UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
( ) Transition report pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from to .
COMMISSION FILE NUMBER 1-2967
UNION ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Missouri 43-0559760
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1901 Chouteau Avenue, St. Louis, Missouri 63103
(Address of principal executive offices and Zip Code)
Registrant's telephone number, including area code: (314) 621-3222
Securities Registered Pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Preferred Stock, without par value (entitled to cumulative dividends):
Stated value $100 per share - } $4.56 Series } $4.50 Series } New York Stock Exchange $4.00 Series } $3.50 Series } |
Securities Registered Pursuant to Section 12(g) of the Act: None.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X . No .
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X).
Aggregate market value of voting stock held by non-affiliates as of March 8, 2001 , based on closing prices most recently available as reported in The Wall Street Journal (excluding Preferred Stock for which quotes are not publicly available): $42,721,795.
Shares of Common Stock, $5 par value, outstanding as of March 8, 2001:
102,123,834 shares (all owned by Ameren Corporation).
Documents incorporated by references.
Portions of the registrant's definitive proxy statement for the 2001 annual meeting are incorporated by reference into Part III.
TABLE OF CONTENTS
PART I Page
Item 1 - Business
General..................................................... 1
Capital Program and Financing............................... 1
Rates....................................................... 2
Fuel Supply for Electric Generating Facilities.............. 2
Regulation.................................................. 3
Industry Issues............................................. 4
Item 2 - Properties..................................................... 4
Item 3 - Legal Proceedings.............................................. 6
Item 4 - Submission of Matters to a Vote of Security Holders<F1>
Executive Officers of the Registrant (Item 401(b) of Regulation S-K)...... 7
PART II
Item 5 - Market for Registrant's Common Equity and Related
Stockholder Matters................................... 7
Item 6 - Selected Financial Data........................................ 7
Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations............................. 8
Item 7A - Quantitative and Qualitative Disclosures about Market Risk..... 17
Item 8 - Financial Statements and Supplementary Data.................... 19
Item 9 - Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure<F1>
PART III
Item 10 - Directors and Executive Officers of the Registrant<F2>......... 38
Item 11 - Executive Compensation<F2>..................................... 38
Item 12 - Security Ownership of Certain Beneficial Owners
and Management<F2>.................................... 38
Item 13 - Certain Relationships and Related Transactions<F2>............. 38
PART IV
Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K. 39
SIGNATURES ........................................................... 41
EXHIBITS ........................................................... 42
[FN]
<F1> Not applicable and not included herein.
<F2> Incorporated herein by reference.
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PART I
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 an energy trading and 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 utility service is supplied in 90 Missouri communities and in the City of Alton, Illinois and vicinity. The Registrant supplies electric service to about 1.2 million customers and natural gas service to about 125,000 customers.
For the year 2000, 95% of total operating revenues was derived from the sale of electric energy and 5% from the sale of natural gas. Electric operating revenues as a percentage of total operating revenues in 1999 and 1998 were 96%.
The Registrant employed 4,195 persons at December 31, 2000. For information on labor agreements, see Note 12 to the "Notes to Financial Statements" under Item 8 herein.
For additional information regarding the Registrant's business operations, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and "Financial Statements and Supplementary Data" under Item 8 herein.
CAPITAL PROGRAM AND FINANCING
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, 9 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, 2000 was 8.4, which would permit the Registrant to issue an additional $3.3 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, 2000, the aggregate amount of Bonds issuable under (a) and (b) above was approximately $2.7 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, 2000 was 39.7, 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 2000, approximately 82%, 6%, and 12% 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 "Results of Operations", "Rate Matters" and "Electric
Industry Restructuring" in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" under Item 7 herein and Notes 2 and 13 to
the "Notes to Financial Statements" under Item 8 herein.
FUEL SUPPLY FOR ELECTRIC GENERATING FACILITIES
Cost of Fuels Year
------------- ------------------------------------------------------------------------------
2000 1999 1998 1997 1996
Per Million BTU - Coal 96.004(cent) 100.685(cent) 100.015(cent) 105.600(cent) 112.250(cent)
- Nuclear 40.269(cent) 46.552(cent) 48.803(cent) 47.472(cent) 47.499(cent)
- System 84.213(cent) 89.833(cent) 90.378(cent) 92.816(cent) 96.596(cent)
Per kWh of Steam Generation .892(cent) .958(cent) .968(cent) .979(cent) 1.024(cent)
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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, delays in coal deliveries, equipment breakdowns and other factors, the Registrant has a policy of maintaining coal inventory consistent with its expected burn practices. Recently, the Registrant has experienced some delays in its coal deliveries due to certain transportation and operating constraints in the system. The Registrant is working closely with the transportation companies and monitoring its operating practices in order to maintain adequate levels of coal inventory for future operating purposes.
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, and refuelings are presently scheduled for the spring of 2001 and the fall of 2002.
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 utility 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", "Liquidity and Capital Resources", "Market Risk Related to Financial Instruments and Commodity Instruments" and "Effects of Inflation and Changing Prices" 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
General Matters. The Registrant is subject to regulation by the Securities and Exchange Commission (SEC) 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 SEC.
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", "Rate Matters" and "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.
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.
Environmental Matters. The Registrant, in certain of its operations is subject to federal, state and local environmental regulations relating to the safety and health of personnel, the public and the environment, including the identification, generation, storage, handling, transportation, disposal, record keeping, labeling, reporting of and emergency response in connection with hazardous and toxic materials, safety and health standards, and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants. Failure to comply with those statutes or regulations could have material adverse effects on the Registrant, including the imposition of criminal or civil liability by regulatory agencies or civil fines and liability to private parties, and the required expenditure of funds to bring the Registrant into compliance. The Registrant is in material compliance with existing regulations.
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 matters.
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 and 12 to the "Notes to Financial Statements" under Item 8 herein.
ITEM 2. PROPERTIES.
For information on the Registrant's principal properties including electric transmission assets, planned additions or replacements and proposed Illinois property transfer, see "Results of Operations", "Liquidity and Capital Resources" and "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Notes 2 and 12 to the "Notes to Financial Statements" under Item 8 herein.
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, Michigan, Illinois and Missouri. The Registrant's bulk power system is operated as an Ameren-wide control area and transmission system under the FERC-approved amended joint dispatch agreement between the Registrant and its Illinois-based affiliates, AmerenEnergy Generating Company (Generating Company) and AmerenCIPS. AmerenCIPS transferred all of its generating assets to Generating Company on May 1, 2000 in conjunction with Illinois' electric utility restructuring legislation, called The Electric Service Customer Choice and Rate Relief Law of 1997. The amended joint dispatch agreement provides a basis upon which AmerenUE and Generating Company can participate in the coordinated operation of Ameren's transmission facilities with their generating facilities in order to achieve economies consistent with the provision of reliable electric service and an equitable sharing of the benefits and costs of that coordinated operation. Ameren has more than 30 interconnections for transmission service and the exchange of electric energy, directly and through the facilities of others.
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 and Dynegy Midwest Generation, Inc. EEI owns and/or operates electric generating and transmission facilities in Illinois that supply electric power primarily to a uranium enrichment plant located in Paducah, Kentucky.
As of December 31, 2000, the Registrant owned approximately 3,500 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, 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 2001 peak. The Registrant is considering proposals to purchase 450 megawatts of additional capacity and energy for the expected 2001 peak.
Energy Gross Kilowatt
Source Plant Location Installed Capability
------- ------- ---------- ----------------------
Coal Labadie Franklin County, MO 2,414,000
Rush Island Jefferson County, MO 1,224,000
Sioux St. Charles County, MO 1,006,000
Meramec St. Louis County, MO 892,000
----------
Total Coal 5,536,000
Nuclear Callaway Callaway County, MO 1,174,000
Hydro Osage Lakeside, MO 212,000
Keokuk Keokuk, IA 126,000
----------
Total Hydro 338,000
Oil and Venice Venice, IL 368,000
Natural Other Various 434,000*
Gas Total Oil and ----------
Natural Gas 802,000
Pumped-
storage Taum Sauk Reynolds County, MO 440,000
----------
TOTAL 8,290,000**
==========
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* Includes 53,000 gross kilowatt installed capability of a new combustion turbine generator placed into service in 2000.
** Excludes gross kilowatt installed capability of generating facilities owned by EEI, of which AmerenUE is a 40% owner.
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 "Liquidity and Capital Resources", "Rate Matters" and "Electric Industry Restructuring" in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under Item 7 herein and Notes 2 and 12 to the "Notes to Financial Statements" under Item 8 herein.
Statements made in this report which are not based on historical facts, are "forward-looking" and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such "forward-looking" statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions and financial performance. 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, including changes in regulatory policy; 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; the effects of withdrawal from the Midwest ISO and membership in the Alliance RTO; 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 construction, installation and 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 12/31/00 Present Position or Appointed
Charles W. Mueller 62 President, 7/1/93
Chief Executive Officer 1/1/94
and Director 6/11/93
Donald E. Brandt 46 Senior Vice President 7/1/88
and Director 4/28/98
Daniel F. Cole 47 Senior Vice President 7/12/99
Garry L. Randolph 52 Senior Vice President 10/16/00
Thomas R. Voss 53 Senior Vice President 6/1/99
Ronald D. Affolter 47 Vice President 10/16/00
Warner L. Baxter 39 Vice President, 5/1/98
Controller and 8/1/96
Director 4/22/99
William J. Carr 63 Vice President 10/1/88
Michael J. Montana 54 Vice President 7/1/88
Charles D. Naslund 48 Vice President 2/1/99
William C. Shores 62 Vice President 7/1/88
Steven R. Sullivan 40 Vice President, General Counsel 7/1/98
and Secretary 9/1/98
Jerre E. Birdsong 46 Treasurer 7/1/93
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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 Mr. 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. 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.
For the Years Ended December 31 (In Thousands) 2000 1999 1998 1997 1996 ------------------------- ---- ---- ---- ---- ---- Operating revenues $2,718,526 $2,527,166 $2,382,071 $2,287,333 $2,260,364 Operating income 452,237 443,268 428,183 448,827 428,314 Net income 353,011 349,252 320,070 301,655 304,876 Preferred stock dividends 8,817 8,817 8,817 8,817 13,249 Net income after preferred stock dividends 344,194 340,435 311,253 292,838 291,627 Common stock dividends 207,224 328,674 259,599 259,395 256,331 As of December 31, Total assets $7,116,126 $7,043,562 $6,829,864 $6,802,285 $6,870,809 Long-term debt 1,760,439 1,882,601 1,674,311 1,846,482 1,798,671 Total common stockholder's equity 2,570,652 2,433,682 2,424,125 2,387,454 2,354,801 |
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 2000, 1999, and 1998 were $344 million, $340 million, and $311
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), expenses relating to
the withdrawal from the electric transmission related Midwest Independent System
Operator (Midwest ISO), charges for a targeted employee separation plan (TSP),
changes in interest expense and changes in income and property taxes.
In the fourth quarter of 2000, the Registrant recorded a $17 million nonrecurring charge to earnings in connection with its withdrawal from the Midwest ISO. The charge reduced earnings $10 million, net of income taxes (see discussion below under "Electric Industry Restructuring" and Note 2 - Regulatory Matters under Notes to Financial Statements for further information). 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).
The significant items affecting revenues, expenses and earnings for the years ended December 31, 2000, 1999, and 1998 are detailed in the following pages.
Electric Operations
Electric Revenues Variations from Prior Year
----------------------------------------------------------------------------
(Millions of Dollars) 2000 1999 1998
----------------------------------------------------------------------------
Rate variations $ - $ (9) $ (8)
Credit to customers (27) 7 (24)
Effect of abnormal weather 7 (37) 48
Growth and other 55 47 48
Interchange sales 119 136 38
----------------------------------------------------------------------------
$ 154 $ 144 $ 102
----------------------------------------------------------------------------
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Electric revenues for 2000 increased $154 million, compared to 1999, primarily due to a 13% increase in total kilowatthour sales. This increase was primarily driven by a 59% increase in interchange sales due to strong marketing efforts, and increases in weather-sensitive residential and commercial sales, of 6% and 9%, respectively. Revenues were partially offset by an increase in the credit to Missouri electric customers (see Note 2 - Regulatory Matters under Notes to Financial Statements for further information) and by a 4% decline in industrial sales.
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 33% 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 3%, commercial sales remained flat, while industrial sales decreased 1%.
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.
Fuel and Purchased Power Variations from Prior Year
--------------------------------------------------------------------------------
(Millions of Dollars) 2000 1999 1998
--------------------------------------------------------------------------------
Fuel:
Generation $ 35 $ (2) $ 24
Price (22) (2) (10)
Generation efficiencies and other (6) (2) 5
Purchased power 65 132 11
--------------------------------------------------------------------------------
$ 72 $ 126 $ 30
--------------------------------------------------------------------------------
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The $72 million increase in fuel and purchased power costs for 2000, compared to 1999, was primarily due to increased generation and power purchases resulting from higher sales volumes, offset in part by lower fuel prices.
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.
Gas Operations
Gas revenues in 2000 increased $37 million, compared to 1999, primarily due to
increases in retail sales, coupled with a $4 million Missouri gas rate increase,
which became effective in November 2000 (see Note 2 - Regulatory Matters under
Notes to Financial Statements for further information) and higher gas costs
reflected in the Registrant's purchased gas adjustment clauses.
Weather-sensitive residential and commercial sales increased by 20 percent and
25 percent, respectively, and industrial sales declined 21 percent. Gas revenues
in 1999 were flat, compared to 1998. 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 Registrant's purchased gas
adjustment clauses. 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 2000 increased $27 million, compared to 1999, primarily due to higher gas prices and increased sales. 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 1998 through 2000 reflected recurring
factors such as growth, inflation, labor and benefit increases, the
capitalization of certain costs as a result of a Missouri Public Service
Commission (MoPSC) Order and charges for estimated costs relating to withdrawal
from the Midwest ISO and charges for the TSP.
In November 2000, the Registrant announced that it is withdrawing from the Midwest ISO to become a member of the Alliance Regional Transmission Organization (Alliance RTO). In the fourth quarter of 2000, the Registrant recorded a pretax nonrecurring charge to earnings of $17 million, as a result of the Registrant's decision to withdraw from the Midwest ISO. This charge relates to the Registrant's estimated obligation under the Midwest ISO agreement for costs incurred by the Midwest ISO, plus estimated exit costs. See discussions below under "Electric Industry Restructuring" and Note 2 - Regulatory Matters under Notes to Financial Statements for further information.
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.
Other operating expenses, excluding the Midwest ISO related nonrecurring charge, discussed above, increased $49 million in 2000, compared to 1999. This increase was primarily due to increased professional services and increases in injuries and damages expense (due to claims experience). 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.
Maintenance expenses increased $3 million in 2000, compared to 1999. The increase was primarily the result of increased fossil power plant maintenance and tree-trimming activity, partially offset by the lack of a Callaway Nuclear Plant outage in 2000. Maintenance expenses increased $25 million 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. 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.
Depreciation and amortization expense increased $14 million in 2000, compared to 1999, due to increased depreciable property. Depreciation and amortization expense increased $12 million in 1998, compared to 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.
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 $5 million in 2000, compared to 1999, primarily due
to prior period write-offs of certain nonregulated investments, partially offset
by increased charitable contributions in 2000. Miscellaneous, net increased $4
million for 1998, compared to 1997, due to increased interest income and gains
on the sale of property.
Interest
Interest expense increased $9 million in 2000, compared to 1999, primarily due
to higher interest expense associated with the nuclear fuel lease and an
increase in other interest expense. 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.
Balance Sheet
The $48 million increase in trade accounts receivable in 2000, compared to 1999,
was due primarily to higher sales and revenues in November and December 2000,
compared to the same 1999 period. The $90 million increase in intercompany notes
receivable at December 31, 2000 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 $97 million decrease in cash and cash equivalents in 2000, compared to 1999, was primarily due to lower temporary cash investments partially offset by an increase in the Registrant's cash account.
The $59 million increase in accounts and wages payable in 2000, compared to 1999, is due to the timing of the payment to suppliers, including the accrual for the nonrecurring charge in connection with the Registrant's withdrawal from the Midwest ISO.
The $19 million increase in other deferred credits and liabilities in 2000, compared to 1999, was primarily due to Callaway Plant decommissioning costs.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $668 million for 2000, compared to $725 million and $651 million in 1999 and 1998, respectively.
Cash flows used in investing activities totaled $414 million, $419 million, and $231 million for the years ended December 31, 2000, 1999 and 1998, respectively. Expenditures in 2000 for constructing new or to improve existing facilities and purchasing rail cars were $316 million. In addition, the Registrant spent $22 million to acquire nuclear fuel and loaned an additional $90 million to the regulated money pool.
Capital expenditures are expected to approximate $374 million in 2001. For the five-year period 2001 through 2005, construction expenditures are estimated at approximately $2 billion. This estimate includes capital expenditures that will be incurred by the Registrant for the replacement of four steam generators at its Callaway Nuclear Plant, as well as expenditures that will be incurred to meet new air quality standards for ozone and particulate matter, as discussed below.
Title IV of the Clean Air Act Amendments of 1990 required 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. The EPA appealed the decision to the U.S. Supreme Court. On February 27, 2001, the U.S. Supreme Court reversed and remanded the case to the U.S. Court of Appeals for the District of Columbia for further evaluation and opinion. The Supreme Court ruled that Congress, in enacting Clean Air Act provisions that authorized the EPA to determine air quality standards, did not unconstitutionally delegate legislative power to the agency. The Supreme Court also rejected industry arguments that the EPA should have considered implementation costs in setting air quality standards. The ruling reaffirms the EPA's authority to establish uniform air quality standards at a level that is sufficient to protect public health. However, the manner in which the EPA proposed to implement the proposed air quality standard for ozone was ruled unlawful and the Court ordered the remand of the EPA's implementation policy to the agency for further consideration. When the proposed ambient standards are ultimately enacted, such standards will require significant additional reductions in SO2 and NOx emissions from the Registrant's power plants. 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 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 regulations were challenged in a U. S. District Court. In March 2000, the Court upheld most of the regulations. However, the Court remanded the state of Missouri's regulations back to the EPA for revision. The Court further delayed the compliance date of the regulations until 2004. The final applicability of the regulations as they might apply to utility boilers in Missouri is still uncertain. The NOx emissions reductions already achieved on several of the Registrant's coal-fired power plants will help reduce the costs of compliance with these regulations. However, the regulations will require the installation of selective catalytic reduction technology on some of the Registrant's units, as well as other additional controls.
Currently, the Registrant estimates that its additional capital expenditures to comply with the final NOx regulations could range from $125 million to $150 million over the period from 2001 to 2005. Associated operations and maintenance expenditures could increase $5 million to $8 million annually, beginning in 2005. 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 ultimate impact of these standards on its future financial condition, results of operations or liquidity. See Note 12 - Commitments and Contingencies under Notes to Financial Statements for further discussion of environmental issues.
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 $351 million for 2000, compared to $236 million and $376 million for 1999 and 1998, respectively. The Registrant's principal financing activities during 2000 included the redemption of $320 million of long-term debt, the issuance of $187 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 commercial paper (maturities generally within 1 to 45 days) and bank loans. At December 31, 2000, 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 $281 million was available at December 31, 2000. In addition, the Registrant has the ability to borrow up to approximately $488 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, 2000, the Registrant had no intercompany borrowings outstanding and $321 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, 2000, the maximum amount that could be financed under the agreement was $120 million. Cash used in financing for 2000 included issuances under the lease for nuclear fuel of $9 million, offset in part by $11 million of redemptions. At December 31, 2000, $114 million was financed under the lease. See Note 6 - Nuclear Fuel Lease under Notes to Financial Statements for further information.
During the course of Ameren's resource planning, several alternatives are being considered to satisfy regulatory load requirements for 2001 and beyond for the Registrant, AmerenCIPS, and AmerenEnergy Resources Company (the Ameren subsidiary which holds its nonregulated generation operations). One of these alternatives was for the Registrant to transfer its Illinois-based electric and natural gas businesses and certain of its Illinois-based distribution and transmission assets and personnel to AmerenCIPS (see Note 2- Regulatory Matters under Notes to Financial Statements for further discussion). The assets and related liabilities were proposed to be transferred from the Registrant to AmerenCIPS at historical net book value. In March 2001, the Registrant decided it will no longer pursue this transfer and will be taking the necessary action to withdraw its pending requests for regulatory approvals. Other alternatives being considered include proposals for the purchase of 450 megawatts of capacity and energy for the summer of 2001, among other things. At this time, management is unable to predict which course of action it will pursue to satisfy these requirements and their ultimate impact on the Registrant's financial position, results of operations or liquidity.
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, over the past two years, the Registrant has recently reached agreements with all of the Registrant's major collective bargaining units which will permit it to manage its labor costs and practices effectively in the future (see Note 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 and transportation 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 suppliers. Management is unable to predict which (if any), and to what extent, these alternatives to reduce its overall cost structure will be
executed, as well as determine the impact of these actions on the Registrant's future financial position, results of operations or liquidity.
RATE MATTERS
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. A new three-year experimental alternative regulation plan (the New Plan) was included in the joint agreement authorized by the MoPSC in its February 1997 order approving the Merger. The New Plan runs from July 1, 1998 through June 30, 2001. On February 1, 2001, the Registrant, MoPSC staff, and other parties submitted filings to the MoPSC addressing the merits of extending the current experimental alternative regulation plan. In its filing, the Registrant supported an extension of this plan with certain modifications, including retail electric rate reductions and additional customer credits. The MoPSC staff filing noted several concerns with the current plan and suggested that under traditional cost of service ratemaking, an annualized electric rate decrease of at least $100 million could be warranted. On March 8, 2001, the MoPSC issued an Order authorizing the MoPSC staff to file an earnings complaint to seek a rate reduction on July 1, 2001 if it determines that one is warranted. In addition, the Order stated that the New Plan will not be continued beyond June 30, 2001. The Registrant has been engaged in discussions with the MoPSC staff and other parties in an effort to address issues associated with the expiration of the New Plan, including the development of a new alternative regulation plan. At this time, the Registrant cannot predict the outcome of these discussions or the timing or amount of any future electric rate reductions.
See Note 2 - Regulatory Matters under Notes to Financial Statements for a further discussion of the experimental alternative regulation plan and a discussion of other 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.
During 2000 and in early 2001, deregulation laws established in the state of California, coupled with high energy prices, increasing demands for power by users in that state, transmission constraints, and limited generation resources, among other things, negatively impacted several major electric utilities in that state. Federal and state regulators and legislators have proposed and implemented, in part, different courses of action to attempt to address these issues. The Registrant does not maintain utility operations in the state of California, nor does it provide energy directly to utilities in that state. At this time, the Registrant is uncertain what impact, if any, changes in deregulation laws will have on future federal and state deregulation laws (including the state of Missouri), which could directly impact the Registrant's future financial position, results of operations or liquidity.
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.
In 1998, the Registrant joined a group of companies that originally supported the formation of the Midwest ISO. An ISO operates, but does not own, electric transmission systems and maintains system reliability and security, while facilitating wholesale and retail competition through the elimination of "pancaked" transmission rates. The Midwest ISO is regulated by the FERC. The FERC conditionally approved the formation of the Midwest ISO in September 1998. The MoPSC and the Illinois Commerce Commission (ICC) have authorized the Registrant to join the Midwest ISO.
In December 1999, the FERC issued Order 2000 relating to Regional Transmission Organizations (RTOs) that would meet certain characteristics such as size and independence. RTOs, including ISOs, are entities that ensure comparable and non-discriminatory access to regional electric transmission systems. Order 2000 calls on all transmission owners to join RTOs.
Following the announcements of Commonwealth Edison and Illinois Power of their intent to withdraw from the Midwest ISO and join the Alliance RTO, the Registrant determined that the operational configuration of the Midwest ISO was unacceptable and announced its withdrawal in November 2000. The Registrant decided to withdraw to ensure the continued reliable and efficient operation of its transmission system. As a result of the Registrant's decision to withdraw from the Midwest ISO, in the fourth quarter of 2000, the Registrant recorded a pretax nonrecurring charge to earnings of $17 million ($10 million after income taxes). This charge relates to the Registrant's estimated obligation under the Midwest ISO agreement for costs incurred by the Midwest ISO, plus estimated exit costs.
In January 2001, the Registrant announced that it had signed an agreement to join the Alliance RTO. Also, in January 2001, the FERC conditionally approved the formation, including the rate structure, of the Alliance RTO. In February 2001, in a proceeding before the FERC, the Alliance RTO and the Midwest ISO reached an agreement that enables the Registrant to withdraw from the Midwest ISO and to join the Alliance RTO. This settlement agreement remains subject to FERC approval. The Registrant's withdrawal from the Midwest ISO remains subject to MoPSC approval. In addition, the Registrant's transfer of control and operation of its transmission assets to the Alliance RTO is subject to MoPSC and ICC approvals. At this time, the Registrant is unable to determine the impact that its withdrawal from the Midwest ISO and its participation in the Alliance RTO will have on its future financial condition, results of operation or liquidity.
Illinois
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 remaining commercial and industrial customers in Illinois were offered choice on December 31, 2000. Commercial and industrial customers in Illinois represent approximately 7% of the Registrant's total sales. As of December 31, 2000, the impact of retail direct access on the Registrant's financial condition, results of operations and liquidity was immaterial. Retail direct access will be offered 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 by approximately $3 million annually compared to pre-Illinois Law rates, 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 has benefited shareholders since 1998 (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. 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, 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 utility restructuring in the state of Missouri;
however, management does not believe that comprehensive restructuring
legislation will be passed in 2001.
The Registrant is participating in discussions with the Missouri legislature regarding legislation that would not restructure the electric industry in Missouri, but would allow utilities to transfer generation assets to an affiliated generating company. In addition, the legislation would allow the State's largest nonresidential customers to choose
their electric supplier, among other things. At this time, the Registrant cannot predict whether any electric industry legislation will be passed, or what the provisions of any such legislation will be.
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. Conversely, a deregulated marketplace can
provide earnings enhancement opportunities. 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. 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.
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, 2000.
MARKET RISK RELATED TO FINANCIAL INSTRUMENTS AND COMMODITY INSTRUMENTS
Market risk represents the risk of changes in value of a financial instrument, derivative or non-derivative, caused by fluctuations in market variables (e.g. interest rates, equity prices, commodity prices, etc.). The following discussion of Ameren's, including 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. Ameren handles market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, Ameren and the Registrant also face 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.
Ameren's risk management objective is to optimize its physical generating assets within prudent risk parameters. Risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers.
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 and
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 2001, as compared to 2000, the Registrant's interest expense would increase by approximately $5 million, and net income would decrease by approximately $3 million. This amount has been determined using the assumptions that the Registrant's outstanding variable-rate debt and commercial paper, as of December 31, 2000, continued to be outstanding throughout 2001, and that the average interest rates for these instruments increased one percentage point over 2000. 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. Several techniques are utilized to mitigate the Registrant's risk,
including utilizing derivative financial instruments. A derivative is a contract
whose value is dependent on, or derived from, the value of some underlying
asset. The derivative financial instruments that the Registrant uses (primarily
forward contracts, futures contracts and option contracts) are dictated by risk
management policies.
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 purchased gas adjustment clauses (PGAs) 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.
Ameren has a subsidiary, AmerenEnergy Fuels and Services Company, a wholly owned subsidiary of AmerenEnergy Resources Company, who is responsible for providing fuel procurement and gas supply services on behalf of Ameren's operating subsidiaries, and for managing fuel and natural gas price risks. Fixed price forward contracts, as well as futures and options, are all instruments, which may be used to manage these risks. The majority of the Registrant's fuel supply contracts are physical forward contracts. 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 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.
Although the Registrant cannot completely eliminate the effects of elevated prices and price volatility, its strategy is designed to minimize the effect of these market conditions on the results of operations. The Registrant's gas procurement strategy includes procuring natural gas under a portfolio of agreements with price structures, including fixed price, indexed price and embedded price hedges such as caps and collars. The Registrant's strategy also utilizes physical assets through storage, operator and balancing agreements to dampen price volatility. The Registrant's electric marketing strategy is to extract additional value from its generation facilities by selling energy in excess of needs for term sales and purchasing energy when the market price is less than the cost of generation. The Registrant's primary use of derivatives has been limited to transactions that are expected to reduce price risk exposure for 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, 2000, 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 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 stockholder's equity. In June 1999, the FASB issued SFAS 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. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - an amendment of FASB Statement No. 133," which amended certain accounting and reporting standards of SFAS 133. The Registrant is adopting SFAS 133 in the first quarter of 2001. The Registrant expects the impact of this standard to result in a cumulative charge as of January 1, 2001 of $5 million after income taxes to the income statement and a cumulative adjustment of $8 million to decrease stockholder's equity. However, the Derivatives Implementation Group (DIG), a committee of the FASB responsible for providing guidance on the implementation of SFAS 133, has not reached a conclusion regarding the appropriate accounting treatment of certain types of energy contracts under SFAS 133. The Registrant is unable to predict when this issue will ultimately be resolved and the impact the resolution will have on the Registrant's future financial position, results of operations or liquidity. Implementation of SFAS 133 will likely increase the volatility of the Registrant's earnings in future periods.
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 relating to retail gas utility services are generally reflected in billings to customers through purchased gas adjustment clauses.
Inflation continues to be a factor affecting operations, earnings, stockholder's 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 and financial performance. 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, including changes in regulatory policy; 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; the effects of withdrawal from the Midwest ISO and membership in Alliance RTO; 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 construction, installation and 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 and Notes 5 and 14 to the "Notes to Financial Statements" under Item 8 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 39 present fairly, in all material respects, the financial position of Union Electric Company at December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14(a)(1) on Page 39 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP St. Louis, Missouri February 5, 2001 |
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
UNION ELECTRIC COMPANY
BALANCE SHEET
(Thousands of Dollars, Except Shares)
December 31, December 31,
ASSETS 2000 1999
----- ---- ----
Property and plant, at original cost:
Electric $9,449,275 $9,210,122
Gas 236,139 223,789
Other 37,140 37,156
------------------ ----------------
9,722,554 9,471,067
Less accumulated depreciation and amortization 4,571,292 4,320,910
------------------ ----------------
5,151,262 5,150,157
Construction work in progress:
Nuclear fuel in process 117,789 88,830
Other 111,527 92,833
------------------ ----------------
Total property and plant, net 5,380,578 5,331,820
------------------ ----------------
Investments and other assets:
Nuclear decommissioning trust fund 190,625 186,760
Other 65,811 59,748
------------------ ----------------
Total investments and other assets 256,436 246,508
------------------ ----------------
Current assets:
Cash and cash equivalents 19,960 117,308
Accounts receivable - trade (less allowance for doubtful
accounts of $6,251and $5,308, respectively) 277,947 229,612
Other accounts and notes receivable 28,216 19,803
Intercompany notes receivable 255,570 165,700
Materials and supplies, at average cost -
Fossil fuel 52,155 65,292
Other 82,161 90,921
Other 16,757 19,205
------------------ ----------------
Total current assets 732,766 707,841
------------------ ----------------
Regulatory assets:
Deferred income taxes 599,973 600,604
Other 146,373 156,789
------------------ ----------------
Total regulatory assets 746,346 757,393
------------------ ----------------
TOTAL ASSETS $7,116,126 $7,043,562
================== ================
CAPITAL AND LIABILITIES
Capitalization:
Common stock, $5 par value, 150,000,000 shares authorized -
102,123,834 shares outstanding $ 510,619 $ 510,619
Other paid-in capital, principally premium on
common stock 701,896 701,896
Retained earnings 1,358,137 1,221,167
------------------ ----------------
Total common stockholder's equity 2,570,652 2,433,682
Preferred stock not subject to mandatory redemption (Note 7) 155,197 155,197
Long-term debt (Note 9) 1,760,439 1,882,601
------------------ ----------------
Total capitalization 4,486,288 4,471,480
------------------ ----------------
Current liabilities:
Current maturity of long-term debt (Note 9) - 11,423
Accounts and wages payable 293,511 234,845
Accumulated deferred income taxes 30,325 48,139
Taxes accrued 86,125 119,699
Other 196,127 208,373
------------------ ----------------
Total current liabilities 606,088 622,479
------------------ ----------------
Commitments and contingencies (Notes 2, 12 and 13)
Accumulated deferred income taxes 1,315,109 1,248,721
Accumulated deferred investment tax credits 132,922 138,665
Regulatory liability 148,643 154,399
Other deferred credits and liabilities 427,076 407,818
------------------ ----------------
TOTAL CAPITAL AND LIABILITIES $7,116,126 $7,043,562
================== ================
|
See Notes to Financial Statements.
UNION ELECTRIC COMPANY
STATEMENT OF INCOME
(Thousands of Dollars)
December 31, December 31, December 31,
For the year ended 2000 1999 1998
---- ---- ----
OPERATING REVENUES:
Electric $2,589,285 $2,435,188 $2,290,896
Gas 129,241 91,978 91,175
----------------- ---------------- -----------------
Total operating revenues 2,718,526 2,527,166 2,382,071
OPERATING EXPENSES:
Operations
Fuel and purchased power 728,512 656,534 530,449
Gas 81,523 54,469 49,496
Other 500,299 434,456 461,987
----------------- ---------------- -----------------
1,310,334 1,145,459 1,041,932
Maintenance 250,030 247,135 221,995
Depreciation and amortization 269,665 256,072 259,787
Income taxes 226,800 230,691 217,385
Other taxes 209,460 204,541 212,789
----------------- ---------------- -----------------
Total operating expenses 2,266,289 2,083,898 1,953,888
OPERATING INCOME 452,237 443,268 428,183
OTHER INCOME AND DEDUCTIONS:
Allowance for equity funds used during
Construction 5,298 7,170 4,985
Miscellaneous, net 16,446 11,648 10,904
----------------- ---------------- -----------------
Total other income and deductions 21,744 18,818 15,889
INCOME BEFORE INTEREST CHARGES 473,981 462,086 444,072
INTEREST CHARGES:
Interest 129,282 119,978 129,947
Allowance for borrowed funds used during construction (8,312) (7,144) (5,945)
----------------- ---------------- -----------------
Net interest charges 120,970 112,834 124,002
NET INCOME 353,011 349,252 320,070
----------------- ---------------- -----------------
Preferred stock dividends 8,817 8,817 8,817
----------------- ---------------- -----------------
NET INCOME AFTER PREFERRED
STOCK DIVIDENDS $ 344,194 $ 340,435 $ 311,253
================= ================ =================
|
See Notes to Financial Statements.
UNION ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
(Thousands of Dollars)
December 31, December 31, December 31,
For the year ended 2000 1999 1998
---- ---- ----
Cash Flows From Operating:
Net income $353,011 $349,252 $320,070
Adjustments to reconcile net income to net cash
Provided by operating activities:
Depreciation and amortization 257,717 246,292 250,323
Amortization of nuclear fuel 37,101 36,068 36,855
Allowance for funds used during construction (13,610) (14,314) (10,930)
Deferred income taxes, net 901 258 (14,213)
Deferred investment tax credits, net (5,743) (5,510) (5,716)
Changes in assets and liabilities:
Receivables, net (56,748) 47,360 (4,883)
Materials and supplies 21,897 (11,346) 2,082
Accounts and wages payable 58,666 1,882 44,949
Taxes accrued (33,574) 18,985 6,547
Other, net 48,055 56,036 26,022
----------------- ------------------ --------------------
Net Cash Provided by Operating Activities 667,673 724,963 651,106
Cash Flows From Investing:
Construction expenditures (315,896) (246,198) (221,502)
Allowance for funds used during construction 13,610 14,314 10,930
Nuclear fuel expenditures (21,527) (21,901) (20,432)
Intercompany note receivable (89,870) (165,700) -
----------------- ------------------ --------------------
Net Cash Used in Investing Activities (413,683) (419,485) (231,004)
Cash Flows From Financing:
Dividends on common stock (207,224) (328,674) (259,599)
Dividends on preferred stock (8,817) (8,817) (8,817)
Redemptions -
Nuclear fuel lease (11,356) (15,138) (67,720)
Short-term debt - - (21,300)
Long-term debt (319,550) (100,000) (195,000)
Issuances -
Nuclear fuel lease 9,109 64,972 16,439
Long-term debt 186,500 152,150 160,000
----------------- ------------------ --------------------
Net Cash Used in Financing Activities (351,338) (235,507) (375,997)
Net Change in Cash and Cash Equivalents (97,348) 69,971 44,105
Cash and Cash Equivalents at Beginning of Year 117,308 47,337 3,232
----------------- ------------------ --------------------
Cash and Cash Equivalents at End of Year $19,960 $117,308 $47,337
======================================================================================================================
Cash paid during the periods:
-----------------------------------------------------------------------------------------------------------------------
Interest (net of amount capitalized) $114,304 $114,212 $125,255
Income taxes $231,052 $215,373 $223,960
-----------------------------------------------------------------------------------------------------------------------
|
See Notes to Financial Statements.
UNION ELECTRIC COMPANY
STATEMENT OF RETAINED EARNINGS
(Thousands of Dollars)
--------------------------------------------------------------------------------
Year Ended December 31, 2000 1999 1998
Balance at Beginning of Period $1,221,167 $1,211,610 $1,159,956
--------------------------------------------------------------------------------
Add:
Net income 353,011 349,252 320,070
--------------------------------------------------------------------------------
1,574,178 1,560,862 1,480,026
--------------------------------------------------------------------------------
Deduct:
Common stock dividends 207,224 328,674 259,599
Preferred stock dividends 8,817 11,021 8,817
--------------------------------------------------------------------------------
216,041 339,695 268,416
--------------------------------------------------------------------------------
Balance at End of Period $1,358,137 $1,221,167 $1,211,610
--------------------------------------------------------------------------------
|
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 $1,326,832 of free and unrestricted retained earnings at December 31, 2000.
SELECTED QUARTERLY INFORMATION (Unaudited)
(Thousands of Dollars)
---------------------------------------------------------------
Operating Operating Net Net Income
Revenues Income Income After
Quarter Ended Preferred
Stock
Dividends
------------------------- ------------ ----------------------- ---------------
March 31, 2000 (a) $561,190 $65,775 $39,236 $37,032
March 31, 1999 (a) 506,071 68,887 43,743 41,539
June 30, 2000 (b) 682,292 114,013 86,852 84,647
June 30, 1999 621,367 96,292 70,669 68,464
September 30, 2000 (c) 873,864 228,125 204,087 201,883
September 30, 1999 905,850 235,707 208,727 206,523
December 31, 2000 (d) 601,180 44,324 22,836 20,632
December 31, 1999 (e) 493,878 42,382 26,113 23,909
------------------------- ------------ ----------------------- ---------------
|
(a) The first quarter of 2000 and 1999 included credits to Missouri electric
customers that reduced net income approximately $6 million and $11 million,
respectively.
(b) The second quarter of 2000 included credits to Missouri electric customers
that reduced net income approximately $3 million.
(c) The third quarter of 2000 included credits to Missouri electric
customers that reduced net income approximately $11 million.
(d) The fourth quarter of 2000 included credits to Missouri electric customers
that reduced net income approximately $17 million. The fourth quarter of
2000 also included a nonrecurring charge related to the withdrawal from
the Midwest ISO that reduced net income approximately $10 million.
(See Note 2 - Regulatory Matters under Notes to Financial Statements for
further information.)
(e) 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, 2000
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 the following operating
companies: the Registrant, Central Illinois Public Service Company (AmerenCIPS)
and AmerenEnergy Generating Company (Generating Company), a wholly owned
subsidiary of AmerenEnergy Resources Company. 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 1.2 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/or operates electric generating and transmission facilities in Illinois that supply 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 2000, 1999 and 1998 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 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
liabilities are recognized for the tax consequences of transactions that have been treated differently for financial reporting and tax return purposes, measured using statutory tax rates.
Investment tax credits utilized in prior years were deferred and are being amortized over the useful lives of the related properties.
Allowance for Funds Used During Construction Allowance for funds used during construction (AFC) is a utility industry accounting practice whereby the cost of borrowed funds and the cost of equity funds (preferred and common stockholders' equity) applicable to the Registrant's regulated construction program are capitalized as a cost of construction. AFC does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing current construction, and treats such financing costs in the same manner as construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of AFC, as well as other construction costs, occurs when completed projects are placed in service and reflected in customer rates. The AFC rates used were 10% during 2000 and 1999 and 9% during 1998.
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 changes in fair market value included in earnings.
AmerenEnergy, Inc., an energy marketing subsidiary of Ameren, enters into
contracts for the sale and purchase of energy on behalf of the Registrant and
Generating Company. As of December 31, 2000, virtually all of AmerenEnergy's
transactions were considered nontrading activities and were accounted for using
the accrual or settlement method, which represents industry practice. See Note
15 - Statement of Financial Accounting Standards No. 133 for information related
to adoption of a new accounting standard in 2001.
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.
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, 2000, 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 2000 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 1998, the
Registrant recorded an estimated $43 million credit for the final year of the
Original Plan, which reduced earnings $26 million.
The MoPSC staff proposed adjustments to the Registrant's estimated customer credit for the final year of the Original Plan ended June 30, 1998, which were the subject of regulatory proceedings before the MoPSC in 1999. In December 1999, the MoPSC issued a Report and Order (Order) concerning these proposed adjustments. Based on the provisions of that Order, the Registrant revised its estimated final year credit of the Original Plan to $31 million in the quarter ended December 31, 1999. Subsequently, the Registrant filed a request for rehearing of the Order with the MoPSC, asking that it reconsider its decision to adopt certain of the MoPSC staff's adjustments. The request was denied by the MoPSC and in February 2000, the Registrant filed a Petition for Writ of Review with the Circuit Court of Cole Country, Missouri, requesting that the Order be reversed. The appeal is pending and the ultimate outcome can not be predicted; however, the final decision is not expected to materially impact the financial condition, results of operations or liquidity of the Registrant. A partial stay of the Order was granted by the Court pending the appeal.
A new three-year experimental alternative regulation plan (the New Plan) was included in the joint agreement authorized by the MoPSC in its February 1997 order approving the Merger. 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 stockholders. 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. The New Plan runs from July 1, 1998 through June 30, 2001. In November 2000, the MoPSC approved a stipulation and agreement of the parties regarding the credit for the plan year ended June 30, 1999 of $22 million, which was paid. At December 31, 2000, the Registrant has recorded estimated credits that the Registrant expects to pay its Missouri electric customers of $50 million and $35 million for the plan years ended June 30, 2001 and June 30, 2000, respectively. In March 2001, the MoPSC approved a stipulation and agreement of the parties regarding the credit for the plan year ended June 30, 2000. In total, the Registrant will pay its Missouri electric customers approximately $30 million in credits. During the year ended December 31, 2000, the Registrant recorded estimated credits in total of $65 million for plan years under the New Plan compared to $33 million in the year ago period. These credits were reflected as a reduction in electric revenues. The final amount of the credits will depend on several factors, including the Registrant's earnings for the respective 12 months ended June 30, 2001.
The joint agreement approved by the MoPSC in its February 1997 Order approving the Merger also provided 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 rate decrease was impacted by the Order issued by the MoPSC in December 1999 relating to the estimated credit for the third year of the Original Plan and a settlement reached between the Registrant, the MoPSC staff and other parties relating to the calculation of the weather-adjusted credits. Based on those results, the Registrant estimates that its Missouri electric rate decrease will be $17 million on an annualized basis. This estimate is subject to the final outcome of the above-referenced court appeal of the Order.
On February 1, 2001, the Registrant, MoPSC staff, and other parties submitted filings to the MoPSC addressing the merits of extending the current experimental alternative regulation plan. In its filing, the Registrant supported an extension of this plan with certain modifications, including retail electric rate reductions and additional customer credits. The MoPSC staff filing noted several concerns with the current plan and suggested that under traditional cost of service ratemaking, an annualized electric rate decrease of at least $100 million could be warranted. On March 8, 2001, the MoPSC issued an Order authorizing the MoPSC staff to file an earnings complaint to seek a rate reduction on July 1, 2001, if it determines one is warranted. In addition, the Order stated that the New Plan will not be continued beyond June 30, 2001. The Registrant has been engaged in discussions with the MoPSC staff and other parties in an effort to address issues associated with the expiration of the New Plan, including the development of a new alternative regulation plan. At this time, the Registrant cannot predict the outcome of these discussions or the timing or amount of any future electric rate reductions.
Gas
In October 2000, the MoPSC approved a $4 million annual rate increase for
natural gas service in the Registrant's Missouri jurisdiction. The rate increase
became effective November 1, 2000.
Midwest ISO
In 1998, the Registrant joined a group of companies that originally supported
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 facilitating wholesale and retail competition
through the elimination of "pancaked" transmission rates. The Midwest ISO is
regulated by the FERC. The FERC conditionally approved the formation of the
Midwest ISO in September 1998. The MoPSC and the Illinois Commerce Commission
(ICC) have authorized the Registrant to join the Midwest ISO.
In December 1999, the FERC issued Order 2000 relating to Regional Transmission Organizations (RTOs) that would meet certain characteristics such as size and independence. RTOs, including ISOs, are entities that ensure comparable and non-discriminatory access to regional electric transmission systems. Order 2000 calls on all transmission owners to join RTOs.
Following the announcements of Commonwealth Edison and Illinois Power of their intent to withdraw from the Midwest ISO and join the Alliance Regional Transmission Organization (Alliance RTO), the Registrant determined that the operational configuration of the Midwest ISO was unacceptable and announced its withdrawal in November 2000. The Registrant decided to withdraw to ensure the continued reliable and efficient operation of its transmission system. As a result of the Registrant's decision to withdraw from the Midwest ISO, in the fourth quarter of 2000, the Registrant recorded a pretax nonrecurring charge to earnings of $17 million. This charge relates to the Registrant's estimated obligation under the Midwest ISO agreement for costs incurred by the Midwest ISO, plus estimated exit costs.
In January 2001, the Registrant announced that it had signed an agreement to join the Alliance RTO. Also, in January 2001, the FERC conditionally approved the formation, including the rate structure, of the Alliance RTO. In February 2001, in a proceeding before the FERC, the Alliance RTO and the Midwest ISO reached an agreement that enables the Registrant to withdraw from the Midwest ISO and to join the Alliance RTO. This settlement agreement remains subject to FERC approval. The Registrant's withdrawal from the Midwest ISO remains subject to MoPSC approval. In addition, the Registrant's transfer of control and operation of its transmission assets to the Alliance RTO is subject to MoPSC and ICC approvals. At this time, the Registrant is unable to determine the impact that its withdrawal from the Midwest ISO and its participation in the Alliance RTO will have on its future financial condition, results of operation or liquidity.
Illinois Electric Restructuring and Related Matters 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. 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 occurred over the 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 and AmerenCIPS filed delivery service tariffs with the ICC. These tariffs would be used by electric customers who choose to purchase their power from alternate suppliers. In August 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. In January 2000, the ICC issued an order resolving the issues set for rehearing. In December 2000, the Registrant and AmerenCIPS filed revised Illinois delivery service tariffs with the ICC. The purpose of the filing was to update financial information that was used to establish the initial rates and to propose new rates. Additionally, the filing establishes tariffs for residential customers who may choose to purchase their power from alternate suppliers beginning in May 2002. These tariffs are subject to ICC approval. The Registrant expects that the ICC will issue its decision with respect to the tariffs in early 2002.
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. Under the Illinois Law, the Registrant was subject to an additional 5% residential electric rate decrease in 2000 and is subject
to an additional 5% residential electric rate decrease in 2002, to the extent its rates exceed the Midwest utility average at that time. In 2000, the Registrant's Illinois electric rates were below the Midwest utility average.
As a result of the Illinois Law, the Registrant and AmerenCIPS filed proposals with the ICC to eliminate their electric fuel adjustment clauses for Illinois retail customers, thereby including historical levels of fuel costs in base rates. The ICC approved the Registrant's and AmerenCIPS' filings 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 Ameren'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. The Registrant did not record any estimated refunds to Illinois customers in 2000.
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.
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 wholesale customers and those retail customers in Illinois who choose other suppliers as allowed under the Illinois Law. In January 2000, the Registrant and other parties to the rate case entered into a settlement agreement resolving all issues pending before the FERC. In May 2000, the FERC approved the settlement and allowed the settlement rates to become effective as of the first quarter of 2000.
The Registrant and AmerenCIPS have filed requests with various regulatory agencies, including the ICC, MoPSC and the SEC, seeking authorization to transfer AmerenUE's Illinois-based electric and natural gas businesses and certain of its Illinois-based distribution and transmission assets and personnel to AmerenCIPS. The assets and related liabilities were proposed to be transferred from the Registrant to AmerenCIPS at historical net book value. In March 2001, the Registrant decided it will no longer pursue this transfer and will be taking the necessary action to withdraw its pending requests for regulatory approvals.
Missouri Electric Restructuring
In Missouri, where approximately 94% of the Registrant's retail electric
revenues are derived, 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 or 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, 2000, the Registrant's net investment in generation facilities
related to its Missouri jurisdiction approximated $2.7 billion and was included
in electric plant in-service on the Registrant's balance sheet. In addition, at
December 31, 2000, the Registrant's Missouri net generation-related regulatory
assets approximated $442 million.
The Registrant is participating in discussions with the Missouri legislature regarding legislation that would not restructure the electric industry in Missouri, but would allow utilities to transfer generation assets to an affiliated generating company. In addition, the legislation would allow the State's largest nonresidential customers to choose their electric supplier, among other things. At this time, the Registrant cannot predict whether any electric industry legislation will be passed, or what the provisions of any such legislation will be.
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.
(in millions) 2000 1999 ------------------------------------------------------------------------------ Regulatory Assets: Income taxes $600 $601 Callaway costs 88 92 Unamortized loss on reacquired debt 25 24 Merger costs 17 22 Other 16 18 ------------------------------------------------------------------------------ Regulatory Assets $746 $757 ------------------------------------------------------------------------------ Regulatory Liability: Income taxes $149 $154 ------------------------------------------------------------------------------ Regulatory Liability $149 $154 ------------------------------------------------------------------------------ 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 $20 million and $15 million, respectively, as of December 31, 2000 and 1999. Intercompany payables included in accounts and wages payable totaled approximately $27 million and $25 million, respectively, as of December 31, 2000 and 1999.
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, 2000, the Registrant had outstanding intercompany receivables of $256 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. Hedging 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 supported by the financial and credit quality of the clearing
members of the 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. No customer represents greater than 10% of the Registrant's accounts receivable. 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, 2000, 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 $13 million in 2000, $16 million during 1999 and $23 million during 1998.
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 $8 million in 2000 and $5 million in 1999 and 1998. Interest charges for these years were based on average interest rates of approximately 7%. Interest charges of $6 million were capitalized in 2000, $4 million were capitalized in 1999, and $3 million were capitalized in 1998.
NOTE 7 - Preferred Stock
At December 31, 2000 and 1999, the Registrant had 25 million shares of authorized preferred stock.
Preferred Stock Not Subject to Mandatory Redemption:
(in millions)
--------------------------------------------------------------------------------
Redemption Price December 31,
(per share) 2000 1999
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 commercial paper (maturities generally within 1-45 days) and bank loans. At December 31, 2000 and 1999 the Registrant had no outstanding short-term borrowings.
At December 31, 2000, 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 $488 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, 2000, the Registrant had no intercompany borrowings outstanding and $321 million available through the regulated money pool.
NOTE 9 - Long-Term Debt
Long-term debt outstanding at December 31, was:
--------------------------------------------------------------------------------
(in millions) 2000 1999
--------------------------------------------------------------------------------
First Mortgage Bonds - note (a)
--------------------------------------------------------------------------------
7.40% Series paid in 2000 $ - $ 60
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
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
--------------------------------------------------------------------------------
1,129 1,189
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
Missouri Environmental Improvement Revenues Bonds
--------------------------------------------------------------------------------
1985 Series A paid in 2000 - 70
1985 Series B paid in 2000 - 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
2000 Series A due 2035 - note (c) 64 -
2000 Series B due 2035 - note (c) 63 -
2000 Series C due 2035 - note (c) 60 -
--------------------------------------------------------------------------------
437 377
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
Subordinated Deferrable Interest Debentures
--------------------------------------------------------------------------------
7.69% Series A due 2036 - note (d) 66 66
--------------------------------------------------------------------------------
Commercial Paper - note (e) 19 152
--------------------------------------------------------------------------------
Nuclear Fuel Lease 114 116
--------------------------------------------------------------------------------
Unamortized Discount and Premium on Debt (5) (6)
--------------------------------------------------------------------------------
Maturities Due Within One Year - (11)
--------------------------------------------------------------------------------
Total Long-Term Debt $1,760 $1,883
--------------------------------------------------------------------------------
|
(a) At December 31, 2000, 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 2000 are as follows:
1991 Series 4.39% 1992 Series 4.31% 1998 Series A 4.31% 1998 Series B 4.28% 1998 Series C 4.33% 2000 Series A 4.57% 2000 Series B 4.57% 2000 Series C 4.56% |
(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,
2000, $19 million of such commercial paper borrowings were outstanding.
(in millions) Principal Amount ------------------------------------------ 2001 $ - 2002 94 2003 100 2004 273 2005 - ------------------------------------------ |
Amounts for years subsequent to 2001 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 2000 resulted in an effective tax rate of 39% on earnings before income taxes (40% in 1999 and 1998).
2000 1999 1998
--------------------------------------------------------------------------------
Statutory federal income
tax rate 35% 35% 35%
Increases (Decreases) from:
Depreciation differences 2 2 2
State income tax 3 4 4
Other (1) (1) (1)
--------------------------------------------------------------------------------
Effective income tax rate 39% 40% 40%
--------------------------------------------------------------------------------
Income tax expense components:
--------------------------------------------------------------------------------
(in millions) 2000 1999 1998
--------------------------------------------------------------------------------
Taxes currently payable
(principally federal):
Included in operating expenses $231 $236 $237
Included in other income--
Miscellaneous, net (3) (4) (5)
--------------------------------------------------------------------------------
228 232 232
Deferred taxes (principally federal):
Included in operating expenses--
Depreciation differences 5 9 (1)
Other (4) (9) (14)
--------------------------------------------------------------------------------
1 - (15)
Deferred investment tax credits,
Amortization
Included in operating expenses (5) (5) (5)
--------------------------------------------------------------------------------
Total income tax expense $224 $227 $212
--------------------------------------------------------------------------------
|
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.
(in millions) 2000 1999 -------------------------------------------------------------------------------- Accumulated Deferred Income Taxes: Depreciation $839 $822 Regulatory assets, net 467 462 Capitalized taxes and expenses 102 60 Deferred benefit costs (63) (47) -------------------------------------------------------------------------------- Total net accumulated deferred income tax liabilities $1,345 $1,297 -------------------------------------------------------------------------------- |
NOTE 11 - Retirement Benefits
On January 1, 1999, the AmerenUE and the AmerenCIPS defined benefit pension plans combined to form the Ameren Retirement Plan (Ameren Plans). The Ameren Plans cover substantially all employees of the Registrant. Benefits are based on the employees' years of service and compensation. The Ameren Plans are 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 Plans and is responsible for its proportional share of the costs. The Registrant's share of the pension costs for 2000 and 1999 were $2 million and $18 million, respectively, of which approximately 20% and 18%, respectively, were charged to construction accounts. Pension costs for the AmerenUE plans for the year 1998 were $28 million, of which approximately 19% were charged to construction accounts.
Components of Net Periodic Pension Benefit Cost:
--------------------------------------------------------------------------
(in millions) 1998
--------------------------------------------------------------------------
Service cost $24
Interest cost 70
Expected return on plan assets (75)
Amortization of:
Transition asset (1)
Prior service cost 6
Actuarial gain (3)
Special termination benefit charge 7
---------------------------------------------------------------------------
Net periodic benefit cost $28
---------------------------------------------------------------------------
|
In addition to providing pension benefits, the Registrant provides certain health care and life insurance benefits for retired employees. On January 1, 2000, the AmerenUE and AmerenCIPS postretirement medical benefit plans combined to form the Ameren Postretirement Benefit Plans (Ameren Postretirement Plans). The Ameren Postretirement Plans cover substantially all employees of the Registrant. The Ameren Postretirement Plans are funded in compliance with income tax regulations and federal funding requirements. The MoPSC and the ICC allow the recovery of postretirement benefit costs in rates to the extent that such costs are funded. The Registrant, along with other subsidiaries of Ameren, is a participant in the Ameren Postretirement Plans and is responsible for its proportional share of the costs. The Registrant's share of the postretirement benefit costs for 2000 were $46 million, of which approximately 17% were charged to construction accounts. The Registrant's postretirement plan information for 1999 and 1998 is presented separately.
The Registrant's postretirement benefit costs in 1999 and 1998 were $46 million and $43 million, respectively, of which 18% and 17%, respectively, were charged to construction accounts. In 1999, claims were paid out of the plan trust funds, which were established in 1995. Following is the plan information related to AmerenUE's plans as of December 31.
(in millions) 1999 --------------------------------------------------------------------------- Change in benefit obligation Net benefit obligation at beginning of year $360 Service cost 15 Interest cost 25 Actuarial (gain)/loss (20) Benefits paid (26) --------------------------------------------------------------------------- Net benefit obligation at end of year 354 Change in plan assets * Fair value of plan assets at beginning of year 110 Actual return on plan assets 4 Employer contributions 46 Unincorporated business income tax - Benefits paid (26) --------------------------------------------------------------------------- Fair value of plan assets at end of year 134 Funded status - deficiency 220 Unrecognized net actuarial gain 29 Unrecognized prior service cost (3) Unrecognized net transition obligation (162) --------------------------------------------------------------------------- Postretirement benefit liability at December 31 $84 --------------------------------------------------------------------------- |
* Plan assets consist principally of common stocks, bonds and money market instruments.
(in millions) 1999 1998
--------------------------------------------------------------------------------
Service cost $15 $14
Interest cost 25 24
Expected return on plan assets (6) (5)
Amortization of:
Transition obligation 12 12
Actuarial gain - (2)
--------------------------------------------------------------------------------
Net periodic benefit cost $46 $43
--------------------------------------------------------------------------------
Assumptions for the Obligation Measurements:
---------------------------------------------------------------------------
1999
---------------------------------------------------------------------------
Discount rate at measurement date 7.75%
Expected return on plan assets 8.5%
Medical cost trend rate - initial -
- ultimate 5.25%
Ultimate medical cost trend rate expected in year 2000
--------------------------------------------------------- -----------------
|
NOTE 12 - Commitments and Contingencies
The Registrant is engaged in a capital program under which expenditures averaging approximately $380 million, including AFC, are anticipated during each of the next five years. This estimate includes capital expenditures for the replacement of four steam turbine generators at its Callaway Nuclear Plant, as well as 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 2001 through 2005 are estimated to total $866 million. Total coal purchases, including transportation costs, for 2000, 1999 and 1998 were $283 million, $312 million and $304 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 2001 through 2005 are estimated to total $89 million. Total delivered natural gas costs were $82 million for 2000, $54 million for 1999 and $50 million for 1998. The Registrant's nuclear fuel commitments for 2001 through 2005, including
uranium concentrates, conversion, enrichment and fabrication,are expected to total $111 million, and are expected to be financed under the nuclear fuel lease. Nuclear fuel expenditures were $22 million for 2000 and 1999 and $20 million for 1998. Additionally, the Registrant has long-term contracts with other utilities to purchase electric capacity. These commitments for 2001 through 2005 are estimated to total $147 million. During 2000, 1999 and 1998, electric capacity purchases were $34 million, $38 million, and $35 million, respectively.
The Registrant's insurance coverage for Callaway Nuclear Plant at December 31, 2000, 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
--------------------------------------------------------------------------------
|
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 required 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. The EPA appealed the decision to the U.S. Supreme Court. On February 27, 2001, the U.S. Supreme Court reversed and remanded the case to the U.S. Court of Appeals for the District of Columbia for further evaluation and opinion. The Supreme Court ruled that Congress, in enacting Clean Air act provisions that authorized the EPA to determine air quality standards, did not unconstitutionally delegate legislative power to the agency. The Supreme Court also rejected industry arguments that the EPA should have considered implementation costs in setting air quality standards. The ruling reaffirms the EPA's authority to establish uniform air quality standards at a level that is sufficient to protect public health. However, the manner in which the EPA proposed to implement the proposed air quality standard for ozone was ruled unlawful and the Supreme Court ordered the remand of the EPA's implementation policy to the agency for further consideration. When the proposed ambient standards are ultimately enacted, such standards will require significant additional reductions in SO2 and NOx emissions from the Registrant's power plants. 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 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 regulations were challenged in a U. S. District Court. In March 2000, the Court upheld most of the regulations. However, the Court remanded the state of Missouri's regulations back to the EPA for revision. The Court further delayed the compliance date of the regulations until 2004. The final applicability of the regulations as they might apply to utility boilers in Missouri is still uncertain. 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, the regulations will require the installation of selective catalytic reduction technology on some of the Registrant's units, as well as other additional controls.
Currently, the Registrant estimates that its additional capital expenditures to comply with the final NOx regulations could range from $125 million to $150 million over the period from 2001 to 2005. Associated operations and maintenance expenditures could increase $5 million to $8 million annually, beginning in 2005. 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 ultimate impact of these standards on its future financial condition, results of operations or liquidity.
The Registrant is involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of fault, legality of original disposal, or ownership of a disposal site. The Registrant has been identified by the federal or state governments as a potentially responsible party at several contaminated sites including two sites that have been listed or are proposed for listing on the National Priorities List.
The Registrant owns or is otherwise responsible for one manufactured gas plant (MGP) site in Illinois, 10 MGP sites in Missouri and one MGP site in Iowa. The ICC permits the recovery of remediation and litigation costs associated with former MGP sites located in Illinois from the Registrant's Illinois electric and natural gas utility customers through environmental adjustment clause rate riders. To be recoverable, such costs must be prudently and properly incurred and are subject to annual reconciliation review by the ICC. Unlike Illinois, the Registrant does not have in effect in Missouri a rate rider mechanism, which permits remediation costs associated with MGP sites to be recovered from utility customers, and the Registrant has no retail utility operations in Iowa.
In June 2000, the EPA notified the Registrant and numerous other companies that certain properties in Sauget, Illinois, may contain soil and groundwater contamination. From approximately 1926 until 1976, the Registrant operated a power generating facility and currently owns and operates electric transmission facilities in the area. At this time, the Registrant is unable to predict the ultimate impact of the Sauget site on its financial position, results of operations or liquidity.
In September 2000, the United States Department of Justice was granted leave by the United States District Court - Southern District of Illinois to add numerous additional parties, including the Registrant, to a preexisting lawsuit between the government and Monsanto Chemical Company and others. The government seeks recovery of response costs under the Comprehensive Environmental Response Compensation Liability Act of 1980 (commonly known as CERCLA or Superfund), incurred in connection with federal Superfund site in Illinois. The Registrant believes that the final resolution of this lawsuit will not have a material adverse effect on its financial position, results of operations or liquidity.
In addition, the Registrant's operations, or that of its predecessor companies, involve the use, disposal and, in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. The Registrant is unable to determine the impact these actions may have on the Registrant's financial position, results of operation or liquidity.
The Registrant's union employees are represented by the International Brotherhood of Electrical Workers and the International Union of Operating Engineers. These employees comprise approximately 74% 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. New contracts with collective bargaining units representing approximately 54% of these employees were ratified in 2000 with terms expiring in 2003.
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 utility 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 $554 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 2000, 1999 and 1998. 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:
2000 1999
--------------------------------------------------------------------------------
(in millions) Carrying Fair Carrying Fair
Amount Value Amount Value
--------------------------------------------------------------------------------
Preferred stock $155 $121 $155 $126
Long-term debt (including current portion) 1,760 1,777 1,894 1,872
--------------------------------------------------------------------------------
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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, 2000 and 1999. In 2000, 1999 and 1998, the proceeds from the sale of investments were $61 million, $83 million and $29 million, respectively. Using the specific identification method to determine cost, the gross realized gains on those sales were approximately $1 million for 2000, $11 million for 1999 and $2 million for 1998. 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.
2000 (in millions) Gross Unrealized
Security Type Cost Gain (Loss) Fair Value
--------------------------------------------------------------------------------
Debt Securities $71 $ 3 $ - $74
Equity Securities 52 61 - 113
Cash equivalents 4 - - 4
--------------------------------------------------------------------------------
$127 $64 $ - $191
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------
|
(in millions) Cost Fair Value
--------------------------------------------------------------------------------
1 year to 5 years $7 $7
5 years to 10 years 32 34
Due after 10 years 32 33
--------------------------------------------------------------------------------
$71 $74
--------------------------------------------------------------------------------
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Note 15 - Statement of Financial Accounting Standards No. 133
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities and requires recognition of all derivatives as either assets or liabilities on the balance sheet measured at fair value. The intended use of the derivatives and their designation as either a fair value hedge, a cash flow hedge, or a foreign currency hedge will determine when the gains or losses on the derivatives are to be reported in earnings and when they are to be reported as a component of other comprehensive income in stockholder's equity. In June 1999, the FASB issued SFAS 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. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - an amendment of FASB Statement No. 133," which amended certain accounting and reporting standards of SFAS 133. The Registrant is adopting SFAS 133 in the first quarter of 2001. The Registrant expects the impact of this standard to result in a cumulative charge as of January 1, 2001 of $5 million after income taxes to the income statement and a cumulative adjustment of $8 million to decrease stockholder's equity. However, the Derivatives Implementation Group (DIG), a committee of the FASB responsible
for providing guidance on the implementation of SFAS 133, has not reached a conclusion regarding the appropriate accounting treatment of certain types of energy contracts under SFAS 133. The Registrant is unable to predict when this issue will ultimately be resolved and the impact the resolution will have on the Registrant's future financial position, results of operations or liquidity. Implementation of SFAS 133 will likely increase the volatility of the Registrant's earnings in future periods.
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 2001 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 "Executive Compensation" in AmerenUE's 2001 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" in AmerenUE's 2001 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 2001 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............................. 18
Balance Sheet - December 31, 2000 and 1999.................... 19
Statement of Income - Years 2000, 1999, and 1998.............. 20
Statement of Cash Flows - Years 2000, 1999, and 1998.......... 21
Statement of Retained Earnings - Years 2000, 1999, and 1998... 22
Notes to Financial Statements................................. 23
Valuation and Qualifying Accounts (Schedule II)
Years 2000, 1999, and 1998................................. 40
Schedules not included have been omitted because they are not
applicable or the required data is shown in the aforementioned
financial statements.
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2. Exhibits: See EXHIBITS beginning on Page 42.
(b) Reports on Form 8-K. The Registrant filed a report on Form 8-K dated January 11, 2001 reporting the recording of a nonrecurring charge in the fourth quarter of 2000 as a result of its decision to withdraw from the Midwest ISO.
UNION ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
Col.A Col.B Col.C Col.D Col.E
----- ----- ----- ----- -----
Additions
-----------------------------------
(1) (2)
Balance at Charged to Balance at
beginning costs and Charged to end of
Description of period expenses other accounts Deductions period
------------ ---------- -------- -------------- ---------- ---------
(Note)
Year ended December 31, 2000
Reserves deducted in the balance sheet from
assets to which they apply:
Allowance for doubtful accounts $5,308,463 $8,440,000 $7,497,221 $6,251,242
========== =========== ========== ==========
Year ended December 31, 1999
Reserves deducted in the balance sheet from
assets to which they apply:
Allowance for doubtful accounts $6,678,422 $8,840,000 $10,209,959 $5,308,463
========== ========== =========== ==========
Year ended December 31, 1998
Reserves deducted in the balance sheet from
assets to which they apply:
Allowance for doubtful accounts $3,645,328 $16,900,000 $13,866,906 $6,678,422
========== =========== =========== ==========
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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 30, 2001 By /s/ Steven R. Sullivan
--------------- -------------------------
(Steven R. Sullivan, Attorney-in-Fact)
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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
CHARLES W. MUELLER (Principal Executive Officer)
/s/ Donald E. Brandt Senior Vice President and Director
DONALD E. BRANDT (Principal Financial Officer)
/s/ Warner L. Baxter Vice President, Controller and Director
WARNER L. BAXTER (Principal Accounting Officer)
/s/ Paul A. Agathen Director
PAUL A. AGATHEN
/s/ Gary L. Rainwater Director
GARY L. RAINWATER
By /s/ Steven R. Sullivan March 30, 2001
-------------------------
(Steven R. Sullivan, Attorney-in Fact)
|
EXHIBITS
Exhibits Filed Herewith
Exhibit No. Description
4.1 - Supplemental Indenture dated February 1, 2000 to the Indenture of Mortgage and Deed of Trust of Union Electric Company d/b/a AmerenUE (the Company) dated June 15, 1937, as amended May 1, 1941.
12 - Statement re Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements.
24 - Powers of Attorney.
Exhibits Incorporated By Reference
The following exhibits heretofore have been filed with the Securities and Exchange Commission (SEC) 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 the Company, CIPSCO Incorporated, Ameren Corporation (Ameren), 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)).
4.2 - 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 (File No. 2-27474, Exhibit 3-E).
4.3 - 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 (File No. 2-27474, Exhibit 3-F).
4.4 - 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 (File No.2-27474, Exhibit 3-G).
4.5 - 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 (File No. 2-4940, Exhibit B-1).
4.6 - 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
-43-
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Exhibit No. Description |
4.7 - 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).
4.8 - 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).
4.9 - 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).
4.10 - 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).
4.11 - 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).
4.12 - 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).
4.13 - 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).
4.14 - 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).
4.15 - 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 as amended and restated effective January 1, 2001 (Ameren's 2000 Form 10-K, Exhibit 10.1).
10.4 - Ameren Deferred Compensation Plan for Members of the Board of Directors (Ameren's 1998 Form 10-K, Exhibit 10.4).
10.5 - Ameren Executive Incentive Compensation Program Elective Deferral Provisions for Members of the Ameren Leadership Team as amended and restated effective January 1, 2001 (Ameren's 2000 Form 10-K, Exhibit 10.2).
Exhibit No. Description
10.6 - Amended Joint Dispatch Agreement among the Company, AmerenEnergy Generating Company and Central Illinois Public Service Company d/b/a AmerenCIPS (File No. 333-56594, Exhibit 10.4).
Exhibits Available Upon Request
The following instrument defining the rights of holders of certain unregistered long-term debt of the Company has not been filed with the SEC but will be furnished upon request.
- Loan Agreement dated as of March 1, 2000, between the Company and the State Environmental Improvement and Energy Resources Authority of the State of Missouri (EIERA) in connection with the EIERA's $186,500,000 Environmental Improvement Revenue Refunding Bonds (AmerenUE Project) ($63,500,000 Series 2000A, $63,000,000 Series 2000B, and $60,000,000 Series 2000C) due March 1, 2035.
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 Forms 8-K, 10-Q and 10-K are on file with the SEC under File Number 1-14756.
UNION ELECTRIC COMPANY
TO
BANK OF AMERICA, NATIONAL ASSOCIATION
(f/k/a Boatmen's Trust Company)
AS TRUSTEE
Supplemental Indenture
Dated February 1, 2000
Supplemental to Mortgage and Deed of Trust Dated June 15, 1937 of Union Electric Company To Bank of America, National Association (f/k/a Boatmen's Trust Company), Trustee
Amendment of Section 8 of Article XIII
SUPPLEMENTAL INDENTURE, effective the first day of February, two thousand (2000), made by and between UNION ELECTRIC COMPANY, a corporation organized and existing under the laws of the State of Missouri (hereinafter called the "Company"), party of the first part, and BANK OF AMERICA, NATIONAL ASSOCIATION (f/k/a Boatmen's Trust Company), a national banking association, (hereinafter called the "Trustee"), as Trustee under the Indenture of Mortgage and Deed of Trust dated June 15, 1937, hereinafter mentioned, party of the second part;
WHEREAS, the Company has heretofore executed and delivered to the Trustee its Indenture of Mortgage and Deed of Trust, dated June 15, 1937, as amended May 1, 1941, April 1, 1971, February 1, 1974, and July 7, 1980 (said Indenture of Mortgage and Deed of Trust as so amended, being hereinafter sometimes referred to as the "Original Indenture"), to secure the payment of the principal of and the interest (and premium, if any) on all Bonds at any time issued and outstanding thereunder, and indentures supplemental thereto dated June 15, 1937, May 1, 1941, March 17, 1942, April 13, 1945, April 27, 1945, October 1, 1945, April 11, 1947, April 13, 1949, September 13, 1950, December 1, 1950, September 20, 1951, May 1, 1952, March 1, 1954, May 1, 1955, August 31, 1955, April 1, 1956, July 1, 1956, August 1, 1957, February 1, 1958, March 1, 1958, November 5, 1958, March 16, 1959, June 24, 1959, December 11, 1959, August 17, 1960, September 1, 1960, October 24, 1960, June 30, 1961, July 1, 1961, August 9, 1962, September 30, 1963, November 1, 1963, March 12, 1965, April 1, 1965, April 14, 1966, May 1, 1966, February 17, 1967, March 1, 1967, February 19, 1968, March 15, 1968, August 21, 1968, April 7, 1969, May 1, 1969, September 12, 1969, October 1, 1969, March 26, 1970, April 1, 1970, January 1, 1971, April 1, 1971, September 15, 1971, December 3, 1973, February 1, 1974, April 25, 1974, February 3, 1975, March 1, 1975, June 11, 1975, May 12, 1976, August 16, 1976, April 26, 1977, October 15, 1977, November 7, 1977, December 1, 1977, August 1, 1978, October 12, 1979, November 1, 1979, July 7, 1980, August 1, 1980, August 20, 1980, February 1, 1981, October 8, 1981, August 27, 1982, September 1, 1982, December 15, 1982, March 1, 1983, June 21, 1984, December 12, 1984, June 11, 1985, March 1, 1986, May 1, 1986, May 1, 1990, December 1, 1991, December 4, 1991, January 1, 1992, September 30, 1992, October 1, 1992, December 1, 1992, February 1, 1993, February 18, 1993, May 1, 1993, August 1, 1993, October 1, 1993, January 1, 1994 and July 25, 1994, respectively, have heretofore been entered into between the Company and the Trustee; and
WHEREAS, the Company desires by this Supplemental Indenture to further modify and amend the Original Indenture, in so far as the holders of Bonds of all series heretofore created and of any subsequently created series are concerned, as permitted in subdivision (d) of Section 1 of Article XIV of the Original Indenture; and
WHEREAS, the Company, in the exercise of the powers and authority conferred upon and reserved to it under the provisions of the Original Indenture and pursuant to appropriate resolutions of its Board of Directors, has duly resolved and determined to make, execute and deliver to the Trustee a Supplemental Indenture in the form hereof for the purposes herein provided; and
WHEREAS, all conditions and requirements necessary to make this Supplemental Indenture a valid binding and legal instrument have been done, performed and fulfilled and the execution and delivery hereof have been in all respects duly authorized.
NOW, THEREFORE, THIS INDENTURE WITNESSETH:
ARTICLE I.
AMENDMENT.
Pursuant to Section 1(d) of Article XIV of the Indenture of Mortgage and Deed of Trust dated June 15, 1937, as heretofore amended May 1, 1941, April 1, 1971, February 1, 1974, and July 7, 1980, Section 8 of Article XIII thereof is hereby modified and amended to read as follows:
"Section 8. Any corporation into which the Trustee or any successor to it in the trust created by this Indenture may be converted to or merged, or with which it or any successor to it may be consolidated, or to which it or any successor to it may transfer its corporate trust business and assets as a whole or substantially as a whole, or any corporation resulting from any such conversion, merger, consolidation or transfer to which it shall be a party, shall, subject to the provisions of Section 5 of this Article, be the successor Trustee under the Indenture without the execution or filing of any instruments or any further act on the part of any of the parties hereto, anything herein to the contrary notwithstanding."
ARTICLE II.
THE TRUSTEE.
The Trustee hereby accepts the trusts hereby declared and provided, and agrees to perform the same upon the terms and conditions in the Original Indenture, and in the indentures supplemental thereto, including this Supplemental Indenture, set forth, and upon the following terms and conditions:
The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or the due execution hereof by the Company or for or in respect of the recitals contained herein, all of which recitals are made by the Company solely.
ARTICLE III.
MISCELLANEOUS PROVISIONS.
All terms contained in this Supplemental Indenture shall, for all purposes thereof, have the meanings given to such terms in Article I of the Original Indenture.
This Supplemental Indenture may be simultaneously executed in any number of counterparts, each of which when so executed shall be deemed to be an original; but such counterparts shall together constitute but one and the same instrument.
IN WITNESS WHEREOF, said Union Electric Company has caused this Supplemental Indenture to be executed on its behalf by its President or one of its Vice Presidents and its corporate seal to be hereto affixed and said seal and this Supplemental Indenture to be attested by its Secretary or one of its Assistant Secretaries; and said Bank of America, National Association (f/k/a Boatmen's Trust Company), in evidence of its acceptance of the trust hereby created, has caused this Supplemental Indenture to be executed on its behalf by its President or one of its Vice Presidents and its corporate seal to be hereto affixed and said seal and this Supplemental Indenture to be attested by its Vice President or one of its Assistant Vice Presidents; all as of the day and year first above written.
UNION ELECTRIC COMPANY
1901 Chouteau Avenue
St. Louis, Missouri 63103
By: __/s/ Donald E. Brandt
--------------------------------------
Donald E. Brandt
Senior Vice President
|
[Corporate Seal]
Attested:
/s/ Steven R. Sullivan ----------------------------------------- Steven R. Sullivan Secretary |
Signed, sealed and delivered by Union Electric Company In the presence of:
/s/ Elizabeth A. Burns --------------------------------------- /s/ Eileen M. Bauman --------------------------------------- |
As Witnesses
BANK OF AMERICA, NATIONAL
ASSOCIATION (f/k/a Boatmen's
Trust Company)
100 N. Broadway, 4th Floor
St. Louis, Missouri 63102
By: /s/ David Ferrell
-------------------------------
David Ferrell
Vice President
|
[Corporate seal]
Attested:
/s/ J. Rector ----------------------------- |
Signed, sealed and delivered by Bank of America, National Association (f/k/a Boatmen's Trust Company) In the presence of:
/s/ Edward Hemby ---------------------------- /s/ J. Kemper ---------------------------- |
As Witnesses
STATE OF MISSOURI )
) SS:
CITY OF ST. LOUIS )
On this 24th day of January, 2000, before me appeared Donald E. Brandt to me personally known, who being by me duly sworn, did say that he is a Senior Vice President of Union Electric Company, a corporation and that the seal affixed to the foregoing instrument is the corporate seal of said corporation and that said instrument was signed and sealed in behalf of said corporation by authority of its Board of Directors, and said Donald E. Brandt acknowledged said instrument to be the free act and deed of said corporation.
IN TESTIMONY WHEREOF, I have hereto set my hand and affixed my official seal at my office in the City and State aforesaid, the day and year last above written.
/s/ Carol A. Head
----------------------------------------
Notary Public - Notary Seal
State of Missouri
St. Charles County
My Commission Expires: Sept. 23, 2002
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STATE OF MISSOURI )
)SS:
CITY OF ST. LOUIS )
On this 24th day of January, 2000, before me appeared David Ferrell to me personally known, who being by me duly sworn, did say that he is Vice President of Bank of America, National Association (f/k/a Boatmen's Trust Company) and that the seal affixed to the foregoing instrument is the corporate seal of said corporation and that said instrument was signed and sealed in behalf of said corporation by authority of its Board of Directors and said David Ferrell acknowledged said instrument to be the free act and deed of said corporation.
IN TESTIMONY WHEREOF, I have hereto set my hand and affixed my official seal at my office in the City and State aforesaid, the day and year last above written.
/s/ L. J. Marlo
--------------------------------------------
Notary Public - Notary Seal
State of Missouri
St. Louis County
My Commission Expires: June 3, 2002
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This form of instrument was prepared by Ameren Services Company Legal Department, 1901 Chouteau Avenue, P.O. Box 66149, St. Louis, Missouri 63166-6149.
UNION ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDEND REQUIREMENTS
Year Ended December 31,
-----------------------------------------------------------------
1996 1997 1998 1999 2000
Thousands of Dollars Except Ratios
Net Income $304,876 $301,655 $320,070 $349,252 $353,011
Add- Extraordinary items net of tax - 26,967 - - -
---------- --------- --------- --------- ---------
---------- --------- --------- --------- ---------
Net income from continuing operations 304,876 328,622 320,070 349,252 353,011
---------- --------- --------- --------- ---------
---------- --------- --------- --------- ---------
Taxes based on income 196,210 199,763 212,554 226,696 224,149
---------- --------- --------- --------- ---------
---------- --------- --------- --------- ---------
Net income before income taxes 501,086 528,385 532,624 575,948 577,160
---------- --------- --------- --------- ---------
---------- --------- --------- --------- ---------
Add- fixed charges:
Interest on long term debt 120,547 125,705 124,766 117,899 121,763
Other interest 7,828 9,299 1,660 (1,342) 4,219
Rentals 3,458 3,727 3,416 3,899 3,928
Amortization of net debt premium, discount,
expenses and losses 4,269 3,672 3,522 3,421 3,300
---------- --------- --------- --------- ---------
---------- --------- --------- --------- ---------
Total fixed charges 136,102 142,403 133,364 123,877 133,210
---------- --------- --------- --------- ---------
---------- --------- --------- --------- ---------
Earnings available for fixed charges 637,188 670,788 665,988 699,825 710,370
========== ========= ========= ========= =========
========== ========= ========= ========= =========
Ratio of earnings to fixed charges 4.68 4.71 4.99 5.64 5.33
========== ========= ========= ========= =========
========== ========= ========= ========= =========
Earnings required for preferred dividends:
Preferred stock dividends 13,249 8,817 8,817 8,817 8,817
Adjustment to pre-tax basis 7,363 4,257 4,649 4,544 4,439
---------- --------- --------- --------- ---------
---------- --------- --------- --------- ---------
20,612 13,074 13,466 13,361 13,256
Fixed charges plus preferred stock dividend
requirements 156,714 155,477 146,830 137,238 146,466
========== ========= ========= ========= =========
========== ========= ========= ========= =========
Ratio of earnings to fixed charges plus
preferred stock dividend requirements 4.06 4.31 4.53 5.09 4.85
========== ========= ========= ========= =========
========== ========= ========= ========= =========
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POWER OF ATTORNEY
WHEREAS, UNION ELECTRIC COMPANY, a Missouri corporation (herein referred to as the "Company"), is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2000; and
WHEREAS, each of the below undersigned holds the office or offices in the Company set opposite his name;
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Charles W. Mueller and/or Donald E. Brandt and/or Steven R. Sullivan the true and lawful attorneys-in-fact of the undersigned, for and in the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto, and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact may do by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 8th day of February 2001:
Charles W. Mueller, President, Chief
Executive Officer and Director
(Principal Executive Officer) /s/ Charles W. Mueller
----------------------------
Paul A. Agathen, Director /s/ Paul A. Agathen
----------------------------
Warner L. Baxter, Vice President,
Controller and Director
(Principal Accounting Officer) /s/ Warner L. Baxter
----------------------------
Donald E. Brandt, Senior Vice
President and Director
(Principal Financial Officer) /s/ Donald E. Brandt
----------------------------
Gary L. Rainwater, Director /s/ Gary L. Rainwater
----------------------------
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STATE OF MISSOURI )
) SS.
CITY OF ST. LOUIS )
|
On this 8th day of February, 2001, before me, the undersigned Notary Public in and for said State, personally appeared the above-named officers and directors of Union Electric Company, known to me to be the persons described in and who executed the foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.
IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.
/s/ K. A. Bell
--------------------------------------------
K. A. BELL
Notary Public - Notary Seal
STATE OF MISSOURI
St. Louis County
My Commission Expires: October 13, 2002
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