union Electric Company (AmerenUE 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, AmerenUE and CIPSCO Incorporated (CIPSCO) combined to form Ameren, with AmerenUE and CIPSCO's subsidiaries, Central Illinois Public Service Company (AmerenCIPS) and CIPSCO Investment Company (CIC), becoming subsidiaries of Ameren (the Merger).
RESULTS OF OPERATIONS
Earnings Earnings for 1999, 1998, and 1997 were $340 million, $311 million, and $293 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 (including Callaway Nuclear Plant refueling outages), merger-related expenses, changes in interest expense, changes in income and property taxes, a targeted employee separation plan and an extraordinary charge.
In 1998, the Registrant recorded a nonrecurring charge to earnings in connection with a targeted separation plan it offered to employees in July 1998. That charge reduced earnings $11 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 Illinois retail electric business as a result of electric industry restructuring legislation enacted in Illinois in December 1997. The write-off reduced earnings $27 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 - ---------------------------------------------------------------------- (Millions of Dollars) 1999 1998 1997 - ---------------------------------------------------------------------- Rate variations $ (9) $ (8) $-- Credit to customers 7 (24) 28 Effect of abnormal weather (37) 48 4 Growth and other 47 48 1 Interchange sales 136 38 (5) - ---------------------------------------------------------------------- $ 144 $ 102 $ 28 - ----------------------------------------------------------------------
Electric revenues for 1999 increased $144 million, compared to 1998, primarily due to a 5% increase in total kilowatthour sales. This increase was primarily driven by a 75% increase in interchange sales, due to strong marketing efforts. Also contributing to the revenue increase was a decrease in the credit to Missouri electric customers (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). Partially offsetting these increases, weather-sensitive residential sales decreased 2%, commercial sales remained flat, while industrial sales decreased 2%.
Electric revenues for 1998 increased $102 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 growth in the service area, and increased interchange revenues, primarily due to favorable market conditions. These increases were partially offset by a rate decrease and an increase in estimated credits to Missouri electric customers, as well as a 5% rate decrease for Illinois electric customers (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). Weather-sensitive residential and commercial sales increased 6% and 4%, respectively, while industrial sales grew 1%. Interchange sales increased 7%, primarily from AmerenCIPS.
The increase in 1997 electric revenues was primarily due to a lower Missouri customer credit recorded in 1997. Residential sales remained flat while interchange sales decreased 5%. Commercial and industrial sales were 1% and 3% higher, respectively.
Fuel and Purchased Power Variations from Prior Year - -------------------------------------------------------------------------------- (Millions of Dollars) 1999 1998 1997 - -------------------------------------------------------------------------------- Fuel: Generation $ (2) $ 24 $ 17 Price (2) (10) (15) Generation efficiencies and other (2) 5 (1) Purchased power 132 11 (14) - -------------------------------------------------------------------------------- $ 126 $ 30 $ (13) - --------------------------------------------------------------------------------
The $126 million increase in fuel and purchased power costs for 1999, compared to 1998, was primarily driven by increased power purchases resulting from higher sales volume.
The $30 million increase in fuel and purchased power costs for 1998, compared to 1997, was primarily driven by increased generation due to higher sales volume, joint dispatch, and higher purchased power prices, partially offset by lower fuel prices. 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. Fuel and purchased power costs decreased in 1997 primarily due to reduced purchased power costs, resulting from relatively flat native load sales coupled with greater generation, as well as lower fuel prices.
Gas Operations Gas revenues in 1998 decreased $7 million compared to 1997, primarily due to an 8% decline in retail sales resulting from mild weather and lower gas costs reflected in the Company's purchased gas adjustment clause. Weather-sensitive residential and commercial sales decreased 10% and 6%, respectively, and industrial sales declined 2%. These decreases were partially offset by benefits realized from an annual $12 million Missouri gas rate increase effective February 1998 (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information).
Gas costs in 1999 increased $5 million compared to 1998, primarily due to higher gas prices partially offset by lower total sales. Gas costs in 1998 declined $14 million compared to 1997, primarily due to lower sales and lower gas prices.
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 the capitalization of certain costs as a result of a Missouri Public Service Commission (MoPSC) Order and 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, the Registrant recorded a nonrecurring, pretax charge of $18 million representing its 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 $11 million in 1998, and approximately $15 million in 1999, and is expected to reduce the Registrant's operating expenses by approximately $14 million to $18 million each year thereafter. See Note 4 - Targeted Separation Plan under Notes to Financial Statements for further information.
The $28 million decrease in other operating expenses in 1999, compared to 1998, was primarily due to the 1998 charge for the TSP and related reduced workforce, decreases in injuries and damages expense (due to claims experience) and information system-related costs and the capitalization of certain costs (including computer software costs) that had previously been expensed for the Registrant's Missouri electric operations (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information).
The $57 million increase in other operating expenses in 1998, compared to 1997, was primarily due to the charge for the TSP and increases in injuries and damages expense and information system-related costs. In 1997, other operating expense increased $26 million primarily due to increased information system-related expenses.
Maintenance expenses increased $25 million in 1999, compared to 1998 primarily due to increased power plant maintenance and tree trimming activity. The expenses incurred for the 35-day refueling outage in the fall of 1999 at the Callaway Nuclear Plant were comparable to those for the 31-day spring 1998 refueling outage. No refueling outage is scheduled for 2000. In 1998, maintenance expenses increased $5 million due to the scheduled spring refueling outage at the Callaway Nuclear Plant; partially offset by less scheduled fossil plant maintenance. In 1997, maintenance expenses decreased $6 million, primarily a result of reduced Callaway Plant expenses due to the absence of a refueling outage in 1997, offset in part by increased scheduled fossil plant maintenance.
Depreciation and amortization expense increased $12 million in 1998 and $7 million in 1997, due to increased depreciable property and amortization of the Missouri portion of merger-related costs which were recorded as a regulatory asset upon Merger close under the conditions of the Missouri Public Service Commission (MoPSC) order approving the Merger.
Taxes Income tax expense from operations increased $13 million in 1999, compared to 1998, due to higher pretax income. Income tax expense from operations increased $25 million in 1998, compared to 1997, due to higher pretax income and a higher effective tax rate. Income tax expense from operations decreased $5 million in 1997 primarily due to a lower effective tax rate.
Other tax expense decreased $8 million in 1999, compared to 1998, primarily due to a decrease in gross receipts taxes related to the Registrant's Illinois jurisdiction. This decrease is the result of the restructuring of the Illinois public utility tax whereby gross receipts taxes are no longer recorded as electric revenues and gross receipts tax expense.
Other Income and Deductions Miscellaneous, net increased $4 million for 1998, compared to 1997, due to increased interest income and gains on the sale of property. Miscellaneous, net increased $12 million for 1997, primarily due to the capitalization of certain merger-related costs in 1997.
Interest Interest expense decreased $10 million in 1999, compared to 1998, primarily due to lower debt outstanding during the year and a decrease in other interest expense. Interest expense decreased $9 million for 1998, compared to 1997, due to lower interest rates and a decrease in other interest expense. Interest expense increased $6 million for 1997 primarily due to higher debt outstanding during the year at higher interest rates.
Balance Sheet The $12 million decrease in trade accounts receivable and unbilled revenue at December 31, 1999, compared to 1998, was due to lower sales and revenues in November and early December 1999, compared to the comparable time period in 1998. The $166 million increase in intercompany notes receivable was due to funds invested in a regulated money pool (see Note 3 - Related Party Transactions under Notes to Financial Statements for further information.)
The $54 million increase in other current liabilities was primarily due to the timing of credit payments to electric customers in the Registrant's Missouri and Illinois jurisdictions, as well as an increase in a liability for an estimated rate reduction for Missouri electric customers retroactive to September 1, 1998 (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). The remaining variance is the result of the timing of various payments to suppliers.
The $37 million increase in other deferred credits and liabilities was primarily due to Callaway Plant decommissioning costs.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $725 million for 1999, compared to $651 million and $602 million in 1998 and 1997, respectively.
Cash flows used in investing activities totaled $419 million, $231 million, and $284 million for the years ended December 31, 1999, 1998 and 1997, respectively. Expenditures in 1999 for constructing new or to improve existing facilities and purchasing rail cars were $246 million. In addition, the Company spent $22 million to acquire nuclear fuel.
Capital expenditures are expected to approximate $297 million in 2000. For the five-year period 2000-2004, construction expenditures are estimated at $1.6 billion. This estimate includes capital expenditures that will be incurred by the Registrant to meet new air quality standards for ozone and particulate matter, as discussed below.
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, early banking of emission credits and installing advanced NOx reduction combustion technology, 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 Missouri (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 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 and 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.
See Note 13 - Callaway Nuclear Plant under Notes to Financial Statements for a discussion of Callaway Plant decommissioning costs.
Cash flows used in financing activities were $236 million for 1999, compared to $376 million and $320 million for 1998 and 1997, respectively. The Registrant's principal financing activities during 1999 included the redemption of $100 million of long-term debt, the issuance of $152 million of long-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 $1 billion 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 $150 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.
The Registrant also has a bank credit agreement due 2002, which permits the borrowing of up to $300 million on a long-term basis, all of which was unused, and $148 million was available at December 31, 1999. In addition, the Registrant has the ability to borrow up to approximately $530 million from Ameren or AmerenCIPS 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 no intercompany borrowings outstanding and $402 million available through the regulated money pool. See Note 8 - Short-Term Borrowings under Notes to Financial Statements for further discussion.
Additionally, the Registrant has a lease agreement that provides for the financing of nuclear fuel. At December 31, 1999, the maximum amount that could be financed under the agreement was $120 million. Cash used in financing for 1999 included issuances under the lease for nuclear fuel of $65 million, offset in part by $15 million of redemptions. At December 31, 1999, $116 million was financed under the lease. See Note 6 - Nuclear Fuel Lease 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 some of the Registrant's collective bargaining units which will permit it to manage its labor costs and practices effectively in the future (see Note 12 - 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 fossil power plants, 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 Federal Energy Regulatory Commission (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 the Registrant, 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 MoPSC and the Illinois Commerce Commission (ICC) have 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 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.
Illinois 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 Illinois Law) providing for electric utility restructuring in Illinois, where approximately 6% of the Registrant's retail electric revenues are derived. This legislation introduces competition into the supply of electric energy at retail in Illinois.
Major provisions of the Illinois 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 6% 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 Illinois Law included a 5% rate decrease for residential customers that became effective in August 1998. This rate decrease reduced electric revenues $1 million in 1999 compared to 1998 and is expected to impact electric revenues by approximately $3 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 Illinois 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 Illinois 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 Illinois Law contains a provision requiring a portion of excess earnings (as defined under the Illinois Law) for the years 1998 through 2004 to be refunded to customers.
In December 1997, after evaluating the impact of the Illinois 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 $27 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.
Missouri In Missouri, where approximately 94% of the Registrant's retail electric revenues are derived, a task force appointed by the MoPSC investigated electric industry restructuring and competition. In 1998 the task force issued a report to the MoPSC that addressed many of the restructuring issues, but did not provide a specific recommendation or approach to restructure the industry. In addition, in 1998, the MoPSC staff issued a proposed plan for restructuring Missouri's electric industry. The staff's plan addressed a number of issues of concern if the industry is restructured in Missouri. It also included a proposal for less than full recovery of strandable costs. The staff's plan has not been addressed by the MoPSC. A joint committee of the Missouri legislature is also conducting hearings on these issues. Several restructuring bills were introduced by the Missouri legislature in 1999 and 2000. The Registrant is unable to predict the timing or ultimate outcome of electric industry restructuring in the state of Missouri.
Summary 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 and net regulatory assets, lower revenues, reduced profit margins and increased costs of capital and operations expenses. The Registrant is actively taking steps to mitigate these potential negative consequences. Most importantly, the Registrant will continue to focus on cost control to ensure that it maintains a competitive cost structure. In Missouri, the Registrant is actively involved in all major deliberations taking place surrounding electric industry restructuring in an effort to ensure that restructuring legislation, if any, contains an orderly transition and is equitable to the Registrant's shareholders. 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 AmerenUE, 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, Note 12 - Commitments and Contingencies and Note 13 - Callaway Nuclear Plant 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 the Registrant's 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. The Registrant handles market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, the Registrant 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 and commercial paper. 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 by approximately $6 million, and net income would decrease by approximately $4 million. This amount has been determined using the assumptions that the Registrant's outstanding variable-rate debt and commercial paper, 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 potential overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would likely take actions to further mitigate 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 in both its Missouri and Illinois jurisdictions. The PGA allows the Registrant to pass on to its customers its prudently incurred costs of natural gas. With approval of the MoPSC, the Registrant participated in an experimental program to control the volatility of gas prices paid by its Missouri customers in the 1998-1999 winter months through the purchase of financial instruments. This program concluded in April 1999.
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 and nuclear fuel to manage its exposure to fuel prices. (See Note 12 - 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 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.
Equity Price Risk The Registrant maintains trust funds, as required by the Nuclear Regulatory Commission and Missouri and Illinois state laws, to fund certain costs of nuclear decommissioning (see Note 13 - Callaway Nuclear Plant under Notes to Financial Statements for further information). As of December 31, 1999, these funds were invested primarily in domestic equity securities, fixed-rate, fixed-income securities, and cash and cash equivalents. By maintaining a portfolio that includes long-term equity investments, the Registrant is seeking to maximize the returns to be utilized to fund nuclear decommissioning costs. However, the equity securities included in the Registrant's portfolio are exposed to price fluctuations in equity markets, and the fixed-rate, fixed-income securities are exposed to changes in interest rates. The Registrant actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, established target allocation percentages of the assets of its trusts to various investment options. The Registrant's exposure to equity price market risk is in large part mitigated due to the fact that the Registrant is currently allowed to recover its decommissioning costs in its rates.
ACCOUNTING MATTERS
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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 and contracts to determine the appropriate accounting for these items under 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 MoPSC and 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 in its Illinois jurisdiction and may be modified in the future for the Registrant's Missouri jurisdiction (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.
In the Illinois retail jurisdiction, 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 Illinois Law (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information). In the Missouri retail jurisdiction, 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. In Illinois and Missouri, changes in gas costs are generally reflected in billings to customers through Purchased Gas Adjustment Clauses.
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 Union Electric Company
In our opinion, the financial statements listed in the index appearing under Item 14(a)(1) on Page 38 present fairly, in all material respects, the financial position of Union Electric Company at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 in conformity with auditing standards 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 accounting principles 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.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP St. Louis, Missouri February 2, 2000
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
UNION ELECTRIC COMPANY BALANCE SHEET (Thousands of Dollars, Except Shares)
See Notes to Financial Statements.
UNION ELECTRIC COMPANY STATEMENT OF INCOME (Thousands of Dollars)
See Notes to Financial Statements.
UNION ELECTRIC 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 Company's Illinois retail electric business as a result of electric industry restructuring legislation enacted in Illinois in December 1997. The write-off reduced earnings $27 million, net of income taxes. See Note 2 - Regulatory Matters under Notes to Financial Statements for further information.
See Notes to Financial Statements.
UNION ELECTRIC COMPANY
STATEMENT OF RETAINED EARNINGS - ------------------------------ (Thousands of Dollars)
- -------------------------------------------------------------------------------- Year Ended December 31, 1999 1998 1997 Balance at Beginning of Period $1,211,610 $1,159,956 $1,126,513 - -------------------------------------------------------------------------------- Add: Net income 349,252 320,070 301,655 - -------------------------------------------------------------------------------- 1,560,862 1,480,026 1,428,168 - -------------------------------------------------------------------------------- Deduct: Common stock dividends 328,674 259,599 259,395 Preferred stock dividends 11,021 8,817 8,817 - -------------------------------------------------------------------------------- 339,695 268,416 268,212 - -------------------------------------------------------------------------------- Balance at End of Period $1,221,167 $1,211,610 $1,159,956 - -------------------------------------------------------------------------------- Under the mortgage indenture, as amended, $31,305 of total retained earnings was restricted against payment of common dividends - except those payable in common stock, leaving $1,189,862 of free and unrestricted retained earnings at December 31, 1999.
SELECTED QUARTERLY INFORMATION (Unaudited) - -------------------------------- (Thousands of Dollars)
- -------------------------------------------------------------------------------- Operating Operating Net Net Income Revenues Income Income After Quarter Ended Preferred Stock Dividends - -------------------------------------------------------------------------------- March 31, 1999 (a) $506,071 $68,887 $43,743 $41,539 March 31, 1998 (a) $478,585 $62,120 $30,302 $28,098 June 30, 1999 621,367 96,292 70,669 68,464 June 30, 1998 (b) 588,676 92,827 66,251 64,046 September 30, 1999 905,850 235,707 208,727 206,523 September 30, 1998 (c) 846,437 233,738 206,551 204,347 December 31, 1999 (d) 493,878 42,382 26,113 23,909 December 31, 1998 468,373 39,498 16,966 14,762 - --------------------------------------------------------------------------------
(a) The first quarter of 1999 and 1998 included credits to Missouri electric customers that reduced net income approximately $11 million and $6 million, respectively. (b) The second quarter of 1998 included credits to Missouri electric customers that reduced net income approximately $18 million. Callaway Plant refueling expenses, which decreased net income approximately $18 million, were also included in the second quarter of 1998. (c) The third quarter of 1998 included a nonrecurring charge related to the targeted employee separation plan that reduced net income $11 million. (See Note 4 - Targeted Separation Plan under Notes to Financial Statements for further information.) (d) The fourth quarter of 1999 included adjustments that increased earnings $9 million as a result of a Report and Order received from the Missouri Public Service Commission relating to the Registrant's electric alternative regulation plan. (See Note 2 - Regulatory Matters under Notes to Financial Statements for further information). In addition, Callaway Plant refueling expenses, which decreased net income approximately $22 million were included in the fourth quarter of 1999.
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.
UNION ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 1999
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation Union Electric Company (AmerenUE or the Registrant) is a subsidiary of Ameren Corporation (Ameren), which is the parent company of two utility operating companies, the Registrant and Central Illinois Public Service Company (AmerenCIPS). Ameren is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA) formed in December 1997 upon the merger of AmerenUE and CIPSCO Incorporated (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 Missouri and Illinois. Contracts among the companies--dealing with jointly-owned 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 1.1 million electric and 125,000 gas customers in a 24,500 square-mile area of Missouri and Illinois, including Metropolitan St. Louis.
The Registrant also has a 40% 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 Missouri Public Service Commission (MoPSC), 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 In the Missouri and Illinois retail electric jurisdictions, the cost of fuel for electric generation is reflected in base rates with no provision for changes to be made through fuel adjustment clauses. (See Note 2 - Regulatory Matters for further information.) In the Illinois jurisdiction in 1997, changes in fuel costs were generally reflected in billings to electric customers through a fuel adjustment clause. In the Illinois and Missouri retail gas jurisdictions, changes in gas costs are generally reflected in billings to gas customers through purchased gas adjustment clauses.
Nuclear Fuel The cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is charged to expense based on net kilowatthours generated and sold.
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 liabili-
ties 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 10% during 1999 and 9% during 1998 and 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 AmerenUE and AmerenCIPS. 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
Missouri Electric In July 1995, the MoPSC approved an agreement establishing contractual obligations involving the Registrant's Missouri retail electric rates. Included was a three-year experimental alternative regulation plan (the Original Plan) that ran from July 1, 1995, through June 30, 1998, which provided that earnings in those years in excess of a 12.61% regulatory return on equity (ROE) be shared equally between customers and stockholders, and earnings above a 14% ROE be credited to customers. The formula for computing the credit used twelve-month results ending June 30, rather than calendar year earnings. In 1996, the Registrant recorded a $47 million credit for the first year of the Original Plan, which reduced earnings $28 million. During 1997, the Registrant recorded a $20 million credit for the second year of the Original Plan, which reduced earnings $11 million. In 1998, the Registrant recorded an estimated $43 million credit for the final year of the Original Plan, which reduced earnings $26 million.
Included in the joint agreement approved by the MoPSC in its February 1997 order authorizing the Merger, was a new three-year experimental alternative regulation plan (the New Plan) that runs from July 1, 1998, through June 30, 2001. Like the Original Plan, the New Plan requires that earnings over a 12.61% ROE up to a 14% ROE be shared equally between customers and shareholders. The New Plan also returns to customers 90% of all earnings above a 14% ROE up to a 16% ROE. Earnings above a 16% ROE are credited entirely to customers. In addition, the joint agreement provides for a Missouri electric rate decrease, retroactive to September 1, 1998, based on the weather-adjusted average annual credits to customers under the Original Plan. The Registrant estimated that its Missouri electric rate decrease should approximate $20 million on an annualized basis and reduced revenues accordingly since September 1998.
In November 1998, the MoPSC Staff proposed adjustments to the customer credit for the third year of the Original Plan. In addition, the MoPSC Staff proposed adjustments to the Registrant's estimated Missouri electric rate decrease based upon their methodology of calculating the weather-adjusted credits. The determination of the credit for the third year of the Original Plan, as well as the determination of the Missouri electric rate decrease, were subject to regulatory proceedings before the MoPSC in 1999.
On December 23, 1999, the MoPSC issued a Report and Order (Order) related to the customer credit for the third year of the Original Plan. Certain of the MoPSC staff's proposed adjustments were accepted by the MoPSC in the Order. In addition, the Order requires the Registrant to capitalize and amortize certain costs (including computer software costs) that had previously been expensed for its Missouri electric operations.
Based on the provisions of the Order, the Registrant estimates that the credit for the third year of the Original Plan will approximate $31 million. In addition, with regard to the Missouri electric rate decrease, the Registrant, the MoPSC staff, and other parties reached a settlement related to the calculation of the weather-adjusted credits. As a result, the Registrant estimates that the annualized Missouri electric rate decrease will approximate $17 million. On February 24, 2000, the Registrant filed a Petition for Writ of Review with the Circuit Court of Cole County, Missouri, asking that the Order be reversed. The Registrant has also requested that the court issue a stay of the MoPSC's Order. While it is unable to predict the ultimate outcome of the judicial appeal of the MoPSC's Order, the Registrant believes that the final decision will not have a material adverse effect on its financial position, results of operations or liquidity.
The provisions of the Order also have an impact on the estimated credit to electric customers recorded by the Registrant for the first year of the New Plan. As a result, the Registrant recorded an estimated credit of $25 million for the plan year ended June 30, 1999. In addition, the Registrant recorded an estimated $20 million credit for the 1999 portion of the second year of the New Plan. Also, the provision of the Order which requires the Registrant to capitalize and amortize certain costs (including computer software costs) that had been previously expensed resulted in the capitalization of approximately $20 million of costs in the fourth quarter of 1999.
In summary, the provisions of the Order and the resulting changes in the Registrant's estimates of credits and Missouri electric rate decrease for the open years under the Original Plan and the New Plan resulted in an increase in earnings of approximately $9 million in the fourth quarter of 1999.
On December 30, 1999, the Registrant filed a request for rehearing with the MoPSC, asking that it reconsider its decision to adopt certain of the MoPSC staff's adjustments. On January 25, 2000, the MoPSC denied the Registrant's request. The Registrant plans to file an appeal with the courts.
Gas In December 1997, the MoPSC approved a $12 million annual rate increase for natural gas service in the Registrant's Missouri jurisdiction. The rate increase became effective in February 1998.
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 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 MoPSC and the ICC have 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.
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 Illinois Law) providing for electric utility restructuring in Illinois, where approximately 6% of the Registrant's retail electric revenues are derived. This legislation introduces competition into the supply of electric energy at retail in Illinois.
Under the Illinois 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 Illinois 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 AmerenCIPS 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 Illinois Law included a 5% residential electric rate decrease for the Registrant's Illinois electric customers, effective August 1, 1998. This rate decrease reduced electric revenues approximately $1 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 Illinois Law, the Registrant filed a proposal with the ICC to eliminate their electric fuel adjustment clause for Illinois retail customers, thereby including a historical levels of fuel costs in base rates. The ICC approved the Registrant's filing in early 1998.
The Illinois Law also contains a provision requiring that one-half of excess earnings from the Illinois jurisdiction for the years 1998 through 2004 be refunded to the Registrant's Illinois customers. Excess earnings are defined as the portion of the two-year average annual rate of return on common equity in excess of 1.5% of the two-year average of an Index, as defined in the Illinois 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 US 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.
Other provisions of the Illinois 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 in Illinois, 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 portion of the business that no longer meets the 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 Illinois 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 Illinois retail portion of its generating business (i.e., the portion of the Registrant's business related to the supply of electric energy in Illinois) in the fourth quarter of 1997. The Registrant evaluated the impact of the Illinois 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 the cash flows from the regulated portion of its business. Accordingly, the Registrant's generation-related regulatory assets and liabilities of its Illinois retail electric business were written off in the fourth quarter of 1997, resulting in an extraordinary charge to earnings of $27 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 deferred charges related to 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.
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 in Illinois who choose other suppliers as allowed under the Illinois 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 Illinois 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 Illinois Law on the Registrant's future financial condition, results of operations or liquidity.
Missouri Electric Restructuring In Missouri, where approximately 94% of the Registrant's retail electric revenues are derived, a task force appointed by the MoPSC investigated electric industry restructuring and competition. In 1998, the task force issued a report to the MoPSC that addressed many of the restructuring issues but did not provide a specific recommendation or approach to restructure the industry. In addition, in 1998, the MoPSC staff issued a proposed plan for restructuring Missouri's electric industry. The staff's plan addressed a number of issues of concern if the industry is restructured in Missouri. It also included a proposal for less than full recovery of strandable costs. The staff's plan has not been
addressed by the MoPSC. A joint committee of the Missouri legislature is also conducting hearings on these issues. Several restructuring bills were introduced by the Missouri legislature in 1999 and 2000.
The Registrant is unable to predict the timing or ultimate outcome of electric industry restructuring in the state of Missouri, as well as the impact of potential electric industry restructuring matters on the Registrant's future financial condition, results of operations or liquidity. The potential negative consequences of electric industry restructuring could be significant and include the impairment and write-down of certain assets, including generation-related plant and net regulatory assets, lower revenues, reduced profit margins and increased costs of capital and operations expense. At December 31, 1999, the Registrant's net investment in generation facilities related to its Missouri jurisdiction approximated $2.6 billion and was included in electric plant in-service on the Registrant's balance sheet. In addition, at December 31, 1999, the Registrant's Missouri net generation-related regulatory assets approximated $454 million.
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 $601 $608 Callaway costs 92 95 Unamortized loss on reacquired debt 24 26 Merger costs 22 24 Other 18 20 - ----------------------------------------------------------------------- Regulatory Assets $757 $773 - ----------------------------------------------------------------------- Regulatory Liability: Income taxes $154 $159 - ----------------------------------------------------------------------- Regulatory Liability $154 $159 - -----------------------------------------------------------------------
Income Taxes: See Note 10 - Income Taxes. Callaway Costs: Represents Callaway Nuclear Plant operations and maintenance expenses, property taxes and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the plant (through 2024). 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. Merger Costs: Represents the portion of merger-related expenses applicable to the Missouri retail jurisdiction. These costs are being amortized within 10 years, based on a MoPSC order.
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. However, as noted in the above paragraphs, electric industry restructuring legislation may impact the recoverability of regulatory assets in the future.
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 $15 million and $6 million, respectively, as of December 31, 1999 and 1998. Intercompany payables included in accounts and wages payable totaled approximately $25 million and $17 million, respectively, as of December 31, 1999 and 1998.
In addition, the Registrant has the ability to borrow funds from Ameren or AmerenCIPS or invest funds through a regulated money pool agreement. At December 31, 1999, the Registrant had outstanding intercompany receivables of $166 million through the regulated money pool. See Note 8 - 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 $18 million was recorded, which reduced earnings $11 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 receivables 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 Missouri and 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 - Nuclear Fuel Lease
The Registrant has a lease agreement that provides for the financing of nuclear fuel. At December 31, 1999, the maximum amount that could be financed under the agreement was $120 million. Pursuant to the terms of the lease, the Registrant has assigned to the lessor certain contracts for purchase of nuclear fuel. The lessor obtains, through the issuance of commercial paper or from direct loans under a committed revolving credit agreement from commercial banks, the necessary funds to purchase the fuel and make interest payments when due.
The Registrant is obligated to reimburse the lessor for all expenditures for nuclear fuel, interest and related costs. Obligations under this lease become due as the nuclear fuel is consumed at the Registrant's Callaway Nuclear Plant. The Registrant reimbursed the lessor $16 million in 1999, $23 million during 1998 and $31 million during 1997.
The Registrant has capitalized the cost, including certain interest costs, of the leased nuclear fuel and has recorded the related lease obligation. Total interest charges under the lease were $5 million in 1999 and 1998 and $6 million in 1997. Interest charges for these years were based on average interest rates of approximately 6%. Interest charges of $4 million were capitalized in 1999 and $3 million were capitalized in 1998 and 1997.
NOTE 7 - Preferred Stock
At December 31, 1999 and 1998, the Registrant had 25 million shares of authorized preferred stock.
Outstanding preferred stock is entitled to cumulative dividends and is redeemable at the redemption prices shown below: - --------------------------------------------------------------------------------
- -------------------------------------------------------------------------------- Preferred Stock Not Subject to Mandatory Redemption: (in millions) - -------------------------------------------------------------------------------- Redemption Price December 31, (per share) 1999 1998 Without par value and stated value of $100 per share-- $7.64 Series - 330,000 shares $103.82 - note (a) $33 $33 $5.50 Series A - 14,000 shares 110.00 1 1 $4.75 Series - 20,000 shares 102.176 2 2 $4.56 Series - 200,000 shares 102.47 20 20 $4.50 Series - 213,595 shares 110.00 - note (b) 21 21 $4.30 Series - 40,000 shares 105.00 4 4 $4.00 Series - 150,000 shares 105.625 15 15 $3.70 Series - 40,000 shares 104.75 4 4 $3.50 Series - 130,000 shares 110.00 13 13
Without par value and stated value of $25 per share-- $1.735 Series - 1,657,500 shares 25.00 42 42 - --------------------------------------------------------------------------------
TOTAL PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION $155 $155 - --------------------------------------------------------------------------------
(a) Beginning February 15, 2003, eventually declining to $100 per share. (b) In the event of voluntary liquidation, $105.50.
- --------------------------------------------------------------------------------
NOTE 8 - 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). At December 31, 1999 and 1998 the Registrant had no outstanding short-term borrowings.
At December 31, 1999, the Registrant had committed bank lines of credit aggregating $150 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 $530 million from Ameren or AmerenCIPS 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 no intercompany borrowings outstanding and $402 million available through the regulated money pool.
NOTE 9 - Long-Term Debt
- -------------------------------------------------------------------------------- (in millions) 1999 1998 - -------------------------------------------------------------------------------- First Mortgage Bonds - note (a) - -------------------------------------------------------------------------------- 6 3/4% Series paid in 1999 $ - $100 8.33% Series due 2002 75 75 7.65% Series due 2003 100 100 6 7/8% Series due 2004 188 188 7 3/8% Series due 2004 85 85 6 3/4% Series due 2008 148 148 7.40% Series due 2020 - note (b) 60 60 8 3/4% Series due 2021 125 125 8% Series due 2022 85 85 8 1/4% Series due 2022 104 104 7.15% Series due 2023 75 75 7% Series due 2024 100 100 5.45% Series due 2028 - note (b) 44 44 - -------------------------------------------------------------------------------- 1,189 1,289 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Missouri Environmental Improvement Revenues Bonds - -------------------------------------------------------------------------------- 1985 Series A due 2015 - note (c) 70 70 1985 Series B due 2015 - note (c) 57 57 1991 Series due 2020 - note (c) 43 43 1992 Series due 2022 - note (c) 47 47 1998 Series A due 2033 - note (c) 60 60 1998 Series B due 2033 - note (c) 50 50 1998 Series C due 2033 - note (c) 50 50 - -------------------------------------------------------------------------------- 377 377 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Subordinated Deferrable Interest Debentures - -------------------------------------------------------------------------------- 7.69% Series A due 2036 - note (d) 66 66 - ------------------------------------------------------------------------------- Commercial Paper - note (e) 152 -- - ------------------------------------------------------------------------------- Nuclear Fuel Lease 116 66 - ------------------------------------------------------------------------------- Unamortized Discount and Premium on Debt (6) (7) - ------------------------------------------------------------------------------- Maturities Due Within One Year (11) (117) ------------------------------------------------------------------------------ Total Long-Term Debt $1,883 $1,674 - -------------------------------------------------------------------------------
(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) Environmental Improvement Series. (c) Interest rates, and the periods during which such rates apply, vary depending on the Registrant's selection of certain defined rate modes. The average interest rates for the year 1999 are as follows: 1985 Series A 3.21% 1985 Series B 3.29% 1991 Series 3.65% 1992 Series 3.55% 1998 Series A 3.49% 1998 Series B 3.48% 1998 Series C 3.46% (d) During the terms of the debentures, the Registrant may, under certain circumstances, defer the payment of interest for up to five years. (e) A bank credit agreement, due 2002, permits the Registrant to borrow or to support commercial paper borrowings up to $300 million. Interest rates will vary depending on market conditions. At December 31, 1999, no such borrowings were outstanding.
Maturities of long-term debt through 2004 are as follows: - ---------------------------------------- (in millions) Principal Amount - ---------------------------------------- 2000 $ 11 2001 -- 2002 227 2003 100 2004 273 - ----------------------------------------
Amounts for years subsequent to 2000 do not include nuclear fuel lease payments since the amounts of such payments are not currently determinable.
NOTE 10 - Income Taxes
Total income tax expense for 1999 resulted in an effective tax rate of 40% on earnings before income taxes (40% in 1998 and 38% in 1997).
Principal reasons such rates differ from the statutory federal rate: - ------------------------------------------------------------------------ 1999 1998 1997 - ------------------------------------------------------------------------ Statutory federal income tax rate 35% 35% 35% Increases (Decreases) from: Depreciation differences 2 2 2 State income tax 4 4 4 Other (1) (1) (3) - ------------------------------------------------------------------------ Effective income tax rate 40% 40% 38% - ------------------------------------------------------------------------
Income tax expense components: - ------------------------------------------------------------------------ (in millions) 1999 1998 1997 - ------------------------------------------------------------------------ Taxes currently payable (principally federal): Included in operating expenses $236 $237 $216 Included in other income-- Miscellaneous, net (4) (5) (3) - ------------------------------------------------------------------------ 232 232 213 Deferred taxes (principally federal): Included in operating expenses-- Depreciation differences 9 (1) (7) Other (9) (14) (10) Included in other income-- Depreciation differences -- -- 1 Other -- -- 9 - ------------------------------------------------------------------------ -- (15) (7) Deferred investment tax credits, Amortization Included in operating expenses (5) (5) (6) - ------------------------------------------------------------------------ Total income tax expense $227 $212 $200 - ------------------------------------------------------------------------
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: Depreciation $822 $814 Regulatory assets, net 462 465 Capitalized taxes and expenses 60 68 Deferred benefit costs (47) (48) - ------------------------------------------------------------------------------ Total net accumulated deferred income tax liabilities $1,297 $1,299 - ------------------------------------------------------------------------------
NOTE 11 - 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 for 1999 were $18 million, of which approximately 18% was charged to construction accounts. The AmerenUE pension plan information for 1998 and 1997 is presented separately.
Pension costs for the years 1998 and 1997 were $28 million and $24 million, respectively, of which approximately 19% and 17%, respectively, was charged to construction accounts.
Funded Status of Pension Plans: - ------------------------------------------------------------------------ (in millions) 1998 - ------------------------------------------------------------------------ Change in benefit obligation Net benefit obligation at beginning of year $999 Service cost 24 Interest cost 70 Amendments 10 Actuarial loss 38 Special termination benefit charge 7 Benefits paid (88) - ------------------------------------------------------------------------ Net benefit obligation at end of year 1,060
Change in plan assets * Fair value of plan assets at beginning of year 1,006 Actual return on plan assets 122 Employer contributions 1 Benefits paid (88) - ------------------------------------------------------------------------ Fair value of plan assets at end of year 1,041
Funded status - deficiency 19 Unrecognized net actuarial gain 121 Unrecognized prior service cost (73) Unrecognized net transition asset 6 - ------------------------------------------------------------------------ Accrued pension cost at December 31 $73 - ------------------------------------------------------------------------ * Plan assets consist principally of common stocks and fixed income securities.
Components of Net Periodic Benefit Cost: - -------------------------------------------------------------------------------- (in millions) 1998 1997 - -------------------------------------------------------------------------------- Service cost $24 $22 Interest cost 70 69 Expected return on plan assets (75) (71) Amortization of: Transition asset (1) (1) Prior service cost 6 7 Actuarial gain (3) (2) Special termination benefit charge 7 -- - -------------------------------------------------------------------------------- Net periodic benefit cost $28 $24 - --------------------------------------------------------------------------------
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 accrues the expected postretirement benefit costs during employees' years of service.
The Registrant's funding policy is to annually contribute the net periodic cost to a Voluntary Employee Beneficiary Association trust (VEBA). Postretirement benefit costs were $46 million in 1999, $43 million for 1998 and $44 million in 1997, of which approximately 18% in 1999 and 17% in 1998 and 1997 were charged to construction accounts. The Registrant's transition obligation at December 31, 1999 is being amortized over the next 13 years.
The MoPSC and the ICC allow the recovery of postretirement benefit costs in rates to the extent that such costs are funded. In December 1995, the Registrant established two external trust funds for retiree health care and life insurance benefits. In 1998, 1997 and 1996, claims were paid out of the plan trust funds.
Funded Status of the Plans: - -------------------------------------------------------------------------------- (in millions) 1999 1998 - -------------------------------------------------------------------------------- Change in benefit obligation Net benefit obligation at beginning of year $360 $333 Service cost 15 14 Interest cost 25 24 Actuarial (gain)/loss (20) 9 Benefits paid (26) (20) - -------------------------------------------------------------------------------- Net benefit obligation at end of year 354 360
Change in plan assets * Fair value of plan assets at beginning of year 110 81 Actual return on plan assets 4 8 Employer contributions 46 44 Unincorporated business income tax -- (3) Benefits paid (26) (20) - -------------------------------------------------------------------------------- Fair value of plan assets at end of year 134 110
Funded status - deficiency 220 250 Unrecognized net actuarial gain 29 11 Unrecognized prior service cost (3) (3) Unrecognized net transition obligation (162) (175) - -------------------------------------------------------------------------------- Postretirement benefit liability at December 31 $84 $83 - -------------------------------------------------------------------------------- * Plan assets consist principally of common stocks and fixed income securities.
Components of Net Periodic Benefit Cost: - -------------------------------------------------------------------------------- (in millions) 1999 1998 1997 - -------------------------------------------------------------------------------- Service cost $15 $14 $12 Interest cost 25 24 23 Expected return on plan assets (6) (5) (2) Amortization of: Transition obligation 12 12 12 Actuarial gain -- (2) (1) - -------------------------------------------------------------------------------- Net periodic benefit cost $46 $43 $44 - --------------------------------------------------------------------------------
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 $4 million and $31 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 $4 million and $31 million, respectively.
NOTE 12 - Commitments and Contingencies
The Registrant is engaged in a capital program under which expenditures averaging approximately $317 million, including AFC, are anticipated during each of the next five years. This estimate includes capital expenditures that will be incurred by the Registrant to meet new air quality standards for ozone and particulate matter, as discussed later in this Note.
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 $1.0 billion. Total coal purchases, including transportation costs, for 1999, 1998 and 1997 were $312 million, $304 million, and $267 million, 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 $54 million for 1999, $50 million for 1998, and $64 million for 1997. The Registrant's nuclear fuel commitments for 2000 through 2004, including uranium concentrates, conversion, enrichment and fabrication, are expected to total $73 million, and are expected to be financed under the nuclear fuel lease. Nuclear fuel expenditures for 1999, 1998 and 1997 were $22 million, $20 million and $35 million, respectively. Additionally, the Registrant has long-term contracts with other utilities to purchase electric capacity. These commitments for 2000 through 2004 are estimated to total $200 million. During 1999, 1998 and 1997, electric capacity purchases were $38 million, $35 million, and $34 million, respectively.
The Registrant's insurance coverage for Callaway Nuclear Plant at December 31, 1999, was as follows:
Type and Source of Coverage - ------------------------------------------------------------------------------- (in millions) Maximum Maximum Coverages Assessments For Single Incidents - ------------------------------------------------------------------------------- Public Liability: American Nuclear Insurers $ 200 $-- Pool Participation 9,338 88 (a) - ------------------------------------------------------------------------------- $ 9,538 (b) $ 88 - ------------------------------------------------------------------------------- Nuclear Worker Liability: American Nuclear Insurers $ 200 (c) $ 3 - ------------------------------------------------------------------------------- Property Damage: Nuclear Electric Insurance Ltd. $ 2,750 (d) $ 11 - ------------------------------------------------------------------------------- Replacement Power: Nuclear Electric Insurance Ltd. $ 490 (e) $2 - ------------------------------------------------------------------------------- (a) Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended, (Price- Anderson). Subject to retrospective assessment with respect to loss from an incident at any U.S. reactor, payable at $10 million per year. Price-Anderson expires in 2002. (b) Limit of liability for each incident under Price-Anderson. (c) Industry limit for potential liability from workers claiming exposure to the hazard of nuclear radiation. (d) Includes premature decommissioning costs. (e) Weekly indemnity of $3.5 million, for 52 weeks which commences after the first 12 weeks of an outage, plus $2.8 million per week for 110 weeks thereafter. - --------------------------------------------------------------------------------
Price-Anderson limits the liability for claims from an incident involving any licensed U.S. nuclear facility. The limit is based on the number of licensed reactors and is adjusted at least every five years based on the Consumer Price Index. Utilities owning a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by Price-Anderson.
If losses from a nuclear incident at Callaway exceed the limits of, or are not subject to, insurance, or if coverage is not available, the Registrant will self-insure the risk. Although the Registrant has no reason to anticipate a serious nuclear incident, if one did occur it could have a material, but indeterminable, adverse effect on the Registrant's financial position, results of operations or liquidity.
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, early banking of emission credits and installing advanced NOx reduction combustion technology, 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 Missouri (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 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.
As of December 31, 1999, the Registrant was designated as a potentially responsible party (PRP) by federal and state environmental protection agencies at four 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 at a former manufactured gas plant site located in Illinois are being accrued and deferred rather than expensed currently, pending recovery through environmental adjustment clause rate riders approved by the ICC. 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 1997 and 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 its hazardous waste 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.
Certain employees of the Registrant are represented by the International Brotherhood of Electrical Workers (IBEW) and the International Union of Operating Engineers. These employees comprise approximately 77% of the Registrant's workforce. New contracts with collective bargaining units representing approximately 46% of these employees were ratified in 1999 with terms 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 employees of the Registrant and Ameren Services Company. Negotiations with Local 1455 are still ongoing. However, after engaging in extensive good-faith bargaining with IBEW Locals 1439, 309 and 649, the Registrant submitted a last, best and final offer to these collective bargaining units on February 2, 2000. The offer was rejected and the Registrant 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 the Registrant'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 other union represented employees to any action by its employees. The Registrant is also unable to determine what, if any, impact these labor matters could have on its future financial condition, results of operations or liquidity.
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 13 - Callaway Nuclear Plant
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill per nuclear-generated kilowatthour sold for future disposal of spent fuel. Electric rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. The Registrant has sufficient storage capacity at the Callaway Plant site until 2020 and has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE's disposal facility is not expected to adversely affect the continued operation of the Callaway Plant.
Electric rates charged to customers provide for recovery of Callaway Plant decommissioning costs over the life of the plant, based on an assumed 40-year life, ending with expiration of the plant's operating license in 2024. The Callaway site is assumed to be decommissioned using the DECON (immediate dismantlement) method. Decommissioning costs, including decontamination, dismantling and site restoration, are estimated to be $509 million in current year dollars and are expected to escalate approximately 4% per year through the end of decommissioning activity in 2033. Decommissioning costs are charged to depreciation expense over Callaway's service life and amounted to approximately $7 million in each of the years 1999, 1998 and 1997. Every three years, the MoPSC and ICC require the Registrant to file updated cost studies for decommissioning Callaway, and electric rates may be adjusted at such times to reflect changed estimates. The latest studies were filed in 1999. Costs collected from customers are deposited in an external trust fund to provide for Callaway's decommissioning. Fund earnings are expected to average approximately 9% annually through the date of decommissioning. If the assumed return on trust assets is not earned, the Registrant believes it is probable that any such earnings deficiency will be recovered in rates. Trust fund earnings, net of expenses, appear on the balance sheet as increases in the nuclear decommissioning trust fund and in the accumulated provision for nuclear decommissioning.
The staff of the SEC has questioned certain current accounting practices of the electric utility industry, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In response to these questions, the Financial Accounting Standards Board has agreed to review the accounting for removal costs, including decommissioning. The Registrant does not expect that changes in the accounting for nuclear decommissioning costs will have a material effect on its financial position, results of operations or liquidity.
NOTE 14 - 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.
Nuclear Decommissioning Trust Fund The fair value is estimated based on quoted market prices for securities.
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 $155 $126 $155 $160 Long-term debt (including current portion) 1,894 1,872 1,791 1,919 - --------------------------------------------------------------------------------
The Registrant has investments in debt and equity securities that are held in trust funds for the purpose of funding the nuclear decommissioning of Callaway Nuclear Plant (see Note 13 - Callaway Nuclear Plant). The Registrant has classified these investments in debt and equity securities as available for sale and has recorded all such investments at their fair market value at December 31, 1999 and 1998. In 1999, 1998 and 1997, the proceeds from the sale of investments were $83 million, $29 million and $24 million, respectively. Using the specific identification method to determine cost, the gross realized gains on those sales were approximately $11 million for 1999, and $2 million for both 1998 and 1997. Net realized and unrealized gains and losses are reflected in the accumulated provision for nuclear decommissioning on the balance sheet, which is consistent with the method used by the Registrant to account for the decommissioning costs recovered in rates.
Costs and fair values of investments in debt and equity securities in the nuclear decommissioning trust fund at December 31 were as follows: - ------------------------------------------------------------------------------- 1999 (in millions) Gross Unrealized Security Type Cost Gain (Loss) Fair Value - ------------------------------------------------------------------------------- Debt Securities $67 $-- $-- $67 Equity Securities 45 73 -- 118 Cash equivalents 2 -- -- 2 - ------------------------------------------------------------------------------- $114 $73 $-- $187 - -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------- 1998 (in millions) Gross Unrealized Security Type Cost Gain (Loss) Fair Value - -------------------------------------------------------------------------------- Debt Securities $48 $4 $-- $52 Equity Securities 46 62 -- 108 Cash equivalents 2 -- -- 2 - -------------------------------------------------------------------------------- $96 $66 $-- $162 - --------------------------------------------------------------------------------
The contractual maturities of investments in debt securities at December 31, 1999, were as follows: - --------------------------------------------------------------------------- (in millions) Cost Fair Value - --------------------------------------------------------------------------- 1 year to 5 years $6 $6 5 years to 10 years 30 30 Due after 10 years 31 31 - --------------------------------------------------------------------------- $67 $67 - ---------------------------------------------------------------------------
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 AmerenUE's 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 AmerenUE's 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 AmerenUE's 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 AmerenUE's 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..................................... 39
Schedules not included have been omitted because they are not applicable or the required data is shown in the aforementioned financial statements.
2. Exhibits: See EXHIBITS beginning on Page 41
(b) Reports on Form 8-K. The Registrant filed a report on Form 8-K dated January 20, 2000 reporting the issuance of a Report and Order dated December 23, 1999 by the Missouri Public Service Commission regarding the Registrant's electric alternative regulation plans.
UNION ELECTRIC 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.
UNION ELECTRIC COMPANY (Registrant)
CHARLES W. MUELLER 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/ C. W. Mueller President, Chief Executive Officer and Director - --------------------------- (Principal Executive Officer) CHARLES W. MUELLER
/s/ Donald E. Brandt Senior Vice President and Director - --------------------------- (Principal Financial Officer) DONALD E. BRANDT
/s/ Warner L. Baxter Vice President, Controller and Director - --------------------------- (Principal Accounting Officer) WARNER L. BAXTER
/s/ Paul A. Agathen Director - --------------------------- PAUL A. AGATHEN
/s/ Gary L. Rainwater Director - --------------------------- GARY L. RAINWATER
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.
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 Union Electric Company, CIPSCO Incorporated, Ameren Corporation, and Arch Merger Inc. (June 30, 1995 Form 10-Q/A (Amendment No. 1), Exhibit 2(a).)
3(i) - Restated Articles of Incorporation of the Company, as filed with the Secretary of State of the State of Missouri. (1993 Form 10-K, Exhibit 3(i).)
3(ii)- By-Laws of the Company as amended to August 26, 1999. (September 30, 1999 Form 10-Q, Exhibit 3(ii).)
4.1 - Order of the Securities and Exchange Commission dated October 16, 1945 in File No. 70-1154 permitting the issue of Preferred Stock, $3.70 Series. (Registration No. 2-27474, Exhibit 3-E.)
4.2 - Order of the Securities and Exchange Commission dated April 30, 1946 in File No. 70-1259 permitting the issue of Preferred Stock, $3.50 Series. (Registration No. 2-27474, Exhibit 3-F.)
4.3 - Order of the Securities and Exchange Commission dated October 20, 1949 in File No. 70-2227 permitting the issue of Preferred Stock, $4.00 Series. (Registration No. 2-27474, Exhibit 3-G.)
4.4 - Indenture of Mortgage and Deed of Trust of the Company dated June 15, 1937, as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941. (Registration No. 2-4940, Exhibit B-1.)
4.5 - Supplemental Indentures to Mortgage
Dated as of File Reference Exhibit No. ----------- -------------- ----------- March 1, 1967 2-58274 2.9 April 1, 1971 Form 8-K, April 1971 6 February 1, 1974 Form 8-K, February 1974 3 July 7, 1980 2-69821 4.6 May 1, 1990 Form 10-K, 1990 4.6 December 1, 1991 33-45008 4.4 December 4, 1991 33-45008 4.5 January 1, 1992 Form 10-K, 1991 4.6 October 1, 1992 Form 10-K, 1992 4.6 December 1, 1992 Form 10-K, 1992 4.7 February 1, 1993 Form 10-K, 1992 4.8 May 1, 1993 Form 10-K, 1993 4.6 August 1, 1993 Form 10-K, 1993 4.7 October 1, 1993 Form 10-K, 1993 4.8 January 1, 1994 Form 10-K, 1993 4.9 December 1, 1996 Form 10-K, 1996 4.36
Exhibit No. Description
4.6 - Series A Agreement of Sale dated as of June 1, 1984 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Letter of Credit and Reimbursement Agreement dated as of June 1, 1984 between Citibank, N.A. and the Company and Series A Trust Indenture dated as of June 1, 1984 between the Authority and Mercantile Trust Company National Association, as trustee. (Registration No. 2-96198, Exhibit 4.25.)
4.7 - Reimbursement Agreement dated as of April 21, 1992 among Swiss Bank Corporation, various financial institutions, and the Company, providing for an alternate letter of credit to serve as a source of payment for bonds issued under the Series A Trust Indenture dated as of June 1, 1984. (1992 Form 10-K, Exhibit 4.23.)
4.8 - Series B Agreement of Sale dated as of June 1, 1984 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Reimbursement Agreement dated as of June 1, 1984 between Chemical Bank and the Company and Series B Trust Indenture dated as of June 1, 1984 between the Authority and Mercantile Trust Company National Association, as trustee. (Registration No. 2-96198, Exhibit 4.26.)
4.9 - Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company, providing for an alternate letter of credit to serve as a source of payment for bonds issued under the Series B Trust Indenture dated as of June 1, 1984. (June 30, 1988 Form 10-Q, Exhibit 4.2.)
4.10 - Amendment and Extension Agreement dated as of June 1, 1990 to the Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company. (1990 Form 10-K, Exhibit 4.29.)
4.11 - Amendment and Extension Agreement dated as of June 1, 1991 to the amended Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.27.)
4.12 - Amendment Agreement dated as of June 1, 1992 to the amended Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.28.)
4.13 - Series 1985 A Reaffirmation Agreement and Second Supplement to Agreement of Sale dated as of June 1, 1985 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Series 1985 A Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company and Series 1985 A Trust Indenture dated as of June 1, 1985 between the Authority and Mercantile Trust Company National Association, as trustee and Texas Commerce Bank National Association, as co-trustee. (June 30, 1985 Form 10-Q, Exhibit 4.1.)
4.14 - Amendment and Extension Agreement dated as of June 1, 1988 revising the Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company. (June 30, 1988 Form 10-Q, Exhibit 4.4.)
4.15 - Amendment and Extension Agreement dated as of June 1, 1990 revising the Reimbursement Agreement dated as of June 1, 1985, as amended, between Union Bank of Switzerland and the Company. (1990 Form 10-K, Exhibit 4.37.)
Exhibit No. Description
4.16 - Amendment and Extension Agreement dated as of June 1, 1991 to the amended Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.32.)
4.17 - Amendment Agreement dated as of June 1, 1992 to the amended Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.33.)
4.18 - Series 1985 B Reaffirmation Agreement and Third Supplement to Agreement of Sale dated as of June 1, 1985 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Series 1985 B Reimbursement Agreement dated as of June 1, 1985 between The Long-term Credit Bank of Japan, Limited and the Company and Series 1985 B Trust Indenture dated as of June 1, 1985 between the Authority and Mercantile Trust Company National Association, as trustee and Texas Commerce Bank National Association, as co-trustee. (June 30, 1985 Form 10-Q, Exhibit 4.2.)
4.19 - Reimbursement Agreement dated as of February 1, 1993 between Westdeutsche Landesbank Girozentrale and the Company, providing for an alternate letter of credit to serve as a source of payment for bonds issued under the Series 1985 B Trust Indenture dated as of June 1, 1985. (1992 Form 10-K, Exhibit 4.35.)
4.20 - Loan Agreement dated as of May 1, 1990 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Indenture of Trust dated as of May 1, 1990 between the Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1990 Form 10-K, Exhibit 4.40.)
4.21 - Loan Agreement dated as of December 1, 1991 between the State Environmental Improvement and Energy Resources Authority and the Company, together with Indenture of Trust dated as of December 1, 1991 between the Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1992 Form 10-K, Exhibit 4.37.)
4.22 - Loan Agreement dated as of December 1, 1992, between the State Environmental Improvement and Energy Resources Authority and the Company, together with Indenture of Trust dated as of December 1, 1992 between the Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1992 Form 10-K, Exhibit 4.38.)
4.23 - Fuel Lease dated as of February 24, 1981 between the Company, as lessee, and Gateway Fuel Company, as lessor, covering nuclear fuel. (1980 Form 10-K, Exhibit 10.20.)
4.24 - Amendments to Fuel Lease dated as of May 8, 1984 and October 15, 1984, respectively, between the Company, as lessee, and Gateway Fuel Company, as lessor, covering nuclear fuel. (Registration No. 2-96198, Exhibit 4.28.)
4.25 - Amendment to Fuel Lease dated as of October 15, 1986 between the Company, as lessee, and Gateway Fuel Company, as lessor, covering nuclear fuel. (September 30, 1986 Form 10-Q, Exhibit 4.3.)
4.26 - Credit Agreement dated as of August 15, 1989 among the Company, Certain Lenders, The First National Bank of Chicago, as Agent and Swiss Bank Corporation, Chicago Branch, as Co-Agent. (September 30, 1989 Form 10-Q, Exhibit 4.)
Exhibit No. Description
4.27 - Series 1998A Loan Agreement dated as of September 1, 1998 between The State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.28.)
4.28 - Series 1998B Loan Agreement dated as of September 1, 1998 between The State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.29.)
4.29 - Series 1998C Loan Agreement dated as of September 1, 1998 between The State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.30.)
10.1 - Ameren Long-Term Incentive Plan of 1998. (Ameren's 1998 Form 10-K, Exhibit 10.1.)
10.2 - Ameren Change of Control Severance Plan. (Ameren's 1998 Form 10-K, Exhibit 10.2.)
10.3 - Ameren Deferred Compensation Plan for Members of the Ameren Leadership Team. (Ameren's 1998 Form 10-K, Exhibit 10.3.)
10.4 - 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 1-2967.
Reports of Ameren on Form 10-K are on file with the SEC under File Number 1-14756.
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 AmerenUE's 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 AmerenUE's 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 AmerenUE's 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 AmerenUE's 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..................................... 39
Schedules not included have been omitted because they are not applicable or the required data is shown in the aforementioned financial statements.
2. Exhibits: See EXHIBITS beginning on Page 41
(b) Reports on Form 8-K. The Registrant filed a report on Form 8-K dated January 20, 2000 reporting the issuance of a Report and Order dated December 23, 1999 by the Missouri Public Service Commission regarding the Registrant's electric alternative regulation plans.
UNION ELECTRIC 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.
UNION ELECTRIC COMPANY (Registrant)
CHARLES W. MUELLER 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/ C. W. Mueller President, Chief Executive Officer and Director - --------------------------- (Principal Executive Officer) CHARLES W. MUELLER
/s/ Donald E. Brandt Senior Vice President and Director - --------------------------- (Principal Financial Officer) DONALD E. BRANDT
/s/ Warner L. Baxter Vice President, Controller and Director - --------------------------- (Principal Accounting Officer) WARNER L. BAXTER
/s/ Paul A. Agathen Director - --------------------------- PAUL A. AGATHEN
/s/ Gary L. Rainwater Director - --------------------------- GARY L. RAINWATER
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.
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 Union Electric Company, CIPSCO Incorporated, Ameren Corporation, and Arch Merger Inc. (June 30, 1995 Form 10-Q/A (Amendment No. 1), Exhibit 2(a).)
3(i) - Restated Articles of Incorporation of the Company, as filed with the Secretary of State of the State of Missouri. (1993 Form 10-K, Exhibit 3(i).)
3(ii)- By-Laws of the Company as amended to August 26, 1999. (September 30, 1999 Form 10-Q, Exhibit 3(ii).)
4.1 - Order of the Securities and Exchange Commission dated October 16, 1945 in File No. 70-1154 permitting the issue of Preferred Stock, $3.70 Series. (Registration No. 2-27474, Exhibit 3-E.)
4.2 - Order of the Securities and Exchange Commission dated April 30, 1946 in File No. 70-1259 permitting the issue of Preferred Stock, $3.50 Series. (Registration No. 2-27474, Exhibit 3-F.)
4.3 - Order of the Securities and Exchange Commission dated October 20, 1949 in File No. 70-2227 permitting the issue of Preferred Stock, $4.00 Series. (Registration No. 2-27474, Exhibit 3-G.)
4.4 - Indenture of Mortgage and Deed of Trust of the Company dated June 15, 1937, as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941. (Registration No. 2-4940, Exhibit B-1.)
4.5 - Supplemental Indentures to Mortgage
Dated as of File Reference Exhibit No. ----------- -------------- ----------- March 1, 1967 2-58274 2.9 April 1, 1971 Form 8-K, April 1971 6 February 1, 1974 Form 8-K, February 1974 3 July 7, 1980 2-69821 4.6 May 1, 1990 Form 10-K, 1990 4.6 December 1, 1991 33-45008 4.4 December 4, 1991 33-45008 4.5 January 1, 1992 Form 10-K, 1991 4.6 October 1, 1992 Form 10-K, 1992 4.6 December 1, 1992 Form 10-K, 1992 4.7 February 1, 1993 Form 10-K, 1992 4.8 May 1, 1993 Form 10-K, 1993 4.6 August 1, 1993 Form 10-K, 1993 4.7 October 1, 1993 Form 10-K, 1993 4.8 January 1, 1994 Form 10-K, 1993 4.9 December 1, 1996 Form 10-K, 1996 4.36
Exhibit No. Description
4.6 - Series A Agreement of Sale dated as of June 1, 1984 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Letter of Credit and Reimbursement Agreement dated as of June 1, 1984 between Citibank, N.A. and the Company and Series A Trust Indenture dated as of June 1, 1984 between the Authority and Mercantile Trust Company National Association, as trustee. (Registration No. 2-96198, Exhibit 4.25.)
4.7 - Reimbursement Agreement dated as of April 21, 1992 among Swiss Bank Corporation, various financial institutions, and the Company, providing for an alternate letter of credit to serve as a source of payment for bonds issued under the Series A Trust Indenture dated as of June 1, 1984. (1992 Form 10-K, Exhibit 4.23.)
4.8 - Series B Agreement of Sale dated as of June 1, 1984 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Reimbursement Agreement dated as of June 1, 1984 between Chemical Bank and the Company and Series B Trust Indenture dated as of June 1, 1984 between the Authority and Mercantile Trust Company National Association, as trustee. (Registration No. 2-96198, Exhibit 4.26.)
4.9 - Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company, providing for an alternate letter of credit to serve as a source of payment for bonds issued under the Series B Trust Indenture dated as of June 1, 1984. (June 30, 1988 Form 10-Q, Exhibit 4.2.)
4.10 - Amendment and Extension Agreement dated as of June 1, 1990 to the Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company. (1990 Form 10-K, Exhibit 4.29.)
4.11 - Amendment and Extension Agreement dated as of June 1, 1991 to the amended Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.27.)
4.12 - Amendment Agreement dated as of June 1, 1992 to the amended Reimbursement Agreement dated as of April 22, 1988 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.28.)
4.13 - Series 1985 A Reaffirmation Agreement and Second Supplement to Agreement of Sale dated as of June 1, 1985 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Series 1985 A Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company and Series 1985 A Trust Indenture dated as of June 1, 1985 between the Authority and Mercantile Trust Company National Association, as trustee and Texas Commerce Bank National Association, as co-trustee. (June 30, 1985 Form 10-Q, Exhibit 4.1.)
4.14 - Amendment and Extension Agreement dated as of June 1, 1988 revising the Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company. (June 30, 1988 Form 10-Q, Exhibit 4.4.)
4.15 - Amendment and Extension Agreement dated as of June 1, 1990 revising the Reimbursement Agreement dated as of June 1, 1985, as amended, between Union Bank of Switzerland and the Company. (1990 Form 10-K, Exhibit 4.37.)
Exhibit No. Description
4.16 - Amendment and Extension Agreement dated as of June 1, 1991 to the amended Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.32.)
4.17 - Amendment Agreement dated as of June 1, 1992 to the amended Reimbursement Agreement dated as of June 1, 1985 between Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit 4.33.)
4.18 - Series 1985 B Reaffirmation Agreement and Third Supplement to Agreement of Sale dated as of June 1, 1985 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Series 1985 B Reimbursement Agreement dated as of June 1, 1985 between The Long-term Credit Bank of Japan, Limited and the Company and Series 1985 B Trust Indenture dated as of June 1, 1985 between the Authority and Mercantile Trust Company National Association, as trustee and Texas Commerce Bank National Association, as co-trustee. (June 30, 1985 Form 10-Q, Exhibit 4.2.)
4.19 - Reimbursement Agreement dated as of February 1, 1993 between Westdeutsche Landesbank Girozentrale and the Company, providing for an alternate letter of credit to serve as a source of payment for bonds issued under the Series 1985 B Trust Indenture dated as of June 1, 1985. (1992 Form 10-K, Exhibit 4.35.)
4.20 - Loan Agreement dated as of May 1, 1990 between the State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company, together with Indenture of Trust dated as of May 1, 1990 between the Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1990 Form 10-K, Exhibit 4.40.)
4.21 - Loan Agreement dated as of December 1, 1991 between the State Environmental Improvement and Energy Resources Authority and the Company, together with Indenture of Trust dated as of December 1, 1991 between the Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1992 Form 10-K, Exhibit 4.37.)
4.22 - Loan Agreement dated as of December 1, 1992, between the State Environmental Improvement and Energy Resources Authority and the Company, together with Indenture of Trust dated as of December 1, 1992 between the Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1992 Form 10-K, Exhibit 4.38.)
4.23 - Fuel Lease dated as of February 24, 1981 between the Company, as lessee, and Gateway Fuel Company, as lessor, covering nuclear fuel. (1980 Form 10-K, Exhibit 10.20.)
4.24 - Amendments to Fuel Lease dated as of May 8, 1984 and October 15, 1984, respectively, between the Company, as lessee, and Gateway Fuel Company, as lessor, covering nuclear fuel. (Registration No. 2-96198, Exhibit 4.28.)
4.25 - Amendment to Fuel Lease dated as of October 15, 1986 between the Company, as lessee, and Gateway Fuel Company, as lessor, covering nuclear fuel. (September 30, 1986 Form 10-Q, Exhibit 4.3.)
4.26 - Credit Agreement dated as of August 15, 1989 among the Company, Certain Lenders, The First National Bank of Chicago, as Agent and Swiss Bank Corporation, Chicago Branch, as Co-Agent. (September 30, 1989 Form 10-Q, Exhibit 4.)
Exhibit No. Description
4.27 - Series 1998A Loan Agreement dated as of September 1, 1998 between The State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.28.)
4.28 - Series 1998B Loan Agreement dated as of September 1, 1998 between The State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.29.)
4.29 - Series 1998C Loan Agreement dated as of September 1, 1998 between The State Environmental Improvement and Energy Resources Authority of the State of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.30.)
10.1 - Ameren Long-Term Incentive Plan of 1998. (Ameren's 1998 Form 10-K, Exhibit 10.1.)
10.2 - Ameren Change of Control Severance Plan. (Ameren's 1998 Form 10-K, Exhibit 10.2.)
10.3 - Ameren Deferred Compensation Plan for Members of the Ameren Leadership Team. (Ameren's 1998 Form 10-K, Exhibit 10.3.)
10.4 - 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 1-2967.
Reports of Ameren on Form 10-K are on file with the SEC under File Number 1-14756.