<PAGE>
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, 1999
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
6, 2000 , based on closing prices most recently available as reported in The
Wall Street Journal (excluding Preferred Stock for which quotes are not publicly
available): $40,056,825.
Shares of Common Stock, $5 par value, outstanding as of March 6, 2000:
102,123,834 shares (all owned by Ameren Corporation).
Documents incorporated by references.
Portions of the registrant's definitive proxy statement for the 2000 annual
meeting are incorporated by reference into Part III.
<PAGE>
TABLE OF CONTENTS
PART I Page
Item 1 - Business
General.................................................... 1
Capital Program and Financing.............................. 1
Rates...................................................... 2
Fuel Supply................................................ 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..... 16
Item 8 - Financial Statements and Supplementary Data.................... 18
Item 9 - Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure1
PART III
Item 10 - Directors and Executive Officers of the Registrant<F2>......... 37
Item 11 - Executive Compensation2........................................ 38
Item 12 - Security Ownership of Certain Beneficial Owners
and Management2....................................... 38
Item 13 - Certain Relationships and Related Transactions<F2>............. 38
PART IV
Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K. 38
SIGNATURES ............................................................ 40
EXHIBITS ............................................................ 41
[FN]
<F1> Not applicable and not included herein.
<F2> Incorporated herein by reference.
</FN>
<PAGE>
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 a power marketing agent for the Registrant and Ameren
Services Company which provides shared support services to the Registrant. For
additional information on the Registrant's business organization, see Note 1 to
the "Notes to Financial Statements" under Item 8 herein.
The Registrant, incorporated in Missouri in 1922, is successor to a number
of companies, the oldest of which was organized in 1881. The Registrant is the
largest electric utility in the State of Missouri and supplies electric service
in territories in Missouri and Illinois having an estimated population of
2,600,000 within an area of approximately 24,500 square miles, including the
greater St. Louis area. Retail gas service is supplied in 90 Missouri
communities and in the City of Alton, Illinois and vicinity.
For the year 1999, 96% of total operating revenues was derived from the
sale of electric energy and 4% from the sale of natural gas. Electric operating
revenues as a percentage of total operating revenues in both 1998 and 1997 were
also 96%.
The Registrant employed 4,184 persons at December 31, 1999. Approximately
77% of such employees are represented by local unions affiliated with the
AFL-CIO. For information on the status of labor agreements with these unions,
see Note 12 to the "Notes to Financial Statements" under Item 8 herein.
CAPITAL PROGRAM AND FINANCING
The Registrant is engaged in a capital program under which construction
expenditures are expected to approximate $297 million in 2000. For the five-year
period 2000-2004, construction expenditures are estimated at $1.6 billion. This
estimate includes capital expenditures which will be incurred by the Registrant
to meet new air quality standards for ozone and particulate matter.
During the five-year period ended 1999, gross additions to the property of
the Registrant, including allowance for funds used during construction and
excluding nuclear fuel, were approximately $1.3 billion (including $228 million
in 1999) and property retirements were $347 million.
In addition to the funds required for construction during the 2000-2004
period, $611 million will be required to repay long-term debt as follows: $11
million in 2000; $227 million in 2002; $100 million in 2003; and $273 million in
2004. Amounts for years subsequent to 2000 do not include the Registrant's
nuclear fuel lease payments since the amounts of such payments are not currently
determinable.
The Registrant has transactions in the normal course of business with other
Ameren subsidiaries and has the ability to borrow funds from Ameren or
AmerenCIPS or invest funds through a regulated money pool agreement. At December
31, 1999, the Registrant had outstanding intercompany receivables of $166
million through the regulated money pool.
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<PAGE>
For information on the Registrant's capital program, external cash sources
and intercompany borrowings, see "Liquidity and Capital Resources" in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" under Item 7 herein and Notes 3, 6, 8 and 12 to the "Notes to
Financial Statements" under Item 8 herein.
Financing Restrictions. Under the most restrictive earnings test contained
in the Registrant's Indenture of Mortgage and Deed of Trust (Mortgage) relating
to its First Mortgage Bonds (Bonds), no Bonds may be issued (except in certain
refunding operations) unless the Registrant's net earnings available for
interest after depreciation for 12 consecutive months within the 15 months
preceding such issuance are at least two times annual interest charges on all
Bonds and prior lien bonds then outstanding and to be issued (all calculated as
provided in the Mortgage). Such ratio for the 12 months ended December 31, 1999
was 7.8, which would permit the Registrant to issue an additional $3.2 billion
of Bonds (8% annual interest rate assumed). Additionally, the Mortgage permits
issuance of new bonds up to (a) 60% of defined property additions, or (b) the
amount of previous bonds retired or to be retired, or (c) the amount of cash put
up for such purpose. At December 31, 1999, the aggregate amount of Bonds
issuable under (a) and (b) above was approximately $2.4 billion.
The Registrant's Restated Articles of Incorporation restrict the Registrant
from selling Preferred Stock unless its net earnings for a period of 12
consecutive months within 15 months preceding such sale are at least two and
one-half times the annual dividend requirements on its Preferred Stock then
outstanding and to be issued. Such ratio for the 12 months ended December 31,
1999 was 39.5, which would permit the Registrant to issue an additional $1.6
billion stated value of Preferred Stock (8% annual dividend rate assumed).
Certain other financing arrangements require the Registrant to obtain prior
consents to various actions by the Registrant, including any future borrowings,
except for permitted financings such as borrowings under revolving credit
agreements, the nuclear fuel lease, unsecured short-term borrowings (subject to
certain conditions), and the issuance of additional Bonds.
RATES
For the year 1999, approximately 83%, 6%, and 11% of the Registrant's
electric operating revenues were based on rates regulated by the Missouri Public
Service Commission (MoPSC), the Illinois Commerce Commission (ICC), and the
Federal Energy Regulatory Commission (FERC) of the U. S. Department of Energy,
respectively. For information on rate matters in these jurisdictions, see
"Electric Industry Restructuring" in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" under Item 7 herein and Note 2 to
the "Notes to Financial Statements" under Item 8 herein.
In February 2000, the Registrant filed a request with the MoPSC to increase
rates approximately $12 million annually for natural gas service in its Missouri
jurisdiction. The MoPSC has until January 2001 to render a decision.
FUEL SUPPLY
<TABLE>
<CAPTION>
Cost of Fuels Year
- ------------- ----------------------------------------------------------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Per Million BTU - Coal 100.685(cent) 100.015(cent) 105.600(cent) 112.250(cent) 117.645(cent)
- Nuclear 46.552(cent) 48.803(cent) 47.472(cent) 47.499(cent) 48.592(cent)
- System 89.833(cent) 90.378(cent) 92.816(cent) 96.596(cent) 101.590(cent)
Per kWh of Steam Generation .958(cent) .968(cent) .979(cent) 1.024(cent) 1.068(cent)
</TABLE>
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.
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<PAGE>
Coal. Because of uncertainties of supply due to potential work stoppages,
equipment breakdowns and other factors, the Registrant has a policy of
maintaining a coal inventory consistent with its expected burn practices.
Nuclear. The components of the nuclear fuel cycle required for nuclear
generating units are as follows: (1) uranium; (2) conversion of uranium into
uranium hexafluoride; (3) enrichment of uranium hexafluoride; (4) conversion of
enriched uranium hexafluoride into uranium dioxide and the fabrication into
nuclear fuel assemblies; and (5) disposal and/or reprocessing of spent nuclear
fuel.
The Registrant has agreements and/or inventories to fulfill its Callaway
Nuclear Plant needs for uranium, enrichment, fabrication and conversion services
through 2002. Additional contracts will have to be entered into in order to
supply nuclear fuel during the remainder of the life of the Plant, at prices
which cannot now be accurately predicted. The Callaway Plant normally requires
refueling at 18-month intervals, with the next regular refueling presently
scheduled for the spring of 2001.
Under the Nuclear Waste Policy Act of 1982, the U. S. Department of Energy
(DOE) is responsible for the permanent storage and disposal of spent nuclear
fuel. DOE currently charges one mill per nuclear generated kilowatt-hour sold
for future disposal of spent fuel. Electric rates charged to customers provide
for recovery of such costs. DOE is not expected to have its permanent storage
facility for spent fuel available until at least 2015. The Registrant has
sufficient storage capacity at the Callaway site until 2020 and has the
capability for additional storage capacity through the licensed life of the
plant in 2024. The delayed availability of the DOE's disposal facility is not
expected to adversely affect the continued operation of Callaway Plant.
For additional information on the Registrant's "Fuel Supply", see "Results
of Operations" in "Management's Discussion and Analysis of Financial Condition
and Results of Operations" under Item 7 herein and Notes 12 and 13 to the "Notes
to Financial Statements" under Item 8 herein.
REGULATION
The Registrant is subject to regulation by the Securities and Exchange
Commission and, as a subsidiary of Ameren, is subject to the provisions of the
Public Utility Holding Company Act of 1935. The Registrant is subject to
regulation by the MoPSC and the ICC as to rates, service, accounts, issuance of
equity securities, issuance of debt having a maturity of more than twelve
months, mergers, and various other matters. The Registrant is also subject to
regulation by the FERC as to rates and charges in connection with the
transmission of electric energy in interstate commerce and the sale of such
energy at wholesale in interstate commerce, mergers, and certain other matters.
Authorization to issue debt having a maturity of twelve months or less is
obtained from the Securities and Exchange Commission.
For information on regulatory matters in these jurisdictions, including the
current status of electric utility restructuring in Illinois and Missouri, see
"Liquidity and Capital Resources" and "Electric Industry Restructuring" in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" under Item 7 herein and Notes 1 and 2 to the "Notes to Financial
Statements" under Item 8 herein.
Operation of the Callaway Plant is subject to regulation by the Nuclear
Regulatory Commission. The Registrant's Facility Operating License for the
Callaway Plant expires on October 18, 2024. The Registrant's Osage hydroelectric
plant and its Taum Sauk pumped-storage hydro plant, as licensed projects under
the Federal Power Act, are subject to certain federal regulations affecting,
among other things, the general operation and maintenance of the projects. The
Registrant's license for the Osage Plant expires on February 28, 2006, and its
license for the Taum Sauk Plant expires on June 30, 2010. The Registrant's
Keokuk Plant and dam located in the Mississippi River between Hamilton, Illinois
and Keokuk, Iowa, are operated under authority, unlimited in time, granted by an
Act of Congress in 1905.
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<PAGE>
The Registrant is regulated, in certain of its operations, by air and water
pollution and hazardous waste regulations at the city, county, state and federal
levels. The Registrant is in substantial compliance with such existing
regulations.
Environmental Issues. See "Liquidity and Capital Resources" in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" under Item 7 herein and Note 12 to the "Notes to Financial
Statements" under Item 8 herein for a discussion of environmental issues.
INDUSTRY ISSUES
The Registrant is facing issues common to the electric and gas utility
industries which have emerged during the past several years. These issues
include: the potential for more intense competition and for changing the
structure of regulation; changes in the structure of the industry as a result of
changes in federal and state laws, including the formation of unregulated
generating entities; on-going consideration of additional changes of the
industry by federal and state authorities; continually developing environmental
laws, regulations and issues, including proposed new air quality standards;
public concern about the siting of new facilities; proposals for demand side
management programs; public concerns about nuclear decommissioning and the
disposal of nuclear wastes; and global climate issues. The Registrant is
monitoring these issues and is unable to predict at this time what impact, if
any, these issues will have on its operations, financial condition, or
liquidity.
For additional information on certain of these issues, see "Liquidity and
Capital Resources" and "Electric Industry Restructuring" in Management's
Discussion and Analysis of Financial Condition and Results of Operations" under
Item 7 herein and Notes 2, 12 and 13 to the "Notes to Financial Statements"
under Item 8 herein.
Year 2000 Issue. The Year 2000 Issue relates to how dates are stored and
used in computer systems, applications, and embedded systems. As the century
date change occurred, certain date-sensitive systems had to recognize and
properly treat the year as 2000 and not as 1900. This inability to recognize and
properly treat the year as 2000 could have caused these systems to process
critical financial and operational information incorrectly. The Registrant
encountered no significant problems associated with the Year 2000 Issue at
year-end. For information on this issue, see "Year 2000 Issue" in "Management's
Discussion and Analysis of Financial Condition and Results of Operations" under
Item 7 herein.
ITEM 2. PROPERTIES.
In planning its construction program, the Registrant is presently utilizing
a forecast of kilowatthour sales growth of approximately 2.0% and peak load
growth of 1.4%, each compounded annually, and is providing for a minimum reserve
margin of approximately 15% above its anticipated peak load requirements.
The Registrant is a member of one of the ten regional electric reliability
councils organized for coordinating the planning and operation of the nation's
bulk power supply - MAIN (Mid-America Interconnected Network) operating
primarily in Wisconsin, Illinois and Missouri. The Registrant's bulk power
system is operated as an Ameren-wide control area and transmission system under
the FERC approved Joint Dispatch Agreement between the Registrant and
AmerenCIPS. Ameren has interconnections for transmission service and the
exchange of electric energy, directly and through the facilities of others, with
more than twenty power suppliers.
The Registrant has also received regulatory approvals to join the Midwest
Independent System Operator (Midwest ISO) which will operate electric
transmission systems and maintain system reliability and security for its
members. For a discussion of the Midwest ISO which is expected to be operational
in the year 2001, see "Electric Industry Restructuring" in Management's
Discussion and
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<PAGE>
Analysis of Financial Condition and Results of Operations" under Item 7 herein
and Note 2 to the "Notes to Financial Statements" under Item 8 herein.
The Registrant owns 40% of the capital stock of Electric Energy, Inc.
("EEI"), and its affiliate, AmerenCIPS, owns 20% of such stock. The balance is
held by two other sponsoring com- panies -- Kentucky Utilities Company ("KU"),
and Illinova Generating ("IG"). EEI owns and operates a generating plant with a
nominal capacity of 1,000 mW. 50% of the plant's output is committed to the
Paducah Project of the DOE, 20% to KU, 15% to AmerenUE, and 7.5% each to IG and
AmerenCIPS.
As of December 31, 1999, the Registrant owned approximately 3,300 circuit
miles of electric transmission lines. The Registrant also owned 2,800 miles of
gas mains and three propane-air gas plants used to supplement the available
pipeline supply of natural gas during periods of abnormally high demands. Other
properties of the Registrant include distribution lines, underground cable,
steam distribution facilities in Jefferson City, Missouri and office buildings,
warehouses, garages and repair shops.
The Registrant has fee title to all principal plants and other important
units of property, or to the real property on which such facilities are located
(subject to mortgage liens securing outstanding indebtedness of the Registrant
and to permitted liens and judgment liens, as defined), except that (i) a
portion of the Osage Plant reservoir, certain facilities at the Sioux Plant,
certain of the Registrant's substations and most of its transmission and
distribution lines and gas mains are situated on lands occupied under leases,
easements, franchises, licenses or permits; (ii) the United States and/or the
State of Missouri own, or have or may have, paramount rights to certain lands
lying in the bed of the Osage River or located between the inner and outer
harbor lines of the Mississippi River, on which certain generating and other
properties of the Registrant are located; and (iii) the United States and/or
State of Illinois and/or State of Iowa and/or City of Keokuk, Iowa own, or have
or may have, paramount rights with respect to, certain lands lying in the bed of
the Mississippi River on which a portion of the Registrant's Keokuk Plant is
located.
Substantially all of the Registrant's property and plant is subject to the
direct first lien of an Indenture of Mortgage and Deed of Trust dated June 15,
1937, as amended and supplemented.
The following table sets forth information with respect to the Registrant's
generating facilities and capability at the time of the expected 2000 peak.
Energy Gross Kilowatt
Source Plant Location Installed Capability
------ ----- -------- --------------------
Coal Labadie Franklin County, MO 2,400,000
Rush Island Jefferson County, MO 1,224,000
Sioux St. Charles County, MO 1,006,000
Meramec St. Louis County, MO 859,000
------------
Total Coal 5,489,000
Nuclear Callaway Callaway County, MO 1,181,000
Hydro Osage Lakeside, MO 212,000
Keokuk Keokuk, IA 126,000
------------
Total Hydro 338,000
Oil and Venice Venice, IL 441,000
Natural Other Various 424,000*
------------
Gas Total Oil and
Natural Gas 865,000
Pumped-
storage Taum Sauk Reynolds County, MO 440,000
------------
TOTAL 8,313,000
===========
* Includes 48,000 gross kilowatt installed capability of a new combustion
turbine generator scheduled for service before the expected 2000 peak.
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ITEM 3. LEGAL PROCEEDINGS.
The Registrant is involved in legal and administrative proceedings before
various courts and agencies with respect to matters arising in the ordinary
course of business, some of which involve substantial amounts. Management
believes that the final disposition of these proceedings will not have a
material adverse effect on its financial position, results of operations or
liquidity.
For additional information on legal and administrative proceedings, see
"Electric Industry Restructuring" in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" under Item 7 herein and Notes 2
and 12 to the "Notes to Financial Statements" under Item 8 herein.
_____________________________
Statements made in this report which are not based on historical facts, are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
"forward-looking" statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions,
financial performance and the Year 2000 Issue. In connection with the "Safe
Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the
Registrant is providing this cautionary statement to identify important factors
that could cause actual results to differ materially from those anticipated. The
following factors, in addition to those discussed elsewhere in this report and
in subsequent securities filings, could cause results to differ materially from
management expectations as suggested by such "forward-looking" statements: the
effects of regulatory actions; changes in laws and other governmental actions;
the impact on the Registrant of current regulations related to the phasing-in of
the opportunity for some customers to choose alternative energy suppliers in
Illinois; the effects of increased competition in the future due to, among other
things, deregulation of certain aspects of the Registrant's business at both the
state and Federal levels; future market prices for fuel and purchased power,
electricity, and natural gas, including the use of financial instruments;
average rates for electricity in the Midwest; business and economic conditions;
interest rates; weather conditions; fuel prices and availability; generation
plant performance; the impact of current environmental regulations on utilities
and generating companies and the expectation that more stringent requirements
will be introduced over time, which could potentially have a negative financial
effect; monetary and fiscal policies; future wages and employee benefits costs;
and legal and administrative proceedings.
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<PAGE>
INFORMATION REGARDING EXECUTIVE OFFICERS REQUIRED BY ITEM 401(b) OF
REGULATION S-K:
Age At Date First Elected
Name 12/31/99 Present Position or Appointed
Charles W. Mueller 61 President, 7/1/93
Chief Executive Officer 1/1/94
and Director 6/11/93
Donald E. Brandt 45 Senior Vice President 7/1/88
and Director 4/28/98
Daniel F. Cole 46 Senior Vice President 7/12/99
Thomas F. Voss 52 Senior Vice President 6/1/99
Warner L. Baxter 38 Vice President, 5/1/98
Controller and 8/1/96
Director 4/22/99
William J. Carr 62 Vice President 10/1/88
Michael J. Montana 53 Vice President 7/1/88
Charles D. Naslund 47 Vice President 2/1/99
Garry L. Randolph 51 Vice President 3/1/91
William C. Shores 61 Vice President 7/1/88
Steven R. Sullivan 39 Vice President, General Counsel 7/1/98
and Secretary 9/1/98
Jerre E. Birdsong 45 Treasurer 7/1/93
All officers are elected or appointed annually by the Board of Directors
following the election of such Board at the annual meeting of stockholders held
in April. Except for Messrs. Baxter and Sullivan, each of the above-named
executive officers has been employed by the Registrant for more than five years
in executive or management positions. Mr. Baxter was previously employed by
PricewaterhouseCoopers LLP. Mr. Sullivan was previously employed by Anheuser
Busch Companies, Inc.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
There is no market for the Registrant's Common Stock since all shares are
owned by its parent, Ameren.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
For the Years Ended
December 31 (In Thousands) 1999 1998 1997 1996 1995
- ------------------------- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Operating revenues $2,527,166 $2,382,071 $2,287,333 $2,260,364 $2,242,364
Operating income 443,268 428,183 448,827 428,314 441,896
Net income 349,252 320,070 301,655 304,876 314,107
Preferred stock dividends 8,817 8,817 8,817 13,249 13,250
Net income after preferred
stock dividends 340,435 311,253 292,838 291,627 300,857
Common stock dividends 328,674 259,599 259,395 256,331 250,714
As of December 31,
Total assets $7,043,562 $6,829,864 $6,802,285 $6,870,809 $6,754,469
Long-term debt 1,882,601 1,674,311 1,846,482 1,798,671 1,763,613
Total common stockholder's equity 2,433,682 2,424,125 2,387,454 2,354,801 2,319,197
</TABLE>
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<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
Union Electric Company (AmerenUE or the Registrant) is a subsidiary of Ameren
Corporation (Ameren), a holding company registered under the Public Utility
Holding Company Act of 1935 (PUHCA). In December 1997, AmerenUE and CIPSCO
Incorporated (CIPSCO) combined to form Ameren, with AmerenUE and CIPSCO's
subsidiaries, Central Illinois Public Service Company (AmerenCIPS) and CIPSCO
Investment Company (CIC), becoming subsidiaries of Ameren (the Merger).
RESULTS OF OPERATIONS
Earnings
Earnings for 1999, 1998, and 1997 were $340 million, $311 million, and $293
million, respectively. Earnings fluctuated due to many conditions, primarily:
sales growth, weather variations, credits to electric customers, electric rate
reductions, gas rate increases, competitive market forces, fluctuating operating
costs (including Callaway Nuclear Plant refueling outages), merger-related
expenses, changes in interest expense, changes in income and property taxes, a
targeted employee separation plan and an extraordinary charge.
In 1998, the Registrant recorded a nonrecurring charge to earnings in connection
with a targeted separation plan it offered to employees in July 1998. That
charge reduced earnings $11 million, net of income taxes (see Note 4 - Targeted
Separation Plan under Notes to Financial Statements for further information). In
addition, the Registrant recorded an extraordinary charge to earnings in the
fourth quarter of 1997 for the write-off of generation-related regulatory assets
and liabilities of the Registrant's Illinois retail electric business as a
result of electric industry restructuring legislation enacted in Illinois in
December 1997. The write-off reduced earnings $27 million, net of income taxes
(see Note 2 - Regulatory Matters under Notes to Financial Statements for further
information.)
The significant items affecting revenues, expenses and earnings for the years
ended December 31, 1999, 1998, and 1997 are detailed in the following pages.
Electric Operations
Electric Revenues Variations from Prior Year
- ----------------------------------------------------------------------
(Millions of Dollars) 1999 1998 1997
- ----------------------------------------------------------------------
Rate variations $ (9) $ (8) $--
Credit to customers 7 (24) 28
Effect of abnormal weather (37) 48 4
Growth and other 47 48 1
Interchange sales 136 38 (5)
- ----------------------------------------------------------------------
$ 144 $ 102 $ 28
- ----------------------------------------------------------------------
Electric revenues for 1999 increased $144 million, compared to 1998, primarily
due to a 5% increase in total kilowatthour sales. This increase was primarily
driven by a 75% increase in interchange sales, due to strong marketing efforts.
Also contributing to the revenue increase was a decrease in the credit to
Missouri electric customers (see Note 2 - Regulatory Matters under Notes to
Financial Statements for further information). Partially offsetting these
increases, weather-sensitive residential sales decreased 2%, commercial sales
remained flat, while industrial sales decreased 2%.
Electric revenues for 1998 increased $102 million, compared to 1997. Revenues
increased primarily due to higher sales to retail customers within the
Registrant's service territory, as a result of warm summer weather and growth in
the service area, and increased interchange revenues, primarily due to favorable
market conditions. These increases were partially offset by a rate decrease and
an increase in estimated credits to Missouri electric customers, as well as a 5%
rate decrease for Illinois electric customers (see Note 2 - Regulatory Matters
under Notes to Financial Statements for further information). Weather-sensitive
residential and commercial sales increased 6% and 4%, respectively, while
industrial sales grew 1%. Interchange sales increased 7%, primarily from
AmerenCIPS.
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<PAGE>
The increase in 1997 electric revenues was primarily due to a lower Missouri
customer credit recorded in 1997. Residential sales remained flat while
interchange sales decreased 5%. Commercial and industrial sales were 1% and 3%
higher, respectively.
Fuel and Purchased Power Variations from Prior Year
- --------------------------------------------------------------------------------
(Millions of Dollars) 1999 1998 1997
- --------------------------------------------------------------------------------
Fuel:
Generation $ (2) $ 24 $ 17
Price (2) (10) (15)
Generation efficiencies and other (2) 5 (1)
Purchased power 132 11 (14)
- --------------------------------------------------------------------------------
$ 126 $ 30 $ (13)
- --------------------------------------------------------------------------------
The $126 million increase in fuel and purchased power costs for 1999, compared
to 1998, was primarily driven by increased power purchases resulting from higher
sales volume.
The $30 million increase in fuel and purchased power costs for 1998, compared to
1997, was primarily driven by increased generation due to higher sales volume,
joint dispatch, and higher purchased power prices, partially offset by lower
fuel prices. Upon consummation of the Merger, AmerenUE and AmerenCIPS began
jointly dispatching generation, therefore allowing Ameren to utilize the most
cost efficient plants of both operating companies to serve customers in either
service territory. Fuel and purchased power costs decreased in 1997 primarily
due to reduced purchased power costs, resulting from relatively flat native load
sales coupled with greater generation, as well as lower fuel prices.
Gas Operations
Gas revenues in 1998 decreased $7 million compared to 1997, primarily due to an
8% decline in retail sales resulting from mild weather and lower gas costs
reflected in the Company's purchased gas adjustment clause. Weather-sensitive
residential and commercial sales decreased 10% and 6%, respectively, and
industrial sales declined 2%. These decreases were partially offset by benefits
realized from an annual $12 million Missouri gas rate increase effective
February 1998 (see Note 2 - Regulatory Matters under Notes to Financial
Statements for further information).
Gas costs in 1999 increased $5 million compared to 1998, primarily due to higher
gas prices partially offset by lower total sales. Gas costs in 1998 declined $14
million compared to 1997, primarily due to lower sales and lower gas prices.
Other Operating Expenses
Other operating expense variations in 1997 through 1999 reflected recurring
factors such as growth, inflation, labor and benefit increases, in addition to
the capitalization of certain costs as a result of a Missouri Public Service
Commission (MoPSC) Order and a charge for the targeted separation plan (TSP), as
discussed below.
In 1998, Ameren announced plans to reduce its other operating expenses,
including plans to eliminate approximately 400 employee positions by mid-1999
through a hiring freeze and the TSP. During the third quarter of 1998, the
Registrant recorded a nonrecurring, pretax charge of $18 million representing
its share of costs incurred to implement the TSP. The elimination of these
positions, exclusive of the nonrecurring charge, reduced the Registrant's
operating expenses approximately $11 million in 1998, and approximately $15
million in 1999, and is expected to reduce the Registrant's operating expenses
by approximately $14 million to $18 million each year thereafter. See Note 4 -
Targeted Separation Plan under Notes to Financial Statements for further
information.
The $28 million decrease in other operating expenses in 1999, compared to 1998,
was primarily due to the 1998 charge for the TSP and related reduced workforce,
decreases in injuries and damages expense (due to claims experience) and
information system-related costs and the capitalization of certain costs
(including computer software costs) that had previously been expensed for the
Registrant's Missouri electric operations (see Note 2 - Regulatory Matters under
Notes to Financial Statements for further information).
The $57 million increase in other operating expenses in 1998, compared to 1997,
was primarily due to the charge for the TSP and increases in injuries and
damages expense and information system-related costs. In 1997, other operating
expense increased $26 million primarily due to increased information
system-related expenses.
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Maintenance expenses increased $25 million in 1999, compared to 1998 primarily
due to increased power plant maintenance and tree trimming activity. The
expenses incurred for the 35-day refueling outage in the fall of 1999 at the
Callaway Nuclear Plant were comparable to those for the 31-day spring 1998
refueling outage. No refueling outage is scheduled for 2000. In 1998,
maintenance expenses increased $5 million due to the scheduled spring refueling
outage at the Callaway Nuclear Plant; partially offset by less scheduled fossil
plant maintenance. In 1997, maintenance expenses decreased $6 million, primarily
a result of reduced Callaway Plant expenses due to the absence of a refueling
outage in 1997, offset in part by increased scheduled fossil plant maintenance.
Depreciation and amortization expense increased $12 million in 1998 and $7
million in 1997, due to increased depreciable property and amortization of the
Missouri portion of merger-related costs which were recorded as a regulatory
asset upon Merger close under the conditions of the Missouri Public Service
Commission (MoPSC) order approving the Merger.
Taxes
Income tax expense from operations increased $13 million in 1999, compared to
1998, due to higher pretax income. Income tax expense from operations increased
$25 million in 1998, compared to 1997, due to higher pretax income and a higher
effective tax rate. Income tax expense from operations decreased $5 million in
1997 primarily due to a lower effective tax rate.
Other tax expense decreased $8 million in 1999, compared to 1998, primarily due
to a decrease in gross receipts taxes related to the Registrant's Illinois
jurisdiction. This decrease is the result of the restructuring of the Illinois
public utility tax whereby gross receipts taxes are no longer recorded as
electric revenues and gross receipts tax expense.
Other Income and Deductions
Miscellaneous, net increased $4 million for 1998, compared to 1997, due to
increased interest income and gains on the sale of property. Miscellaneous, net
increased $12 million for 1997, primarily due to the capitalization of certain
merger-related costs in 1997.
Interest
Interest expense decreased $10 million in 1999, compared to 1998, primarily due
to lower debt outstanding during the year and a decrease in other interest
expense. Interest expense decreased $9 million for 1998, compared to 1997, due
to lower interest rates and a decrease in other interest expense. Interest
expense increased $6 million for 1997 primarily due to higher debt outstanding
during the year at higher interest rates.
Balance Sheet
The $12 million decrease in trade accounts receivable and unbilled revenue at
December 31, 1999, compared to 1998, was due to lower sales and revenues in
November and early December 1999, compared to the comparable time period in
1998. The $166 million increase in intercompany notes receivable was due to
funds invested in a regulated money pool (see Note 3 - Related Party
Transactions under Notes to Financial Statements for further information.)
The $54 million increase in other current liabilities was primarily due to the
timing of credit payments to electric customers in the Registrant's Missouri and
Illinois jurisdictions, as well as an increase in a liability for an estimated
rate reduction for Missouri electric customers retroactive to September 1, 1998
(see Note 2 - Regulatory Matters under Notes to Financial Statements for further
information). The remaining variance is the result of the timing of various
payments to suppliers.
The $37 million increase in other deferred credits and liabilities was primarily
due to Callaway Plant decommissioning costs.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $725 million for 1999, compared to
$651 million and $602 million in 1998 and 1997, respectively.
Cash flows used in investing activities totaled $419 million, $231 million, and
$284 million for the years ended December 31, 1999, 1998 and 1997, respectively.
Expenditures in 1999 for constructing new or to improve existing facilities and
purchasing rail cars were $246 million. In addition, the Company spent $22
million to acquire nuclear fuel.
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Capital expenditures are expected to approximate $297 million in 2000. For the
five-year period 2000-2004, construction expenditures are estimated at $1.6
billion. This estimate includes capital expenditures that will be incurred by
the Registrant to meet new air quality standards for ozone and particulate
matter, as discussed below.
Title IV of the Clean Air Act Amendments of 1990 requires the Registrant to
significantly reduce total annual sulfur dioxide (SO2) and nitrogen oxide (NOx)
emissions by the year 2000. By switching to low-sulfur coal, early banking of
emission credits and installing advanced NOx reduction combustion technology,
the Registrant is meeting these requirements.
In July 1997, the United States Environmental Protection Agency (EPA) issued
regulations revising the National Ambient Air Quality Standards for ozone and
particulate matter. In May 1999, the U.S. Court of Appeals for the District of
Columbia remanded the regulations back to the EPA for review. Litigation
regarding appeals of these regulations is ongoing. New ambient standards may
result in significant additional reductions in SO2 and NOx emissions from the
Registrant's power plants by 2007. At this time, the Registrant is unable to
predict the ultimate impact of these revised air quality standards on its future
financial condition, results of operations or liquidity.
In an attempt to lower ozone levels across the eastern United States, the EPA
issued the implementation of regulations in September 1998 to reduce NOx
emissions from coal-fired boilers and other sources in 22 states, including
Missouri (where all of the Registrant's coal-fired power plant boilers are
located). The proposed regulations mandate a 75% reduction from 1990 levels by
the year 2003 and require states to develop plans to reduce NOx emissions to
help alleviate ozone problem areas. The NOx emissions reductions already
achieved on several of the Registrant's coal-fired power plants will help to
reduce the costs of compliance with these regulations. However, preliminary
analysis of the regulations indicate that selective catalytic reduction
technology may be required for some of the Registrant's units, as well as other
additional controls.
In March 2000, the U.S. Court of Appeals for the District of Columbia
substantially upheld the proposed NOx regulations but remanded portions of them
to the EPA for further consideration. The implementation date of the regulations
is uncertain and further legal challenge is possible. Assuming an implementation
date of 2003, the Registrant currently estimates that its additional capital
expenditures to comply with the final NOx regulations could range from $125
million to $150 million. Associated operations and maintenance expenditures
could increase $5 million to $8 million annually, beginning in 2003. The
Registrant is exploring alternatives to comply with these new regulations in
order to minimize, to the extent possible, its capital costs and operating
expenses. The Registrant is unable to predict the outcome of the litigation, the
regulation implementation date and the ultimate impact of these standards on its
future financial condition, results of operations or liquidity.
In November 1998, the United States signed an agreement with numerous other
countries (the Kyoto Protocol) containing certain environmental provisions,
which would require decreases in greenhouse gases in an effort to address the
"global warming" issue. The Kyoto Protocol has not been ratified by the United
States Senate. Implementation of the Kyoto Protocol in its present form would
likely result in significantly higher capital costs and operations and
maintenance expenses by the Registrant. At this time, the Registrant is unable
to determine the impact of these proposals on the Registrant's future financial
condition, results of operations or liquidity.
See Note 13 - Callaway Nuclear Plant under Notes to Financial Statements for a
discussion of Callaway Plant decommissioning costs.
Cash flows used in financing activities were $236 million for 1999, compared to
$376 million and $320 million for 1998 and 1997, respectively. The Registrant's
principal financing activities during 1999 included the redemption of $100
million of long-term debt, the issuance of $152 million of long-term debt, and
the payment of dividends.
The Registrant plans to continue utilizing short-term debt to support normal
operations and other temporary requirements. The Registrant is authorized by the
Securities and Exchange Commission (SEC) under PUHCA to have up to $1 billion of
short-term unsecured debt instruments outstanding at any one time. Short-term
borrowings consist of bank loans (maturities generally on an overnight basis)
and commercial paper (maturities generally within 10 to 45 days). At December
31, 1999, the Registrant had committed bank lines of credit aggregating $150
million, all of which was unused and available at such date, which make
available interim financing at various rates of interest based on LIBOR, the
bank certificate of deposit rate or other options. The lines of credit are
renewable annually at various dates throughout the year. At year-end, the
Registrant had no outstanding short-term borrowings.
The Registrant also has a bank credit agreement due 2002, which permits the
borrowing of up to $300 million on a long-term basis, all of which was unused,
and $148 million was available at December 31, 1999. In addition, the Registrant
has the ability to borrow up to approximately $530 million from Ameren or
AmerenCIPS through a
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regulated money pool agreement. The regulated money pool was established to
coordinate and provide for certain short-term cash and working capital
requirements and is administered by Ameren Services Company, another subsidiary
of Ameren. Interest is calculated at varying rates of interest depending on the
composition of internal and external funds in the regulated money pool. At
December 31, 1999, the Registrant had no intercompany borrowings outstanding and
$402 million available through the regulated money pool. See Note 8 - Short-Term
Borrowings under Notes to Financial Statements for further discussion.
Additionally, the Registrant has a lease agreement that provides for the
financing of nuclear fuel. At December 31, 1999, the maximum amount that could
be financed under the agreement was $120 million. Cash used in financing for
1999 included issuances under the lease for nuclear fuel of $65 million, offset
in part by $15 million of redemptions. At December 31, 1999, $116 million was
financed under the lease. See Note 6 - Nuclear Fuel Lease under Notes to
Financial Statements for further information.
The Registrant, in the ordinary course of business, explores opportunities to
reduce its costs in order to remain competitive in the marketplace. Areas where
the Registrant focuses its review include, but are not limited to, labor costs
and fuel supply costs. In the labor area, the Registrant has recently reached
agreements with some of the Registrant's collective bargaining units which will
permit it to manage its labor costs and practices effectively in the future (see
Note 12 - Commitments and Contingencies under Notes to Financial Statements for
further discussion.) The Registrant also explores alternatives to effectively
manage the size of its workforce. These alternatives include utilizing hiring
freezes, outsourcing and offering employee separation packages. In the fuel
supply area, the Registrant explores alternatives to effectively manage its
overall fuel costs. These alternatives include diversifying fuel sources for use
at the Registrant's fossil power plants, as well as restructuring or terminating
existing contracts with suppliers.
Certain of these reduction alternatives could result in additional investments
being made at the Registrant's power plants in order to utilize different types
of coal, or could require nonrecurring payments of employee separation benefits
or nonrecurring payments to restructure or terminate existing fuel contracts
with a supplier. Management is unable to predict which (if any), and to what
extent, these alternatives to reduce its overall cost structure will be
executed. Management is unable to determine the impact of these actions on the
Registrant's future financial position, results of operations or liquidity.
RATE MATTERS
See Note 2 - Regulatory Matters under Notes to Financial Statements for a
discussion of rate matters.
ELECTRIC INDUSTRY RESTRUCTURING
Steps taken and being considered at the federal and state levels continue to
change the structure of the electric industry and utility regulation, and
encourage increased competition. At the federal level, the Energy Policy Act of
1992 reduced various restrictions on the operation and ownership of independent
power producers and gave the Federal Energy Regulatory Commission (FERC) the
authority to order electric utilities to provide transmission access to third
parties.
In April 1996, the FERC issued Order 888 and Order 889, which are intended to
promote competition in the wholesale electric market. The FERC requires
transmission-owning public utilities, such as the Registrant, to provide
transmission access and service to others in a manner similar and comparable to
that which the utilities have by virtue of ownership. Order 888 requires that a
single tariff be used by the utility in providing transmission service. Order
888 also provides for the recovery of strandable costs, under certain
conditions, related to the wholesale business.
Order 889 established the standards of conduct and information requirements that
transmission owners must adhere to in doing business under the open access rule.
Under Order 889, utilities must obtain transmission service for their own use in
the same manner their customers will obtain service, thus mitigating market
power through control of transmission facilities. In addition, under Order 889,
utilities must separate their merchant function (buying and selling wholesale
power) from their transmission and reliability functions.
The Registrant believes that Order 888 and Order 889, which relate to its
wholesale business, will not have a material adverse effect on its financial
condition, results of operations or liquidity.
In 1998, the Registrant joined a group of companies that support the formation
of the Midwest Independent System Operator (Midwest ISO). An ISO operates, but
does not own, electric transmission systems and maintains system
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reliability and security, while alleviating pricing issues associated with the
"pancaking" of rates. The Midwest ISO would be regulated by the FERC. Thirteen
transmission-owning utilities have joined the Midwest ISO as of December 31,
1999. The FERC conditionally approved the formation of the Midwest ISO in
September 1998, and it is expected to be operational during the year 2001. The
MoPSC and the Illinois Commerce Commission (ICC) have authorized the Registrant
to join the Midwest ISO and to transfer control of its transmission facilities
to the Midwest ISO. The Midwest ISO covers 14 states, represents portions of
60,000 miles of transmission line and controls $8 billion of assets. The
Registrant believes that the operation of the Midwest ISO will not have a
material adverse effect on its financial condition, results of operations or
liquidity.
In December 1999, the FERC issued Order 2000 relating to Regional Transmission
Organizations (RTOs) that would meet certain characteristics such as size and
independence. Order 2000 calls on all transmission owners to join RTOs. In
particular, all public utilities that own, operate, or control interstate
transmission facilities must file with the FERC by October 15, 2000, a proposal
for an RTO, or alternatively a description of efforts by the utility to join an
RTO. The Registrant expects that its participation in the Midwest ISO will
satisfy the requirements of Order 2000.
Illinois
Certain states are considering proposals or have adopted legislation that will
promote competition at the retail level. In December 1997, the Governor of
Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997
(the Illinois Law) providing for electric utility restructuring in Illinois,
where approximately 6% of the Registrant's retail electric revenues are derived.
This legislation introduces competition into the supply of electric energy at
retail in Illinois.
Major provisions of the Illinois Law include the phasing-in through 2002 of
retail direct access, which allows customers to choose their electric generation
suppliers. The phase-in of retail direct access began on October 1, 1999, with
large commercial and industrial customers principally comprising the initial
group. The customers in this group represent approximately 6% of the
Registrant's total sales. As of December 31, 1999, the impact of retail direct
access on the Registrant's financial condition, results of operations or
liquidity was immaterial. Retail direct access will be offered to the remaining
commercial and industrial customers on December 31, 2000, and to residential
customers on May 1, 2002.
In addition, the Illinois Law included a 5% rate decrease for residential
customers that became effective in August 1998. This rate decrease reduced
electric revenues $1 million in 1999 compared to 1998 and is expected to impact
electric revenues by approximately $3 million annually, based on estimated
levels of sales and assuming normal weather conditions. (See Note 2 - Regulatory
Matters under Notes to Financial Statements for further information.) In 1998,
the Registrant eliminated its Uniform Fuel Adjustment Clause (FAC) as allowed by
the Illinois Law, which benefited shareholders in 1998 and 1999 and is expected
to benefit shareholders in the future (see Note 1 - Summary of Significant
Accounting Policies under Notes to Financial Statements for further
information). The Illinois Law contains a provision allowing for the potential
recovery of a portion of strandable costs, which represent costs that would not
be recoverable in a restructured environment, through a transition charge
collected from customers who choose an alternate electric supplier. In addition,
the Illinois Law contains a provision requiring a portion of excess earnings (as
defined under the Illinois Law) for the years 1998 through 2004 to be refunded
to customers.
In December 1997, after evaluating the impact of the Illinois Law, the
Registrant determined that it was necessary to write-off the generation-related
regulatory assets and liabilities of its Illinois retail electric business. This
extraordinary charge reduced 1997 earnings $27 million, net of income taxes. The
Registrant has also concluded that its remaining net generation-related assets
are not impaired for financial reporting purposes and that no plant writedowns
are necessary at this time. See Note 2 - Regulatory Matters under Notes to
Financial Statements for further information.
Missouri
In Missouri, where approximately 94% of the Registrant's retail electric
revenues are derived, a task force appointed by the MoPSC investigated electric
industry restructuring and competition. In 1998 the task force issued a report
to the MoPSC that addressed many of the restructuring issues, but did not
provide a specific recommendation or approach to restructure the industry. In
addition, in 1998, the MoPSC staff issued a proposed plan for restructuring
Missouri's electric industry. The staff's plan addressed a number of issues of
concern if the industry is restructured in Missouri. It also included a proposal
for less than full recovery of strandable costs. The staff's plan has not been
addressed by the MoPSC. A joint committee of the Missouri legislature is also
conducting hearings on these issues. Several restructuring bills were introduced
by the Missouri legislature in 1999 and 2000. The Registrant is unable to
predict the timing or ultimate outcome of electric industry restructuring in the
state of Missouri.
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Summary
In summary, the potential negative consequences associated with electric
industry restructuring could be significant and could include the impairment and
writedown of certain assets, including generation-related plant and net
regulatory assets, lower revenues, reduced profit margins and increased costs of
capital and operations expenses. The Registrant is actively taking steps to
mitigate these potential negative consequences. Most importantly, the Registrant
will continue to focus on cost control to ensure that it maintains a competitive
cost structure. In Missouri, the Registrant is actively involved in all major
deliberations taking place surrounding electric industry restructuring in an
effort to ensure that restructuring legislation, if any, contains an orderly
transition and is equitable to the Registrant's shareholders. The Registrant is
also actively involved in shaping the policies of the Midwest ISO to protect its
shareholders' interests. At this time, the Registrant is unable to predict the
ultimate impact of electric industry restructuring on the Registrant's future
financial condition, results of operations or liquidity.
YEAR 2000 ISSUE
The Year 2000 Issue relates to how dates are stored and used in computer
systems, applications, and embedded systems. As the century date change
occurred, certain date-sensitive systems had to recognize the year as 2000 and
not as 1900. This inability to recognize and properly treat the year as 2000
could have caused these systems to process critical financial and operational
information incorrectly. Management implemented a Year 2000 plan covering
Ameren, including AmerenUE, and briefed Ameren's Board of Directors about the
Year 2000 Issue and how it might have affected the Registrant. Ameren
encountered no significant problems associated with the Year 2000 Issue at
year-end. In addressing the Year 2000 Issue, Ameren incurred internal labor
costs as well as external consulting and other expenses to prepare for the new
century. As of December 31, 1999, Ameren had expended approximately $8 million
in external costs (consulting fees and related costs). The impact of the Year
2000 Issue on the Registrant's financial condition, results of operations or
liquidity was immaterial. Ameren will continue to monitor date-sensitive systems
as certain key dates occur throughout the year.
CONTINGENCIES
See Note 2 - Regulatory Matters, Note 12 - Commitments and Contingencies and
Note 13 - Callaway Nuclear Plant under Notes to Financial Statements for
material issues existing at December 31, 1999.
MARKET RISK RELATED TO FINANCIAL INSTRUMENTS AND COMMODITY INSTRUMENTS
Market risk represents the risk of changes in value of a financial instrument,
derivative or non-derivative, caused by fluctuations in market variables (e.g.
interest rates, equity prices, commodity prices, etc.). The following discussion
of the Registrant's risk management activities includes "forward-looking"
statements that involve risks and uncertainties. Actual results could differ
materially from those projected in the "forward-looking" statements. The
Registrant handles market risks in accordance with established policies, which
may include entering into various derivative transactions. In the normal course
of business, the Registrant also faces risks that are either non-financial or
non-quantifiable. Such risks principally include business, legal, operational,
and credit risk and are not represented in the following analysis.
Interest Rate Risk
The Registrant is exposed to market risk through changes in interest rates
through its issuance of both long-term and short-term variable-rate debt,
fixed-rate debt and commercial paper. The Registrant manages its interest rate
exposure by controlling the amount of these instruments it holds within its
total capitalization portfolio and by monitoring the effects of market changes
in interest rates.
If interest rates increase one percentage point in 2000, as compared to 1999,
the Registrant's interest expense would increase by approximately $6 million,
and net income would decrease by approximately $4 million. This amount has been
determined using the assumptions that the Registrant's outstanding variable-rate
debt and commercial paper, as of December 31, 1999, continued to be outstanding
throughout 2000, and that the average interest rates for these instruments
increased one percentage point over 1999. The model does not consider the
effects of the reduced level of potential overall economic activity that would
exist in such an environment. In the event of a significant change in interest
rates, management would likely take actions to further mitigate its exposure to
this market risk. However, due to the uncertainty of the specific actions that
would be taken and their possible effects, the sensitivity analysis assumes no
change in the Registrant's financial structure.
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Commodity Price Risk
The Registrant is exposed to changes in market prices for natural gas, fuel and
electricity. With regard to its natural gas utility business, the Registrant's
exposure to changing market prices is in large part mitigated by the fact that
the Registrant has a Purchased Gas Adjustment Clause (PGA) in place in both its
Missouri and Illinois jurisdictions. The PGA allows the Registrant to pass on to
its customers its prudently incurred costs of natural gas. With approval of the
MoPSC, the Registrant participated in an experimental program to control the
volatility of gas prices paid by its Missouri customers in the 1998-1999 winter
months through the purchase of financial instruments. This program concluded in
April 1999.
Since the Registrant does not have a provision similar to the PGA for its
electric operations, the Registrant has entered into several long-term contracts
with various suppliers to purchase coal and nuclear fuel to manage its exposure
to fuel prices. (See Note 12 - Commitments and Contingencies under Notes to
Financial Statements for further information). With regard to the Registrant's
exposure to commodity price risk for purchased power and excess electricity
sales, Ameren has established a subsidiary, AmerenEnergy, Inc., (AmerenEnergy),
whose primary responsibility includes managing market risks associated with
changing market prices for electricity purchased and sold on behalf of the
Registrant.
AmerenEnergy utilizes several techniques to mitigate its market risk for
electricity, including utilizing derivative financial instruments. A derivative
is a contract whose value is dependent on or derived from the value of some
underlying asset. The derivative financial instruments that AmerenEnergy is
allowed to utilize (which include forward contracts, futures contracts, and
option contracts) are dictated by a risk management policy, which has been
reviewed with the Auditing Committee of Ameren's Board of Directors. Compliance
with the risk management policy is the responsibility of a risk management
steering committee, consisting of Ameren officers and an independent risk
management officer at AmerenEnergy.
As of December 31, 1999, the fair value of derivative financial instruments
exposed to commodity price risk was immaterial. AmerenEnergy's primary use of
derivatives has been limited to transactions that are either risk-neutral or
that reduce price risk exposure of the Registrant.
Equity Price Risk
The Registrant maintains trust funds, as required by the Nuclear Regulatory
Commission and Missouri and Illinois state laws, to fund certain costs of
nuclear decommissioning (see Note 13 - Callaway Nuclear Plant under Notes to
Financial Statements for further information). As of December 31, 1999, these
funds were invested primarily in domestic equity securities, fixed-rate,
fixed-income securities, and cash and cash equivalents. By maintaining a
portfolio that includes long-term equity investments, the Registrant is seeking
to maximize the returns to be utilized to fund nuclear decommissioning costs.
However, the equity securities included in the Registrant's portfolio are
exposed to price fluctuations in equity markets, and the fixed-rate,
fixed-income securities are exposed to changes in interest rates. The Registrant
actively monitors its portfolio by benchmarking the performance of its
investments against certain indices and by maintaining, and periodically
reviewing, established target allocation percentages of the assets of its trusts
to various investment options. The Registrant's exposure to equity price market
risk is in large part mitigated due to the fact that the Registrant is currently
allowed to recover its decommissioning costs in its rates.
ACCOUNTING MATTERS
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS 133 establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities and requires
recognition of all derivatives as either assets or liabilities on the balance
sheet measured at fair value. The intended use of the derivatives and their
designation as either a fair value hedge, a cash flow hedge, or a foreign
currency hedge will determine when the gains or losses on the derivatives are to
be reported in earnings and when they are to be reported as a component of other
comprehensive income. In June 1999, the FASB issued SFAS No. 137, "Accounting
for Derivative Instruments and Hedging Activities--Deferral of the Effective
Date of FASB Statement No. 133," which delayed the effective date of SFAS 133 to
all fiscal quarters of all fiscal years, beginning after June 15, 2000. Earlier
application is still encouraged. The Registrant expects to adopt SFAS 133 in the
first quarter of 2001.
The Registrant is currently evaluating the impact of SFAS 133 on its financial
position and results of operations upon adoption. The Registrant's evaluation
includes reviewing existing derivative instruments and contracts to determine
the appropriate accounting for these items under SFAS 133. At this time,
management believes that adoption of SFAS 133 will not have a material impact on
the Registrant's financial position or results of operations
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upon adoption based on the derivative instruments which existed as of December
31, 1999. However, changing market conditions, the volume of future transactions
which may fall within the scope of SFAS 133, and potential amendments to SFAS
133 could change management's current assessment. As a result, SFAS 133 could
increase the volatility of the Registrant's future earnings and could be
material to the Registrant's financial position and results of operations upon
adoption.
EFFECTS OF INFLATION AND CHANGING PRICES
The Registrant's rates for retail electric and gas utility service are generally
regulated by the MoPSC and the ICC. Non-retail electric rates are regulated by
the FERC.
The current replacement cost of the Registrant's utility plant substantially
exceeds its recorded historical cost. Under existing regulatory practice, only
the historical cost of plant is recoverable from customers. As a result, cash
flows designed to provide recovery of historical costs through depreciation
might not be adequate to replace plants in future years. Regulatory practice has
been modified for the Registrant's generation portion of its business in its
Illinois jurisdiction and may be modified in the future for the Registrant's
Missouri jurisdiction (see Note 2 - Regulatory Matters under Notes to Financial
Statements for further information). In addition, the impact on common
stockholders is mitigated to the extent depreciable property is financed with
debt that is repaid with dollars of less purchasing power.
In the Illinois retail jurisdiction, the cost of fuel for electric generation,
which was previously reflected in billings to customers through a Uniform Fuel
Adjustment Clause, has been added to base rates as provided for in the Illinois
Law (see Note 2 - Regulatory Matters under Notes to Financial Statements for
further information). In the Missouri retail jurisdiction, the cost of fuel for
electric generation is reflected in base rates with no provision for changes to
be made through a fuel adjustment clause. In Illinois and Missouri, changes in
gas costs are generally reflected in billings to customers through Purchased Gas
Adjustment Clauses.
Inflation continues to be a factor affecting operations, earnings, stockholders'
equity and financial performance.
SAFE HARBOR STATEMENT
Statements made in this report which are not based on historical facts, are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
"forward-looking" statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions,
financial performance and the Year 2000 Issue. In connection with the "Safe
Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the
Registrant is providing this cautionary statement to identify important factors
that could cause actual results to differ materially from those anticipated. The
following factors, in addition to those discussed elsewhere in this report and
in subsequent securities filings, could cause results to differ materially from
management expectations as suggested by such "forward-looking" statements: the
effects of regulatory actions; changes in laws and other governmental actions;
the impact on the Registrant of current regulations related to the phasing-in of
the opportunity for some customers to choose alternative energy suppliers in
Illinois; the effects of increased competition in the future due to, among other
things, deregulation of certain aspects of the Registrant's business at both the
state and Federal levels; future market prices for fuel and purchased power,
electricity, and natural gas, including the use of financial instruments;
average rates for electricity in the Midwest; business and economic conditions;
interest rates; weather conditions; fuel prices and availability; generation
plant performance; the impact of current environmental regulations on utilities
and generating companies and the expectation that more stringent requirements
will be introduced over time, which could potentially have a negative financial
effect; monetary and fiscal policies; future wages and employee benefits costs;
and legal and administrative proceedings.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information required to be reported by this item is included under "Market
Risk Related to Financial Instruments and Commodity Instruments" in
"Management's Discussion and Analysis of Financial Conditions and Results of
Operations" under Item 7 herein.
-16-
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------
To the Board of Directors and Shareholders
of Union Electric Company
In our opinion, the financial statements listed in the index appearing under
Item 14(a)(1) on Page 38 present fairly, in all material respects, the financial
position of Union Electric Company at December 31, 1999 and 1998, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1999 in conformity with auditing standards
generally accepted in the United States. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with accounting principles generally
accepted in the United States, which require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 2, 2000
-17-
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
UNION ELECTRIC COMPANY
BALANCE SHEET
(Thousands of Dollars, Except Shares)
<TABLE>
<CAPTION>
December 31, December 31,
ASSETS 1999 1998
- ------ ---- ----
<S> <C> <C>
Property and plant, at original cost:
Electric $9,210,122 $8,975,542
Gas 223,789 209,556
Other 37,156 35,994
---------- ----------
9,471,067 9,221,092
Less accumulated depreciation and amortization 4,320,910 4,110,250
---------- ----------
5,150,157 5,110,842
Construction work in progress:
Nuclear fuel in process 88,830 108,294
Other 92,833 127,168
---------- ----------
Total property and plant, net 5,331,820 5,346,304
---------- ----------
Investments and other assets:
Nuclear decommissioning trust fund 186,760 161,877
Other 59,748 45,688
---------- ----------
Total investments and other assets 246,508 207,565
---------- ----------
Current assets:
Cash and cash equivalents 117,308 47,337
Accounts receivable - trade (less allowance for doubtful
accounts of $5,308 and $6,678, respectively) 151,399 143,912
Unbilled revenue 78,213 97,361
Other accounts and notes receivable 19,803 55,502
Intercompany notes receivable 165,700 --
Materials and supplies, at average cost -
Fossil fuel 65,292 53,036
Other 90,921 91,831
Other 19,205 13,529
---------- ----------
Total current assets 707,841 502,508
---------- ----------
Regulatory assets:
Deferred income taxes 600,604 608,353
Other 156,789 165,134
---------- ----------
Total regulatory assets 757,393 773,487
---------- ----------
TOTAL ASSETS $7,043,562 $6,829,864
========== ==========
CAPITAL AND LIABILITIES
Capitalization:
Common stock, $5 par value, authorized 150,000,000 shares -
outstanding 102,123,834 shares $ 510,619 $ 510,619
Other paid-in capital, principally premium on
common stock 701,896 701,896
Retained earnings 1,221,167 1,211,610
---------- ----------
Total common stockholder's equity 2,433,682 2,424,125
Preferred stock not subject to mandatory redemption (Note 7) 155,197 155,197
Long-term debt (Note 9) 1,882,601 1,674,311
---------- ----------
Total capitalization 4,471,480 4,253,633
---------- ----------
Current liabilities:
Current maturity of long-term debt (Note 9) 11,423 117,269
Accounts and wages payable 234,845 232,963
Accumulated deferred income taxes 48,139 45,061
Taxes accrued 119,699 100,714
Other 208,373 151,385
---------- ----------
Total current liabilities 622,479 647,392
---------- ----------
Commitments and Contingencies (Notes 2, 12 and 13)
Accumulated deferred income taxes 1,248,721 1,254,372
Accumulated deferred investment tax credits 138,665 144,175
Regulatory liability 154,399 159,317
Other deferred credits and liabilities 407,818 370,975
---------- ----------
TOTAL CAPITAL AND LIABILITIES $7,043,562 $6,829,864
========== ==========
</TABLE>
See Notes to Financial Statements.
-18-
<PAGE>
UNION ELECTRIC COMPANY
STATEMENT OF INCOME
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31, December 31, December 31,
For the year ended 1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
OPERATING REVENUES:
Electric $ 2,435,017 $ 2,290,526 $ 2,188,571
Gas 91,978 91,175 98,259
Other 171 370 503
----------- ----------- -----------
Total operating revenues 2,527,166 2,382,071 2,287,333
OPERATING EXPENSES:
Operations
Fuel and purchased power 656,534 530,449 499,995
Gas 54,469 49,496 63,453
Other 434,456 461,987 404,956
----------- ----------- -----------
1,145,459 1,041,932 968,404
Maintenance 247,135 221,995 217,426
Depreciation and amortization 256,072 259,787 247,961
Income taxes 230,691 217,385 192,766
Other taxes 204,541 212,789 211,949
----------- ----------- -----------
Total operating expenses 2,083,898 1,953,888 1,838,506
Operating Income 443,268 428,183 448,827
OTHER INCOME AND DEDUCTIONS:
Allowance for equity funds used during
construction 7,170 4,985 4,461
Miscellaneous, net 11,648 10,904 7,334
----------- ----------- -----------
Total other income and deductions 18,818 15,889 11,795
Income Before Interest Charges 462,086 444,072 460,622
INTEREST CHARGES:
Interest 119,978 129,947 138,676
Allowance for borrowed funds used during construction (7,144) (5,945) (6,676)
----------- ----------- -----------
Net interest charges 112,834 124,002 132,000
Income Before Extraordinary Charge 349,252 320,070 328,622
----------- ----------- -----------
Extraordinary Charge, net of income taxes (Note 2) -- -- (26,967)
----------- ----------- -----------
NET INCOME 349,252 320,070 301,655
----------- ----------- -----------
Preferred Stock Dividends 8,817 8,817 8,817
----------- ----------- -----------
NET INCOME AFTER PREFERRED
STOCK DIVIDENDS $ 340,435 $ 311,253 $ 292,838
=========== =========== ===========
</TABLE>
See Notes to Financial Statements.
-19-
<PAGE>
UNION ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31, December 31, December 31,
For the year ended 1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Cash Flows From Operating:
Income before extraordinary charge $349,252 $320,070 $328,622
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 246,292 250,323 238,846
Amortization of nuclear fuel 36,068 36,855 37,126
Allowance for funds used during construction (14,314) (10,930) (11,137)
Deferred income taxes, net 258 (14,213) (23,788)
Deferred investment tax credits, net (5,510) (5,716) (10,451)
Changes in assets and liabilities:
Receivables, net 47,360 (4,883) 14,356
Materials and supplies (11,346) 2,082 11,219
Accounts and wages payable 1,882 44,949 (22,335)
Taxes accrued 18,985 6,547 42,622
Other, net 56,036 26,022 (2,941)
--------------- ---------------- ---------------
Net Cash Provided by Operating Activities
724,963 651,106 602,139
Cash Flows From Investing:
Construction expenditures (246,198) (221,502) (259,418)
Allowance for funds used during construction 14,314 10,930 11,137
Nuclear fuel expenditures (21,901) (20,432) (35,432)
Intercompany note receivable (165,700) -- --
--------------- ---------------- ---------------
Net Cash Used in Investing Activities (419,485) (231,004) (283,713)
Cash Flows From Financing:
Dividends on common stock (328,674) (259,599) (259,395)
Dividends on preferred stock (8,817) (8,817) (8,817)
Redemptions -
Nuclear fuel lease (15,138) (67,720) (28,292)
Short-term debt -- (21,300) --
Long-term debt (100,000) (195,000) (45,000)
Preferred stock -- -- (63,924)
Issuances -
Nuclear fuel lease 64,972 16,439 40,337
Short-term debt -- -- 10,000
Long-term debt 152,150 160,000 35,000
--------------- ---------------- ---------------
Net Cash Used in Financing Activities (235,507) (375,997) (320,091)
Net Change in Cash and Cash Equivalents 69,971 44,105 (1,665)
Cash and Cash Equivalents at Beginning of Year 47,337 3,232 4,897
--------------- ---------------- ---------------
Cash and Cash Equivalents at End of Year $117,308 $47,337 $3,232
===============================================================================================================
Cash paid during the periods:
- ---------------------------------------------------------------------------------------------------------------
Interest (net of amount capitalized) $114,212 $125,255 $117,187
Income taxes $215,373 $223,960 $195,498
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
SUPPLEMENTAL DISCLOSURE OF NONCASH TRANSACTION:
An extraordinary charge to earnings was recorded in the fourth quarter of 1997
for the write-off of generation-related regulatory assets and liabilities of the
Company's Illinois retail electric business as a result of electric industry
restructuring legislation enacted in Illinois in December 1997. The write-off
reduced earnings $27 million, net of income taxes. See Note 2 - Regulatory
Matters under Notes to Financial Statements for further information.
See Notes to Financial Statements.
-20-
<PAGE>
UNION ELECTRIC COMPANY
STATEMENT OF RETAINED EARNINGS
- ------------------------------
(Thousands of Dollars)
- --------------------------------------------------------------------------------
Year Ended December 31, 1999 1998 1997
Balance at Beginning of Period $1,211,610 $1,159,956 $1,126,513
- --------------------------------------------------------------------------------
Add:
Net income 349,252 320,070 301,655
- --------------------------------------------------------------------------------
1,560,862 1,480,026 1,428,168
- --------------------------------------------------------------------------------
Deduct:
Common stock dividends 328,674 259,599 259,395
Preferred stock dividends 11,021 8,817 8,817
- --------------------------------------------------------------------------------
339,695 268,416 268,212
- --------------------------------------------------------------------------------
Balance at End of Period $1,221,167 $1,211,610 $1,159,956
- --------------------------------------------------------------------------------
Under the mortgage indenture, as amended, $31,305 of total retained earnings was
restricted against payment of common dividends - except those payable in common
stock, leaving $1,189,862 of free and unrestricted retained earnings at December
31, 1999.
SELECTED QUARTERLY INFORMATION (Unaudited)
- --------------------------------
(Thousands of Dollars)
- --------------------------------------------------------------------------------
Operating Operating Net Net Income
Revenues Income Income After
Quarter Ended Preferred
Stock
Dividends
- --------------------------------------------------------------------------------
March 31, 1999 (a) $506,071 $68,887 $43,743 $41,539
March 31, 1998 (a) $478,585 $62,120 $30,302 $28,098
June 30, 1999 621,367 96,292 70,669 68,464
June 30, 1998 (b) 588,676 92,827 66,251 64,046
September 30, 1999 905,850 235,707 208,727 206,523
September 30, 1998 (c) 846,437 233,738 206,551 204,347
December 31, 1999 (d) 493,878 42,382 26,113 23,909
December 31, 1998 468,373 39,498 16,966 14,762
- --------------------------------------------------------------------------------
(a) The first quarter of 1999 and 1998 included credits to Missouri electric
customers that reduced net income approximately $11 million and $6 million,
respectively.
(b) The second quarter of 1998 included credits to Missouri electric customers
that reduced net income approximately $18 million. Callaway Plant refueling
expenses, which decreased net income approximately $18 million, were also
included in the second quarter of 1998.
(c) The third quarter of 1998 included a nonrecurring charge related to the
targeted employee separation plan that reduced net income $11 million. (See Note
4 - Targeted Separation Plan under Notes to Financial Statements for further
information.)
(d) The fourth quarter of 1999 included adjustments that increased earnings $9
million as a result of a Report and Order received from the Missouri Public
Service Commission relating to the Registrant's electric alternative regulation
plan. (See Note 2 - Regulatory Matters under Notes to Financial Statements for
further information). In addition, Callaway Plant refueling expenses, which
decreased net income approximately $22 million were included in the fourth
quarter of 1999.
Other changes in quarterly earnings are due to the effect of weather on sales
and other factors that are characteristic of public utility operations.
See Notes to Financial Statements.
-21-
<PAGE>
UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1999
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation
Union Electric Company (AmerenUE or the Registrant) is a subsidiary of Ameren
Corporation (Ameren), which is the parent company of two utility operating
companies, the Registrant and Central Illinois Public Service Company
(AmerenCIPS). Ameren is a registered holding company under the Public Utility
Holding Company Act of 1935 (PUHCA) formed in December 1997 upon the merger of
AmerenUE and CIPSCO Incorporated (the Merger). Both Ameren and its subsidiaries
are subject to the regulatory provisions of the PUHCA. The operating companies
are engaged principally in the generation, transmission, distribution and sale
of electric energy and the purchase, distribution, transportation and sale of
natural gas in the states of Missouri and Illinois. Contracts among the
companies--dealing with jointly-owned generating facilities, interconnecting
transmission lines, and the exchange of electric power--are regulated by the
Federal Energy Regulatory Commission (FERC) or the Securities and Exchange
Commission (SEC). Administrative support services are provided to the Registrant
by a separate Ameren subsidiary, Ameren Services Company. The Registrant serves
1.1 million electric and 125,000 gas customers in a 24,500 square-mile area of
Missouri and Illinois, including Metropolitan St. Louis.
The Registrant also has a 40% interest in Electric Energy, Inc. (EEI), which is
accounted for under the equity method of accounting. EEI owns and operates an
electric generating and transmission facility in Illinois that supplies electric
power primarily to a uranium enrichment plant located in Paducah, Kentucky.
Regulation
In addition to the SEC, the Registrant is regulated by the Missouri Public
Service Commission (MoPSC), Illinois Commerce Commission (ICC), and the FERC.
The accounting policies of the Registrant conform to U.S. generally accepted
accounting principles (GAAP). See Note 2 - Regulatory Matters for further
information.
Property and Plant
The cost of additions to and betterments of units of property and plant is
capitalized. Cost includes labor, material, applicable taxes and overheads. An
allowance for funds used during construction is also added for the Registrant's
regulated assets, and interest incurred during construction is added for
nonregulated assets. Maintenance expenditures and the renewal of items not
considered units of property are charged to income as incurred. When units of
depreciable property are retired, the original cost and removal cost, less
salvage value, are charged to accumulated depreciation.
Depreciation
Depreciation is provided over the estimated lives of the various classes of
depreciable property by applying composite rates on a straight-line basis. The
provision for depreciation in 1999, 1998 and 1997 was approximately 3% of the
average depreciable cost.
Fuel and Gas Costs
In the Missouri and Illinois retail electric jurisdictions, the cost of fuel for
electric generation is reflected in base rates with no provision for changes to
be made through fuel adjustment clauses. (See Note 2 - Regulatory Matters for
further information.) In the Illinois jurisdiction in 1997, changes in fuel
costs were generally reflected in billings to electric customers through a fuel
adjustment clause. In the Illinois and Missouri retail gas jurisdictions,
changes in gas costs are generally reflected in billings to gas customers
through purchased gas adjustment clauses.
Nuclear Fuel
The cost of nuclear fuel is amortized to fuel expense on a unit-of-production
basis. Spent fuel disposal cost is charged to expense based on net kilowatthours
generated and sold.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments
purchased with an original maturity of three months or less.
Income Taxes
The Registrant is included in the consolidated federal income tax return filed
by Ameren. Income taxes are allocated to the individual companies based on their
respective taxable income or loss. Deferred tax assets and liabili-
-22-
<PAGE>
ties are recognized for the tax consequences of transactions that have been
treated differently for financial reporting and tax return purposes, measured
using statutory tax rates.
Investment tax credits utilized in prior years were deferred and are being
amortized over the useful lives of the related properties.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFC) is a utility industry
accounting practice whereby the cost of borrowed funds and the cost of equity
funds (preferred and common stockholders' equity) applicable to the Registrant's
regulated construction program are capitalized as a cost of construction. AFC
does not represent a current source of cash funds. This accounting practice
offsets the effect on earnings of the cost of financing current construction,
and treats such financing costs in the same manner as construction charges for
labor and materials.
Under accepted ratemaking practice, cash recovery of AFC, as well as other
construction costs, occurs when completed projects are placed in service and
reflected in customer rates. The AFC rates used were 10% during 1999 and 9%
during 1998 and 1997.
Unamortized Debt Discount, Premium and Expense
Discount, premium and expense associated with long-term debt are amortized over
the lives of the related issues.
Revenue
The Registrant accrues an estimate of electric and gas revenues for service
rendered but unbilled at the end of each accounting period.
Energy Contracts
The Emerging Issues Task Force of the Financial Accounting Standards Board
(EITF) Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities" became effective on January 1, 1999. EITF 98-10 provides guidance on
the accounting for energy contracts entered into for the purchase or sale of
electricity, natural gas, capacity and transportation. The EITF reached a
consensus in EITF 98-10 that sales and purchase activities being performed need
to be classified as either trading or nontrading. Furthermore, transactions that
are determined to be trading activities would be recognized on the balance sheet
measured at fair value, with gains and losses included in earnings.
AmerenEnergy, Inc., an energy marketing subsidiary of Ameren, enters into
contracts for the sale and purchase of energy on behalf of AmerenUE and
AmerenCIPS. Currently, virtually all of AmerenEnergy's transactions are
considered nontrading activities and are accounted for using the accrual or
settlement method, which represents industry practice. EITF 98-10 did not have a
material impact on the Registrant's financial position or results of operations
upon adoption.
Software
Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use" became effective on January 1, 1999. SOP
98-1 provides guidance on accounting for the costs of computer software
developed or obtained for internal use. Under SOP 98-1, certain costs may be
capitalized and amortized over some future period. SOP 98-1 did not have a
material impact on the Registrant's financial position or results of operations
upon adoption.
Evaluation of Assets for Impairment
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
prescribes general standards for the recognition and measurement of impairment
losses. The Registrant determines if long-lived assets are impaired by comparing
their undiscounted expected future cash flows to their carrying amount. An
impairment loss is recognized if the undiscounted expected future cash flows are
less than the carrying amount of the asset. SFAS 121 also requires that
regulatory assets which are no longer probable of recovery through future
revenues be charged to earnings (see Note 2 - Regulatory Matters for further
information). As of December 31, 1999, no impairment was identified.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires
management to make certain estimates and assumptions. Such estimates and
assumptions affect reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reported period. Actual
results could differ from those estimates.
Reclassifications
Certain reclassifications have been made to prior-years' financial statements to
conform with 1999 reporting.
-23-
<PAGE>
NOTE 2 - Regulatory Matters
Missouri Electric
In July 1995, the MoPSC approved an agreement establishing contractual
obligations involving the Registrant's Missouri retail electric rates. Included
was a three-year experimental alternative regulation plan (the Original Plan)
that ran from July 1, 1995, through June 30, 1998, which provided that earnings
in those years in excess of a 12.61% regulatory return on equity (ROE) be shared
equally between customers and stockholders, and earnings above a 14% ROE be
credited to customers. The formula for computing the credit used twelve-month
results ending June 30, rather than calendar year earnings. In 1996, the
Registrant recorded a $47 million credit for the first year of the Original
Plan, which reduced earnings $28 million. During 1997, the Registrant recorded a
$20 million credit for the second year of the Original Plan, which reduced
earnings $11 million. In 1998, the Registrant recorded an estimated $43 million
credit for the final year of the Original Plan, which reduced earnings $26
million.
Included in the joint agreement approved by the MoPSC in its February 1997 order
authorizing the Merger, was a new three-year experimental alternative regulation
plan (the New Plan) that runs from July 1, 1998, through June 30, 2001. Like the
Original Plan, the New Plan requires that earnings over a 12.61% ROE up to a 14%
ROE be shared equally between customers and shareholders. The New Plan also
returns to customers 90% of all earnings above a 14% ROE up to a 16% ROE.
Earnings above a 16% ROE are credited entirely to customers. In addition, the
joint agreement provides for a Missouri electric rate decrease, retroactive to
September 1, 1998, based on the weather-adjusted average annual credits to
customers under the Original Plan. The Registrant estimated that its Missouri
electric rate decrease should approximate $20 million on an annualized basis and
reduced revenues accordingly since September 1998.
In November 1998, the MoPSC Staff proposed adjustments to the customer credit
for the third year of the Original Plan. In addition, the MoPSC Staff proposed
adjustments to the Registrant's estimated Missouri electric rate decrease based
upon their methodology of calculating the weather-adjusted credits. The
determination of the credit for the third year of the Original Plan, as well as
the determination of the Missouri electric rate decrease, were subject to
regulatory proceedings before the MoPSC in 1999.
On December 23, 1999, the MoPSC issued a Report and Order (Order) related to the
customer credit for the third year of the Original Plan. Certain of the MoPSC
staff's proposed adjustments were accepted by the MoPSC in the Order. In
addition, the Order requires the Registrant to capitalize and amortize certain
costs (including computer software costs) that had previously been expensed for
its Missouri electric operations.
Based on the provisions of the Order, the Registrant estimates that the credit
for the third year of the Original Plan will approximate $31 million. In
addition, with regard to the Missouri electric rate decrease, the Registrant,
the MoPSC staff, and other parties reached a settlement related to the
calculation of the weather-adjusted credits. As a result, the Registrant
estimates that the annualized Missouri electric rate decrease will approximate
$17 million. On February 24, 2000, the Registrant filed a Petition for Writ of
Review with the Circuit Court of Cole County, Missouri, asking that the Order be
reversed. The Registrant has also requested that the court issue a stay of the
MoPSC's Order. While it is unable to predict the ultimate outcome of the
judicial appeal of the MoPSC's Order, the Registrant believes that the final
decision will not have a material adverse effect on its financial position,
results of operations or liquidity.
The provisions of the Order also have an impact on the estimated credit to
electric customers recorded by the Registrant for the first year of the New
Plan. As a result, the Registrant recorded an estimated credit of $25 million
for the plan year ended June 30, 1999. In addition, the Registrant recorded an
estimated $20 million credit for the 1999 portion of the second year of the New
Plan. Also, the provision of the Order which requires the Registrant to
capitalize and amortize certain costs (including computer software costs) that
had been previously expensed resulted in the capitalization of approximately $20
million of costs in the fourth quarter of 1999.
In summary, the provisions of the Order and the resulting changes in the
Registrant's estimates of credits and Missouri electric rate decrease for the
open years under the Original Plan and the New Plan resulted in an increase in
earnings of approximately $9 million in the fourth quarter of 1999.
On December 30, 1999, the Registrant filed a request for rehearing with the
MoPSC, asking that it reconsider its decision to adopt certain of the MoPSC
staff's adjustments. On January 25, 2000, the MoPSC denied the Registrant's
request. The Registrant plans to file an appeal with the courts.
-24-
<PAGE>
Gas
In December 1997, the MoPSC approved a $12 million annual rate increase for
natural gas service in the Registrant's Missouri jurisdiction. The rate increase
became effective in February 1998.
Midwest ISO
In 1998, the Registrant joined a group of companies that support the formation
of the Midwest Independent System Operator (Midwest ISO). An ISO operates, but
does not own, electric transmission systems and maintains system reliability and
security while alleviating pricing issues associated with the "pancaking" of
rates. The Midwest ISO would be regulated by the FERC. Thirteen
transmission-owning utilities have joined the Midwest ISO, as of December 31,
1999. The FERC conditionally approved the formation of the Midwest ISO in
September 1998, and it is expected to be operational during the year 2001. The
MoPSC and the ICC have authorized the Registrant to join the Midwest ISO and to
transfer control of its transmission facilities to the Midwest ISO. The Midwest
ISO covers 14 states, represents portions of 60,000 miles of transmission line
and controls $8 billion in assets. The Registrant believes that the operation of
the Midwest ISO will not have a material adverse effect on its financial
condition, results of operations or liquidity.
In December 1999, the FERC issued its Order 2000 relating to Regional
Transmission Organizations (RTOs) that would meet certain characteristics such
as size and independence. Order 2000 calls on all transmission owners to join
RTOs. In particular, all public utilities that own, operate, or control
interstate transmission facilities must file with the FERC by October 15, 2000,
a proposal for an RTO, or alternatively a description of efforts by the utility
to join an RTO. The Registrant expects that its participation in the Midwest ISO
will satisfy the requirements of Order 2000.
Illinois Electric Restructuring
Certain states are considering proposals or have adopted legislation that will
promote competition at the retail level. In December 1997, the Governor of
Illinois signed the Electric Service Customer Choice and Rate Relief Law of 1997
(the Illinois Law) providing for electric utility restructuring in Illinois,
where approximately 6% of the Registrant's retail electric revenues are derived.
This legislation introduces competition into the supply of electric energy at
retail in Illinois.
Under the Illinois Law, retail direct access, which allows customers to choose
their electric generation suppliers, will be phased in over several years.
Access for commercial and industrial customers will occur over a period from
October 1999 to December 2000, and access for residential customers will occur
after May 1, 2002.
As a requirement of the Illinois Law, in March 1999, the Registrant filed
delivery service tariffs with the ICC. These tariffs would be used by electric
customers who choose to purchase their power from alternate suppliers. On August
25, 1999, the ICC issued an order approving the delivery services tariffs, with
an allowed rate of return on equity of 10.45%. The Registrant and AmerenCIPS
filed a joint petition for rehearing of that order requesting the ICC to alter
its conclusions on a number of issues. On October 13, 1999, the ICC granted a
rehearing on certain issues. An order on this reopened proceeding was issued in
2000 resolving all outstanding issues.
The Illinois Law included a 5% residential electric rate decrease for the
Registrant's Illinois electric customers, effective August 1, 1998. This rate
decrease reduced electric revenues approximately $1 million in 1999. The
Registrant may be subject to additional 5% residential electric rate decreases
in each of 2000 and 2002, to the extent its rates exceed the Midwest utility
average at that time. The Registrant's rates are currently below the Midwest
utility average.
As a result of the Illinois Law, the Registrant filed a proposal with the ICC to
eliminate their electric fuel adjustment clause for Illinois retail customers,
thereby including a historical levels of fuel costs in base rates. The ICC
approved the Registrant's filing in early 1998.
The Illinois Law also contains a provision requiring that one-half of excess
earnings from the Illinois jurisdiction for the years 1998 through 2004 be
refunded to the Registrant's Illinois customers. Excess earnings are defined as
the portion of the two-year average annual rate of return on common equity in
excess of 1.5% of the two-year average of an Index, as defined in the Illinois
Law. The Index is defined as the sum of the average for the twelve months ended
September 30 of the average monthly yields of the 30-year US Treasury bonds,
plus prescribed percentages ranging from 4% to 7%. Filings must be made with the
ICC on, or before, March 31 of each year 2000 through 2005.
Other provisions of the Illinois Law include (1) potential recovery of a portion
of strandable costs, which represent costs which would not be recoverable in a
restructured environment, through a transition charge collected from
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<PAGE>
customers who choose another electric supplier; (2) a mechanism to securitize
certain future revenues; and (3) a provision relieving the Registrant of the
requirement to file electric rate cases or alternative regulatory plans in
Illinois, following the consummation of the Merger to reflect the effects of net
merger savings.
The Registrant's accounting policies and financial statements conform to GAAP
applicable to rate-regulated enterprises and reflect the effects of the
ratemaking process in accordance with SFAS 71, "Accounting for the Effects of
Certain Types of Regulation." Such effects concern mainly the time at which
various items enter into the determination of net income in order to follow the
principle of matching costs and revenues. For example, SFAS 71 allows the
Registrant to record certain assets and liabilities (regulatory assets and
regulatory liabilities) that are expected to be recovered or settled in future
rates and would not be recorded under GAAP for nonregulated entities. In
addition, reporting under SFAS 71 allows companies whose service obligations and
prices are regulated to maintain assets on their balance sheets representing
costs they reasonably expect to recover from customers, through inclusion of
such costs in future rates. SFAS 101, "Accounting for the Discontinuance of
Application of FASB Statement No. 71," specifies how an enterprise that ceases
to meet the criteria for application of SFAS 71 for all or part of its
operations should report that event in its financial statements. In general,
SFAS 101 requires that the enterprise report the discontinuance of SFAS 71 by
eliminating from its balance sheet all regulatory assets and liabilities related
to the portion of the business that no longer meets the SFAS 71 criteria. The
EITF has concluded that application of SFAS 71 accounting should be discontinued
once sufficiently detailed deregulation legislation is issued for a separable
portion of a business for which a plan of deregulation has been established.
However, the EITF further concluded that regulatory assets associated with the
deregulated portion of the business, which will be recovered through tariffs
charged to customers of a regulated portion of the business, should be
associated with the regulated portion of the business from which future cash
recovery is expected (not the portion of the business from which the costs
originated). Those assets can therefore continue to be carried on the regulated
entity's balance sheet to the extent such assets are recoverable. In addition,
SFAS 121 establishes accounting standards for the impairment of long-lived
assets.
Due to the enactment of the Illinois Law, prices for the retail supply of
electric generation are expected to transition from cost-based, regulated rates
to rates determined in large part by competitive market forces in the state of
Illinois. As a result, the Registrant discontinued application of SFAS 71 for
the Illinois retail portion of its generating business (i.e., the portion of the
Registrant's business related to the supply of electric energy in Illinois) in
the fourth quarter of 1997. The Registrant evaluated the impact of the Illinois
Law on the future recoverability of its regulatory assets and liabilities
related to the generation portion of its business and determined that it was not
probable that such assets and liabilities would be recovered through the cash
flows from the regulated portion of its business. Accordingly, the Registrant's
generation-related regulatory assets and liabilities of its Illinois retail
electric business were written off in the fourth quarter of 1997, resulting in
an extraordinary charge to earnings of $27 million, net of income taxes. These
regulatory assets and liabilities included previously incurred costs originally
expected to be collected/refunded in future revenues, such as deferred charges
related to a generating plant and income tax-related regulatory assets and
liabilities. In addition, the Registrant has evaluated whether the
recoverability of the costs associated with its remaining net generation-related
assets has been impaired as defined under SFAS 121. The Registrant has concluded
that impairment, as defined under SFAS 121, does not exist and that no plant
writedowns are necessary at this time.
In August 1999, the Registrant filed a transmission system rate case with the
FERC. This filing was primarily designed to implement rates, terms and
conditions for transmission service for those retail customers in Illinois who
choose other suppliers as allowed under the Illinois Law. On October 14, 1999,
the FERC issued an order suspending the proposed rates until March 25, 2000. In
January 2000, a settlement in principle was reached with the FERC trial staff
and other interested parties. The settlement establishes the rates for
transmission service that are to go into effect in the first quarter of 2000.
The settlement is subject to approval by the FERC. The Registrant expects that
the FERC will approve the settlement in 2000.
The provisions of the Illinois Law could also result in lower revenues, reduced
profit margins and increased costs of capital and operations expense. At this
time, the Registrant is unable to determine the impact of the Illinois Law on
the Registrant's future financial condition, results of operations or liquidity.
Missouri Electric Restructuring
In Missouri, where approximately 94% of the Registrant's retail electric
revenues are derived, a task force appointed by the MoPSC investigated electric
industry restructuring and competition. In 1998, the task force issued a report
to the MoPSC that addressed many of the restructuring issues but did not provide
a specific recommendation or approach to restructure the industry. In addition,
in 1998, the MoPSC staff issued a proposed plan for restructuring Missouri's
electric industry. The staff's plan addressed a number of issues of concern if
the industry is restructured in Missouri. It also included a proposal for less
than full recovery of strandable costs. The staff's plan has not been
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<PAGE>
addressed by the MoPSC. A joint committee of the Missouri legislature is also
conducting hearings on these issues. Several restructuring bills were introduced
by the Missouri legislature in 1999 and 2000.
The Registrant is unable to predict the timing or ultimate outcome of electric
industry restructuring in the state of Missouri, as well as the impact of
potential electric industry restructuring matters on the Registrant's future
financial condition, results of operations or liquidity. The potential negative
consequences of electric industry restructuring could be significant and include
the impairment and write-down of certain assets, including generation-related
plant and net regulatory assets, lower revenues, reduced profit margins and
increased costs of capital and operations expense. At December 31, 1999, the
Registrant's net investment in generation facilities related to its Missouri
jurisdiction approximated $2.6 billion and was included in electric plant
in-service on the Registrant's balance sheet. In addition, at December 31, 1999,
the Registrant's Missouri net generation-related regulatory assets approximated
$454 million.
Regulatory Assets and Liabilities
In accordance with SFAS 71, the Registrant has deferred certain costs pursuant
to actions of its regulators, and is currently recovering such costs in electric
rates charged to customers.
At December 31, the Registrant had recorded the following regulatory assets and
regulatory liability:
- -----------------------------------------------------------------------
(in millions) 1999 1998
- -----------------------------------------------------------------------
Regulatory Assets:
Income taxes $601 $608
Callaway costs 92 95
Unamortized loss on reacquired debt 24 26
Merger costs 22 24
Other 18 20
- -----------------------------------------------------------------------
Regulatory Assets $757 $773
- -----------------------------------------------------------------------
Regulatory Liability:
Income taxes $154 $159
- -----------------------------------------------------------------------
Regulatory Liability $154 $159
- -----------------------------------------------------------------------
Income Taxes: See Note 10 - Income Taxes.
Callaway Costs: Represents Callaway Nuclear Plant operations and maintenance
expenses, property taxes and carrying costs incurred between the plant
in-service date and the date the plant was reflected in rates. These costs are
being amortized over the remaining life of the plant (through 2024).
Unamortized Loss on Reacquired Debt: Represents losses related to refunded debt.
These amounts are being amortized over the lives of the related new debt issues
or the remaining lives of the old debt issues if no new debt was issued. Merger
Costs: Represents the portion of merger-related expenses applicable to the
Missouri retail jurisdiction. These costs are being amortized within 10 years,
based on a MoPSC order.
The Registrant continually assesses the recoverability of its regulatory assets.
Under current accounting standards, regulatory assets are written off to
earnings when it is no longer probable that such amounts will be recovered
through future revenues. However, as noted in the above paragraphs, electric
industry restructuring legislation may impact the recoverability of regulatory
assets in the future.
NOTE 3 - Related Party Transactions
The Registrant has transactions in the normal course of business with other
Ameren subsidiaries. These transactions are primarily comprised of power
purchases and sales and services received or rendered. Intercompany receivables
included in other accounts and notes receivable were approximately $15 million
and $6 million, respectively, as of December 31, 1999 and 1998. Intercompany
payables included in accounts and wages payable totaled approximately $25
million and $17 million, respectively, as of December 31, 1999 and 1998.
In addition, the Registrant has the ability to borrow funds from Ameren or
AmerenCIPS or invest funds through a regulated money pool agreement. At December
31, 1999, the Registrant had outstanding intercompany receivables of $166
million through the regulated money pool. See Note 8 - Short-Term Borrowings for
further information.
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<PAGE>
NOTE 4 - Targeted Separation Plan
In July 1998, Ameren offered separation packages to employees whose positions
were eliminated through a targeted separation plan (TSP). During the third
quarter of 1998, a nonrecurring, pretax charge of $18 million was recorded,
which reduced earnings $11 million, representing the Registrant's share of costs
incurred to implement the TSP.
NOTE 5 - Concentration of Risk
Market Risk
The Registrant engages in price risk management activities related to
electricity and fuel. In addition to buying and selling these commodities, the
Registrant uses derivative financial instruments to manage market risks and
reduce exposure resulting from fluctuations in interest rates and the prices of
electricity and fuel. Derivative instruments used include futures, forward
contracts and options. The use of these types of contracts allows the Registrant
to manage and hedge its contractual commitments and reduce exposure related to
the volatility of commodity market prices.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties fail
to perform as contracted. New York Mercantile Exchange (NYMEX) traded futures
contracts are guaranteed by NYMEX and have nominal credit risk. On all other
transactions, the Registrant is exposed to credit risk in the event of
nonperformance by the counterparties in the transaction.
The Registrant's financial instruments subject to credit risk consist primarily
of trade accounts receivables and forward contracts. The risk associated with
trade receivables is mitigated by the large number of customers in a broad range
of industry groups comprising the Registrant's customer base. The Registrant's
revenues are primarily derived from sales of electricity and natural gas to
customers in Missouri and Illinois. For each counterparty in forward contracts,
the Registrant analyzes the counterparty's financial condition prior to entering
into an agreement, establishes credit limits and monitors the appropriateness of
these limits on an ongoing basis through a credit risk management program.
NOTE 6 - Nuclear Fuel Lease
The Registrant has a lease agreement that provides for the financing of nuclear
fuel. At December 31, 1999, the maximum amount that could be financed under the
agreement was $120 million. Pursuant to the terms of the lease, the Registrant
has assigned to the lessor certain contracts for purchase of nuclear fuel. The
lessor obtains, through the issuance of commercial paper or from direct loans
under a committed revolving credit agreement from commercial banks, the
necessary funds to purchase the fuel and make interest payments when due.
The Registrant is obligated to reimburse the lessor for all expenditures for
nuclear fuel, interest and related costs. Obligations under this lease become
due as the nuclear fuel is consumed at the Registrant's Callaway Nuclear Plant.
The Registrant reimbursed the lessor $16 million in 1999, $23 million during
1998 and $31 million during 1997.
The Registrant has capitalized the cost, including certain interest costs, of
the leased nuclear fuel and has recorded the related lease obligation. Total
interest charges under the lease were $5 million in 1999 and 1998 and $6 million
in 1997. Interest charges for these years were based on average interest rates
of approximately 6%. Interest charges of $4 million were capitalized in 1999 and
$3 million were capitalized in 1998 and 1997.
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<PAGE>
NOTE 7 - Preferred Stock
At December 31, 1999 and 1998, the Registrant had 25 million shares of
authorized preferred stock.
Outstanding preferred stock is entitled to cumulative dividends and is
redeemable at the redemption prices shown below:
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Preferred Stock Not Subject to Mandatory Redemption:
(in millions)
- --------------------------------------------------------------------------------
Redemption Price December 31,
(per share) 1999 1998
Without par value and stated value
of $100 per share--
$7.64 Series - 330,000 shares $103.82 - note (a) $33 $33
$5.50 Series A - 14,000 shares 110.00 1 1
$4.75 Series - 20,000 shares 102.176 2 2
$4.56 Series - 200,000 shares 102.47 20 20
$4.50 Series - 213,595 shares 110.00 - note (b) 21 21
$4.30 Series - 40,000 shares 105.00 4 4
$4.00 Series - 150,000 shares 105.625 15 15
$3.70 Series - 40,000 shares 104.75 4 4
$3.50 Series - 130,000 shares 110.00 13 13
Without par value and stated value of
$25 per share--
$1.735 Series - 1,657,500 shares 25.00 42 42
- --------------------------------------------------------------------------------
TOTAL PREFERRED STOCK NOT
SUBJECT TO MANDATORY REDEMPTION $155 $155
- --------------------------------------------------------------------------------
(a) Beginning February 15, 2003, eventually declining to $100 per share.
(b) In the event of voluntary liquidation, $105.50.
- --------------------------------------------------------------------------------
NOTE 8 - Short-Term Borrowings
Short-term borrowings of the Registrant consist of bank loans (maturities
generally on an overnight basis) and commercial paper (maturities generally
within 10-45 days). At December 31, 1999 and 1998 the Registrant had no
outstanding short-term borrowings.
At December 31, 1999, the Registrant had committed bank lines of credit
aggregating $150 million (all of which was unused and available at such date)
which make available interim financing at various rates of interest based on
LIBOR, the bank certificate of deposit rate, or other options. These lines of
credit are renewable annually at various dates throughout the year.
Also, the Registrant has the ability to borrow up to approximately $530 million
from Ameren or AmerenCIPS through a regulated money pool agreement. The
regulated money pool was established to coordinate and provide for certain
short-term cash and working capital requirements and is administered by Ameren
Services Company. Interest is calculated at varying rates of interest depending
on the composition of internal and external funds in the regulated money pool.
At December 31, 1999, the Registrant had no intercompany borrowings outstanding
and $402 million available through the regulated money pool.
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<PAGE>
NOTE 9 - Long-Term Debt
- --------------------------------------------------------------------------------
(in millions) 1999 1998
- --------------------------------------------------------------------------------
First Mortgage Bonds - note (a)
- --------------------------------------------------------------------------------
6 3/4% Series paid in 1999 $ - $100
8.33% Series due 2002 75 75
7.65% Series due 2003 100 100
6 7/8% Series due 2004 188 188
7 3/8% Series due 2004 85 85
6 3/4% Series due 2008 148 148
7.40% Series due 2020 - note (b) 60 60
8 3/4% Series due 2021 125 125
8% Series due 2022 85 85
8 1/4% Series due 2022 104 104
7.15% Series due 2023 75 75
7% Series due 2024 100 100
5.45% Series due 2028 - note (b) 44 44
- --------------------------------------------------------------------------------
1,189 1,289
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Missouri Environmental Improvement Revenues Bonds
- --------------------------------------------------------------------------------
1985 Series A due 2015 - note (c) 70 70
1985 Series B due 2015 - note (c) 57 57
1991 Series due 2020 - note (c) 43 43
1992 Series due 2022 - note (c) 47 47
1998 Series A due 2033 - note (c) 60 60
1998 Series B due 2033 - note (c) 50 50
1998 Series C due 2033 - note (c) 50 50
- --------------------------------------------------------------------------------
377 377
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Subordinated Deferrable Interest Debentures
- --------------------------------------------------------------------------------
7.69% Series A due 2036 - note (d) 66 66
- -------------------------------------------------------------------------------
Commercial Paper - note (e) 152 --
- -------------------------------------------------------------------------------
Nuclear Fuel Lease 116 66
- -------------------------------------------------------------------------------
Unamortized Discount and Premium on Debt (6) (7)
- -------------------------------------------------------------------------------
Maturities Due Within One Year (11) (117)
------------------------------------------------------------------------------
Total Long-Term Debt $1,883 $1,674
- -------------------------------------------------------------------------------
(a) At December 31, 1999, substantially all of the property and plant was
mortgaged under, and subject to liens of, the respective indentures
pursuant to which the bonds were issued.
(b) Environmental Improvement Series.
(c) Interest rates, and the periods during which such rates apply, vary
depending on the Registrant's selection of certain defined rate modes. The
average interest rates for the year 1999 are as follows:
1985 Series A 3.21%
1985 Series B 3.29%
1991 Series 3.65%
1992 Series 3.55%
1998 Series A 3.49%
1998 Series B 3.48%
1998 Series C 3.46%
(d) During the terms of the debentures, the Registrant may, under certain
circumstances, defer the payment of interest for up to five years.
(e) A bank credit agreement, due 2002, permits the Registrant to borrow or to
support commercial paper borrowings up to $300 million. Interest rates will
vary depending on market conditions. At December 31, 1999, no such
borrowings were outstanding.
Maturities of long-term debt through 2004 are as follows:
- ----------------------------------------
(in millions) Principal Amount
- ----------------------------------------
2000 $ 11
2001 --
2002 227
2003 100
2004 273
- ----------------------------------------
Amounts for years subsequent to 2000 do not include nuclear fuel lease payments
since the amounts of such payments are not currently determinable.
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<PAGE>
NOTE 10 - Income Taxes
Total income tax expense for 1999 resulted in an effective tax rate of 40% on
earnings before income taxes (40% in 1998 and 38% in 1997).
Principal reasons such rates differ from the statutory federal rate:
- ------------------------------------------------------------------------
1999 1998 1997
- ------------------------------------------------------------------------
Statutory federal income
tax rate 35% 35% 35%
Increases (Decreases) from:
Depreciation differences 2 2 2
State income tax 4 4 4
Other (1) (1) (3)
- ------------------------------------------------------------------------
Effective income tax rate 40% 40% 38%
- ------------------------------------------------------------------------
Income tax expense components:
- ------------------------------------------------------------------------
(in millions) 1999 1998 1997
- ------------------------------------------------------------------------
Taxes currently payable (principally
federal):
Included in operating expenses $236 $237 $216
Included in other income--
Miscellaneous, net (4) (5) (3)
- ------------------------------------------------------------------------
232 232 213
Deferred taxes (principally federal):
Included in operating expenses--
Depreciation differences 9 (1) (7)
Other (9) (14) (10)
Included in other income--
Depreciation differences -- -- 1
Other -- -- 9
- ------------------------------------------------------------------------
-- (15) (7)
Deferred investment tax credits,
Amortization
Included in operating expenses (5) (5) (6)
- ------------------------------------------------------------------------
Total income tax expense $227 $212 $200
- ------------------------------------------------------------------------
In accordance with SFAS 109, "Accounting for Income Taxes," a regulatory asset,
representing the probable recovery from customers of future income taxes, which
is expected to occur when temporary differences reverse, was recorded along with
a corresponding deferred tax liability. Also, a regulatory liability,
recognizing the lower expected revenue resulting from reduced income taxes
associated with amortizing accumulated deferred investment tax credits, was
recorded. Investment tax credits have been deferred and will continue to be
credited to income over the lives of the related property.
The Registrant adjusts its deferred tax liabilities for changes enacted in tax
laws or rates. Recognizing that regulators will probably reduce future revenues
for deferred tax liabilities initially recorded at rates in excess of the
current statutory rate; reductions in the deferred tax liability were credited
to the regulatory liability.
Temporary differences gave rise to the following deferred tax assets and
deferred tax liabilities at December 31:
- ------------------------------------------------------------------------------
(in millions) 1999 1998
- ------------------------------------------------------------------------------
Accumulated Deferred Income Taxes:
Depreciation $822 $814
Regulatory assets, net 462 465
Capitalized taxes and expenses 60 68
Deferred benefit costs (47) (48)
- ------------------------------------------------------------------------------
Total net accumulated deferred income tax liabilities $1,297 $1,299
- ------------------------------------------------------------------------------
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<PAGE>
NOTE 11 - Retirement Benefits
On January 1, 1999, the AmerenUE and the AmerenCIPS defined benefit pension
plans combined to form the Ameren Retirement plan. The Ameren plan covers
qualified employees of the Registrant. Benefits are based on the employees'
years of service and compensation. The Ameren plan is funded in compliance with
income tax regulations and federal funding requirements. The Registrant, along
with other subsidiaries of Ameren, is a participant in the Ameren plan and is
responsible for its proportional share of the costs and the assets or
liabilities. The Registrant's share of the pension costs for 1999 were $18
million, of which approximately 18% was charged to construction accounts. The
AmerenUE pension plan information for 1998 and 1997 is presented separately.
Pension costs for the years 1998 and 1997 were $28 million and $24 million,
respectively, of which approximately 19% and 17%, respectively, was charged to
construction accounts.
Funded Status of Pension Plans:
- ------------------------------------------------------------------------
(in millions) 1998
- ------------------------------------------------------------------------
Change in benefit obligation
Net benefit obligation at beginning of year $999
Service cost 24
Interest cost 70
Amendments 10
Actuarial loss 38
Special termination benefit charge 7
Benefits paid (88)
- ------------------------------------------------------------------------
Net benefit obligation at end of year 1,060
Change in plan assets *
Fair value of plan assets at beginning of year 1,006
Actual return on plan assets 122
Employer contributions 1
Benefits paid (88)
- ------------------------------------------------------------------------
Fair value of plan assets at end of year 1,041
Funded status - deficiency 19
Unrecognized net actuarial gain 121
Unrecognized prior service cost (73)
Unrecognized net transition asset 6
- ------------------------------------------------------------------------
Accrued pension cost at December 31 $73
- ------------------------------------------------------------------------
* Plan assets consist principally of common stocks and fixed income securities.
Components of Net Periodic Benefit Cost:
- --------------------------------------------------------------------------------
(in millions) 1998 1997
- --------------------------------------------------------------------------------
Service cost $24 $22
Interest cost 70 69
Expected return on plan assets (75) (71)
Amortization of:
Transition asset (1) (1)
Prior service cost 6 7
Actuarial gain (3) (2)
Special termination benefit charge 7 --
- --------------------------------------------------------------------------------
Net periodic benefit cost $28 $24
- --------------------------------------------------------------------------------
Weighted-average Assumptions for Actuarial Present Value of Projected Benefit
Obligations:
- --------------------------------------------------------------
1998
- --------------------------------------------------------------
Discount rate at measurement date 6.75%
Expected return on plan assets 8.5%
Increase in future compensation 4%
- --------------------------------------------------------------
In addition to providing pension benefits, the Registrant provides certain
health care and life insurance benefits for retired employees. The Registrant
accrues the expected postretirement benefit costs during employees' years of
service.
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<PAGE>
The Registrant's funding policy is to annually contribute the net periodic cost
to a Voluntary Employee Beneficiary Association trust (VEBA). Postretirement
benefit costs were $46 million in 1999, $43 million for 1998 and $44 million in
1997, of which approximately 18% in 1999 and 17% in 1998 and 1997 were charged
to construction accounts. The Registrant's transition obligation at December 31,
1999 is being amortized over the next 13 years.
The MoPSC and the ICC allow the recovery of postretirement benefit costs in
rates to the extent that such costs are funded. In December 1995, the Registrant
established two external trust funds for retiree health care and life insurance
benefits. In 1998, 1997 and 1996, claims were paid out of the plan trust funds.
Funded Status of the Plans:
- --------------------------------------------------------------------------------
(in millions) 1999 1998
- --------------------------------------------------------------------------------
Change in benefit obligation
Net benefit obligation at beginning of year $360 $333
Service cost 15 14
Interest cost 25 24
Actuarial (gain)/loss (20) 9
Benefits paid (26) (20)
- --------------------------------------------------------------------------------
Net benefit obligation at end of year 354 360
Change in plan assets *
Fair value of plan assets at beginning of year 110 81
Actual return on plan assets 4 8
Employer contributions 46 44
Unincorporated business income tax -- (3)
Benefits paid (26) (20)
- --------------------------------------------------------------------------------
Fair value of plan assets at end of year 134 110
Funded status - deficiency 220 250
Unrecognized net actuarial gain 29 11
Unrecognized prior service cost (3) (3)
Unrecognized net transition obligation (162) (175)
- --------------------------------------------------------------------------------
Postretirement benefit liability at December 31 $84 $83
- --------------------------------------------------------------------------------
* Plan assets consist principally of common stocks and fixed income securities.
Components of Net Periodic Benefit Cost:
- --------------------------------------------------------------------------------
(in millions) 1999 1998 1997
- --------------------------------------------------------------------------------
Service cost $15 $14 $12
Interest cost 25 24 23
Expected return on plan assets (6) (5) (2)
Amortization of:
Transition obligation 12 12 12
Actuarial gain -- (2) (1)
- --------------------------------------------------------------------------------
Net periodic benefit cost $46 $43 $44
- --------------------------------------------------------------------------------
Assumptions for the Obligation Measurements:
- --------------------------------------------------------------------------------
1999 1998
- --------------------------------------------------------------------------------
Discount rate at measurement date 7.75% 6.75%
Expected return on plan assets 8.5% 8.5%
Medical cost trend rate - initial -- 5.75%
- ultimate 5.25% 4.75%
Ultimate medical cost trend rate expected in year 2000 2000
- --------------------------------------------------------------------------------
A one percentage point increase in the medical cost trend rate is estimated to
increase the net periodic cost and the accumulated postretirement benefit
obligation approximately $4 million and $31 million, respectively. A one
percentage point decrease in the medical cost trend rate is estimated to
decrease the net periodic cost and the accumulated postretirement benefit
obligation approximately $4 million and $31 million, respectively.
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<PAGE>
NOTE 12 - Commitments and Contingencies
The Registrant is engaged in a capital program under which expenditures
averaging approximately $317 million, including AFC, are anticipated during each
of the next five years. This estimate includes capital expenditures that will be
incurred by the Registrant to meet new air quality standards for ozone and
particulate matter, as discussed later in this Note.
The Registrant has commitments for the purchase of coal under long-term
contracts. Coal contract commitments, including transportation costs, for 2000
through 2004 are estimated to total $1.0 billion. Total coal purchases,
including transportation costs, for 1999, 1998 and 1997 were $312 million, $304
million, and $267 million, respectively. The Registrant also has existing
contracts with pipeline and natural gas suppliers to provide, transport and
store natural gas for distribution and electric generation. Gas-related contract
cost commitments for 2000 through 2004 are estimated to total $54 million. Total
delivered natural gas costs were $54 million for 1999, $50 million for 1998, and
$64 million for 1997. The Registrant's nuclear fuel commitments for 2000 through
2004, including uranium concentrates, conversion, enrichment and fabrication,
are expected to total $73 million, and are expected to be financed under the
nuclear fuel lease. Nuclear fuel expenditures for 1999, 1998 and 1997 were $22
million, $20 million and $35 million, respectively. Additionally, the Registrant
has long-term contracts with other utilities to purchase electric capacity.
These commitments for 2000 through 2004 are estimated to total $200 million.
During 1999, 1998 and 1997, electric capacity purchases were $38 million, $35
million, and $34 million, respectively.
The Registrant's insurance coverage for Callaway Nuclear Plant at December 31,
1999, was as follows:
Type and Source of Coverage
- -------------------------------------------------------------------------------
(in millions) Maximum Maximum
Coverages Assessments
For Single
Incidents
- -------------------------------------------------------------------------------
Public Liability:
American Nuclear Insurers $ 200 $--
Pool Participation 9,338 88 (a)
- -------------------------------------------------------------------------------
$ 9,538 (b) $ 88
- -------------------------------------------------------------------------------
Nuclear Worker Liability:
American Nuclear Insurers $ 200 (c) $ 3
- -------------------------------------------------------------------------------
Property Damage:
Nuclear Electric Insurance Ltd. $ 2,750 (d) $ 11
- -------------------------------------------------------------------------------
Replacement Power:
Nuclear Electric Insurance Ltd. $ 490 (e) $2
- -------------------------------------------------------------------------------
(a) Retrospective premium under the Price-Anderson liability provisions of the
Atomic Energy Act of 1954, as amended, (Price- Anderson). Subject to
retrospective assessment with respect to loss from an incident at any U.S.
reactor, payable at $10 million per year. Price-Anderson expires in 2002.
(b) Limit of liability for each incident under Price-Anderson.
(c) Industry limit for potential liability from workers claiming exposure to
the hazard of nuclear radiation.
(d) Includes premature decommissioning costs.
(e) Weekly indemnity of $3.5 million, for 52 weeks which commences after the
first 12 weeks of an outage, plus $2.8 million per week for 110 weeks
thereafter.
- --------------------------------------------------------------------------------
Price-Anderson limits the liability for claims from an incident involving any
licensed U.S. nuclear facility. The limit is based on the number of licensed
reactors and is adjusted at least every five years based on the Consumer Price
Index. Utilities owning a nuclear reactor cover this exposure through a
combination of private insurance and mandatory participation in a financial
protection pool as established by Price-Anderson.
If losses from a nuclear incident at Callaway exceed the limits of, or are not
subject to, insurance, or if coverage is not available, the Registrant will
self-insure the risk. Although the Registrant has no reason to anticipate a
serious nuclear incident, if one did occur it could have a material, but
indeterminable, adverse effect on the Registrant's financial position, results
of operations or liquidity.
Title IV of the Clean Air Act Amendments of 1990 requires the Registrant to
significantly reduce total annual sulfur dioxide (SO2) and nitrogen oxide (NOx)
emissions by the year 2000. By switching to low-sulfur coal, early banking of
emission credits and installing advanced NOx reduction combustion technology,
the Registrant is meeting these requirements.
-34-
<PAGE>
In July 1997, the United States Environmental Protection Agency (EPA) issued
regulations revising the National Ambient Air Quality Standards for ozone and
particulate matter. In May 1999, the U.S. Court of Appeals for the District of
Columbia remanded the regulations back to the EPA for review. Litigation
regarding appeals of these regulations is ongoing. New ambient standards may
result in significant additional reductions in SO2 and NOx emissions from the
Registrant's power plants by 2007. At this time, the Registrant is unable to
predict the ultimate impact of these revised air quality standards on its future
financial condition, results of operations or liquidity.
In an attempt to lower ozone levels across the eastern United States, the EPA
issued the implementation of regulations in September 1998 to reduce NOx
emissions from coal-fired boilers and other sources in 22 states, including
Missouri (where all of the Registrant's coal-fired power plant boilers are
located). The proposed regulations mandate a 75% reduction from 1990 levels by
the year 2003 and require states to develop plans to reduce NOx emissions to
help alleviate ozone problem areas. The NOx emissions reductions already
achieved on several of the Registrant's coal-fired power plants will help to
reduce the costs of compliance with these regulations. However, preliminary
analysis of the regulations indicate that selective catalytic reduction
technology may be required for some of the Registrant's units, as well as other
additional controls.
In March 2000, the U.S. Court of Appeals for the District of Columbia
substantially upheld the proposed NOx regulations but remanded portions of them
to the EPA for further consideration. The implementation date of the regulations
is uncertain and further legal challenge is possible. Assuming an implementation
date of 2003, the Registrant currently estimates that its additional capital
expenditures to comply with the final NOx regulations could range from $125
million to $150 million. Associated operations and maintenance expenditures
could increase $5 million to $8 million annually, beginning in 2003. The
Registrant is exploring alternatives to comply with these new regulations in
order to minimize, to the extent possible, its capital costs and operating
expenses. The Registrant is unable to predict the outcome of the litigation, the
regulation implementation date or the ultimate impact of these standards on its
future financial condition, results of operations or liquidity.
In November 1998, the United States signed an agreement with numerous other
countries (the Kyoto Protocol) containing certain environmental provisions,
which would require decreases in greenhouse gases in an effort to address the
"global warming" issue. The Kyoto Protocol has not been ratified by the United
States Senate. Implementation of the Kyoto Protocol in its present form would
likely result in significantly higher capital costs and operations and
maintenance expenses by the Registrant. At this time, the Registrant is unable
to determine the impact of these proposals on the Registrant's future financial
condition, results of operations or liquidity.
As of December 31, 1999, the Registrant was designated as a potentially
responsible party (PRP) by federal and state environmental protection agencies
at four hazardous waste sites. Other hazardous waste sites have been identified
for which the Registrant may be responsible but has not been designated a PRP.
Costs relating to studies and remediation at a former manufactured gas plant
site located in Illinois are being accrued and deferred rather than expensed
currently, pending recovery through environmental adjustment clause rate riders
approved by the ICC. The ICC has instituted reconciliation proceedings to review
the Registrant's environmental remediation activities to determine whether the
revenues collected from customers under its environmental adjustment clause rate
riders were consistent with the amount of remediation costs prudently and
properly incurred. Amounts found to have been incorrectly included under the
riders would be subject to refund. Rulings from the ICC are pending with respect
to these proceedings applicable to the years 1997 and 1998. The reconciliation
proceedings relating to the Registrant's 1999 environmental remediation
activities will commence by the ICC in 2000.
The Registrant continually reviews remediation costs that may be required for
all of its hazardous waste sites. Any unrecovered environmental costs are not
expected to have a material adverse effect on the Registrant's financial
position, results of operations or liquidity.
Certain employees of the Registrant are represented by the International
Brotherhood of Electrical Workers (IBEW) and the International Union of
Operating Engineers. These employees comprise approximately 77% of the
Registrant's workforce. New contracts with collective bargaining units
representing approximately 46% of these employees were ratified in 1999 with
terms expiring in 2002. Labor agreements which expired in 1999 have not been
renewed with IBEW Locals 1439, 309, 649 and 1455, who collectively represent
approximately 2,000 employees of the Registrant and Ameren Services Company.
Negotiations with Local 1455 are still ongoing. However, after engaging in
extensive good-faith bargaining with IBEW Locals 1439, 309 and 649, the
Registrant submitted a last, best and final offer to these collective bargaining
units on February 2, 2000. The offer was rejected and the Registrant informed
these locals that it would implement the noneconomic portion of its offer
effective March 6, 2000. The employees are currently working under the
noneconomic portion of the Registrant's last, best and final offer. The
Registrant is unable to predict what further action, if any, these collective
bargaining units will take or the
-35-
<PAGE>
response of the Registrant's other union represented employees to any action by
its employees. The Registrant is also unable to determine what, if any, impact
these labor matters could have on its future financial condition, results of
operations or liquidity.
Regulatory changes enacted and being considered at the federal and state levels
continue to change the structure of the utility industry and utility regulation,
as well as encourage increased competition. At this time, the Registrant is
unable to predict the impact of these changes on the Registrant's future
financial condition, results of operations or liquidity. See Note 2 - Regulatory
Matters for further information.
The Registrant is involved in other legal and administrative proceedings before
various courts and agencies with respect to matters arising in the ordinary
course of business, some of which involve substantial amounts. The Registrant
believes that the final disposition of these proceedings will not have a
material adverse effect on its financial position, results of operations or
liquidity.
NOTE 13 - Callaway Nuclear Plant
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is
responsible for the permanent storage and disposal of spent nuclear fuel. The
DOE currently charges one mill per nuclear-generated kilowatthour sold for
future disposal of spent fuel. Electric rates charged to customers provide for
recovery of such costs. The DOE is not expected to have its permanent storage
facility for spent fuel available until at least 2015. The Registrant has
sufficient storage capacity at the Callaway Plant site until 2020 and has the
capability for additional storage capacity through the licensed life of the
plant. The delayed availability of the DOE's disposal facility is not expected
to adversely affect the continued operation of the Callaway Plant.
Electric rates charged to customers provide for recovery of Callaway Plant
decommissioning costs over the life of the plant, based on an assumed 40-year
life, ending with expiration of the plant's operating license in 2024. The
Callaway site is assumed to be decommissioned using the DECON (immediate
dismantlement) method. Decommissioning costs, including decontamination,
dismantling and site restoration, are estimated to be $509 million in current
year dollars and are expected to escalate approximately 4% per year through the
end of decommissioning activity in 2033. Decommissioning costs are charged to
depreciation expense over Callaway's service life and amounted to approximately
$7 million in each of the years 1999, 1998 and 1997. Every three years, the
MoPSC and ICC require the Registrant to file updated cost studies for
decommissioning Callaway, and electric rates may be adjusted at such times to
reflect changed estimates. The latest studies were filed in 1999. Costs
collected from customers are deposited in an external trust fund to provide for
Callaway's decommissioning. Fund earnings are expected to average approximately
9% annually through the date of decommissioning. If the assumed return on trust
assets is not earned, the Registrant believes it is probable that any such
earnings deficiency will be recovered in rates. Trust fund earnings, net of
expenses, appear on the balance sheet as increases in the nuclear
decommissioning trust fund and in the accumulated provision for nuclear
decommissioning.
The staff of the SEC has questioned certain current accounting practices of the
electric utility industry, regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating stations in the
financial statements of electric utilities. In response to these questions, the
Financial Accounting Standards Board has agreed to review the accounting for
removal costs, including decommissioning. The Registrant does not expect that
changes in the accounting for nuclear decommissioning costs will have a material
effect on its financial position, results of operations or liquidity.
NOTE 14 - Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate that
value:
Cash and Temporary Investments/Short-Term Borrowings
The carrying amounts approximate fair value because of the short-term maturity
of these instruments.
Nuclear Decommissioning Trust Fund
The fair value is estimated based on quoted market prices for securities.
Preferred Stock
The fair value is estimated based on the quoted market prices for the same or
similar issues.
-36-
<PAGE>
Long-Term Debt
The fair value is estimated based on the quoted market prices for same or
similar issues or on the current rates offered to the Registrant for debt of
comparable maturities.
Derivative Financial Instruments
Market prices used to determine fair value are based on management's estimates,
which take into consideration factors like closing exchange prices,
over-the-counter prices, time value of money and volatility factors.
Carrying amounts and estimated fair values of the Registrant's financial
instruments at December 31:
1999 1998
- --------------------------------------------------------------------------------
(in millions) Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------
Preferred stock $155 $126 $155 $160
Long-term debt (including current portion) 1,894 1,872 1,791 1,919
- --------------------------------------------------------------------------------
The Registrant has investments in debt and equity securities that are held in
trust funds for the purpose of funding the nuclear decommissioning of Callaway
Nuclear Plant (see Note 13 - Callaway Nuclear Plant). The Registrant has
classified these investments in debt and equity securities as available for sale
and has recorded all such investments at their fair market value at December 31,
1999 and 1998. In 1999, 1998 and 1997, the proceeds from the sale of investments
were $83 million, $29 million and $24 million, respectively. Using the specific
identification method to determine cost, the gross realized gains on those sales
were approximately $11 million for 1999, and $2 million for both 1998 and 1997.
Net realized and unrealized gains and losses are reflected in the accumulated
provision for nuclear decommissioning on the balance sheet, which is consistent
with the method used by the Registrant to account for the decommissioning costs
recovered in rates.
Costs and fair values of investments in debt and equity securities in the
nuclear decommissioning trust fund at December 31 were as follows:
- -------------------------------------------------------------------------------
1999 (in millions) Gross Unrealized
Security Type Cost Gain (Loss) Fair Value
- -------------------------------------------------------------------------------
Debt Securities $67 $-- $-- $67
Equity Securities 45 73 -- 118
Cash equivalents 2 -- -- 2
- -------------------------------------------------------------------------------
$114 $73 $-- $187
- -------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1998 (in millions) Gross Unrealized
Security Type Cost Gain (Loss) Fair Value
- --------------------------------------------------------------------------------
Debt Securities $48 $4 $-- $52
Equity Securities 46 62 -- 108
Cash equivalents 2 -- -- 2
- --------------------------------------------------------------------------------
$96 $66 $-- $162
- --------------------------------------------------------------------------------
The contractual maturities of investments in debt securities at December 31,
1999, were as follows:
- ---------------------------------------------------------------------------
(in millions) Cost Fair Value
- ---------------------------------------------------------------------------
1 year to 5 years $6 $6
5 years to 10 years 30 30
Due after 10 years 31 31
- ---------------------------------------------------------------------------
$67 $67
- ---------------------------------------------------------------------------
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Any information concerning directors required to be reported by this item
is included under "Item (1): Election of Directors" in AmerenUE's 2000
definitive proxy statement filed pursuant to Regulation 14A and is incorporated
herein by reference.
Information concerning executive officers required by this item is reported
in Part I of this Form 10-K.
-37-
<PAGE>
ITEM 11. EXECUTIVE COMPENSATION.
Any information required to be reported by this item is included under
"Compensation" in AmerenUE's 2000 definitive proxy statement filed pursuant to
Regulation 14A and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Any information required to be reported by this item is included under
"Security Ownership of Management" in AmerenUE's 2000 definitive proxy statement
filed pursuant to Regulation 14A and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Any information required to be reported by this item is included under
"Item (1): Election of Directors" in AmerenUE's 2000 definitive proxy statement
filed pursuant to Regulation 14A and is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements and Financial Statement Schedule Covered by
Report of Independent Accountants
Pages Herein
Report of Independent Accountants................................. 17
Balance Sheet - December 31, 1999 and 1998........................ 18
Statement of Income - Years 1999, 1998, and 1997.................. 19
Statement of Cash Flows - Years 1999, 1998, and 1997.............. 20
Statement of Retained Earnings - Years 1999, 1998, and 1997....... 21
Notes to Financial Statements..................................... 22
Valuation and Qualifying Accounts (Schedule II)
Years 1999, 1998, and 1997..................................... 39
Schedules not included have been omitted because they are not
applicable or the required data is shown in the aforementioned
financial statements.
2. Exhibits: See EXHIBITS beginning on Page 41
(b) Reports on Form 8-K. The Registrant filed a report on Form 8-K
dated January 20, 2000 reporting the issuance of a Report and
Order dated December 23, 1999 by the Missouri Public Service
Commission regarding the Registrant's electric alternative
regulation plans.
-38-
<PAGE>
UNION ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C> <C>
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
========== =========== =========== ==========
Year ended December 31, 1997
Reserves deducted in the balance sheet from
assets to which they apply:
Allowance for doubtful accounts $5,195,332 $10,860,000 $12,410,004 $3,645,328
========== =========== =========== ==========
</TABLE>
Note: Uncollectible accounts charged off, less recoveries.
-39-
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
UNION ELECTRIC COMPANY
(Registrant)
CHARLES W. MUELLER
President and
Chief Executive Officer
Date March 29, 2000 By /s/ Steven R. Sullivan
------------------- ------------------------
(Steven R. Sullivan, Attorney-in-Fact)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
Signature Title
/s/ C. W. Mueller President, Chief Executive Officer and Director
- --------------------------- (Principal Executive Officer)
CHARLES W. MUELLER
/s/ Donald E. Brandt Senior Vice President and Director
- --------------------------- (Principal Financial Officer)
DONALD E. BRANDT
/s/ Warner L. Baxter Vice President, Controller and Director
- --------------------------- (Principal Accounting Officer)
WARNER L. BAXTER
/s/ Paul A. Agathen Director
- ---------------------------
PAUL A. AGATHEN
/s/ Gary L. Rainwater Director
- ---------------------------
GARY L. RAINWATER
By /s/ Steven R. Sullivan March 29, 2000
------------------------
(Steven R. Sullivan, Attorney-in Fact)
-40-
<PAGE>
EXHIBITS
Exhibits Filed Herewith
Exhibit No. Description
12 - Statement re Computation of Ratio of Earnings to Fixed Charges and
Preferred Stock Dividend Requirements.
24 - Powers of Attorney.
27 - Financial Data Schedule.
-41-
<PAGE>
Exhibits Incorporated By Reference
The following exhibits heretofore have been filed with the Securities and
Exchange Commission pursuant to requirements of the Acts administered by the
Commission. Such exhibits are identified by the references following the listing
of each such exhibit, and they are hereby incorporated herein by reference.
Exhibit No. Description
2 - Agreement and Plan of Merger, dated as of August 11, 1995, by and among
Union Electric Company, CIPSCO Incorporated, Ameren Corporation, and Arch
Merger Inc. (June 30, 1995 Form 10-Q/A (Amendment No. 1), Exhibit 2(a).)
3(i) - Restated Articles of Incorporation of the Company, as filed with the
Secretary of State of the State of Missouri. (1993 Form 10-K, Exhibit
3(i).)
3(ii)- By-Laws of the Company as amended to August 26, 1999. (September 30,
1999 Form 10-Q, Exhibit 3(ii).)
4.1 - Order of the Securities and Exchange Commission dated October 16, 1945 in
File No. 70-1154 permitting the issue of Preferred Stock, $3.70 Series.
(Registration No. 2-27474, Exhibit 3-E.)
4.2 - Order of the Securities and Exchange Commission dated April 30, 1946 in
File No. 70-1259 permitting the issue of Preferred Stock, $3.50 Series.
(Registration No. 2-27474, Exhibit 3-F.)
4.3 - Order of the Securities and Exchange Commission dated October 20, 1949 in
File No. 70-2227 permitting the issue of Preferred Stock, $4.00 Series.
(Registration No. 2-27474, Exhibit 3-G.)
4.4 - Indenture of Mortgage and Deed of Trust of the Company dated June 15,
1937, as amended May 1, 1941, and Second Supplemental Indenture dated May
1, 1941. (Registration No. 2-4940, Exhibit B-1.)
4.5 - Supplemental Indentures to Mortgage
Dated as of File Reference Exhibit No.
----------- -------------- -----------
March 1, 1967 2-58274 2.9
April 1, 1971 Form 8-K, April 1971 6
February 1, 1974 Form 8-K, February 1974 3
July 7, 1980 2-69821 4.6
May 1, 1990 Form 10-K, 1990 4.6
December 1, 1991 33-45008 4.4
December 4, 1991 33-45008 4.5
January 1, 1992 Form 10-K, 1991 4.6
October 1, 1992 Form 10-K, 1992 4.6
December 1, 1992 Form 10-K, 1992 4.7
February 1, 1993 Form 10-K, 1992 4.8
May 1, 1993 Form 10-K, 1993 4.6
August 1, 1993 Form 10-K, 1993 4.7
October 1, 1993 Form 10-K, 1993 4.8
January 1, 1994 Form 10-K, 1993 4.9
December 1, 1996 Form 10-K, 1996 4.36
-42-
<PAGE>
Exhibit No. Description
4.6 - Series A Agreement of Sale dated as of June 1, 1984 between the State
Environmental Improvement and Energy Resources Authority of the State of
Missouri and the Company, together with Letter of Credit and Reimbursement
Agreement dated as of June 1, 1984 between Citibank, N.A. and the Company
and Series A Trust Indenture dated as of June 1, 1984 between the Authority
and Mercantile Trust Company National Association, as trustee.
(Registration No. 2-96198, Exhibit 4.25.)
4.7 - Reimbursement Agreement dated as of April 21, 1992 among Swiss Bank
Corporation, various financial institutions, and the Company, providing for
an alternate letter of credit to serve as a source of payment for bonds
issued under the Series A Trust Indenture dated as of June 1, 1984. (1992
Form 10-K, Exhibit 4.23.)
4.8 - Series B Agreement of Sale dated as of June 1, 1984 between the State
Environmental Improvement and Energy Resources Authority of the State of
Missouri and the Company, together with Reimbursement Agreement dated as of
June 1, 1984 between Chemical Bank and the Company and Series B Trust
Indenture dated as of June 1, 1984 between the Authority and Mercantile
Trust Company National Association, as trustee. (Registration No. 2-96198,
Exhibit 4.26.)
4.9 - Reimbursement Agreement dated as of April 22, 1988 between Union Bank of
Switzerland and the Company, providing for an alternate letter of credit to
serve as a source of payment for bonds issued under the Series B Trust
Indenture dated as of June 1, 1984. (June 30, 1988 Form 10-Q, Exhibit 4.2.)
4.10 - Amendment and Extension Agreement dated as of June 1, 1990 to the
Reimbursement Agreement dated as of April 22, 1988 between Union Bank of
Switzerland and the Company. (1990 Form 10-K, Exhibit 4.29.)
4.11 - Amendment and Extension Agreement dated as of June 1, 1991 to the amended
Reimbursement Agreement dated as of April 22, 1988 between Union Bank of
Switzerland and the Company. (1992 Form 10-K, Exhibit 4.27.)
4.12 - Amendment Agreement dated as of June 1, 1992 to the amended Reimbursement
Agreement dated as of April 22, 1988 between Union Bank of Switzerland and
the Company. (1992 Form 10-K, Exhibit 4.28.)
4.13 - Series 1985 A Reaffirmation Agreement and Second Supplement to Agreement
of Sale dated as of June 1, 1985 between the State Environmental
Improvement and Energy Resources Authority of the State of Missouri and the
Company, together with Series 1985 A Reimbursement Agreement dated as of
June 1, 1985 between Union Bank of Switzerland and the Company and Series
1985 A Trust Indenture dated as of June 1, 1985 between the Authority and
Mercantile Trust Company National Association, as trustee and Texas
Commerce Bank National Association, as co-trustee. (June 30, 1985 Form
10-Q, Exhibit 4.1.)
4.14 - Amendment and Extension Agreement dated as of June 1, 1988 revising the
Reimbursement Agreement dated as of June 1, 1985 between Union Bank of
Switzerland and the Company. (June 30, 1988 Form 10-Q, Exhibit 4.4.)
4.15 - Amendment and Extension Agreement dated as of June 1, 1990 revising the
Reimbursement Agreement dated as of June 1, 1985, as amended, between Union
Bank of Switzerland and the Company. (1990 Form 10-K, Exhibit 4.37.)
-43-
<PAGE>
Exhibit No. Description
4.16 - Amendment and Extension Agreement dated as of June 1, 1991 to the amended
Reimbursement Agreement dated as of June 1, 1985 between Union Bank of
Switzerland and the Company. (1992 Form 10-K, Exhibit 4.32.)
4.17 - Amendment Agreement dated as of June 1, 1992 to the amended Reimbursement
Agreement dated as of June 1, 1985 between Union Bank of Switzerland and
the Company. (1992 Form 10-K, Exhibit 4.33.)
4.18 - Series 1985 B Reaffirmation Agreement and Third Supplement to Agreement
of Sale dated as of June 1, 1985 between the State Environmental
Improvement and Energy Resources Authority of the State of Missouri and the
Company, together with Series 1985 B Reimbursement Agreement dated as of
June 1, 1985 between The Long-term Credit Bank of Japan, Limited and the
Company and Series 1985 B Trust Indenture dated as of June 1, 1985 between
the Authority and Mercantile Trust Company National Association, as trustee
and Texas Commerce Bank National Association, as co-trustee. (June 30, 1985
Form 10-Q, Exhibit 4.2.)
4.19 - Reimbursement Agreement dated as of February 1, 1993 between Westdeutsche
Landesbank Girozentrale and the Company, providing for an alternate letter
of credit to serve as a source of payment for bonds issued under the Series
1985 B Trust Indenture dated as of June 1, 1985. (1992 Form 10-K, Exhibit
4.35.)
4.20 - Loan Agreement dated as of May 1, 1990 between the State Environmental
Improvement and Energy Resources Authority of the State of Missouri and the
Company, together with Indenture of Trust dated as of May 1, 1990 between
the Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1990
Form 10-K, Exhibit 4.40.)
4.21 - Loan Agreement dated as of December 1, 1991 between the State
Environmental Improvement and Energy Resources Authority and the Company,
together with Indenture of Trust dated as of December 1, 1991 between the
Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1992 Form
10-K, Exhibit 4.37.)
4.22 - Loan Agreement dated as of December 1, 1992, between the State
Environmental Improvement and Energy Resources Authority and the Company,
together with Indenture of Trust dated as of December 1, 1992 between the
Authority and Mercantile Bank of St. Louis, N.A., as trustee. (1992 Form
10-K, Exhibit 4.38.)
4.23 - Fuel Lease dated as of February 24, 1981 between the Company, as lessee,
and Gateway Fuel Company, as lessor, covering nuclear fuel. (1980 Form
10-K, Exhibit 10.20.)
4.24 - Amendments to Fuel Lease dated as of May 8, 1984 and October 15, 1984,
respectively, between the Company, as lessee, and Gateway Fuel Company, as
lessor, covering nuclear fuel. (Registration No. 2-96198, Exhibit 4.28.)
4.25 - Amendment to Fuel Lease dated as of October 15, 1986 between the Company,
as lessee, and Gateway Fuel Company, as lessor, covering nuclear fuel.
(September 30, 1986 Form 10-Q, Exhibit 4.3.)
4.26 - Credit Agreement dated as of August 15, 1989 among the Company, Certain
Lenders, The First National Bank of Chicago, as Agent and Swiss Bank
Corporation, Chicago Branch, as Co-Agent. (September 30, 1989 Form 10-Q,
Exhibit 4.)
-44-
<PAGE>
Exhibit No. Description
4.27 - Series 1998A Loan Agreement dated as of September 1, 1998 between The
State Environmental Improvement and Energy Resources Authority of the State
of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.28.)
4.28 - Series 1998B Loan Agreement dated as of September 1, 1998 between The
State Environmental Improvement and Energy Resources Authority of the State
of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.29.)
4.29 - Series 1998C Loan Agreement dated as of September 1, 1998 between The
State Environmental Improvement and Energy Resources Authority of the State
of Missouri and the Company. (September 30, 1998 Form 10-Q, Exhibit 4.30.)
10.1 - Ameren Long-Term Incentive Plan of 1998. (Ameren's 1998 Form 10-K,
Exhibit 10.1.)
10.2 - Ameren Change of Control Severance Plan. (Ameren's 1998 Form 10-K,
Exhibit 10.2.)
10.3 - Ameren Deferred Compensation Plan for Members of the Ameren Leadership
Team. (Ameren's 1998 Form 10-K, Exhibit 10.3.)
10.4 - Ameren Deferred Compensation Plan for Members of the Board of Directors.
(Ameren's 1998 Form 10-K, Exhibit 10.4.)
Note:Reports of the Company on Forms 8-K, 10-Q and 10-K are on file with the
SEC under File Number 1-2967.
Reports of Ameren on Form 10-K are on file with the SEC under File Number
1-14756.
-45-
UNION ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------------
1995 1996 1997 1998 1999
Thousands of Dollars Except Ratios
<S> <C> <C> <C> <C> <C>
Net Income $314,107 $304,876 $301,655 $320,070 $349,252
Add- Extraordinary items net of tax -- -- 26,967 -- --
---------- ---------- ---------- ---------- ----------
Net Income from continuing operations 314,107 304,876 328,622 320,070 349,252
---------- ---------- ---------- ---------- ----------
Taxes based on income 207,734 196,210 199,763 212,554 226,696
---------- ---------- ---------- ---------- ----------
Net income before income taxes 521,841 501,086 528,385 532,624 575,948
---------- ---------- ---------- ---------- ----------
Add- fixed charges:
Interest on long term debt 121,738 120,547 125,705 124,766 117,899
Other interest 7,501 7,828 9,299 1,660 (1,342)
Rentals 3,330 3,458 3,727 3,416 3,899
Amortization of net debt premium, discount,
expenses and losses 5,502 4,269 3,672 3,522 3,421
---------- ---------- ---------- ---------- ----------
Total fixed charges 138,071 136,102 142,403 133,364 123,877
---------- ---------- ---------- ---------- ----------
Earnings available for fixed charges 659,912 637,188 670,788 665,988 699,825
========== ========== ========== ========== ==========
Ratio of earnings to fixed charges 4.78 4.68 4.71 4.99 5.64
========== ========== ========== ========== ==========
Earnings required for preferred dividends:
Preferred stock dividends 13,250 13,249 8,817 8,817 8,817
Adjustment to pre-tax basis 7,558 7,363 4,257 4,649 4,544
---------- ---------- ---------- ---------- ----------
20,808 20,612 13,074 13,466 13,361
Fixed charges plus preferred stock dividend
requirements 158,879 156,714 155,477 146,830 137,238
========== ========== ========== ========== ==========
Ratio of earnings to fixed charges plus
preferred stock dividend requirements 4.15 4.06 4.31 4.53 5.09
========== ========== ========== ========== ==========
</TABLE>
Exhibit 24
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, 1999;
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 10th
day of February 2000:
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
------------------------
STATE OF MISSOURI )
) SS.
CITY OF ST. LOUIS )
On this 10th day of February, 2000, 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
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
Exhibit 27
UNION ELECTRIC COMPANY
10-K DECEMBER 31, 1999
FINANCIAL DATA SCHEDULE UT
PUBLIC UTILITY COMPANIES AND PUBLIC UTILITY HOLDING COMPANIES
APPENDIX E TO ITEM 601 (C) OF REGULATION S-K
(Thousands of Dollars)
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 5,331,820
<OTHER-PROPERTY-AND-INVEST> 186,760
<TOTAL-CURRENT-ASSETS> 707,841
<TOTAL-DEFERRED-CHARGES> 59,748
<OTHER-ASSETS> 757,393
<TOTAL-ASSETS> 7,043,562
<COMMON> 510,619
<CAPITAL-SURPLUS-PAID-IN> 701,896
<RETAINED-EARNINGS> 1,221,167
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,433,682
0
155,197
<LONG-TERM-DEBT-NET> 1,777,291
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 105,310
<LEASES-CURRENT> 11,423
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,560,659
<TOT-CAPITALIZATION-AND-LIAB> 7,043,562
<GROSS-OPERATING-REVENUE> 2,527,166
<INCOME-TAX-EXPENSE> 230,691
<OTHER-OPERATING-EXPENSES> 1,853,207
<TOTAL-OPERATING-EXPENSES> 2,083,898
<OPERATING-INCOME-LOSS> 443,268
<OTHER-INCOME-NET> 18,818
<INCOME-BEFORE-INTEREST-EXPEN> 462,086
<TOTAL-INTEREST-EXPENSE> 112,834
<NET-INCOME> 349,252
8,817
<EARNINGS-AVAILABLE-FOR-COMM> 340,435
<COMMON-STOCK-DIVIDENDS> 328,674
<TOTAL-INTEREST-ON-BONDS> 112,076
<CASH-FLOW-OPERATIONS> 724,963
<EPS-BASIC> 0.00 <F1>
<EPS-DILUTED> 0.00 <F1>
<FN>
<F1> Information not normally disclosed in financial statements and notes.
</FN>
</TABLE>
