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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, 1998
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 (I.R.S. Employer Identification No.)
of 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
5, 1999 , based on closing prices most recently available as reported in the The
Wall Street Journal (excluding Preferred Stock for which quotes are not publicly
available: $52,371,815.
Shares of Common Stock, $5 par value, outstanding as of March 5, 1999:
102,123,834 shares (all owned by Ameren Corporation).
Documents incorporated by references.
Portions of the registrant's definitive proxy statement for the 1999
annual meeting are incorporated by reference into Part III.
TABLE OF CONTENTS
PART I Page
Item 1-Business
General............................................................. 1
Capital Program and Financing....................................... 1
Rates............................................................... 2
Fuel Supply......................................................... 3
Regulation.......................................................... 3
Industry Issues..................................................... 4
Item 2-Properties........................................................... 5
Item 3-Legal Proceedings.................................................... 6
Item 4-Submission of Matters to a Vote of Security Holders
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.............................................. 8
Item 7-Management's Discussion and Analysis of Financial Condition
and Results of Operations........................................... 8
Item 7A-Quantitative and Qualitative Disclosures about Market Risk.......... 17
Item 8-Financial Statements and Supplementary Data.......................... 19
Item 9-Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure
PART III
Item 10-Directors and Executive Officers of the Registrant ............. 37
Item 11-Executive Compensation ......................................... 37
Item 12-Security Ownership of Certain Beneficial Owners
and Management .............................................. 37
Item 13-Certain Relationships and Related Transactions ................. 38
PART IV
Item 14-Exhibits, Financial Statement Schedules and Reports on Form 8-K..... 38
SIGNATURES ................................................................. 40
EXHIBITS .................................................................. 41
___________________
Not applicable and not included herein.
Incorporated herein by reference.
PART I
ITEM 1. BUSINESS.
GENERAL
Union Electric Company (UE, 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, Union Electric
Company (UE) and CIPSCO Incorporated (CIPSCO) combined with the result that the
common shareholders of UE and CIPSCO became the common shareholders of Ameren,
and Ameren became the owner of 100% of the common stock of UE and CIPSCO's
operating subsidiaries, Central Illinois Public Service Company (CIPS) and
CIPSCO Investment Company (the Merger).
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 1998, 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 1997 and 1996 were
also 96%.
The Registrant employed 4,365 persons at December 31, 1998. Approximately
76% of such employees are represented by local unions affiliated with the
AFL-CIO. Labor agreements covering 97% of the represented employees will expire
in 1999 and labor agreements covering approximately 100 employees expire in
2000.
CAPITAL PROGRAM AND FINANCING
The Registrant is engaged in a capital program under which construction
expenditures are expected to approximate $230 million in 1999. For the five-year
period 1999-2003, construction expenditures are estimated at $1.5 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 1998, gross additions to the property of
the Registrant, including allowance for funds used during construction and
excluding nuclear fuel, were approximately $1.4 billion (including $208 million
in 1998) and property retirements were $309 million.
In addition to the funds required for construction during the 1999-2003
period, $292 million will be required to repay long-term debt as follows: $117
million in 1999; $75 million in 2002; and $100 million in 2003. Amounts for
years subsequent to 1999 do not include UE's nuclear fuel lease payments since
the amounts of such payments are not currently determinable.
For information on the Registrant's external cash sources, see "Liquidity
and Capital Resources" in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" under Item 7 herein.
Financing Restrictions. Under the most restrictive earnings test contained
in UE'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 UE's net earnings available for interest after depreciation
for 12 consecutive months within the 15 months preceding such issuance are at
1
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, 1998 was 6.8, which would permit
UE to issue an additional $2.9 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,
1998, the aggregate amount of Bonds issuable under (a) and (b) above was
approximately $2.3 billion.
UE's Restated Articles of Incorporation restrict UE 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, 1998 was 36.0, which would
permit UE to issue an additional $1.4 billion stated value of Preferred Stock
(8% annual dividend rate assumed). Certain other financing arrangements require
UE to obtain prior consents to various actions by UE, 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 1998, approximately 82%, 7%, 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.
The electric utility restructuring legislation in Illinois included a 5%
residential rate decrease for the Registrant's Illinois electric customers,
effective August 1, 1998. This rate decrease reduced electric revenues
approximately $1 million in 1998 and is expected to reduce electric revenues by
approximately $3 million annually thereafter, based on estimated levels of sales
and assuming normal weather conditions. See "Regulation" for additional
reference to this legislation.
The Registrant was also subject to an electric rate decrease for its
Missouri customers, effective September 1, 1998. This rate decrease is based on
the weather-adjusted average annual credits to customers under an experimental
alternative regulation plan that ran from July 1, 1995 through June 30, 1998.
The Registrant estimates that its Missouri electric rate decrease should
approximate $15 million to $20 million on an annualized basis. However, the
MoPSC staff has proposed adjustments to the Registrant's estimate. The staff's
adjustments, if ultimately accepted, could increase the Registrant's proposed
Missouri rate decrease by $15 million to $20 million.
As permitted by electric utility restructuring legislation in Illinois, in
1998, the Registrant filed to eliminate the fuel adjustment clause on sales of
electricity in Illinois, thereby including a historical level of fuel costs in
base rates. The ICC approved the Registrant's filing in April 1998.
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.
In June 1998, the Registrant filed a request with the ICC to increase rates
for natural gas service in its Illinois jurisdiction. In February 1999, the ICC
approved a $1 million annual rate increase. The rate increase became effective
in February 1999.
For additional information on "Rates", see Note 2 to the "Notes to
Financial Statements" under Item 8 herein.
2
FUEL SUPPLY
Cost of Fuels Year
- ------------- ---------------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Per Million BTU - Coal 100.015(cent) 105.600(cent) 112.250(cent) 117.645(cent) 123.950(cent)
- Nuclear 48.803(cent) 47.472(cent) 47.499(cent) 48.592(cent) 49.932(cent)
- System 90.378(cent) 92.816(cent) 96.596(cent) 101.590(cent) 101.867(cent)
Per kWh of Steam Generation .968(cent) .979(cent) 1.024(cent) 1.068(cent) 1.064(cent)
Oil and Gas. The actual and prospective use of such fuels is minimal, and
the Registrant has not experienced and does not expect to experience difficulty
in obtaining adequate supplies.
Coal. Because of uncertainties of supply due to potential work stoppages,
equipment breakdowns and other factors, the Registrant has a policy of
maintaining a coal inventory consistent with its expected burn practices.
Nuclear. The components of the nuclear fuel cycle required for nuclear
generating units are as follows: (1) uranium; (2) conversion of uranium into
uranium hexafluoride; (3) enrichment of uranium hexafluoride; (4) conversion of
enriched uranium hexafluoride into uranium dioxide and the fabrication into
nuclear fuel assemblies; and (5) disposal and/or reprocessing of spent nuclear
fuel.
The Registrant has agreements and/or inventories to fulfill its Callaway
Nuclear Plant needs for uranium, enrichment, fabrication and conversion services
through 2002. Additional contracts will have to be entered into in order to
supply nuclear fuel during the remainder of the life of the Plant, at prices
which cannot now be accurately predicted. The Callaway Plant normally requires
refueling at 18-month intervals, with the next regular refueling presently
scheduled for the fall of 1999. The Registrant anticipates that it will be
necessary to perform a special refueling at the Plant for about two weeks in
April 1999 to replace certain fuel assemblies. This action is required to
maintain the full generating capability of the Callaway Plant until the
scheduled fall 1999 refueling.
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 2004 and is pursuing a
viable storage alternative. This alternative has been approved by the Nuclear
Regulatory Commission, and when implemented, will provide sufficient spent fuel
storage for 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 Callaway Plant.
For additional information on the Registrant's "Fuel Supply", see Notes 11
and 12 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. 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
3
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.
In December 1997, the Governor of Illinois signed the Electric Service
Customer Choice and Rate Relief Law of 1997 providing for electric utility
restructuring in Illinois. This legislation introduces competition into the
supply of electric energy in Illinois and, as a result, retail direct access,
which allows customers to choose their electric generation supplier, 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. For a discussion of the
Illinois legislation, as well as the current status of electric utility
restructuring in Missouri, 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.
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.
UE 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 11 to the "Notes to Financial
Statements" under Item 8 herein for a discussion of environmental issues.
Other aspects of the Registrant's business are subject to the jurisdiction
of various regulatory authorities and, for additional information on regulation
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 11 to the "Notes to Financial Statements" under Item 8 herein.
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; 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 "Electric
Industry Restructuring" in Management's Discussion and Analysis of Financial
Condition and Results of Operations" under Item 7 herein and Notes 2 and 11 to
the "Notes to Financial Statements" under Item 8 herein.
Year 2000 Issue. The Year 2000 Issue relates to how dates are stored and
used in computer systems, applications, and embedded systems. As the century
date change occurs, certain date-sensitive systems need to be able to recognize
the year as 2000 and not as 1900. This inability to recognize and
4
properly treat the year as 2000 may cause these systems to process critical
financial and operational information incorrectly. 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 1.7% and peak load
growth of 1.2%, each compounded annually, and is providing for a minimum reserve
margin of approximately 15% to 18% 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 UE and CIPS. Ameren has
interconnections for transmission service and the exchange of electric energy,
directly and through the facilities of others, with twenty private utilities and
nine government utilities that operate control areas.
The Registrant owns 40% of the capital stock of Electric Energy, Inc.
("EEI"), and its affiliate, CIPS, owns 20% of such stock. The balance is held by
two other sponsoring companies -- Kentucky Utilities Company ("KU"), and
Illinova Generating ("IG"). EEI owns and operates a generating plant with a
nominal capacity of 1,000 mW. 60% of the plant's output is committed to the
Paducah Project of the DOE, 20% to KU, 10% to UE, and 5% each to IG and CIPS.
As of December 31, 1998, 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.
UE 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 Company's Keokuk Plant is located.
Substantially all of UE'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.
5
The following table sets forth information with respect to the Registrant's
generating facilities and capability at the time of the expected 1999 peak.
Gross Kilowatt
Energy Installed
Source Plant Location 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 925,000
----------
Total Coal 5,555,000
Nuclear Callaway Callaway County, MO 1,196,000
Hydro Osage Lakeside, MO 212,000
Keokuk Keokuk, IA 126,000
------------
Total Hydro 338,000
Oil and Venice Venice, IL 442,000
Natural Other Various 381,000
Gas ------------
Total Oil and
Natural Gas 823,000
Pumped-
storage Taum Sauk Reynolds County, MO 440,000
------------
TOTAL 8,352,000
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
"Rates" under Item 1 herein and Notes 2 and 11 to the "Notes to Financial
Statements" under Item 8 herein.
__________________________
Statements made in this report which are not based on historical facts, are
forward-looking and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
forward-looking statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions and
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.
Factors include, but are not limited to, the effects of: regulatory actions;
changes in laws and other governmental actions; competition; future market
prices for fuel and
6
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; monetary and fiscal policies; future wages and
employee benefits costs; and legal and administrative proceedings.
INFORMATION REGARDING EXECUTIVE OFFICERS REQUIRED BY ITEM 401(b) OF REGULATION S-K:
Age At Date First Elected
Name 12/31/98 Present Position or Appointed
---- -------- ---------------- ------------
Charles W. Mueller 60 President, 7/1/93
Chief Executive Officer 1/1/94
and Director 6/11/93
Donald E. Brandt 44 Senior Vice President 7/1/88
and Director 4/28/98
Charles J. Schukai 64 Senior Vice President 7/1/88
and Director 4/28/98
Warner L. Baxter 37 Vice President 5/1/98
and Controller 8/1/96
William J. Carr 61 Vice President 10/1/88
Michael J. Montana 52 Vice President 7/1/88
Garry L. Randolph 50 Vice President 3/1/91
Robert J. Schukai 60 Vice President 7/1/88
William C. Shores 60 Vice President 7/1/88
Steven R. Sullivan 38 Vice President, General Counsel 7/1/98
and Secretary 9/1/98
Jerre E. Birdsong 44 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. There are no family relationships between the foregoing officers of UE
except that Charles J. Schukai and Robert J. Schukai are brothers. 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.
7
ITEM 6. SELECTED FINANCIAL DATA.
For the Years Ended
December 31 (In Thousands) 1998 1997 1996 1995 1994
- ------------------------- ---- ---- ---- ---- ----
Operating revenues $2,382,071 $2,287,333 $2,260,364 $2,242,364 $2,223,938
Operating income 428,183 448,827 428,314 441,896 450,186
Net income 320,070 301,655 304,876 314,107 320,757
Preferred stock dividends 8,817 8,817 13,249 13,250 13,252
Net income after preferred
stock dividends 311,253 292,838 291,627 300,857 307,505
Common stock dividends 259,599 259,395 256,331 250,714 244,586
As of December 31,
Total assets $6,829,864 $6,802,285 $6,870,809 $6,754,469 $6,624,701
Long-term debt 1,674,311 1,846,482 1,798,671 1,763,613 1,823,489
Total common stockholder's equity 2,424,125 2,387,454 2,354,801 2,319,197 2,269,054
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 wholly-owned subsidiaries of Ameren (the
Merger).
RESULTS OF OPERATIONS
Earnings
Earnings for 1998, 1997, and 1996 were $311 million, $293 million, and $292
million, respectively. Earnings fluctuated due to many conditions, primarily:
weather variations, electric rate reductions, competitive market forces, credits
to electric customers, sales growth, fluctuating operating costs (including
Callaway Nuclear Plant refueling outages), merger-related expenses, changes in
interest expense, changes in income and property taxes, a charge for a targeted
employee separation plan in 1998 and an extraordinary charge in 1997.
In 1998, the Registrant recorded a nonrecurring charge to earnings in connection
with a targeted separation plan it offered to employees in July 1998. The charge
reduced earnings $11 million, net of income taxes (see Note 3 - 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, 1998, 1997, and 1996 are detailed in the following pages.
Electric Operations
Electric Revenues Variations from Prior Year
- -------------------------------------------- -------- -------- --------
(Millions of Dollars) 1998 1997 1996
- -------------------------------------------- -------- -------- --------
Rate variations $ (8) $ -- $ (20)
Credit to customers (24) 28 (15)
Effect of abnormal weather 48 4 (63)
Growth and other 48 1 96
Interchange sales 38 (5) 9
- -------------------------------------------- ------ ------ ------
$ 102 $ 28 $ 7
- -------------------------------------------- -------- -------- -------
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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. Upon consummation of the Merger, AmerenUE and AmerenCIPS began
jointly dispatching generation, therefore allowing Ameren to utilize the most
cost efficient plants of both operating companies to serve customers in either
service territory.
The increase in 1997 electric revenues was primarily due to a lower Missouri
customer credit recorded in 1997. Kilowatthour sales in 1997 remained unchanged
compared to the same period in 1996. Residential sales remained flat while
interchange sales decreased 5%. Commercial and industrial sales were 1% and 3%
higher, respectively.
The increase in 1996 electric revenues was due to a 4% increase in kilowatthour
sales over the year-ago period, partly offset by the 1.8% rate decrease for
Missouri electric customers and the net increase in customer credits recorded
during 1996 versus 1995. The kilowatthour sales increase reflected strong
economic growth in AmerenUE's service area and increased interchange sales
opportunities, partially offset by milder weather during the period. Residential
and commercial sales each rose 3% over 1995, while industrial sales grew 2% and
interchange sales increased 7%.
Fuel and Purchased Power Variations from Prior Year
- ------------------------------------------------------------------------
(Millions of Dollars) 1998 1997 1996
- ------------------------------------------------------------------------
Fuel:
Variation in generation $ 24 $ 17 $ 15
Price (10) (15) (18)
Generation efficiencies and other 5 (1) 3
Purchased power variation 11 (14) 8
- ------------------------------------------------------------------------
$ 30 $(13) $ 8
- ------------------------------------------------------------------------
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. 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. The increase in
1996 fuel and purchased power costs was driven mainly by higher kilowatthour
sales, partially offset by lower fuel prices.
While unprecedented prices for power purchases occurred in the marketplace
during the last week of June 1998, the Registrant was able to effectively manage
its power costs in the face of soaring wholesale electricity prices. Overall,
the abnormally high prices for power purchases in June had little impact on the
Registrant's financial results for 1998.
Gas Operations
Gas revenues in 1998 decreased $7 million compared to 1997, primarily due to an
8% decline in retail sales resulting from mild winter 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 revenues in 1997 were
relatively flat compared to 1996. The increase in 1996 gas revenues was
primarily due to higher sales. Weather-sensitive residential and commercial
sales increased 7% and 9%, respectively, while industrial sales declined 15%
compared to the prior year.
Gas costs in 1998 declined $14 million compared to 1997, primarily due to lower
sales and lower gas prices. Gas costs for 1997 remained flat as compared to
those of 1996. In 1996, gas costs increased $13 million primarily due to a 26%
rise in natural gas purchased for resale (due to higher sales and gas prices).
9
Other Operating Expenses
Other operations expense variations in 1996 through 1998 reflected recurring
factors such as growth, inflation, and labor and benefit increases, in addition
to a charge for the targeted separation plan (TSP) as discussed below.
In March 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. In July 1998, Ameren offered separation
packages to employees whose positions were to be eliminated through the TSP.
During the third quarter of 1998, the Registrant recorded a nonrecurring,
pre-tax charge of $18 million (which reduced earnings $11 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 the Registrant expects
operating expenses to be reduced approximately $14 million to $18 million
annually thereafter. See Note 3 - Targeted Separation Plan under Notes to
Financial Statements for further information.
The $57 million increase in other operations 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 operations
expense increased $26 million primarily due to increased information
system-related expenses. In 1996, other operations expense increased $11 million
primarily due to increased employee benefits, injuries and damages and
information system-related costs.
Maintenance expenses increased $5 million in 1998, compared to 1997, due to the
scheduled spring refueling outage at the Callaway Nuclear Plant; partially
offset by less scheduled fossil plant maintenance. The spring 1998 refueling was
completed in 31 days. There was no refueling outage in 1997. 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. In 1996, maintenance
expenses increased $2 million primarily due to increased labor expenses at
Callaway Plant and fossil plants.
Depreciation and amortization expense increased $12 million in 1998, compared to
1997, primarily 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. Depreciation and amortization
expense increased $7 million in 1997 and $8 million in 1996, due to increased
depreciable property.
Taxes
Income tax expense from operations increased $25 million in 1998, compared to
1997, due to higher pre-tax 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. Income tax expense from operations decreased $12 million in
1996 principally due to lower pre-tax income.
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. Miscellaneous, net increased $2 million for 1996,
primarily due to reduced merger-related expenses.
Interest
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. In 1996, interest expense declined $2 million
primarily due to lower debt outstanding during the year and lower rates on
variable-rate long-term debt.
Balance Sheet
The $36 million decrease in accounts receivable at December 31, 1998, compared
to 1997, was due to lower sales and revenues in November and early December
1998, compared to the comparable time period in 1997, due to mild winter
weather. The Registrant's service territory experienced much colder weather in
the latter part of December 1998, resulting in higher sales and revenues at that
time compared to the comparable 1997 period. This increase in sales caused a $26
million increase in unbilled revenues.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $651 million for 1998, compared to
$602 million and $605 million in 1997 and 1996, respectively.
10
Cash flows used in investing activities totaled $231 million, $284 million, and
$363 million for the years ended December 31, 1998, 1997 and 1996, respectively.
Expenditures in 1998 for constructing new or to improve existing facilities and
purchasing rail cars were $222 million. In addition, the Company spent $20
million to acquire nuclear fuel.
Construction expenditures are expected to approximate $230 million in 1999. For
the five-year period 1999-2003, construction expenditures are estimated at $1.5
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.
Under Title IV of the Clean Air Act Amendments of 1990, the Registrant is
required to significantly reduce total annual sulfur dioxide (SO2) and nitrogen
oxide (NOx) emissions by the year 2000. By switching to low-sulfur coal, early
banking of emissions credits and installing low NOx burner technology, the
majority of these reductions have been achieved.
In July 1997, the United States Environmental Protection Agency (EPA) issued
final regulations revising the National Ambient Air Quality Standards for ozone
and particulate matter. The new ambient standards may result in significant
additional reductions in SO2 and NOx emissions from the Registrant's power
plants. The new particulate matter standards may require SO2 reductions of up to
50% beyond that already required by Phase II acid rain control provisions of the
1990 Clean Air Act Amendments and could be required by 2007. The full details of
these requirements are under study by the Registrant. At this time, the
Registrant in 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 final 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). Although
reduction requirements in NOx emissions from the Registrant's coal-fired boilers
are anticipated to exceed 75 percent from 1990 levels by the year 2003, it is
not yet possible to determine the exact magnitude of the reductions required
from the Registrant's power plants because each state has up to one year to
develop a plan to comply with the EPA rule. The NOx emissions reductions already
achieved on several of the Registrant's coal-fired power plants will help to
reduce the costs of compliance with this regulation. However, preliminary
analysis of the regulations indicate that selective catalytic reduction
technology will be required for some of the Registrant's units, as well as other
additional controls.
Currently, the Registrant estimates that its additional capital expenditures to
comply with the EPA's final regulations issued in September 1998, could range
from $125 million to $175 million over the period from 1999 to 2002. Associated
operations and maintenance expenditures could increase $5 million to $8 million
annually, beginning in 2003. The Registrant will explore alternatives to comply
with these new regulations in order to minimize, to the extent possible, its
capital costs and operating expenses. The Registrant is unable to predict the
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 must be ratified by the United States
Senate before provisions are effective for the United States. Until ratification
is obtained, the Registrant is unable to predict what requirements, if any, will
be adopted in this country; however, 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.
In April 1999, the Registrant anticipates that it will be necessary to perform a
special refueling at the Callaway Nuclear Plant for about two weeks to replace
certain fuel assemblies. This refueling is required to maintain the full
generating capability of the Callaway Plant until the scheduled fall 1999
refueling, and is not expected to have a material adverse effect on the
Registrant's financial condition, results of operation and liquidity. See Note
12 - Callaway Nuclear Plant under Notes to Financial Statements for a discussion
of Callaway Plant decommissioning costs.
Cash flows used in financing activities were $376 million for 1998, compared to
$320 million and $238 million for 1997 and 1996, respectively. The Registrant's
principal financing activities during 1998 included the redemption of $195
million of long-term debt, the issuance of $160 million of long-term debt, and
the payment of dividends.
11
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) 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,
1998, the Registrant had committed bank lines of credit aggregating $137 million
(all of which were unused 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 2000, which permits the
borrowing of up to $300 million on a long-term basis, all of which was unused
and available at December 31, 1998. Also, Ameren has a bank credit agreement due
2003, which permits the borrowing of up to $200 million on a long-term basis.
This credit agreement is available to Ameren and its subsidiaries, including the
Registrant. As of December 31, 1998, $190 million was available for the
Registrant's use.
Additionally, the Registrant has a lease agreement that provides for the
financing of nuclear fuel. At December 31, 1998, the maximum amount that could
be financed under the agreement was $120 million. Cash used in financing for
1998 included redemptions under the lease for nuclear fuel of $68 million offset
in part by $16 million of issuances. At December 31, 1998, $67 million was
financed under the lease. See Note 5 - Nuclear Fuel Lease under Notes to
Financial Statements for further information.
RATE MATTERS
See Note 2 - Regulatory Matters under Notes to Financial Statements for a
discussion of rate matters.
ELECTRIC INDUSTRY RESTRUCTURING
Changes enacted and being considered at the federal and state levels continue to
change the structure of the electric industry and utility regulation, as well as
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 that 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 stranded 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 ten other utility companies which
support the formation of the Midwest Independent System Operator (Midwest ISO).
An ISO operates, but does not own, transmission systems and maintains system
reliability and security while alleviating pricing issues associated with the
"pancaking" of rates. The Midwest ISO would be regulated by FERC. The FERC
conditionally approved the formation of the Midwest ISO in September 1998, and
it is expected to be operational by the year 2001. The Registrant's membership
in the Midwest ISO must be approved by the Missouri Public Service Commission
(MoPSC). The Midwest ISO covers eight states and represents portions of 40,000
miles of transmission line and 62,000 megawatts of electric power. Collectively,
the member companies serve more than seven million customers.
In addition, 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
12
Relief Law of 1997 (the Law) providing for electric utility restructuring in
Illinois. This legislation introduces competition into the supply of electric
energy in Illinois.
Major provisions of the Law include the phasing-in through 2002 of retail direct
access, which allows customers to choose their electric generation supplier. In
addition, the Law includes a 5% rate decrease for residential customers that
became effective in August 1998. The decrease reduced electric revenues by
approximately $1 million in 1998 and is expected to reduce electric revenues by
approximately $3 million annually thereafter, based on estimated levels of sales
and assuming normal weather conditions. In 1998, the Registrant eliminated its
Uniform Fuel Adjustment Clause (FAC) as allowed by the Law, which the Registrant
expects to benefit shareholders in the future. (See Note 1 - Summary of
Significant Accounting Policies under Notes to Financial Statements for further
information.) The Law contains a provision allowing for the potential recovery
of a portion of strandable costs, which represent costs which would not be
recoverable in a restructured environment, through a transition charge collected
from customers who choose an alternate electric supplier. In addition, the Law
contains a provision requiring a portion of excess earnings (as defined under
the Law) for the years 1998 through 2004 to be refunded to customers. See Note 2
- - Regulatory Matters under Notes to Financial Statements for further
information.
In December 1997, after evaluating the impact of the Law, the Registrant
determined that it was necessary to write-off the generation-related regulatory
assets and liabilities of its Illinois retail electric business. This
extraordinary charge reduced 1997 earnings $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.
In Missouri, where approximately 92% of the Company'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 legislative committee is also conducting hearings on these
issues. The Registrant is unable to predict the timing or ultimate outcome of
electric industry restructuring in the state of Missouri.
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 expense. The Registrant is actively taking steps to
mitigate these negative consequences. Most importantly, the Registrant will
continue to focus on cost control to ensure that it maintains a competitive cost
structure. Also, in Illinois, the Registrant's actions include strengthening its
marketing operations to maintain its current customers and obtain new customers,
as well as enhancing its information systems. 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 shareholders. The
Registrant is also actively involved in shaping the policies of the Midwest ISO
to protect 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 occurs,
certain date-sensitive systems need to be able to recognize the year as 2000 and
not as 1900. This inability to recognize and properly treat the year as 2000 may
cause these systems to process critical financial and operational information
incorrectly. The Registrant's primary concern is the potential for any
interruption in providing electric and gas service to customers, as well as the
potential inability to process critical financial and operational information on
a timely basis, including billing its customers, if appropriate steps are not
taken to address this issue. Management has developed a Year 2000 plan (Plan)
covering Ameren, including AmerenUE, and Ameren's Board of Directors has been
briefed about the Year 2000 Issue and how it may affect the Registrant.
Ameren's Plan to resolve the Year 2000 Issue involves three phases: assessment,
planning, and implementation/testing. Implementation of the Plan is directly
supervised by each area's responsible Vice President. A Year 2000 Project
Director coordinates the implementation of the Plan among functional teams who
are addressing issues specific to a particular area, such as nuclear and
non-nuclear generation facilities, energy management systems, gas
13
distribution, etc. Ameren has also engaged certain outside consultants,
technicians and other external resources to aid in formulating and implementing
the Plan.
Ameren has completed its assessment phase, which included analyzing
date-sensitive electronic hardware, software applications and embedded systems
and has developed a compliance plan to address issues that were identified. Many
of the major corporate computer systems at Ameren are relatively new and
therefore are either Year 2000 compliant or only require minor modifications.
Also, several of the operating hardware and embedded systems (i.e.,
microprocessor chips) use analog rather than digital technology and thus are
unaffected by the two-digit date issue. In addition, Ameren has contacted
hundreds of vendors and suppliers to verify compliance.
Ameren has also completed its planning phase. Items that have been identified
for remediation have been prioritized into groups based on their significance to
Ameren's operations. The implementation/testing phase for all
components/applications is approximately 45% complete as of December 31, 1998.
Ameren expects to complete remediation of its significant
components/applications by the end of the third quarter 1999.
With respect to third parties, for areas that interface directly with
significant vendors, Ameren has inventoried vendors and major suppliers and is
currently assessing their Year 2000 readiness through surveys, websites and
personal contact. Ameren plans to follow up with major suppliers and vendors and
verify Year 2000 compliance, where appropriate. Ameren has also queried its
health insurance providers. To date, Ameren is not aware of any problems that
would materially impact its financial condition, results of operations or
liquidity; however, neither Ameren nor the Registrant has the means of ensuring
that these parties will be Year 2000 compliant. The inability of those parties
to complete their Year 2000 resolution process could materially impact Ameren
and the Registrant.
Ameren is also addressing the impact of electric power grid problems that may
occur outside of its own electric system. Ameren has started Year 2000 electric
power grid impact planning through the system's various electric interconnection
affiliations and is working with the Mid-American Interchange Network (MAIN) to
begin planning Year 2000 operational preparedness and restoration scenarios. As
of January 31, 1999 (the latest information available), MAIN was 99% complete
with its assessment phase, 94% complete with its planning phase and 53% complete
with its implementation/testing phase. In addition, Ameren provides monthly
status reports to the North American Electric Reliability Council (NERC) to
assist them in assessing Year 2000 readiness of the regional electric grid. As
of January 31, 1999 (the latest information available), NERC was 98% complete
with its assessment phase, 90% complete with its planning phase and 57% complete
with its implementation/testing phase. Through the Electric Power Research
Institute (EPRI), an industry-wide effort has been established to deal with Year
2000 problems affecting digital systems and equipment used by the nation's
electric power companies. Under this effort, participating utilities are working
together to assess specific vendors' system problems and test plans. The
assessment will be shared by the industry as a whole to facilitate Year 2000
problem solving.
In addressing the Year 2000 Issue, Ameren will incur internal labor costs as
well as external consulting and other expenses to prepare for the new century.
Ameren estimates that its external costs (consulting fees and related costs) for
addressing the Year 2000 Issue will range from $10 million to $15 million. As of
December 31, 1998, Ameren has expended approximately $2.4 million. Ameren's
plans to complete Year 2000 modifications are based on management's best
estimates, which are derived utilizing numerous assumptions of future events
including the continued availability of certain resources, and other factors.
However, there can be no guarantee that these estimates will be achieved and
actual results could differ materially from those plans. Specific factors that
might cause such material differences include, but are not limited to, the
availability and cost of personnel trained in this area, the ability to locate
and correct all relevant computer codes, and similar uncertainties.
Ameren believes that, with appropriate modifications to existing computer
systems/components, updates by vendors and trading partners, and conversion to
new software and hardware in the ordinary course of business, the Year 2000
Issue will not pose significant operational problems for the Registrant.
However, if such conversions are not completed in a proper and timely manner by
all affected parties, the Year 2000 Issue could result in material adverse
operational and financial consequences to the Registrant, and there can be no
assurance that Ameren's efforts, or those of vendors and trading partners,
interconnection affiliates, NERC or EPRI to address the Year 2000 Issue will be
successful. Ameren is in the process of developing contingency plans to address
potential risks, including risks of vendor/trading partners noncompliance, as
well as noncompliance of any of the Registrant's material operating systems. The
first operational contingency plan addressing power grid issues is expected to
be completed by the end of the first quarter 1999. Contingency plans related to
the business areas are expected to be completed by the end of the second quarter
1999. At this time, the Registrant is unable to predict the ultimate impact, if
any, of the Year 2000 Issue on the Registrant's financial condition, results of
operations or liquidity; however, the impact could be material.
14
CONTINGENCIES
See Note 11 - Commitments and Contingencies and Note 2 - Regulatory Matters
under Notes to Financial Statements for material issues existing at December 31,
1998.
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 interest rates and
equity prices. The following discussion of Ameren's, including AmerenUE's, risk
management activities includes forward-looking statements that involve risks and
uncertainties. Actual results could differ materially from those projected in
the "forward-looking" statements. Ameren handles market risks in accordance with
established policies, which may include entering into various derivative
transactions. In the normal course of business, Ameren also faces risks that are
either non-financial or non-quantifiable. Such risks principally include credit
risk and legal 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 1% in 1999 as compared to 1998, the Registrant's
interest expense would increase by approximately $5 million and net income would
decrease by approximately $3 million. This amount has been determined using the
assumptions that the Registrant's outstanding variable rate debt as of December
31, 1998, continued to be outstanding throughout 1999, and that the average
interest rates for these instruments increased 1% over 1998. The model does not
consider the effects of the reduced level of overall economic activity that
would exist in such an environment. In the event of a significant change in
interest rates, management would likely take actions to further mitigate its
exposure to this market risk. However, due to the uncertainty of the specific
actions that would be taken and their possible effects, the sensitivity analysis
assumes no change in the Registrant's financial structure.
Commodity Price Risk
The Registrant is exposed to changes in market prices for natural gas and fuel
and purchased power. 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 AmerenUE 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 is participating in an experimental
program to control the volatility of gas prices paid by its Missouri customers
in the winter months through the purchase of financial instruments.
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 11 - Commitments and Contingencies under Notes to
Financial Statements for further information). With regard to the Registrant's
exposure to commodity risk for purchased power, Ameren has established a
subsidiary, AmerenEnergy, Inc., whose primary responsibility includes managing
market risks associated with the changing market prices for purchased power for
the Registrant.
AmerenEnergy utilizes several techniques to mitigate its market risk for
purchased power, 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 and futures 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, 1998, the fair value of derivative financial instruments
exposed to commodity price risk was immaterial. The Registrant expects an
increase in the derivative financial instruments used to manage risk in 1999 due
to expected growth at AmerenEnergy.
15
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 12 - Callaway Nuclear Plant under Notes to
Financial Statements for further information). As of December 31, 1998, 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 its November 1998 meeting, the Emerging Issues Task Force of the Financial
Accounting Standards Board (EITF) reached a consensus on EITF Issue 98-10,
"Accounting for Energy Trading and Risk Management Activities." 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 non-trading. 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. EITF 98-10 includes factors or indicators to consider when determining
if a transaction is a trading or non-trading activity. EITF 98-10 will be
effective beginning in 1999. Currently, AmerenEnergy enters into contracts for
the sale and purchase of energy on behalf of the Registrant. These transactions
are considered nontrading activities and are accounted for using the accrual or
settlement method, which represents industry practice. Should any of
AmerenEnergy's future activities be considered trading activities based on the
indicators provided in EITF 98-10, the related transaction may need to be
measured at fair value and recognized in the balance sheet, with a gain or less
included in earnings. EITF 98-10 is not expected to have a material impact on
the Registrant's financial position or results of operations upon adoption. Many
of the provisions of EITF 98-10 will likely be superseded by Statement of
Financial Accounting Standards (SFAS) 133, "Accounting for Derivative
Instruments and Hedging Activities" (see below).
In June 1998, the Financial Accounting Standards Board issued SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities and requires recognition of all derivatives on the
balance sheet measured at fair value. SFAS 133 is effective for all fiscal
quarters of all fiscal years beginning after June 15, 1999. Earlier application
is encouraged. SFAS 133 cannot be applied retroactively. At this time, the
Registrant is unable to determine the impact of SFAS 133 on its financial
position or results of operations upon adoption.
In March 1998, the Accounting Standards Executive Committee of the American
Institute of Certified Public Accountants issued Statement of Position (SOP)
98-1, "Accounting for the Costs of Computer Software Developed or Obtained for
Internal Use." 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, which are currently expensed by the Registrant, may be
capitalized and amortized over some future period. SOP 98-1 is effective for
fiscal years beginning after December 15, 1998. SOP 98-1 is not expected to have
a material impact on the Registrant's financial position or results of
operations upon adoption.
EFFECTS OF INFLATION AND CHANGING PRICES
The Registrant's rates for retail electric and gas service are regulated by the
MoPSC and the Illinois Commerce Commission. 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).
16
In the Illinois retail jurisdiction, the cost of fuel for electric generation,
which was previously reflected in billings to customers through a fuel
adjustment clause, has been added to base rates as provided for in the Law (see
Note 2 - Regulatory Matters under Notes to Financial Statements for further
information). 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 a purchased gas
adjustment clause.
Inflation continues to be a factor affecting operations, earnings, stockholders'
equity and financial performance.
SAFE HARBOR STATEMENT
Statements made in this report which are not based on historical facts, are
forward-looking and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
forward-looking statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions,
financial performance and the Year 2000 Issue. In connection with the "Safe
Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the
Registrant is providing this cautionary statement to identify important factors
that could cause actual results to differ materially from those anticipated.
Factors include, but are not limited to, the effects of regulatory actions;
changes in laws and other governmental actions; competition; 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; 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.
17
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, 1998 and 1997, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1998 in conformity with generally accepted
accounting principles. 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 generally accepted auditing standards which
require that we plan and perform the audit to obtain reasonable assurance about
whether 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 4, 1999
18
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
UNION ELECTRIC COMPANY
BALANCE SHEET
-------------
(Thousands of Dollars, Except Shares)
December 31, December 31,
ASSETS 1998 1997
- ------ ---- ----
Property and plant, at original cost:
Electric $8,975,542 $8,832,039
Gas 209,556 197,959
Other 35,994 36,023
---------- ----------
9,221,092 9,066,021
Less accumulated depreciation and amortization 4,110,250 3,866,925
---------- ----------
5,110,842 5,199,096
Construction work in progress:
Nuclear fuel in process 108,294 134,804
Other 127,168 68,074
---------- ----------
Total property and plant, net 5,346,304 5,401,974
---------- ----------
Investments and other assets:
Nuclear decommissioning trust fund 161,877 122,438
Other 45,688 33,315
---------- ----------
Total investments and other assets 207,565 155,753
---------- ----------
Current assets:
Cash and cash equivalents 47,337 3,232
Accounts receivable - trade (less allowance for doubtful
accounts of $6,678 and $3,645, respectively) 143,912 179,708
Unbilled revenue 97,361 71,156
Other accounts and notes receivable 55,502 41,028
Materials and supplies, at average cost -
Fossil fuel 53,036 49,574
Other 91,831 97,375
Other 13,529 11,040
---------- ----------
Total current assets 502,508 453,113
---------- ----------
Regulatory assets:
Deferred income taxes 608,353 611,740
Other 165,134 179,705
---------- ----------
Total regulatory assets 773,487 791,445
---------- ----------
TOTAL ASSETS $6,829,864 $6,802,285
========== ==========
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 701,896 716,879
Retained earnings 1,211,610 1,159,956
---------- ----------
Total common stockholder's equity 2,424,125 2,387,454
Preferred stock not subject to mandatory redemption (Note 6) 155,197 155,197
Long-term debt (Note 8) 1,674,311 1,846,482
---------- ----------
Total capitalization 4,253,633 4,389,133
---------- ----------
Current liabilities:
Current maturity of long-term debt 117,269 28,797
Short-term debt -- 21,300
Accounts and wages payable 242,522 188,014
Accumulated deferred income taxes 45,061 35,809
Taxes accrued 100,714 94,167
Other 151,385 142,859
---------- ----------
Total current liabilities 656,951 510,946
---------- ----------
Commitments and Contingencies (Notes 2, 11 and 12)
Accumulated deferred income taxes 1,254,372 1,264,800
Accumulated deferred investment tax credits 144,175 149,891
Regulatory liability 159,317 175,638
Other deferred credits and liabilities 361,416 311,877
========== ==========
TOTAL CAPITAL AND LIABILITIES $6,829,864 $6,802,285
========== ==========
See Notes to Financial Statements.
19
UNION ELECTRIC COMPANY
----------------------
STATEMENT OF INCOME
-------------------
(Thousands of Dollars)
December 31, December 31, December 31,
For the year ended 1998 1997 1996
---- ---- ----
OPERATING REVENUES:
Electric $ 2,290,526 $ 2,188,571 $ 2,160,815
Gas 91,175 98,259 99,064
Steam 370 503 485
----------- ----------- -----------
Total operating revenues 2,382,071 2,287,333 2,260,364
OPERATING EXPENSES:
Operations
Fuel and purchased power 530,449 499,995 512,831
Gas 49,496 63,453 64,548
Other 461,987 404,956 379,106
--------- --------- ---------
1,041,932 968,404 956,485
Maintenance 221,995 217,426 223,632
Depreciation and amortization 259,787 247,961 241,298
Income taxes 217,385 192,766 197,369
Other taxes 212,789 211,949 213,266
--------- --------- ---------
Total operating expenses 1,953,888 1,838,506 1,832,050
Operating Income 428,183 448,827 428,314
OTHER INCOME AND DEDUCTIONS:
Allowance for equity funds used during
Construction 4,985 4,461 6,492
Miscellaneous, net 10,904 7,334 (4,293)
--------- --------- ---------
Total other income and deductions 15,889 11,795 2,199
Income Before Interest Charges 444,072 460,622 430,513
INTEREST CHARGES:
Interest 129,947 138,676 132,644
Allowance for borrowed funds used during construction (5,945) (6,676) (7,007)
--------- --------- ---------
Net interest charges 124,002 132,000 125,637
Income Before Extraordinary Charge 320,070 328,622 304,876
--------- --------- ---------
Extraordinary Charge (Net of Income Taxes) (Note 2) -- (26,967) --
--------- --------- ---------
NET INCOME 320,070 301,655 304,876
--------- --------- ---------
Preferred Stock Dividends 8,817 8,817 13,249
--------- --------- ---------
NET INCOME AFTER PREFERRED
STOCK DIVIDENDS $ 311,253 $ 292,838 $ 291,627
=========== =========== ===========
See Notes to Financial Statements.
20
UNION ELECTRIC COMPANY
----------------------
STATEMENT OF CASH FLOWS
-----------------------
(Thousands of Dollars)
December 31, December 31 December 31,
For the year ended 1998 1997 1996
---- ---- ----
Cash Flows From Operating:
Income before extraordinary charge $ 320,070 $ 328,622 $ 304,876
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 250,323 238,846 231,743
Amortization of nuclear fuel 36,855 37,126 37,792
Allowance for funds used during construction (10,930) (11,137) (13,499)
Deferred income taxes, net (14,213) (23,788) 4,948
Deferred investment tax credits, net (5,716) (10,451) (6,182)
Changes in assets and liabilities:
Receivables, net (4,883) 14,356 (11,028)
Materials and supplies 2,082 11,219 (18,866)
Accounts and wages payable 54,508 (22,335) 4,732
Taxes accrued 6,547 42,622 3,832
Other, net 16,463 (2,941) 66,344
--------- ----------- ----------
Net Cash Provided by Operating Activities 651,106 602,139 604,692
Cash Flows From Investing:
Construction expenditures (221,502) (259,418) (325,110)
Allowance for funds used during construction 10,930 11,137 13,499
Nuclear fuel expenditures (20,432) (35,432) (51,176)
--------- ---------- ----------
Net Cash Used in Investing Activities (231,004) (283,713) (362,787)
Cash Flows From Financing:
Dividends on common stock (259,599) (259,395) (256,331)
Dividends on preferred stock (8,817) (8,817) (12,941)
Redemptions -
Nuclear fuel lease (67,720) (28,292) (34,819)
Short-term debt (21,300) -- (8,300)
Long-term debt (195,000) (45,000) (35,000)
Preferred stock -- (63,924) (26)
Issuances -
Nuclear fuel lease 16,439 40,337 43,884
Short-term debt -- 10,000 --
Long-term debt 160,000 35,000 65,500
--------- --------- ----------
Net Cash Used in Financing Activities (375,997) (320,091) (238,033)
Net Change in Cash and Cash Equivalents 44,105 (1,665) 3,872
Cash and Cash Equivalents at Beginning of Year 3,232 4,897 1,025
========= ========= ==========
Cash and Cash Equivalents at End of Year $ 47,337 $ 3,232 $ 4,897
======================================================================================================
Cash paid during the periods:
- ------------------------------------------------------------------------------------------------------
Interest (net of amount capitalized) $ 125,255 $ 117,187 $ 120,745
Income taxes $ 223,960 $ 195,498 $ 193,043
- ------------------------------------------------------------------------------------------------------
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.
21
UNION ELECTRIC COMPANY
----------------------
STATEMENT OF RETAINED EARNINGS
- ------------------------------
(Thousands of Dollars)
- -----------------------------------------------------------------------------------------
Year Ended December 31, 1998 1997 1996
Balance at Beginning of Period $1,159,956 $1,126,513 $1,090,909
- -----------------------------------------------------------------------------------------
Add:
Net income 320,070 301,655 304,876
- -----------------------------------------------------------------------------------------
1,480,026 1,428,168 1,395,785
- -----------------------------------------------------------------------------------------
Deduct:
Preferred stock dividends 8,817 8,817 12,941
Common stock cash dividends 259,599 259,395 256,331
- -----------------------------------------------------------------------------------------
268,416 268,212 269,272
- -----------------------------------------------------------------------------------------
Balance at End of Period $1,211,610 $1,159,956 $1,126,513
- -----------------------------------------------------------------------------------------
Under mortgage indentures as amended, $31,305 of total retained earnings was
restricted against payment of common dividends - except those payable in common
stock, leaving $1,180,305 of free and unrestricted retained earnings at December
31, 1998.
SELECTED QUARTERLY INFORMATION (Unaudited)
- ------------------------------
(Thousands of Dollars, Except Per Share Amounts)
- ------------------------------------------------------------------------------------------------
Operating Operating Net Net Income
Revenues Income Income After
Quarter Ended Preferred
Stock
Dividends
- ------------------------------------------------------------------------------------------------
March 31, 1998 $478,585 $62,120 $30,302 $28,098
March 31, 1997 487,258 65,587 31,630 29,426
June 30, 1998 588,676 92,827 66,251 64,046
June 30, 1997 549,954 104,084 69,642 67,437
September 30, 1998 846,437 233,738 206,551 204,347
September 30, 1997 774,354 218,646 183,779 181,575
December 31, 1998 468,373 39,498 16,966 14,762
December 31, 1997 475,767 60,510 16,604 14,400
- ------------------------------------------------------------------------------------------------
The first quarter of 1998 and 1997 included credits to Missouri electric
customers which reduced net income and earnings on common stock approximately $6
million and $7 million, respectively
The second quarter of 1998 and 1997 included credits to Missouri electric
customers which reduced net income and earnings on common stock approximately
$18 million and $4 million, respectively. Callaway Plant refueling expenses,
which decreased net income approximately $18 million, were included in the
second quarter of 1998.
The third quarter of 1998 included a nonrecurring charge related to the
targeted separation plan, which reduced net income $11 million. See Note 3 -
Targeted Separation Plan under Notes to Financial Statements for further
information.
The fourth quarter of 1997 included a net reversal of the Missouri
portion of merger-related expenses of $22 million. The fourth quarter of 1997
also included an extraordinary charge of $27 million, net of income taxes (see
Note 2 - Regulatory Matters under Notes to Financial Statements for further
information).
Other changes in quarterly earnings are due to the effect of weather on sales
and other factors that are characteristic of public utility operations.
See Notes to Financial Statements.
22
UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1998
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation
Union Electric Company (AmerenUE or the Registrant) is a wholly-owned 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 124,000 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 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
non-regulated 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 1998, 1997 and 1996 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 Illinois in 1997 and 1996, changes in fuel costs were
generally reflected in billings to electric customers through the 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 kilowatthours
sold.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments
purchased with an original maturity of three months or less.
Income Taxes
The Registrant is included in the consolidated federal income tax return filed
by Ameren. Income taxes are allocated to the individual companies based on their
respective taxable income or loss. Deferred tax assets and liabilities are
recognized for the tax consequences of transactions that have been treated
differently for financial
23
reporting and tax return purposes, measured using statutory tax rates expected
to be in effect when the temporary differences reverse.
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 9% during 1998, 1997, and
1996.
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.
Evaluation of Assets for Impairment
Statement of Financial Accounting Standards (SFAS) 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, 1998, 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 may 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.
NOTE 2 - Regulatory Matters
In July 1995, the MoPSC approved an agreement establishing contractual
obligations involving the Registrant's Missouri retail electric rates. Included
was a three-year experimental alternative regulation plan 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 Ameren's 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 plan, which reduced earnings $28
million. During 1997, the Registrant recorded a $20 million credit for the
second year of the plan, which reduced earnings $11 million. In 1998, the
Registrant recorded an estimated $43 million credit for the final year of the
plan, which reduced earnings $24 million. In November 1998, the MoPSC staff
proposed preliminary adjustments to the Registrant's estimated credit. The
credit for the final year of the plan will be subject to regulatory proceedings.
The Registrant expects that the regulatory proceedings will be completed in
1999. The staff's proposed adjustments, if ultimately accepted, could increase
the Registrant's estimated credit up to $10 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 that will run 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 will
be shared equally between customers and Ameren's stockholders. The new
three-year plan will also return to customers 90% of all earnings above a 14%
ROE up to a 16% ROE. Earnings above a 16% ROE will be credited entirely to
customers. In addition, the joint agreement provides for a Missouri electric
rate decrease, retroactive to September 1, 1998,
24
based on the weather-adjusted average annual credits to customers under the
original experimental alternative regulation plan. The Registrant estimates that
its Missouri electric rate decrease should approximate $15 million to $20
million on an annualized basis. However, the MoPSC staff has proposed
adjustments to the Registrant's estimate based upon their methodology of
calculating the weather-adjusted credits. In addition, the results of the
regulatory proceedings associated with the final year of the original
experimental alternative regulation plan will impact the final Missouri electric
rate decrease as well. The Registrant expects that the regulatory proceedings
associated with determining the Missouri electric rate decrease will be
completed in 1999. The staff's proposed adjustments, if ultimately accepted,
could increase the Registrant's proposed Missouri electric rate decrease by $15
million to $20 million.
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.
In June 1998, the Registrant filed a request with the ICC to increase rates for
natural gas service in the Illinois jurisdiction. In February 1999, the ICC
approved a $1 million annual rate increase. The rate increase became effective
in February 1999.
In 1998, the Registrant joined a group of ten other utility companies which
support the formation of the Midwest Independent System Operator (Midwest ISO).
An ISO operates, but does not own, transmission systems and maintains system
reliability and security while alleviating pricing issues associated with the
"pancaking" of rates. The Midwest ISO would be regulated by FERC. The FERC
conditionally approved the Midwest ISO in September 1998, and it is expected to
be operational by the year 2001. The Registrant's membership in the Midwest ISO
must be approved by the MoPSC. The Midwest ISO covers eight states and
represents portions of 40,000 miles of transmission line and 62,000 megawatts of
electric power. Collectively, the member companies serve more than seven million
customers.
In addition, certain states are considering proposals or have adopted
legislation that will promote competition at the retail level. In December 1997,
the Governor of Illinois signed the Electric Service Customer Choice and Rate
Relief Law of 1997 (the Law) providing for electric utility restructuring in
Illinois. This legislation introduces competition into the supply of electric
energy in Illinois.
Under the Law, retail direct access, which allows customers to choose their
electric generation supplier, 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.
The Law includes 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 1998 and is expected to
decrease electric revenues approximately $3 million annually thereafter, based
on estimated levels of sales and assuming normal weather conditions. The
Registrant may be subject to additional 5% residential electric rate decreases
in each of 2000 and 2002, to the extent its rates exceed the Midwest utility
average at that time. The Registrant's rates are currently below the Midwest
utility average.
As a result of the Law, the Registrant filed a proposal with the ICC to
eliminate the electric fuel adjustment clause for Illinois retail customers,
thereby including a historical level of fuel costs in base rates. The ICC
approved the Registrant's filing in April 1998.
The Law contains a provision requiring one-half of excess earnings from the
Illinois regulated jurisdiction for the years 1998 through 2004 to be refunded
to the Registrant's Illinois customers. Excess earnings are defined as the
excess of the two-year average annual rate of return on common equity over the
two-year average of the average monthly yields of the 30-year U.S. Treasury
bonds, plus prescribed percentages ranging from 5.5% to 6.5%. Filings must be
made with the ICC on or before March 31 of each year 2000 through 2005. At this
time, the Registrant is unable to determine the impact of this provision on its
future financial condition, results of operations or liquidity.
Other provisions of the Law include (1) potential recovery of a portion of
strandable costs, which represent costs which would not be recoverable in a
restructured environment, through a transition charge collected from customers
who choose another electric supplier; (2) a mechanism to securitize certain
future revenues; (3) a requirement to file a delivery service tariff in March
1999 for customers who choose alternative suppliers; and (4) a provision
relieving the Registrant of the requirement to file an electric rate case or an
alternative regulatory plan in Illinois following the consummation of the Merger
to reflect the effects of net merger savings.
25
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) which 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
Emerging Issues Task Force of the Financial Accounting Standards Board (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), and 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 (see
Note 1 - Summary of Significant Accounting Policies for further information).
Due to the enactment of the Law, prices for the retail supply of electric
generation are expected to transition from cost-based, regulated rates to rates
determined in large part by competitive market forces in the state of Illinois.
As a result, the Registrant discontinued application of SFAS 71 for the 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 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
write-downs are necessary at this time. At December 31, 1998, the Registrant's
net investment in generation facilities related to its Illinois retail
jurisdiction approximated $216 million and was included in electric plant
in-service on the Registrant's consolidated balance sheet.
The provisions of the Law could also result in lower revenues, reduced profit
margins and increased costs of capital and operations expense. At this time, the
Registrant is unable to determine the impact of the Law on the Registrant's
future financial condition, results of operations or liquidity.
In Missouri, where approximately 92% 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 legislative committee is also conducting
hearings on these issues.
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, 1998, the
Registrant's net investment in generation facilities related to its Missouri
jurisdiction approximated $2.5 billion and was included in electric plant
in-service on the Registrant's balance sheet.
26
In addition, at December 31, 1998, the Registrant's Missouri net generation-
related regulatory assets approximated $464 million.
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) 1998 1997
- ------------------------------------------- ------- -------
Regulatory Assets:
Income taxes $608 $612
Callaway costs 95 99
Merger costs 24 28
Unamortized loss on reacquired debt 26 26
Other 20 26
- ------------------------------------------- ------- -------
Regulatory Assets $773 $791
- ------------------------------------------- ------- -------
Regulatory Liability:
Income taxes $159 $176
- ------------------------------------------- ------- -------
Regulatory Liability $159 $176
- ------------------------------------------- ------- -------
Income Taxes: See Note 9 - 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).
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.
Unamortized Loss on Reacquired Debt: Represents losses related to refunded debt.
These amounts are being amortized over the lives of the related new debt issues
or the remaining lives of the old debt issues if no new debt was issued.
The Registrant continually assesses the recoverability of its regulatory assets.
Under current accounting standards, regulatory assets are written off to
earnings when it is no longer probable that such amounts will be recovered
through future revenues. However, as noted in the above paragraphs, electric
industry restructuring legislation may impact the recoverability of regulatory
assets in the future.
In April 1996, the FERC issued Order 888 and Order 889 related to the industry's
wholesale electric business. In January 1998, Ameren filed a combined open
access tariff that conforms to the FERC's orders.
NOTE 3 - 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, pre-tax charge of $18 million was recorded,
which reduced earnings $11 million, representing the Registrant's share of costs
incurred to implement the TSP. The remaining liability associated with the TSP
at December 31, 1998, was $11 million.
NOTE 4 - Concentration of Risk
Market Risk
The Registrant engages in price risk management activities related to
electricity and natural gas. 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 natural gas. Derivative instruments used
include futures and forward contracts. 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 accounting 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.
27
The Registrant's financial instruments subject to credit risk consist primarily
of trade accounts receivable and forward contracts. The risk associated with
trade receivables is mitigated by the large number of customers in a broad range
of industry groups comprising the Registrant's customer base. The Registrant's
revenues are primarily derived from sales of electricity and natural gas to
customers in 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.
NOTE 5 - Nuclear Fuel Lease
The Registrant has a lease agreement that provides for the financing of nuclear
fuel. At December 31, 1998, 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 $23 million in 1998, $31 million during
1997 and $37 million during 1996.
The Registrant has capitalized the cost, including certain interest costs, of
the leased nuclear fuel and has recorded the related lease obligation. During
1998, the total interest charges under the lease were $5 million. In both 1997
and 1996, the total interest charges under the lease were $6 million. Interest
charges for these years were based on average interest rates of approximately
6%. Interest charges of $3 million were capitalized in each respective year.
NOTE 6 - Preferred Stock
At December 31, 1998 and 1997, 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) 1998 1997
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 7 - Short-Term Borrowings
Short-term borrowings of the Registrant consist of bank loans (maturities
generally on an overnight basis) and commercial paper (maturities generally
within 10-45 days). At December 31, 1998 the Registrant had no
28
outstanding short-term borrowings. At December 31, 1997, $21 million of
short-term borrowings were outstanding having a weighted average interest rate
of 7.0%.
At December 31, 1998, the Registrant had committed bank lines of credit
aggregating $137 million (all of which was unused) 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.
NOTE 8 - Long-Term Debt
Long-term debt outstanding at December 31, was:
- --------------------------------------------------------------------------------------------------
(in millions) 1998 1997
- --------------------------------------------------------------------------------------------------
First Mortgage Bonds - note (a)
- --------------------------------------------------------------------------------------------------
6 3/4% Series due 1999 $100 $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
- --------------------------------------------------------------------------------------------------
1,289 1,289
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
Missouri Environmental Improvement Revenues Bonds
- --------------------------------------------------------------------------------------------------
1984 Series A paid in 1998 - 80
1984 Series B paid in 1998 - 80
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 -
1998 Series B due 2033 - note (c) 50 -
1998 Series C due 2033 - note (c) 50 -
- --------------------------------------------------------------------------------------------------
377 377
- --------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------
Subordinated Deferrable Interest Debentures
- --------------------------------------------------------------------------------------------------
7.69% Series A due 2036 - note (d) 66 66
- --------------------------------------------------------------------------------------------------
Commercial Paper - note (e) - 35
- --------------------------------------------------------------------------------------------------
Nuclear Fuel Lease 66 117
- --------------------------------------------------------------------------------------------------
Unamortized Discount and Premium on Debt (7) (9)
- --------------------------------------------------------------------------------------------------
Maturities Due Within One Year (117) (29)
- --------------------------------------------------------------------------------------------------
Total Long-Term Debt $1,674 $1,846
- --------------------------------------------------------------------------------------------------
(a) At December 31, 1998, 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 1998 are as follows:
1985 Series A 3.47%
1985 Series B 3.72%
1991 Series 3.75%
1992 Series 3.63%
1998 Series A 3.54%
1998 Series B 3.50%
1998 Series C 3.57%
(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 2000, 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, 1998, no such
borrowings were outstanding.
29
Maturities of long-term debt through 2003 are as follows:
- -------------------------------------------------------------
(in millions) Principal Amount
- -------------------------------------------------------------
1999 $117
2000 -
2001 -
2002 75
2003 100
- -------------------------------------------------------------
Amounts for years subsequent to 1999 do not include nuclear fuel lease payments
since the amounts of such payments are not currently determinable.
Also, Ameren has a bank credit agreement due 2003, which permits the borrowing
of up to $200 million on a long-term basis. This credit agreement is available
to Ameren and its subsidiaries, including the Registrant. As of December 31,
1998, $190 million was available for the Registrant's use.
NOTE 9 - Income Taxes
Total income tax expense for 1998 resulted in an effective tax rate of 40% on
earnings before income taxes (38% in 1997 and 39% in 1996).
Principal reasons such rates differ from the statutory federal rate:
- ---------------------------------------------------------------------------------------------------
1998 1997 1996
- ---------------------------------------------------------------------------------------------------
Statutory federal income
tax rate 35% 35% 35%
Increases (Decreases) from:
Depreciation differences 2 2 2
State tax 4 4 4
Other (1) (3) (2)
- ---------------------------------------------------------------------------------------------------
Effective income tax rate 40% 38% 39%
- ---------------------------------------------------------------------------------------------------
Income tax expense components:
- ---------------------------------------------------------------------------------------------------
(in millions) 1998 1997 1996
- ---------------------------------------------------------------------------------------------------
Taxes currently payable (principally
Federal):
Included in operating expenses $237 $216 $199
Included in other income--
Miscellaneous, net (5) (3) (2)
- ---------------------------------------------------------------------------------------------------
232 213 197
Deferred taxes (principally federal):
Included in operating expenses--
Depreciation differences (1) (7) 2
Other (14) (10) 2
Included in other income--
Depreciation differences - 1 1
Other - 9 -
- ---------------------------------------------------------------------------------------------------
(15) (7) 5
Deferred investment tax credits,
Amortization
Included in operating expenses (5) (6) (6)
- ---------------------------------------------------------------------------------------------------
Total income tax expense $212 $200 $196
- ---------------------------------------------------------------------------------------------------
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.
30
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) 1998 1997
- -----------------------------------------------------------------------------------------
Accumulated Deferred Income Taxes:
Depreciation $814 $812
Regulatory assets, net 465 451
Capitalized taxes and expenses 68 84
Deferred benefit costs (48) (46)
- -----------------------------------------------------------------------------------------
Total net accumulated deferred income tax liabilities $1,299 $1,301
- -----------------------------------------------------------------------------------------
NOTE 10 - Retirement Benefits
In 1998, the Registrant adopted SFAS 132, "Employers' Disclosures about Pension
and Other Postretirement Benefits," which resulted in revisions to the 1997 and
1996 information previously reported.
The Registrant has defined-benefit retirement plans covering substantially all
employees of AmerenUE as well as certain employees of Ameren Services Company.
Benefits are based on the employees' years of service and compensation. The
Registrant's plans are funded in compliance with income tax regulations and
federal funding requirements.
Pension costs for the years 1998, 1997 and 1996, were $28 million, $24 million
and $28 million, respectively, of which approximately 19%, 17% and 19%,
respectively, was charged to construction accounts.
Funded Status of Pension Plans:
- -----------------------------------------------------------------------------------------
(in millions) 1998 1997
- -----------------------------------------------------------------------------------------
Change in benefit obligation
Net benefit obligation at beginning of year $999 $919
Service cost 24 22
Interest cost 70 69
Amendments 10 -
Actuarial loss 38 42
Special termination benefit charge 7 -
Benefits paid (88) (53)
----------------------------------------------------------------------------------------
Net benefit obligation at end of year 1,060 999
Change in plan assets
Fair value of plan assets at beginning of year 1,006 924
Actual return on plan assets 122 134
Employer contributions 1 1
Benefits paid (88) (53)
----------------------------------------------------------------------------------------
Fair value of plan assets at end of year 1,041 1,006
Funded status - (excess)/deficiency 19 (7)
Unrecognized net actuarial gain 121 115
Unrecognized prior service cost (73) (69)
Unrecognized net transition assets 6 7
- -----------------------------------------------------------------------------------------
Accrued pension cost at December 31 $73 $46
- -----------------------------------------------------------------------------------------
Plan assets consist principally of common stocks and fixed income
securities.
31
Components of Net Periodic Benefit Cost:
- ---------------------------------------------------------------------------------------
(in millions) 1998 1997 1996
- ---------------------------------------------------------------------------------------
Service cost $24 $22 $22
Interest cost 70 69 65
Expected return on plan assets (75) (71) (66)
Amortization of:
Transition asset (1) (1) (1)
Prior service cost 6 7 7
Actuarial (gain)/loss (3) (2) 1
Special termination benefit charge 7 - -
- ---------------------------------------------------------------------------------------
Net periodic benefit cost $28 $24 $28
- ---------------------------------------------------------------------------------------
Weighted-average Assumptions for Actuarial Present Value of Projected Benefit Obligations:
- ------------------------------------------------------------------------------------------
1998 1997
- ---------------------------------------------------------------------------
Discount rate at measurement date 6.75% 7%
Expected return on plan assets 8.5% 8.5%
Increase in future compensation 4% 4%
- ---------------------------------------------------------------------------
In addition to providing pension benefits, the Registrant provides certain
health care and life insurance benefits for retired employees. The Registrant
accrues the expected postretirement benefit costs during employees' years of
service.
The Registrant's funding policy is to annually contribute the net periodic cost
to a Voluntary Employee Beneficiary Association trust (VEBA). Postretirement
benefit costs were $43 million for 1998 and $44 million for both 1997 and 1996,
of which approximately 17% were charged to construction accounts in 1998 and
1997, and 19% in 1996. The Registrant's transition obligation at December 31,
1998 is being amortized over the next 14 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) 1998 1997
- --------------------------------------------------------------------------------
Change in benefit obligation
Net benefit obligation at beginning of year $333 $311
Service cost 14 12
Interest cost 24 23
Actuarial loss 9 5
Benefits paid (20) (18)
------------------------------------------------------------------------------
Net benefit obligation at end of year 360 333
Change in plan assets
Fair value of plan assets at beginning of year 81 47
Actual return on plan assets 8 9
Employer contributions 44 44
Unincorporated business income tax (3) (1)
Benefits paid (20) (18)
- --------------------------------------------------------------------------------
Fair value of plan assets at end of year 110 81
Funded status - deficiency 250 252
Unrecognized net actuarial gain 11 18
Unrecognized prior service cost (3) -
Unrecognized net transition obligation (175) (187)
- --------------------------------------------------------------------------------
Postretirement benefit liability at December 31 $83 $83
- --------------------------------------------------------------------------------
Plan assets consist principally of common stocks and fixed income
securities.
32
Components of Net Periodic Benefit Cost:
- -----------------------------------------------------------------------------
(in millions) 1998 1997 1996
- -----------------------------------------------------------------------------
Service cost $14 $12 $12
Interest cost 24 23 22
Expected return on plan assets (5) (2) (1)
Amortization of:
Transition obligation 12 12 12
Actuarial gain (2) (1) (1)
- -----------------------------------------------------------------------------
Net periodic benefit cost $43 $44 $44
- -----------------------------------------------------------------------------
Assumptions for the Obligation Measurements:
- -----------------------------------------------------------------------------
1998 1997
- -----------------------------------------------------------------------------
Discount rate at measurement date 6.75% 7%
Expected return on plan assets 8.5% 8.5%
Medical cost trend rate - initial 5.75% 7%
- ultimate 4.75% 5%
Ultimate medical cost trend rate expected in year 2000 2000
- -----------------------------------------------------------------------------
A 1% 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 $29 million, respectively. A 1% 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 $29
million, respectively.
NOTE 11 - Commitments and Contingencies
The Registrant is engaged in a capital program under which expenditures
averaging approximately $292 million, including AFC, are anticipated during each
of the next five years. This estimate includes 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 1999
through 2003 are estimated to total $877 million. Total coal purchases,
including transportation costs, for 1998, 1997 and 1996 were $304 million, $267
million and $297 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
contracted cost commitments for 1999 through 2003 are estimated to total $51
million. Total delivered natural gas costs were $50 million for 1998, and $64
million for both 1997 and 1996. The Registrant's nuclear fuel commitments for
1999 through 2003, including uranium concentrates, conversion, enrichment and
fabrication, are expected to total $107 million, and are expected to be financed
under the nuclear fuel lease. Nuclear fuel expenditures for 1998, 1997 and 1996
were $20 million, $35 million and $51 million, respectively. Additionally, the
Registrant has long-term contracts with other utilities to purchase electric
capacity. These commitments for 1999 through 2003 are estimated to total $179
million. During 1998, 1997 and 1996, electric capacity purchases were $35
million, $34 million and $44 million, respectively.
The Registrant's insurance coverage for Callaway Nuclear Plant at December 31,
1998, was as follows:
33
Type and Source of Coverage
- --------------------------------------------------------------------------------
(in millions) Maximum Maximum
Coverages Assessments
For Single
Incidents
- --------------------------------------------------------------------------------
Public Liability:
American Nuclear Insurers $ 200 $ -
Pool Participation 9,602 88
- --------------------------------------------------------------------------------
$ 9,802 $ 88
- --------------------------------------------------------------------------------
Nuclear Worker Liability:
American Nuclear Insurers $ 200 $ 3
- --------------------------------------------------------------------------------
Property Damage:
Nuclear Electric Insurance Ltd. $ 2,750 $ 13
- --------------------------------------------------------------------------------
Replacement Power:
Nuclear Electric Insurance Ltd. $ 494 $ 3
- --------------------------------------------------------------------------------
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.
Limit of liability for each incident under Price-Anderson.
Industry limit for potential liability from workers claiming exposure to
the hazard of nuclear radiation.
Includes premature decommissioning costs.
Weekly indemnity of $3.5 million, for 58 weeks which commences after the
first 17 weeks of an outage, plus $2.8 million per week for 104 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.
Under the Title IV of the Clean Air Act Amendments of 1990, the Registrant is
required to significantly reduce total annual sulfur dioxide (SO2) and nitrogen
oxide (NOx) emissions by the year 2000. By switching to low-sulfur coal, early
banking of emission credits and installing low NOx burner technology, the
majority of these reductions have been achieved.
In July 1997, the United States Environmental Protection Agency (EPA) issued
final regulations revising the National Ambient Air Quality Standards for ozone
and particulate matter. The new ambient standards may result in significant
additional reductions in SO2 and NOx emissions from the Registrant's power
plants. The new particulate matter standards may require SO2 reductions of up to
50% beyond that already required by Phase II acid rain control provisions of the
1990 Clean Air Act Amendments and could be required by 2007. The full details of
these requirements are under study by the Registrant. 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 final regulations in September 1998 pertaining to 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). Although
reduction requirements in NOx emissions from the Registrant's coal-fired boilers
are anticipated to exceed 75 percent from 1990 levels by the year 2003, it is
not yet possible to determine the exact magnitude of the reductions required
from the Registrant's power plants because each state has up to one year to
develop a plan to comply with the EPA rule. The NOx emissions reductions already
achieved on several of the Registrant's coal-fired power plants will help to
reduce the costs of compliance with this regulation. However, preliminary
analysis of the regulations indicate that selective catalytic reduction
technology will be required for some of the Registrant's units, as well as other
additional controls.
Currently, the Registrant estimates that its additional capital expenditures to
comply with the EPA's final regulations issued in September 1998, could range
from $125 million to $175 million over the period from 1999 to 2002. Associated
operations and maintenance expenditures could increase $5 million to $8 million
annually, beginning in 2003. The Registrant will explore alternatives to comply
with these new regulations in order to minimize, to the
34
extent possible, its capital costs and operating expenses. The Registrant
is unable to predict the ultimate impact of these standards on its future
financial condition, results of operations or liquidity.
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 must be ratified by the United States
Senate before provisions are effective for the United States. Until ratification
is obtained, the Registrant is unable to predict what requirements, if any, will
be adopted in this country; however, 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, 1998, 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 the site located in Illinois are
being accrued and deferred rather than expensed currently, pending recovery
through rates. The ICC has instituted a reconciliation proceeding to review the
Registrant's environmental remediation activities through 1996 and 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. A ruling from the ICC is still
pending with respect to this proceeding. The reconciliation proceeding relating
to the Registrant's 1997 environmental remediation activities was commenced in
April 1998, but has not yet been submitted to the ICC for a decision.
The Registrant continually reviews remediation costs that may be required for
all of these sites. Any unrecovered environmental costs are not expected to have
a material adverse effect on the Registrant's financial position, results of
operations or liquidity.
Certain employees of the Registrant are represented by the International
Brotherhood of Electrical Workers and the International Union of Operating
Engineers. These employees comprise approximately 75% of the Registrant's
workforce. The collective bargaining agreements covering 97% of these
represented employees expire in July 1999. Preliminary discussions with these
collective bargaining units are currently underway. At this time, the Registrant
is unable to predict the impact of these negotiations on its future financial
condition, results of operations or cash flows.
Regulatory changes enacted and being considered at the federal and state levels
continue to change the structure of the utility industry and utility regulation,
as well as encourage increased competition. At this time, the Registrant is
unable to predict the impact of these changes on the Registrant's future
financial condition, results of operations or liquidity. See Note 2 - Regulatory
Matters for further information.
The Registrant is involved in other legal and administrative proceedings before
various courts and agencies with respect to matters arising in the ordinary
course of business, some of which involve substantial amounts. The Registrant
believes that the final disposition of these proceedings will not have a
material adverse effect on its financial position, results of operations or
liquidity.
NOTE 12 - 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 Callaway site until 2004 and is pursuing a viable
storage alternative. This alternative has been approved by the Nuclear
Regulatory Commission, and when implemented, will provide sufficient spent fuel
storage for 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 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 $485
35
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 $7 million in each of the years 1998, 1997 and 1996. Every three
years, the MoPSC requires 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 study was filed in 1996. Costs collected
from customers are deposited in an external trust fund to provide for Callaway's
decommissioning. Fund earnings are expected to average 9.25% annually through
the date of decommissioning. If the assumed return on trust assets is not
earned, the Registrant believes it is probable that such earnings deficiency
will be recovered in rates. Trust fund earnings, net of expenses, appear on the
consolidated 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 13 - Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate that
value.
Cash and Temporary Investments/Short-Term Borrowings
The carrying amounts approximate fair value because of the short-term maturity
of these instruments.
Nuclear Decommissioning Trust Fund
The fair value is estimated based on quoted market prices for securities.
Preferred Stock
The fair value is estimated based on the quoted market prices for the same or
similar issues.
Long-Term Debt
The fair value is estimated based on the quoted market prices for same or
similar issues or on the current rates offered to the Registrant for debt of
comparable maturities.
Carrying amounts and estimated fair values of the Registrant's financial instruments at December 31:
1998 1997
- -------------------------------------------------------------------------------------------
(in millions) Carrying Fair Carrying Fair
Amount Value Amount Value
- -------------------------------------------------------------------------------------------
Preferred stock $155 $160 $155 $143
Long-term debt (including current portion) 1,791 1,919 1,875 1,969
- -------------------------------------------------------------------------------------------
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 12 - 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,
1998 and 1997. In 1998, 1997 and 1996, the proceeds from the sale of investments
were $29 million, $24 million and $20 million, respectively. Using the specific
identification method to determine cost, the gross realized gains on those sales
were approximately $2 million for both 1998 and 1997 and $1 million for 1996.
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.
36
Costs and fair values of investments in debt and equity securities in the
nuclear decommissioning trust fund at December 31 were as follows:
- --------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1997 (in millions) Gross Unrealized
Security Type Cost Gain (Loss) Fair Value
- --------------------------------------------------------------------------------
Debt Securities $34 $ 3 $ - $37
Equity Securities 43 40 - 83
Cash equivalents 2 - - 2
- --------------------------------------------------------------------------------
$79 $43 $ - $122
- --------------------------------------------------------------------------------
The contractual maturities of investments in debt securities at December 31,
1998, were as follows:
- --------------------------------------------------------------------------------
(in millions) Cost Fair Value
- --------------------------------------------------------------------------------
1 year to 5 years $3 $3
5 years to 10 years 21 22
Due after 10 years 24 27
- --------------------------------------------------------------------------------
$48 $52
- --------------------------------------------------------------------------------
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 UE's 1999 definitive
proxy statement filed pursuant to Regulation 14A and is incorporated herein by
reference.
Information concerning executive officers required by this item is reported
in Part I of this Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION.
Any information required to be reported by this item is included under
"Compensation" in UE's 1999 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 UE's 1999 definitive proxy statement filed
pursuant to Regulation 14A and is incorporated herein by reference.
37
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 UE's 1999 definitive proxy statement filed
pursuant to Regulation 14A and is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements and Financial Statement Schedule Covered by
Report of Independent Accountants
Pages Herein
------------
Report of Independent Accountants.................................. 18
Balance Sheet - December 31, 1998 and 1997......................... 19
Statement of Income - Years 1998, 1997, and 1996................... 20
Statement of Cash Flows - Years 1998, 1997, and 1996............... 21
Statement of Retained Earnings - Years 1998, 1997, and 1996........ 22
Notes to Financial Statements...................................... 23
Valuation and Qualifying Accounts (Schedule II)
Years 1998, 1997, and 1996....................................... 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
October 8, 1998 reporting on the impact of Ameren Corporation's (parent
company of the Registrant) employee separation plan and on the effect of
the final rule issued in September 1998 by the United States
Environmental Protection Agency pertaining to nitrogen oxide emissions.
38
UNION ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Col. A Col. B Col. C Col. D Col. E
------ ------ ------ ------ ------
Additions
--------------------------------
(1) (2)
Balance at Charged to Balance at
beginning costs and Charged to end of
Description of period expenses other accounts Deductions period
----------- --------- --------- -------------- ---------- ------
(Note)
Year ended December 31, 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
========== =========== =========== ==========
Year ended December 31, 1996
Reserves deducted in the balance sheet from
assets to which they apply:
Allowance for doubtful accounts $6,924,965 $12,100,000 $13,829,633 $5,195,332
========== =========== =========== ==========
Note: Uncollectible accounts charged off, less recoveries.
39
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, 1999 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
- ----------------------
CHARLES W. MUELLER (Principal Executive Officer)
/s/ Donald E. Brandt Senior Vice President and Director
- ----------------------
DONALD E. BRANDT (Principal Financial and Accounting Officer)
/s/ Warner L. Baxter Vice President and Controller
- ----------------------
WARNER L. BAXTER (Principal Accounting Officer)
/s/ Paul A. Agathen Director
- ----------------------
PAUL A. AGATHEN
/s/ Gary L. Rainwater Director
- ----------------------
GARY L. RAINWATER
/s/ Charles J. Schukai Director
- ----------------------
CHARLES J. SCHUKAI
By /s/ Steven R. Sullivan March 29, 1999
--------------------------
(Steven R. Sullivan, Attorney-in-Fact)
40
EXHIBITS
Exhibits Filed Herewith
-----------------------
Exhibit No. Description
- ----------- -----------
3(ii) - By-Laws of the Company as amended effective December 14, 1998.
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
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 11, 1995. (June 30, 1995
Form 10-Q/A (Amendment No. 2), 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
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, provid-
ing 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 Authori-
ty 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 Environ-
mental 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 Asso-
ciation, 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
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 Reimburse-
ment Agreement dated as of June 1, 1985 between Union Bank of Switzer-
land and the Company. (1992 Form 10-K, Exhibit 4.33.)
4.18 - Series 1985 B Reaffirmation Agreement and Third Supplement to Agree-
ment 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 Improvemen 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 Com-
pany, 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
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 Improvemen 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, Ex-
hibit 10.1.)
10.2 - Ameren Change of Control Severance Plan. (Ameren's 1998 Form 10-K, Ex-
hibit 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