UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
OR
( ) Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 (No Fee Required)
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
6, 1998, based on closing prices most recently available as reported in The Wall
Street Journal (excluding Preferred Stock for which quotes are not publicly
available): $48,703,840.
Shares of Common Stock, $5 par value, outstanding as of March 6, 1998:
102,123,834 shares.
Documents incorporated by references.
Portions of the registrant's definitive proxy statement for the 1998 annual
meeting are incorporated by reference into Part III.
TABLE OF CONTENTS
PART I Page
Item 1-Business
General ................................................ 1
Construction Program and Financing ..................... 1
Rates .................................................. 2
Fuel Supply ............................................ 3
Regulation ............................................. 3
Industry Issues ........................................ 5
Item 2-Properties .......................................................... 5
Item 3-Legal Proceedings ................................................... 7
Item 4-Submission of Matters to a Vote of Security Holders1
PART II
Item 5-Market for Registrant's Common Equity and Related
Stockholder Matters ......................................... 7
Item 6-Selected Financial Data ............................................ 7
Item 7-Management's Discussion and Analysis of Financial Condition
and Results of Operations ..................................... 8
Item 8-Financial Statements and Supplementary Data ........................ 15
Item 9-Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure1
PART III
Item 10-Directors and Executive Officers of the Registrant ................ 34
Item 11-Executive Compensation2 ........................................... 35
Item 12-Security Ownership of Certain Beneficial Owners
and Management2 ................................................ 35
Item 13-Certain Relationships and Related Transactions2 ................... 35
PART IV
Item 14-Exhibits, Financial Statement Schedules and Reports on Form 8-K ... 36
SIGNATURES ................................................................ 38
EXHIBITS .................................................................. 39
- --------
1 Not applicable and not included herein.
2 Incorporated herein by reference.
PART I
ITEM 1. BUSINESS.
GENERAL
On December 31, 1997, following the receipt of all required
approvals, the registrant, Union Electric Company (the "Company" - or
"AmerenUE", as noted), and CIPSCO Incorporated ("CIPSCO"), parent company of
Central Illinois Public Service Company ("CIPS"), combined to form Ameren
Corporation ("Ameren") with the result that the common shareholders of the
Company and CIPSCO became the common shareholders of Ameren and Ameren became
the owner of 100% of the common stock of CIPS and the Company. Pursuant to an
Agreement and Plan of Merger dated as of August 11, 1995 between (among others)
the Company, CIPSCO and Ameren, each outstanding share of the Company's common
stock was exchanged for one share of Ameren common stock and each outstanding
share of CIPSCO common stock was exchanged for 1.03 shares of Ameren common
stock. For additional information on the Merger, see Notes 1 and 2 to the "Notes
to Financial Statements" under Item 8 herein.
The Company, incorporated in Missouri in 1922, is successor to a
number of companies, the oldest of which was organized in 1881. The Company 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.
The Company 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 Company's Illinois retail electric business as a result
of electricity industry restructuring legislation enacted in Illinois in
December 1997. The write-off reduced earnings $27 million, net of income taxes.
(See Note 2 to the "Notes to Financial Statements" under Item 8 herein.)
For each of the last five years, 96% of total operating revenues
was derived from the sale of electric energy and 4% from the sale of natural
gas.
The Company employed 5,903 persons at December 31, 1997.
Approximately 68% of such employees are represented by local unions affiliated
with the AFL-CIO. Labor agreements covering 4,034 employees will expire in 1999
and labor agreements covering 111 employees expire in 2000. Effective with the
merger, approximately 1,230 employees transferred to Ameren's subsidiary, Ameren
Services Company.
CONSTRUCTION PROGRAM AND FINANCING
The Company is engaged in a construction program under which
expenditures averaging approximately $243 million are anticipated during each of
the next five years. Capital expenditures for compliance with the Clean Air Act
Amendments of 1990 are included in the construction program, but the estimate
does not include expenditures which may be incurred to meet new air quality
standards -- also see "Regulation", below. The Company does not anticipate a
need for additional base load electric generating capacity until after the year
2013.
During the five-year period ended 1997, gross additions to the
property of the Company, including allowance for funds used during construction
and excluding nuclear fuel, were
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approximately $1.5 billion (including $259 million in 1997) and property
retirements were $311 million.
In addition to the funds required for construction during the
1998-2002 period, $239 million will be required to repay long-term debt as
follows: $29 million in 1998, $135 million in 1999, and $75 million in 2002.
Amounts for years subsequent to 1998 do not include nuclear fuel lease payments
since the amounts of such payments are not currently determinable.
For information on the Company'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 the Company's Indenture of Mortgage and Deed of Trust ("Mortgage")
relating to its First Mortgage Bonds ("Bonds"), no Bonds may be issued (except
in certain refunding operations) unless the Company's net earnings available for
interest after depreciation for 12 consecutive months within the 15 months
preceding such issuance are at least two times annual interest charges on all
Bonds and prior lien bonds then outstanding and to be issued (all calculated as
provided in the Mortgage). Such ratio for the 12 months ended December 31, 1997
was 6.7, which would permit the Company to issue an additional $2.8 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, 1997, the aggregate amount of Bonds
issuable under (a) and (b) above was approximately $2.1 billion.
The Company's Restated Articles of Incorporation restrict the
Company 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,
1997 was 33.9, which would permit the Company to issue an additional $1.3
billion stated value of Preferred Stock (8% annual dividend rate assumed).
Certain other financing arrangements require the Company to obtain prior
consents to various actions by the Company, 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 1997, approximately 83%, 7%, and 10% of the
Company'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.
As permitted by electric utility restructuring legislation in
Illinois, the Company has 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 request is pending with the ICC, and a decision is expected
in early May, 1998.
For additional information on "Rates", see Note 2 to the "Notes
to Financial Statements" under Item 8 herein.
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FUEL SUPPLY
Cost of Fuels Year
- ------------- -------------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
Per Million BTU - Coal 105.600(cent) 112.250(cent) 117.645(cent) 123.950(cent) 153.284(cent)
- Nuclear 47.472(cent) 47.499(cent) 48.592(cent) 49.932(cent) 56.848(cent)
- System 92.816(cent) 96.596(cent) 101.590(cent) 101.867(cent) 126.362(cent)
Per kWh of Steam Generation .979(cent) 1.024(cent) 1.068(cent) 1.064(cent) 1.331(cent)
Oil and Gas. The actual and prospective use of such fuels is
minimal, and the Company 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 Company has a policy of
maintaining a coal inventory consistent with its expected burn practices. See
"Regulation" for additional reference to the Company's coal requirements.
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 Company has agreements to fulfill its needs for uranium,
enrichment, and fabrication services through 2002. The Company's agreements for
conversion services are sufficient to supply the Callaway Plant through 1999.
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 re-fueling at
18-month intervals and refuelings are presently scheduled for the spring of 1998
and the fall of 1999.
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 Company has
sufficient storage capacity at the Callaway Plant site until 2004 and is
pursuing a viable storage alternative. This alternative will require Nuclear
Regulatory Commission approval. The delayed availability of DOE's disposal
facility is not expected to adversely affect the continued operation of the
Callaway Plant.
For additional information on the Company's "Fuel Supply", see Note
10 to the "Notes to Financial Statements" under Item 8 herein.
REGULATION
The Company 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 Company 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 Company is also subject to regulation by the FERC as
to rates and charges in connection with the transmission of electric energy in
interstate commerce and the sale of such energy at wholesale in interstate
commerce, mergers, and certain other matters. Authorization to issue debt having
a maturity of twelve months or less is obtained from the Securities and Exchange
Commission.
- 3 -
See Note 2 to the "Notes to Financial Statements" under Item 8
herein for a discussion of legislation which introduces competition into the
supply of electric energy in Illinois.
Operation of the Company's Callaway Plant is subject to regulation
by the Nuclear Regulatory Commission. The Company's Facility Operating License
for the Callaway Plant expires on October 18, 2024. The Company's Osage
hydroelectric plant and its Taum Sauk pumpedstorage 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 Company'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
Company's Keokuk Plant and dam located in the Mississippi River between
Hamilton, Illinois and Keokuk, Iowa, are operated under authority, unlimited in
time, granted by an Act of Congress in 1905.
The Company 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 Company is in substantial compliance with such existing
regulations.
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. Although specific emission control
requirements are still being developed, it is believed that the revised
standards will require significant additional reductions in nitrogen oxide and
sulfur dioxide emissions from coal-fired boilers. In October 1997, the EPA
announced that Missouri and Illinois are included in the area targeted for
nitrogen oxide emissions reductions as part of the EPA's regional control
program. Reduction requirements in nitrogen oxide emissions from the Company's
coal-fired boilers could exceed 80% from 1990 levels by the year 2002. Reduction
requirements in sulfur dioxide emissions may be 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. Because of the magnitude of these
additional reductions, the Company could be required to incur significantly
higher capital costs to meet future compliance obligations for its coal-fired
boilers or purchase power from other sources, either of which could have
significantly higher operations and maintenance expenditures associated with
compliance. At this time, the Company is unable to determine the impact of the
revised air quality standards on its future financial condition, results of
operations or liquidity.
In December 1997, the United States and numerous other countries
agreed to certain environmental provisions (the Kyoto Protocol), which would
require decreases in greenhouse gases in an effort to address the "global
warming" issue. The Company 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 expenditures by the Company. At this time, the
Company is unable to determine the impact of these proposals on its future
financial condition, results of operations or liquidity.
Under Title IV of the Clean Air Act Amendments of 1990, the Company
is required to significantly reduce total sulfur dioxide emissions by the year
2000. Significant reductions in nitrogen oxide are also required. By switching
to low-sulfur coal and early banking of emission credits, the Company
anticipates that it can comply with the requirements of the law without
significant revenue increases because the related capital costs, are largely
offset by lower fuel costs. As of the end of 1997, the estimated remaining
capital costs expected to be incurred for Clean Air Act - related projects was
$35 million.
- 4 -
As of December 31, 1997, the Company was designated 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 Company may be responsible but has not been designated a PRP. The
Company continually reviews the remediation costs that may be required for all
of these sites. However, any unrecovered environmental costs are not expected to
have a material adverse effect on the Company's financial position, results of
operations or liquidity.
Other aspects of the Company's business are subject to the
jurisdiction of various regulatory authorities and, for additional information
on regulations 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 10 to the "Notes to Financial Statements" under Item 8
herein.
INDUSTRY ISSUES
The Company 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 Company 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 "Outlook"
in "Management's Discussion and Analysis of Financial Condition and Results of
Operations" under Item 7 herein and Notes 2 and 10 to the "Notes to Financial
Statements" under Item 8 herein.
ITEM 2. PROPERTIES.
In planning its construction program, the Company is presently
utilizing a forecast of kilowatthour sales growth of approximately 1.9% and peak
load growth of 1%, each compounded annually, and is providing for a minimum
reserve margin of approximately 17% to 21% above its anticipated peak load
requirements.
The Company 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 Company has
interconnections for the exchange of power, directly and through the facilities
of others, with thirteen private utilities and with Associated Electric
Cooperative, Inc., the City of Columbia, Missouri, the Southwestern Power
Administration and the Tennessee Valley Authority.
The Company 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, 10% to the Company, 20% to KU, and 5% each to IG and CIPS.
- 5 -
As of December 31, 1997 the Company owned approximately 3,304
circuit miles of electric transmission lines and substations with a transformer
capacity of approximately 45,754,000 kVA. The Company operates three propane-air
plants with an aggregate daily natural gas equivalent deliverability of 29
million Btu and 2,737 miles of gas mains. Other properties of the Company
include distribution lines, underground cable, steam distribution facilities in
Jefferson City, Missouri and office buildings, warehouses, garages and repair
shops.
The Company 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
Company 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 Company'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 Company 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 the Company's property and plant is subject to
the direct first lien of an Indenture of Mortgage and Deed of Trust dated June
15, 1937, as amended and supplemented.
The following table sets forth information with respect to the
Company's generating facilities and capability at the time of the expected 1998
peak.
Gross Kilowatt
Energy Installed
Source Plant Location Capability
------ --------- ------------ ---------------
Coal Labadie Franklin County, Mo. 2,404,000
Rush Island Jefferson County, Mo. 1,214,000
Sioux St. Charles County, Mo. 1,008,000
Meramec St. Louis County, Mo. 927,000
----------
Total Coal 5,553,000
Nuclear Callaway Callaway County, Mo. 1,199,000
Hydro Osage Lakeside, Mo. 212,000
Keokuk Keokuk, Ia. 126,000
---------
Total Hydro 338,000
Oil and Venice Venice, Ill. 459,000
Natural Other Various 383,000
---------
Gas Total Oil and
Natural Gas 842,000
Pumped-
storage Taum Sauk Reynolds County, Mo. 350,000
---------
TOTAL 8,282,000
=========
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ITEM 3. LEGAL PROCEEDINGS.
The Company 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 is of
the opinion that the final disposition of these proceedings will not have a
material adverse effect on the Company's financial position, results of
operations or liquidity.
Statements made in this report which are not based on historical facts,
are forward-looking and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
forward-looking statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans strategies, objectives, events, conditions and
financial performance. In connection with the "Safe Harbor" provisions of the
Private Securities Litigation Reform Act of 1995, the Company 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 electricity; average
rates for electricity in the Midwest; business and economic conditions; weather
conditions; fuel prices and availability; generation plant performance; monetary
and fiscal policies; and legal and administrative proceedings.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.
There is no market for the Company's Common Stock since all shares are
owned by its parent, Ameren.
ITEM 6. SELECTED FINANCIAL DATA.
For the Years Ended
December 31 (In Thousands) 1997 1996 1995 1994 1993
- ------------------------- ---- ---- ---- ---- ----
Operating revenues $2,287,333 $2,260,364 $2,242,364 $2,223,938 $2,220,037
Operating income 448,827 428,314 441,896 450,186 411,297
Net income 301,655 304,876 314,107 320,757 297,160
Preferred stock dividends 8,817 13,249 13,250 13,252 14,087
Net income after preferred
stock dividends 292,838 291,627 300,857 307,505 283,073
Common stock dividends 259,395 256,331 250,714 244,586 238,459
As of December 31,
Total assets $6,802,285 $6,870,809 $6,754,469 $6,624,701 $6,595,570
Long-term debt 1,846,482 1,798,671 1,763,613 1,823,489 1,766,655
- 7 -
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Union Electric Company (AmerenUE or the Company) is a subsidiary of Ameren
Corporation (Ameren), a newly created holding company which is 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.
RESULTS OF OPERATIONS
Earnings
Earnings for 1997, 1996, and 1995 were $293 million, $292 million, and $301
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 Plant nuclear refueling outages, merger-related expenses, changes in
interest expense, changes in income and property taxes and an extraordinary
charge.
The Company 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 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.)
Electric Operations
The impacts of the more significant items affecting electric revenues and
operating expenses during the past three years are analyzed and discussed below:
Electric Revenues Variations from Prior Year
- ------------------------------------- ------------ ------------ ---------
(Millions of Dollars) 1997 1996 1995
- ------------------------------------- ------------ ------------ ---------
Rate variations $ - $(20) $(14)
Credit to customers 28 (15) (33)
Effect of abnormal weather 4 (63) 53
Growth and other 1 96 39
Interchange sales (5) 9 (28)
- ------------------------------------- ------------ ------------ ---------
$ 28 $ 7 $ 17
- ------------------------------------- ------------ ------------ ---------
Electric revenues in 1997 were $28 million higher compared to 1996
primarily due to a lower estimated Missouri customer credit recorded in 1997.
(See Note 2 - Regulatory Matters under Notes to Financial Statements for further
information.) 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. (See Note 2 - Regulatory Matters under
Notes to Financial Statements for further information.) 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%.
The increase in 1995 electric revenues was due to increased retail
kilowatthour sales compared to 1994, mainly due to unusually hot weather in the
third quarter and sales growth reflecting our healthy service area economy.
Weather-sensitive residential and commercial sales increased 6% and 3%,
respectively, over 1994, and industrial sales grew 3%. This increase was
partially offset by a one-time $30 million credit, the rate decrease and a 17%
decline in interchange sales due to decreased interchange sales opportunities.
(See Note 2 - Regulatory Matters under Notes to Financial Statements for further
information.)
Fuel and Purchased Power Variations from Prior Year
- -------------------------------------- ------ ----- ------
(Millions of Dollars) 1997 1996 1995
- -------------------------------------- ------ ------ ------
Fuel:
Variation in generation $ 17 $ 15 $ 1
Price (15) (18) (1)
Generation efficiencies and other (1) 3 2
Purchased power variation (14) 8 5
- -------------------------------------- ------ ----- ------
$(13) $ 8 $ 7
- -------------------------------------- ------ ----- ------
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 due to the use of lower-cost coal. The
increase in 1995 fuel and purchased power costs reflected increased purchased
power costs due to greater kilowatthour sales during the hot 1995 summer and the
need for replacement power during Callaway Plant's spring nuclear refueling
outage.
Operating Expenses, Other than Fuel and Purchased Power
Other operations expense variations in 1995 through 1997 reflected
recurring factors such as growth, inflation, labor and benefit increases. In
1997, other operations expense increased $26 million primarily due to increased
consultant expenses and information system-related expenses. 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). In 1996, other operations expense
increased $11 million primarily due to increased employee benefits, injuries and
damages and consulting expenses. In 1995, gas costs decreased $9 million, mainly
due to a 15% reduction in natural gas purchased for resale (due primarily to
lower gas prices). In 1995, other operations expense decreased $8 million,
primarily due to decreases in employee benefits, injuries and damages, and
insurance expenses. These decreases were partially offset by increased labor and
material and supplies expenses.
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. In 1995, maintenance expenses
increased $24 million, mainly due to scheduled power plant maintenance expenses
partially offset by reduced distribution system maintenance expenses. Callaway
Plant's maintenance expenses increased $17 million primarily due to the spring
1995 refueling outage. Maintenance expenses at other power plants increased $11
million primarily due to scheduled maintenance outages.
Depreciation and amortization expense increased $7 million in 1997, $8
million in 1996 and $7 million in 1995, due to increased depreciable property.
Taxes
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 pretax income. Income tax expense
from operations increased $3 million in 1995 primarily due to a higher effective
income tax rate partially offset by lower pretax income.
Other Income and Deductions
Miscellaneous, net increased $12 million for 1997, primarily due to the
capitalization of merger-related expenses. (See Note 2 - Regulatory Matters
under Notes to Financial Statements for further information.) Miscellaneous, net
increased $2 million for 1996, primarily due to reduced merger-related expenses.
Miscellaneous, net decreased $6 million for 1995, primarily due to increased
merger-related expenses.
Interest
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. In 1995, interest expense decreased
$6 million as declines in other interest expense were partly offset by higher
interest rates on variable-rate long-term debt.
Balance Sheet
The $27 million decrease in other current liabilities at December 31, 1997,
compared to December 31, 1996, was primarily due to a lower accrued customer
credit. (See Note 2 - Regulatory Matters under Notes to Financial Statements for
further information.) The $57 million increase in other deferred credits and
liabilities was attributable to increases in the accrued pension liability and
the nuclear decommissioning trust fund.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $602 million for 1997,
compared to $605 million and $640 million in 1996 and 1995, respectively.
Cash flows used in investing activities totaled $284 million, $363 million,
and $341 million for the years ended December 31, 1997, 1996 and 1995,
respectively. Expenditures in 1997 for constructing new or to improve existing
facilities, purchasing rail cars and complying with the Clean Air Act were $259
million. In addition, the Company spent $35 million to acquire nuclear fuel.
Construction expenditures are expected to be about $230 million in 1998.
For the five-year period 1998-2002, construction expenditures are estimated at
$1.2 billion. This estimate does not include any construction expenditures which
may be incurred by the Company to meet new air quality standards for ozone and
particulate matter, as discussed below.
The Company's need for additional base load electric generating capacity is
not anticipated until after the year 2013. Under Title IV of the Clean Air Act
Amendments of 1990, the Company is required to significantly reduce total sulfur
dioxide emissions by the year 2000. Significant reductions in nitrogen oxide are
also required. By switching to low-sulfur coal and early banking of emissions
credits, the Company anticipates that it can comply with the requirements of the
law without significant revenue increases because the related capital costs are
largely offset by lower fuel costs. As of year-end 1997, estimated remaining
capital costs expected to be incurred pertaining to Clean Air Act-related
projects totaled $35 million.
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. Although specific emission control requirements
are still being developed, it is believed that the revised standards will
require significant additional reductions in nitrogen oxide and sulfur dioxide
emissions from coal-fired boilers. In October 1997, the EPA announced that
Missouri and Illinois are included in the area targeted for nitrogen oxide
emissions reductions as part of the EPA's regional control program. Reduction
requirements in nitrogen oxide emissions from the Company's coal-fired boilers
could exceed 80% from 1990 levels by the year 2002. Reduction requirements in
sulfur dioxide emissions may be 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. Because of the magnitude of these additional reductions,
the Company could be required to incur significantly higher capital costs to
meet future compliance obligations for its coal-fired boilers or purchase power
from other sources, either of which could have significantly higher operations
and maintenance expenditures associated with compliance. At this time, the
Company is unable to determine the impact of the revised air quality standards
on its future financial condition, results of operations or liquidity.
In December 1997, the United States and numerous other countries agreed to
certain environmental provisions (the Kyoto Protocol), which would require
decreases in greenhouse gases in an effort to address the "global warming"
issue. The Company 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 expenditures by the Company. At this time, the
Company is unable to determine the impact of these proposals on its future
financial condition, results of operations or liquidity.
See Note 11 - Callaway Nuclear Plant under Notes to Financial Statements
for a discussion of Callaway Plant decommissioning costs.
Cash flows used in financing activities were $320 million for 1997,
compared to $238 million and $299 million for 1996 and 1995, respectively. The
Company's principal financing activities during 1997 included the redemption of
$64 million of preferred stock and the payment of dividends.
The Company plans to continue utilizing short-term debt to support normal
operations and other temporary requirements. The Company is authorized by the
Federal Energy Regulatory Commission (FERC) to have up to $600 million of
short-term unsecured debt instruments outstanding at any one time. Short-term
borrowings consist of bank loans (maturities generally on an overnight basis)
and commercial paper (maturities generally within 10 to 45 days). At December
31, 1997, the Company had committed bank lines of credit aggregating $179
million (of which $164 million 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 Company had $21
million of short-term borrowings.
The Company also has bank credit agreements due 1999 which permit the
borrowing of up to $300 million and $200 million on a long-term basis. At
December 31, 1997, $35 million of such borrowings were outstanding.
Additionally, the Company has a lease agreement which provides for the
financing of nuclear fuel. At December 31, 1997, the maximum amount which could
be financed under the agreement was $120 million. Cash provided from financing
for 1997 included issuances under the lease for nuclear fuel of $40 million,
offset in part by $28 million of redemptions. At December 31, 1997, $117 million
was financed under the lease. (See Note 3 - 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.
CONTINGENCIES
See Note 10 - Commitments and Contingencies under Notes to Financial
Statements for material issues existing at December 31, 1997.
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 FERC the authority to
order electric utilities to provide transmission access to third parties.
In April 1996, the FERC issued Order 888 and Order 889 which are intended
to promote competition in the wholesale electric market. The FERC requires
transmission-owning public utilities, such as the Company, 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 Company 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 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 Act) providing for electric utility restructuring in
Illinois. This legislation introduces competition into the supply of electric
energy in Illinois. (See Note 2 - Regulatory Matters under Notes to Financial
Statements for further information.)
After evaluating the impact of this legislation, the Company 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 Company has also
concluded that its remaining net generation-related assets are not impaired and
that no plant write-downs are necessary at this time. The provisions of the Act
could also result in lower revenues, reduced profit margins and increased costs
of capital. At this time, the Company is unable to determine any further impact
of the Act on its future financial condition, results of operations or
liquidity. (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 Missouri Public Service
Commission (MoPSC) is investigating electric industry restructuring and
competition and is expected to issue a report to the MoPSC in 1998. A joint
legislative committee is also conducting studies on these issues. Up to this
point, retail wheeling has not been allowed in Missouri; however, the joint
agreement approved by the MoPSC in February 1997 as part of its merger
authorization includes a provision that required the Company to file a proposal
for a 100-megawatt experimental retail wheeling pilot program in Missouri. The
Company filed its proposal with the MoPSC in September 1997. This proposal is
subject to review and approval by the MoPSC.
The Company is unable to predict the timing or ultimate outcome of electric
industry restructuring in the state of Missouri, as well as its impact on the
Company'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. (See Note 2 - Regulatory
Matters under Notes to Financial Statements for further information.)
INFORMATION SYSTEMS
The Year 2000 issue relates to computer systems and applications that
currently use two-digit date fields to designate a year. As the century date
change occurs, date-sensitive systems will recognize the year 2000 as 1900, or
not at all. This inability to recognize or properly treat the year 2000 may
cause systems to process critical financial and operational information
incorrectly.
The Company is utilizing both internal and external resources to identify,
correct or reprogram and test information systems for Year 2000 compliance. The
Company estimates that its costs for addressing the Year 2000 issue will range
from $7 to $11 million. These costs will be expensed as incurred.
OUTLOOK
Significant changes are taking place in the electric utility industry. The
Company's management and Board of Directors recognize that competition likely
will continue to increase in the future, especially in the energy supply portion
of the business. New air quality standards are being considered which could
significantly increase capital costs, purchased power expenses and other
operations and maintenance expenditures. In addition, expenditures for
information systems are increasing (including those costs associated with the
Year 2000 issue). These issues will result in numerous challenges and
uncertainties for the Company and the utility industry, including the potential
for increased earnings pressure on the Company and other electric utilities. At
this time, management cannot predict the ultimate timing or impact of these
matters on its future financial condition, results of operations or liquidity.
The Company's management and its Board of Directors are taking actions to
address these challenges. Efforts are underway to accelerate merger cost savings
and other expense reductions. The Company is also analyzing the potential
benefits associated with the Illinois electric industry restructuring
legislation, including the elimination of the fuel adjustment clause and the
securitization of certain future revenues. Through these initiatives and other
strategies, the Company intends to address these challenges, maximize the value
of its strategic generating assets and enhance shareholder value.
ACCOUNTING MATTERS
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income"
and SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information." SFAS 130 establishes standards for reporting and displaying
comprehensive income. SFAS 131 establishes standards for reporting information
about operating segments in annual financial statements and interim reports to
shareholders. SFAS 130 and SFAS 131 are effective for fiscal years beginning
after December 15, 1997. SFAS 130 and SFAS 131 are not expected to have a
material effect on the Company's financial position or results of operations
upon adoption.
EFFECTS OF INFLATION AND CHANGING PRICES
The Company'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 Company's utility plants substantially
exceeds their recorded historical cost. Under existing regulatory practice, only
the historical cost of plants is recoverable from customers. As a result, cash
flows designed to provide recovery of historical costs through depreciation may
not be adequate to replace plant in future years. However, existing regulatory
practice may be modified for the Company's generation portion of its business
(see Note 2 - Regulatory Matters under Notes to Financial Statements for further
information).
In Illinois, changes in the cost of fuel for electric generation and gas
costs are generally reflected in billings to customers through fuel and
purchased gas adjustment clauses. However, existing regulatory practice may be
modified in the Illinois retail jurisdiction for changes in the cost of fuel for
electric generation (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. Changes in
gas costs in the Missouri retail jurisdiction 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 and
financial performance. In connection with the "Safe Harbor" provisions of the
Private Securities Litigation Reform Act of 1995, the Company 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 electricity; average
rates for electricity in the Midwest; business and economic conditions; weather
conditions; fuel prices and availability; generation plant performance; monetary
and fiscal policies; and legal and administrative proceedings.
REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------
To the Board of Directors
of Union Electric Company
In our opinion, the financial statements listed in the index appearing under
Item 14(a)1 on page 36 present fairly, in all material respects, the financial
position of Union Electric Company at December 31, 1997 and 1996, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1997 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/ PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
St. Louis, Missouri
February 5, 1998
- 14 -
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
UNION ELECTRIC COMPANY
BALANCE SHEET
(Thousands of Dollars, Except Shares)
December 31, December 31,
ASSETS 1997 1996
Property and plant, at original cost:
Electric $8,832,039 $8,630,628
Gas 197,959 185,867
Other 36,023 35,965
------------------ -----------------
9,066,021 8,852,460
Less accumulated depreciation and amortization 3,866,925 3,656,890
------------------ -----------------
5,199,096 5,195,570
Construction work in progress:
Nuclear fuel in process 134,804 96,147
Other 68,074 90,953
------------------ -----------------
Total property and plant, net 5,401,974 5,382,670
------------------ -----------------
Investments and other assets:
Nuclear decommissioning trust fund 122,438 96,601
Other 33,315 37,968
------------------ -----------------
Total investments and other assets 155,753 134,569
------------------ -----------------
Current assets:
Cash and cash equivalents 3,232 4,897
Accounts receivable - trade (less allowance for doubtful
accounts of $3,645 and $5,195, respectively) 179,708 192,868
Unbilled revenue 71,156 76,190
Other accounts and notes receivable 41,028 37,190
Materials and supplies, at average cost -
Fossil fuel 49,574 63,651
Other 97,375 94,517
Other 11,040 13,326
------------------ -----------------
Total current assets 453,113 482,639
------------------ -----------------
Regulatory assets:
Deferred income taxes 611,740 692,171
Other 179,705 178,760
------------------ -----------------
Total regulatory assets 791,445 870,931
------------------ -----------------
Total Assets $6,802,285 $6,870,809
================== =================
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 716,879 717,669
Retained earnings 1,159,956 1,126,513
------------------ -----------------
Total common stockholders' equity 2,387,454 2,354,801
Preferred stock not subject to mandatory redemption 155,197 218,497
Preferred stock subject to mandatory redemption - 624
Long-term debt 1,846,482 1,798,671
------------------ -----------------
Total capitalization 4,389,133 4,372,593
------------------ -----------------
Current liabilities:
Current maturity of long-term debt 28,797 73,966
Short-term debt 21,300 11,300
Accounts and wages payable 188,014 210,349
Accumulated deferred income taxes 35,809 43,933
Taxes accrued 94,167 51,545
Other 142,859 169,368
------------------ -----------------
Total current liabilities 510,946 560,461
------------------ -----------------
Accumulated deferred income taxes 1,264,800 1,318,404
Accumulated deferred investment tax credits 149,891 160,342
Regulatory liability 175,638 203,822
Other deferred credits and liabilities 311,877 255,187
================== =================
Total Capital and Liabilities $6,802,285 $6,870,809
================== =================
See Notes to Financial Statements.
UNION ELECTRIC COMPANY
STATEMENT OF INCOME
(Thousands of Dollars)
December 31, December 31, December 31,
For the year ended 1997 1996 1995
OPERATING REVENUES:
Electric $ 2,188,571 $ 2,160,815 $ 2,154,109
Gas 98,259 99,064 87,814
Steam 503 485 441
----------- ----------- -----------
Total operating revenues 2,287,333 2,260,364 2,242,364
OPERATING EXPENSES:
Operations
Fuel and purchased power 499,995 512,831 504,815
Gas 63,453 64,548 51,251
Other 404,956 379,106 367,870
----------- ----------- -----------
968,404 956,485 923,936
Maintenance 217,426 223,632 221,609
Depreciation and amortization 247,961 241,298 233,237
Income taxes 192,766 197,369 209,541
Other taxes 211,949 213,266 212,145
----------- ----------- -----------
Total operating expenses 1,838,506 1,832,050 1,800,468
OPERATING INCOME 448,827 428,314 441,896
OTHER INCOME AND DEDUCTIONS:
Allowance for equity funds used during
construction 4,461 6,492 6,827
Miscellaneous, net 7,334 (4,293) (5,981)
----------- ----------- -----------
Total other income and deductions 11,795 2,199 846
INCOME BEFORE INTEREST CHARGES 460,622 430,513 442,742
INTEREST CHARGES:
Interest 138,676 132,644 134,741
Allowance for borrowed funds used during construction (6,676) (7,007) (6,106)
Net interest charges 132,000 125,637 128,635
----------- ----------- -----------
INCOME BEFORE EXTRAORDINARY CHARGE 328,622 304,876 314,107
----------- ----------- -----------
EXTRAORDINARY CHARGE (NET OF
INCOME TAXES) (NOTE 2) (26,967) -- --
----------- ----------- -----------
NET INCOME 301,655 304,876 314,107
----------- ----------- -----------
PREFERRED STOCK DIVIDENDS 8,817 13,249 13,250
----------- ----------- -----------
NET INCOME AFTER PREFERRED
STOCK DIVIDENDS $ 292,838 $ 291,627 $ 300,857
=========== =========== ===========
See Notes to Financial Statements.
UNION ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
(Thousands of Dollars)
December 31, December 31 December 31,
For the year ended 1997 1996 1995
Cash Flows From Operating:
Income before extraordinary charge $328,622 $304,876 $314,107
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 238,846 231,743 223,705
Amortization of nuclear fuel 37,126 37,792 35,140
Allowance for funds used during construction (11,137) (13,499) (12,933)
Postretirement benefit accrued - - 11,923
Deferred income taxes, net (23,788) 4,948 (5,628)
Deferred investment tax credits, net (10,451) (6,182) (6,181)
Changes in assets and liabilities:
Receivables, net 14,356 (11,028) (41,405)
Materials and supplies 11,219 (18,866) 11,914
Accounts and wages payable (22,335) 4,732 108,997
Taxes accrued 42,622 3,832 (5,722)
Other, net (2,941) 66,344 5,595
-------------------- ------------------ --------------------
Net cash provided by operating activities 602,139 604,692 639,512
Cash Flows From Investing:
Construction expenditures (259,418) (325,110) (311,253)
Allowance for funds used during construction 11,137 13,499 12,933
Nuclear fuel expenditures (35,432) (51,176) (42,444)
-------------------- ------------------ --------------------
Net cash used in investing activities (283,713) (362,787) (340,764)
Cash Flows From Financing:
Dividends on common stock (259,395) (256,331) (250,714)
Dividends on preferred stock (8,817) (12,941) (13,250)
Environmental bond funds - - 4,443
Redemptions -
Nuclear fuel lease (28,292) (34,819) (70,420)
Short-term debt - (8,300) -
Long-term debt (45,000) (35,000) (38,000)
Preferred stock (63,924) (26) (26)
Issuances -
Nuclear fuel lease 40,337 43,884 49,134
Short-term debt 10,000 - 19,600
Long-term debt 35,000 65,500 -
-------------------- ------------------ --------------------
Net cash used in financing activities (320,091) (238,033) (299,233)
Net change in cash and cash equivalents (1,665) 3,872 (485)
Cash and cash equivalents at beginning of year 4,897 1,025 1,510
================== ================== ====================
Cash and cash equivalents at end of year $3,232 $4,897 $1,025
===================================================== ================== ================== ====================
Cash paid during the periods:
- --------------------------------------- --------------------------------- ----------------- -- --------------------
Interest (net of amount capitalized) $117,187 $120,745 $131,635
Income taxes $195,498 $193,043 $226,458
- --------------------------------------- --------------------------------- ----------------- -- --------------------
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 for further
information.)
See Notes to Financial Statements.
UNION ELECTRIC COMPANY
STATEMENT OF RETAINED EARNINGS
(Thousands of Dollars)
- --------------------------------------- --------------------- ------------------- -------------------
Year Ended December 31, 1997 1996 1995
- --------------------------------------- --------------------- ------------------- -------------------
Balance at Beginning of Period $1,126,513 $1,090,909 $1,040,766
- --------------------------------------- --------------------- ------------------- -------------------
Add:
Net income 301,655 304,876 314,107
- --------------------------------------- --------------------- ------------------- -------------------
1,428,168 1,395,785 1,354,873
- --------------------------------------- --------------------- ------------------- -------------------
Deduct:
Preferred stock dividends 8,817 12,941 13,250
Common stock cash dividends 259,395 256,331 250,714
- --------------------------------------- --------------------- ------------------- -------------------
268,212 269,272 263,964
- --------------------------------------- --------------------- ------------------- -------------------
$1,159,956 $1,126,513 $1,090,909
- --------------------------------------- --------------------- ------------------- -------------------
Under mortgage indentures as amended, $34,435 of total retained earnings
was restricted against payment of common dividends - except those payable in
common stock, leaving $1,125,521 of free and unrestricted retained earnings at
December 31, 1997.
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, 1997 (a) $487,258 $65,587 $31,630 $29,426
March 31, 1996 (a) 495,570 69,754 40,140 36,828
June 30, 1997 (b) 549,954 104,084 69,642 67,437
June 30, 1996 (b) 545,444 95,646 63,947 60,634
September 30, 1997 (c) 774,354 218,646 183,779 181,575
September 30, 1996 (c) 743,666 213,974 184,966 181,655
December 31, 1997 (d) 475,767 60,510 16,604 14,400
December 31, 1996 (d) 475,684 48,940 15,823 12,510
- --------------------------- -- ------------ -- ------------- -- -------------- ---------------
(a) The first quarter of 1997 and 1996 included credits to Missouri
electric customers which reduced net income and earnings on common stock
approximately $7 million and $8 million, respectively. In addition, a 1.8% rate
decrease effective August 1995 for Missouri electric customers reduced net
income and earnings on common stock for the first quarter of 1996 $4 million.
(b) The second quarter of 1997 and 1996 included credits to Missouri
electric customers which reduced net income and earnings on common stock
approximately $4 million and $18 million, respectively. In addition, the 1995
rate decrease reduced net income and earnings on common stock for the second
quarter of 1996 $5 million.
(c) The 1995 rate decrease reduced net income and earnings on common stock
for the third quarter of 1996 $3 million. Merger-related expenses of $4 million
and $1 million were also included for the third quarter of 1997 and 1996,
respectively.
(d) 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. The
fourth quarter of 1996 included merger-related expenses of $3 million. Callaway
Plant refueling expenses, which decreased net income and earnings on common
stock approximately $18 million, were also included in the fourth quarter of
1996.
Other changes in quarterly earnings are due to the effect of weather on
sales and other factors that are characteristic of public utility operations.
See Notes to Financial Statements.
UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1997
NOTE 1 - Summary of Significant Accounting Policies
Merger and Basis of Presentation
Effective December 31, 1997, following the receipt of all required state
and federal regulatory approvals, Union Electric Company (AmerenUE or the
Company) and CIPSCO Incorporated (CIPSCO) combined to form Ameren Corporation
(Ameren)(the Merger).
AmerenUE is a wholly-owned subsidiary of Ameren, which is the parent
company of two utility operating companies, the Company and Central Illinois
Public Service Company (AmerenCIPS). Ameren is registered as a holding company
under the Public Utility Holding Company Act of 1935 (PUHCA). 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.
The Company 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
The Company is regulated by the Missouri Public Service Commission (MoPSC),
Illinois Commerce Commission (ICC), and the FERC. The accounting policies of the
Company 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, plus
an allowance for funds used during construction. 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, 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 1997, 1996 and 1995 was approximately 3% of the
average depreciable cost.
Fuel and Gas Costs
In Illinois, changes in the cost of fuel for electric generation and gas
costs are generally reflected in billings to customers through fuel and
purchased gas adjustment clauses. However, existing regulatory practice may be
modified in the Illinois retail jurisdiction for changes in the cost of fuel for
electric generation (see Note 2 - Regulatory Matters 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. Changes in gas costs in the Missouri retail jurisdiction are
generally reflected in billings to customers through a purchased gas adjustment
clause.
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 a maturity of three months or less.
Income Taxes
The Company is included in the consolidated federal income tax return filed
by Ameren. Income taxes are allocated to the individual companies based on their
respective taxable income or loss. Deferred tax assets and liabilities are
recognized for the tax consequences of transactions that have been treated
differently for financial reporting and tax return purposes, measured using
statutory tax rates.
Investment tax credits utilized in prior years were deferred and are being
amortized over the useful lives of the related properties.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFC) is a utility industry
accounting practice whereby the cost of borrowed funds and the cost of equity
funds (preferred and common stockholders' equity) applicable to the Company's
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 rate-making 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 during 1997, 1996, and 1995 were
8.7%, 9.0% and 9.3%, respectively.
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 Company accrues an estimate of electric and gas revenues for service
rendered but unbilled at the end of each accounting period.
Stock Compensation Plans
The Company applies Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees" (APB 25) in accounting for its plans.
Long-Lived Assets
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
became effective on January 1, 1996. SFAS 121 prescribes general standards for
the recognition and measurement of impairment losses. SFAS 121 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).
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 involving the Company's
Missouri retail electric rates. The agreement decreased rates 1.8% for all
classes of Missouri retail electric customers, effective August 1, 1995,
reducing annual revenues about $30 million and reducing earnings $18 million. In
addition, a one-time $30 million credit to retail Missouri electric customers
reduced 1995 earnings by $18 million. Also included was a three-year
experimental alternative regulation plan that runs from July 1, 1995 through
June 30, 1998, which provides that earnings in any future years in excess of a
12.61% regulatory return on equity (ROE) will be shared equally between
customers and stockholders, and earnings above a 14% ROE will be credited to
customers. The formula for computing the credit uses twelve-month results ending
June 30, rather than calendar year earnings. The agreement also provides that no
party shall file for a general increase or decrease in the Company's Missouri
retail electric rates prior to July 1, 1998, except that the Company may file
for an increase if certain adverse events occur. During 1997, the Company
recorded a $20 million credit for the second year of the plan, which reduced
earnings $11 million. During 1996, the Company recorded a $47 million credit,
which reduced earnings $28 million. These credits were reflected as a reduction
in electric revenues.
Included in the joint agreement approved by the MoPSC in its February 1997
order authorizing the Merger, is a new three-year experimental alternative
regulation plan that will run from July 1, 1998 through June 30, 2001. Like the
current plan, the new plan requires that earnings over a 12.61% ROE up to a 14%
ROE will be shared equally between customers and 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 would be credited entirely to
customers. Other agreement provisions include: recovery within a 10-year period
of the merger-related expenses applicable to the Missouri retail jurisdiction; a
Missouri electric rate decrease, effective September 1, 1998, based on the
weather-adjusted average annual credits to customers under the current
experimental alternative regulation plan; and an experimental retail wheeling
pilot program for 100 megawatts of electric power. Also, as part of the
agreement, the Company did not seek to recover in Missouri the merger premium.
The exclusion of the merger premium from rates did not result in a charge to
earnings.
In September 1997, the ICC approved the Merger subject to certain
conditions. The conditions included the requirement for the Company to file
electric and gas rate cases or alternative regulatory plans within six months
after the Merger became final to determine how net merger savings would be
shared between the ratepayers and stockholders.
In December 1997, the Governor of Illinois signed the Electric Service
Customer Choice and Rate Relief Law of 1997 (the Act) providing for electric
utility restructuring in Illinois. This legislation introduces competition into
the supply of electric energy in Illinois. The Act includes a 5% rate decrease
for the Company's Illinois residential electric customers, effective August 1,
1998. The Company 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 Company's rates are currently below the
Midwest utility average. The Company estimates that the initial 5% rate decrease
will result in a decrease in annual electric revenues of about $3 million, based
on estimated levels of sales and assuming normal weather conditions. 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 Act
also relieves the Company of the requirement in the ICC's September 1997 Order
(which approved the Merger), requiring the Company to file an electric rate case
or alternative regulatory plan in Illinois following consummation of the Merger
to reflect the effects of net merger savings. Other provisions of the Act
include (1) potential recovery of a portion of stranded costs through a
transition charge collected from customers who choose another electric supplier,
(2) the option to eliminate the uniform fuel adjustment clause (FAC) and to roll
into base rates a historical level of fuel expense and (3) a mechanism to
securitize certain future revenues.
The Company'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 No. 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
Company 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 which no longer meets the SFAS 71 criteria. At
its July 24, 1997 meeting, the Emerging Issues Task Force of the Financial
Accounting Standards Board (EITF) 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 recovered. 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 Act, 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 Company discontinued application of SFAS 71 for the Illinois
retail portion of its generating business (i.e., the portion of the Company's
business related to the supply of electric energy in Illinois) in the fourth
quarter of 1997. The Company has evaluated the impact of the Act on the future
recoverability of its regulatory assets and liabilities related to the
generation portion of its business and has determined that it is not probable
that such assets and liabilities will be recovered through the cash flows from
the regulated portion of its business. Accordingly, the Company'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 Company has evaluated whether the recoverability
of the costs associated with its remaining net generation-related assets have
been impaired as defined under SFAS 121. The Company 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, 1997, the Company's net
investment in generation facilities related to its Illinois retail jurisdiction
approximated $234 million and was included in electric plant in-service on the
Company's balance sheet.
The provisions of the Act could also result in lower revenues, reduced
profit margins and increased costs of capital. At this time, the Company is
unable to determine any further impact of the Act on its future financial
condition, results of operations or liquidity.
In Missouri, where approximately 92% of the Company's retail electric
revenues are derived, a task force appointed by the MoPSC is conducting studies
of electric industry restructuring and competition and is expected to issue a
report to the MoPSC in 1998. A joint legislative committee is also conducting
studies and is expected to report its findings and recommendations to the
Missouri General Assembly. Up to this point, retail wheeling has not been
allowed in Missouri; however, the joint agreement approved by the MoPSC in
February 1997 as part of its merger authorization includes a provision that
required the Company to file a proposal for a 100-megawatt experimental retail
wheeling pilot program in Missouri. The Company filed its proposal with the
MoPSC in September 1997. This proposal is subject to review and approval by the
MoPSC.
The Company is unable to predict the timing or ultimate outcome of electric
industry restructuring in the state of Missouri, as well as its impact on the
Company'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. At December 31, 1997, the
Company's net investment in generation facilities related to its Missouri
jurisdiction approximated $2.7 billion and was included in electric plant
in-service on the Company's balance sheet. In addition, at December 31, 1997,
the Company's Missouri net generation-related regulatory assets approximated
$462 million.
In accordance with SFAS 71, the Company 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 Company had recorded the following regulatory assets
and regulatory liability:
- ------------------------------------------ ------------------------ -------------------------
(in millions) 1997 1996
- ------------------------------------------ ------------------------ -------------------------
Regulatory Assets:
Income taxes $612 $692
Callaway costs 99 111
Merger costs 28 -
Unamortized loss on reacquired debt 26 30
DOE decommissioning assessment 15 18
Other 11 20
- ------------------------------------------ ------------------------ -------------------------
Regulatory Assets $791 $871
- ------------------------------------------ ------------------------ -------------------------
Regulatory Liability:
Income taxes $176 $204
- ------------------------------------------ ------------------------ -------------------------
Regulatory Liability $176 $204
- ------------------------------------------ ------------------------ -------------------------
Income Taxes: See Note 7 - 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.
Department of Energy (DOE) Decommissioning Assessment: Represents fees
assessed by the DOE to decommission its uranium enrichment facility. These costs
are being amortized through 2007 as payments are made to the DOE.
The Company 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 which conforms to the FERC's orders.
NOTE 3 - Nuclear Fuel Lease
The Company has a lease agreement which provides for the financing of
nuclear fuel. At December 31, 1997, the maximum amount that could be financed
under the agreement was $120 million. Pursuant to the terms of the lease, the
Company 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 Company 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 Company's Callaway Nuclear Plant. The
Company reimbursed the lessor $31 million during 1997, $37 million during 1996,
and $34 million during 1995.
The Company has capitalized the cost, including certain interest costs, of
the leased nuclear fuel and has recorded the related lease obligation. During
each of the years 1997, 1996 and 1995, the total interest charges under the
lease were $6 million (based on average interest rates of 5.8%, 5.7% and 6.1%,
respectively) of which $3 million was capitalized in each respective year.
NOTE 4 - Preferred Stock
At December 31, 1997 and 1996, the Company had 25 million shares of
authorized preferred stock.
In 1997, the Company redeemed $64 million of preferred stock (see note (b)
in table below). The Company retired 260 shares, $6.30 Series preferred stock in
1996.
Outstanding preferred stock is redeemable at the redemption prices shown below:
- ------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------
December 31, 1997 1996
(in millions)
- ----------------------------------------------------- --------------------- ------- -------
Preferred Stock Not Subject to Mandatory
Redemption:
- ----------------------------------------------------- --------------------- ------- -------
Preferred stock outstanding without par value
(entitled to cumulative dividends)
Redemption Price
(per share)
Stated value of $100 per share--
$7.64 Series - 330,000 shares $103.82 - note (a) $33 $33
$7.44 Series - 330,001 shares 101.00 - note (b) - 33
$6.40 Series - 300,000 shares 101.50 - note (b) - 30
$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 (c) 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
Stated value of $25.00 per share--
$1.735 Series - 1,657,500 shares 25.00 - note (d) 42 42
- ----------------------------------------------------- --------------------- ------- ------
TOTAL PREFERRED STOCK NOT
SUBJECT TO MANDATORY REDEMPTION $155 $218
- ----------------------------------------------------- --------------------- ------- ------
Preferred Stock Subject to Mandatory Redemption:
- ----------------------------------------------------- --------------------- ------- ------
Preferred stock outstanding without par value
(entitled to cumulative dividends)
Stated value of $100 per share--
$6.30 Series - 0 and 6,240 shares
at respective dates $100.00 - note (b) $ - $1
- ----------------------------------------------------- --------------------- ------- ------
TOTAL PREFERRED STOCK SUBJECT
TO MANDATORY REDEMPTION $ - $1
- ----------------------------------------------------- --------------------- ------- ------
(a) Beginning February 15, 2003, eventually declining to $100 per share. (b) The
Company redeemed this series in 1997. (c) In the event of voluntary liquidation,
$105.50.
(d) Not redeemable prior to August 1, 1998.
- ------------------------------------------------------------------------------------------------
NOTE 5 - Short-Term Borrowings
Short-term borrowings of the Company consist of bank loans (maturities
generally on an overnight basis) and commercial paper (maturities generally
within 10-45 days). At December 31, 1997 and 1996, $21 million and $11 million,
respectively, of short-term borrowings were outstanding. The weighted average
interest rates on borrowings outstanding at December 31, 1997 and 1996, were
7.0% and 7.1%, respectively.
At December 31, 1997, the Company had committed bank lines of credit
aggregating $179 million (of which $164 million were 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 6 - Long-Term Debt
Long-term debt outstanding at December 31, was:
- ----------------------------------------------------------- -------------------------- ----------------------
(in millions) 1997 1996
- ----------------------------------------------------------- -------------------------- ----------------------
First Mortgage Bonds - note (a)
- ----------------------------------------------------------- -------------------------- ----------------------
5 5/8% Series paid in 1997 $ - $ 5
5 1/2% Series paid in 1997 - 40
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 1,334
- ----------------------------------------------------------- -------------------------- ----------------------
- ----------------------------------------------------------- -------------------------- ----------------------
Missouri Environmental Improvement Revenues Bonds
- ----------------------------------------------------------- -------------------------- ----------------------
1984 Series A due 2014 - note (c) 80 80
1984 Series B due 2014 - note (c) 80 80
1985 Series A due 2015 - note (d) 70 70
1985 Series B due 2015 - note (d) 57 57
1991 Series due 2020 - note (d) 43 43
1992 Series due 2022 - note (d) 47 47
- ----------------------------------------------------------- -------------------------- ----------------------
377 377
- ----------------------------------------------------------- -------------------------- ----------------------
- ----------------------------------------------------------- -------------------------- ----------------------
Subordinated Deferrable Interest Debentures
- ----------------------------------------------------------- -------------------------- ----------------------
7.69% Series A due 2036 - note (e) 66 66
- ----------------------------------------------------------- -------------------------- ----------------------
Commercial Paper - note (f) 35 -
- ----------------------------------------------------------- -------------------------- ----------------------
Nuclear Fuel Lease 117 106
- ----------------------------------------------------------- -------------------------- ----------------------
Unamortized Discount and Premium on Debt (9) (10)
- ----------------------------------------------------------- -------------------------- ----------------------
Maturities Due Within One Year (29) (74)
- ----------------------------------------------------------- -------------------------- ----------------------
Total Long-Term Debt $1,846 $1,799
- ----------------------------------------------------------- -------------------------- ----------------------
(a) At December 31, 1997, 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) On June 1 of each year, the interest rate is established for the following
year, or alternatively at the option of the Company, may be fixed until
maturity. A per annum rate of 3.95% is effective for the year ended May 31,
1998.Thereafter, the interest rates will depend on market conditions and
the selection of an annual versus remaining life rate by the Company. The
average interest rate for 1997 was 3.83%.
(d) Interest rates, and the periods during which such rates apply, vary
depending on the Company's selection of certain defined rate modes. The
average interest rates for the year 1997, for 1985 Series A, 1985 Series B,
1991 Series and 1992 Series bonds were 3.61%, 3.82%, 3.86%, and 3.83%,
respectively.
(e) During the terms of the debentures, the Company may, under certain
circumstances, defer the payment of interest for up to five years.
(f) A bank credit agreement, due 1999, permits the Company to borrow or to
support commercial paper borrowings up to $300 million. Interest rates will
vary depending on market conditions. At December 31, 1997, the oustanding
commercial paper was at an average annualized rate of 5.93%.
(g) A bank credit agreement, due 1999, permits the Company to borrow up to $200
million. Interest rates will vary depending on market conditions and the
Company's selection of various options under the agreement. At December 31,
1997, no such borrowings were outstanding.
- --------------------------------------------------------------------------------
Maturities of long-term debt through 2002 are as follows:
- ------------------- ----------------------------------------
(in millions) Principal Amount
- ------------------- ----------------------------------------
1998 $ 29
1999 135
2000 -
2001 -
2002 75
- ------------------- ----------------------------------------
Amounts for years subsequent to 1998 do not include nuclear fuel lease
payments since the amounts of such payments are not currently determinable.
NOTE 7 - Income Taxes
Total income tax expense for 1997 resulted in an effective tax rate of 38%
on earnings before income taxes (39% in 1996 and 40% in 1995).
Principal reasons such rates differ from the statutory federal rate:
- ----------------------------------- ---- ---- ----
1997 1996 1995
- ----------------------------------- ---- ---- ----
Statutory federal income
tax rate 35% 35% 35%
Increases (Decreases) from:
Depreciation differences 2 2 2
State tax 4 4 4
Other (3) (2) (1)
- ----------------------------------- ---- ---- ----
Effective income tax rate 38% 39% 40%
- ----------------------------------- ---- ---- ----
Income tax expense components:
- ----------------------------------- ---- ---- ----
(in millions) 1997 1996 1995
- ----------------------------------- ---- ---- ----
Taxes currently payable (principally federal):
Included in operating expenses $216 $199 $223
Included in other income--
Miscellaneous, net (3) (2) (3)
- ----------------------------------- ---- ---- ----
213 197 220
Deferred taxes (principally federal):
Included in operating expenses--
Depreciation differences (7) 2 5
Postretirement benefits (9)
Other (10) 2 (3)
Included in other income--
Depreciation differences 1 1 1
Other 9 - -
- ----------------------------------- ---- ---- -----
(7) 5 (6)
Deferred investment tax credits,
amortization
Included in operating expenses (6) (6) (6)
- ----------------------------------- ---- ---- -----
Total income tax expense $200 $196 $208
- ----------------------------------- ---- ---- -----
In accordance with SFAS 109, "Accounting for Income Taxes," a regulatory
asset, representing the probable recovery from customers of future income taxes
which is expected to occur when temporary differences reverse, was recorded
along with a corresponding deferred tax liability. Also, a regulatory liability,
recognizing the lower expected revenue resulting from reduced income taxes
associated with amortizing accumulated deferred investment tax credits, was
recorded. Investment tax credits have been deferred and will continue to be
credited to income over the lives of the related property.
The Company 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) 1997 1996
- ----------------------------------- ---- ----
Accumulated Deferred Income Taxes:
Depreciation $812 $826
Regulatory assets, net 451 488
Capitalized taxes and expenses 84 107
Deferred benefit costs (46) (48)
Disallowed plant costs - (11)
- ----------------------------------- ---- ----
Total net accumulated deferred income tax liabilities $1,301 $1,362
- ----------------------------------- ---- ----
NOTE 8 - Retirement Benefits
The Company has defined-benefit retirement plans covering substantially all
of its employees. Benefits are based on the employees' years of service and
compensation. The Company's plans are funded in compliance with income tax
regulations and federal funding requirements.
Pension costs for the years 1997, 1996 and 1995, were $24 million, $28
million and $26 million, respectively, of which approximately 17%, 19% and 20%,
respectively, was charged to construction accounts.
Funded Status of Pension Plans:
- ---------------------------------- ----- ---- ----
(in millions) 1997 1996 1995
- ---------------------------------- ----- ---- ----
Actuarial present value
of benefit obligation:
Vested benefit obligation $705 $661 $679
- ---------------------------------- ---- ---- ----
Accumulated benefit obligation
$829 $752 $758
- ---------------------------------- ---- ---- ----
Projected benefit obligation for
service rendered to date $999 $919 $913
Plan assets at fair value * 1,006 924 847
- ---------------------------------- ----- ---- ----
(Excess) Deficiency of plan assets
versus projected benefit obligation (7) (5) 66
Unrecognized net gain 115 96 22
Unrecognized prior service cost (69) (76) (82)
Unrecognized net assets at transition 7 8 9
- ----------------------------------- ------ ----- ----
Accrued pension cost at December 31 $46 $23 $15
- ----------------------------------- ------ ----- ----
* Plan assets consist principally of common stocks and fixed income securities.
Components of Net Pension Expense:
- ---------------------------------- ---- ---- ----
(in millions) 1997 1996 1995
- ---------------------------------- ---- ---- ----
Service cost - benefits earned
during the period $22 $22 $19
Interest cost on projected
benefit obligation 69 65 66
Actual return on plan assets (134) (107) (166)
Net amortization and deferral 67 48 107
- --------------------------------- ----- ----- -----
Pension Cost $24 $28 $26
- --------------------------------- ----- ----- ----
Assumptions for Actuarial Present Value of Projected Benefit Obligations:
- --------------------------------- ---- ---- ----
1997 1996 1995
- --------------------------------- ---- ---- ----
Discount rate at measurement date 7.0% 7.5% 7.25%
Increase in future compensation 4.0% 4.5% 4.25%
Plan assets long-term rate of return 8.5% 8.5% 8.5%
- --------------------------------- ---- ---- ----
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees. Substantially all
of the Company's employees may become eligible for those benefits if they reach
retirement age while working for the Company. The Company accrues the expected
postretirement benefit costs during employees' years of service.
The Company's funding policy is to annually contribute the net periodic
cost to a Voluntary Employee Beneficiary Association trust (VEBA).
Postretirement benefit costs were $44 million for each of the years 1997, 1996
and 1995, of which approximately 17% was charged to construction accounts in
1997 and 19% in each of 1996 and 1995. The Company's transition obligation at
December 31, 1997, is being amortized over the next 15 years.
In August 1994, the MoPSC authorized the recovery of postretirement benefit
costs in rates to the extent that such costs are funded. In December 1995, the
Company established two external trust funds for retiree health care and life
insurance benefits. For 1995, actual claims paid were approximately $15 million.
In 1997 and 1996, claims were paid out of the plan trust funds.
Funded Status of the Plans:
- ------------------------------------------ ---- ---- ----
(in millions) 1997 1996 1995
- ------------------------------------------ ---- ---- ----
Accumulated postretirement benefit
obligation
Active employees eligible for benefits $41 $38 $74
Retired employees 202 193 211
Other active employees 90 80 32
- ------------------------------------------ ---- ---- ----
Total benefit obligation 333 311 317
Plan assets at fair market value * 81 47 14
- ------------------------------------------ ---- ----- ----
Accumulated postretirement benefit
obligation in excess of plan assets 252 264 303
Unrecognized - transition obligation (187) (200) (213)
- gain/(loss) 18 19 (7)
- ------------------------------------------- ---- ---- ----
Postretirement benefit liability at December 31 $83 $83 $83
- ------------------------------------------- ---- ---- ----
* Plan assets consist principally of common stocks and fixed income securities.
Components of Postretirement Benefit Cost:
- ------------------------------------------- ---- ---- ----
(in millions) 1997 1996 1995
- ------------------------------------------- ---- ---- ----
Service cost - benefits earned
during the period $12 $12 $10
Interest cost on projected
benefit obligation 23 22 24
Actual return on plan assets (9) (4) -
Amortization - transition obligation 12 12 12
- unrecognized gain (1) (1) (2)
Deferred gain 7 3 -
- ------------------------------------------- ---- ---- ----
Net periodic cost $44 $44 $44
- ------------------------------------------- ---- ---- ----
Assumptions for the Obligation Measurements:
- ------------------------------------------- ---- ---- ----
1997 1996 1995
- ------------------------------------------- ---- ---- ----
Discount rate at measurement date 7.0% 7.5% 7.25%
Plan assets long-term rate of return 8.5% 8.5% 8.5%
Medical cost trend rate - initial 7.0% 8.25% 9.25%
- ultimate 5.0% 5.25% 5.25%
Ultimate medical cost trend rate
expected in year 2000 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 $3 million and $23 million, respectively.
NOTE 9 - Stock Option Plans
The Company has a long-term incentive plan (the Plan) for eligible
employees. The Plan provides for the grant of options, performance awards,
restricted stock, dividend equivalents and stock appreciation rights. Under the
terms of the Plan, options may be granted at a price not less than the fair
market value of the common shares at the date of grant. Granted options vest
over a period of five years, beginning at the date of grant, and provide for
acceleration of exercisability of the options upon the occurrence of certain
events, including retirement. Outstanding options expire on various dates
through 2007. Under the Plan, subject to adjustment as provided in the Plan, 2.5
million shares have been authorized to be issued or delivered.
Summary of Stock Options:
- ------------------------------------------------------ -------------------- --------------- ------------------
1997 1996 1995
- ------------------------------------------------------ -------------------- --------------- ------------------
Options outstanding at beginning of the year 307,390 142,500 -
Options granted during the year 195,880 165,590 142,500
Options exercised during the year - - -
Options expired/canceled during the year 7,200 700 -
- ------------------------------------------------------ -------------------- --------------- ------------------
Options outstanding at end of the year 496,070 307,390 142,500
- ------------------------------------------------------ -------------------- --------------- ------------------
Options exercisable at end of the year 134,785 39,710 9,800
- ------------------------------------------------------ -------------------- --------------- ------------------
Exercise price range of options granted $38.50 $43 $35.50 - $35.875
- ------------------------------------------------------ -------------------- --------------- ------------------
In accordance with APB 25, no compensation cost has been recognized for the
Company's stock compensation plans. In 1996, the Company adopted the
disclosure-only method under SFAS 123, "Accounting for Stock-Based
Compensation." If the fair value based accounting method under this statement
had been used to account for stock-based compensation cost, the effects on 1997,
1996 and 1995 net income and earnings per share would have been immaterial.
NOTE 10 - Commitments and Contingencies
The Company is engaged in a construction program under which expenditures
averaging approximately $243 million, including AFC, are anticipated during each
of the next five years. This estimate does not include any construction
expenditures which may be incurred by the Company to meet new air quality
standards for ozone and particulate matter, as discussed later in this Note.
The Company has commitments for the purchase of coal under long-term
contracts. Coal contract commitments, including transportation costs, for 1998
through 2002 are estimated to total $903 million. Total coal purchases,
including transportation costs, for 1997, 1996 and 1995 were $267 million, $297
million and $271 million, respectively. The Company also has existing contracts
with pipeline and natural gas suppliers to provide natural gas for distribution
and electric generation. Gas-related contracted cost commitments for 1998
through 2002 are estimated to total $79 million. Total delivered natural gas
costs for 1997, 1996 and 1995 were $63 million, $64 million and $60 million,
respectively. The Company's nuclear fuel commitments for 1998 through 2002,
including uranium concentrates, conversion, enrichment and fabrication, are
expected to total $116 million, and are expected to be financed under the
nuclear fuel lease. Nuclear fuel expenditures for 1997, 1996 and 1995 were $35
million, $51 million and $42 million, respectively. Additionally, the Company
has long-term contracts with other utilities to purchase electric capacity.
These commitments for 1998 through 2002 are estimated to total $187 million.
During 1997, 1996 and 1995, electric capacity purchases were $34 million, $44
million and $42 million, respectively.
The Company's insurance coverage for Callaway Nuclear Plant at December 31,
1997, was as follows:
Type and Source of Coverage
- ------------------------------------------------- -------------------- ---- -------------------- -----
(in millions) Maximum Maximum
Coverages Assessments
for Single
Incidents
- ------------------------------------------------------------------------------------------------------
Public Liability:
American Nuclear Insurers $ 200 $ -
Pool Participation 8,720 79 (a)
- ------------------------------------------------------------------------------------------------------
$8,920 (b) $ 79
- ------------------------------------------------------------------------------------------------------
Nuclear Worker Liability:
American Nuclear Insurers $ 200 (c) $ 3
- ------------------------------------------------------------------------------------------------------
Property Damage:
American Nuclear Insurers $ 500 $ -
Nuclear Electric Insurance Ltd. 2,250 (d) 11
- ------------------------------------------------------------------------------------------------------
$2,750 $ 11
- ------------------------------------------------------------------------------------------------------
Replacement Power:
Nuclear Electric Insurance Ltd. $ 473 (e) $ 4
- ------------------------------------------------------------------------------------------------------
(a) Retrospective premium under the Price-Anderson liability provisions of the
Atomic Energy Act of 1954, as amended, (Price- Anderson). Subject to
retrospective assessment with respect to loss from an incident at any U.S.
reactor, payable at $10 million per year.
(b) Limit of liability for each incident under Price-Anderson.
(c) Industry limit for potential liability from workers claiming exposure to
the hazard of nuclear radiation.
(d) Includes premature decommissioning costs.
(e) Weekly indemnity of $3.5 million, for 52 weeks which commences after the
first 21 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 Plant exceed the limits of,
or are not subject to, insurance, or if coverage is not available, the Company
will self-insure the risk. Although the Company has no reason to anticipate a
serious nuclear incident, if one did occur it could have a material but
indeterminable adverse effect on the Company's financial position, results of
operations or liquidity.
Under the Title IV of the Clean Air Act Amendments of 1990, the Company is
required to significantly reduce total annual sulfur dioxide emissions by the
year 2000. Significant reductions in nitrogen oxide are also required. By
switching to low-sulfur coal and early banking of emission credits, the Company
anticipates that it can comply with the requirements of the law without
significant revenue increases because the related capital costs are largely
offset by lower fuel costs. As of year-end 1997, estimated remaining capital
costs expected to be incurred pertaining to Clean Air Act-related projects
totaled $35 million.
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. Although specific emission control requirements
are still being developed, it is believed that the revised standards will
require significant additional reductions in nitrogen oxide and sulfur dioxide
emissions from coal-fired boilers. In October 1997, the EPA announced that
Missouri and Illinois are included in the area targeted for nitrogen oxide
emissions reductions as part of the EPA's regional control program. Reduction
requirements in nitrogen oxide emissions from the Company's coal-fired boilers
could exceed 80% from 1990 levels by the year 2002. Reduction requirements in
sulfur dioxide emissions may be 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. Because of the magnitude of these additional reductions,
the Company could be required to incur significantly higher capital costs to
meet future compliance obligations for its coal-fired boilers or purchase power
from other sources, either of which could have significantly higher operations
and maintenance expenditures associated with compliance. At this time, the
Company is unable to determine the impact of the revised air quality standards
on its future financial condition, results of operations or liquidity. In
December 1997, the United States and numerous other countries agreed to certain
environmental provisions (the Kyoto Protocol), which would require decreases in
greenhouse gases in an effort to address the "global warming" issue. The Company
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
expenditures by the Company. At this time, the Company is unable to determine
the impact of these proposals on its future financial condition, results of
operations or liquidity.
As of December 31, 1997, the Company was designated 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 Company may be responsible but has not been designated a PRP.
The Company 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 Company's financial position, results of
operations or liquidity.
Regulatory changes enacted and being considered at the federal and state
levels continue to change the structure of the utility industry and utility
regulation, as well as encourage increased competition. At this time, the
Company is unable to predict the impact of these changes on its future financial
condition, results of operations or liquidity. (See Note 2 - Regulatory Matters
for further discussion.)
The Company 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
Company 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 11 - Callaway Nuclear Plant
Under the Nuclear Waste Policy Act of 1982, the 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 Company has sufficient storage capacity at
Callaway Plant site until 2004 and is pursuing a viable storage alternative.
This alternative will require Nuclear Regulatory Commission approval. 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 $451 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 1997, 1996 and 1995. Every three years, the MoPSC requires the
Company 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 Company believes it is
probable that such earnings deficiency will be recovered in rates. Trust fund
earnings, net of expenses, appear on the balance sheet as increases in 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 Company 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 12 - Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value.
Cash and Temporary Investments/Short-Term Borrowings
The carrying amounts approximate fair value because of the short-term
maturity of these instruments.
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 Company for debt of
comparable maturities.
Carrying amounts and estimated fair values of the Company's financial
instruments at December 31 were as follows:
1997 1996
- ---------------------------------------------- ------------------------------ -----------------------
(in millions) Carrying Fair Carrying Fair
Amount Value Amount Value
- ---------------------------------------------- ----------------------------- -----------------------
Preferred stock $155 $143 $219 $192
Long-term debt (including current portion) $1,875 $1,969 $1,873 $1,921
- ---------------------------------------------- ------------------------------ -----------------------
The Company 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 11 - Callaway Nuclear Plant). The Company 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, 1997
and 1996. In 1997, 1996 and 1995, the proceeds from the sale of investments were
$24 million, $20 million and $9 million, respectively. Using the specific
identification method to determine cost, the gross realized gains on those sales
were approximately $2 million for 1997 and $1 million each for 1996 and 1995.
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 Company to account for the decommissioning costs
recovered in rates.
Costs and fair values of investments in debt and equity securities in the
nuclear decommissioning trust fund at December 31 were as follows:
- -------------------------- ------------------- -------------------- -------------------- -------------------
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
- -------------------------- ------------------- -------------------- -------------------- -------------------
- ----------------------- --------------------- -------------------- -------------------- --------------------
1996(in millions) Gross Unrealized
Security Type Cost Gain (Loss) Fair Value
- ----------------------- --------------------- -------------------- -------------------- --------------------
Debt Securities $29 $ 2 $ - $31
Equity Securities 40 22 - 62
Cash equivalents 4 - - 4
- ----------------------- --------------------- -------------------- -------------------- --------------------
$73 $24 $ - $97
- ----------------------- --------------------- -------------------- -------------------- --------------------
The contractual maturities of investments in debt securities at December 31,
1997, were as follows:
- -----------------------------------------------------------------------------------------------------------
(in millions) Cost Fair Value
- -----------------------------------------------------------------------------------------------------------
1 year to 5 years $4 $4
5 years to 10 years 6 7
Due after 10 years 24 26
- -----------------------------------------------------------------------------------------------------------
$34 $37
- -----------------------------------------------------------------------------------------------------------
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
DIRECTORS
William E. Cornelius, Retired Chairman and
Chief Executive Officer - Union Electric
Company
Thomas A. Hays, Retired Deputy Chairman -
The May Department Stores Company
Thomas H. Jacobsen, Chairman, President and
Chief Executive Officer - Mercantile
Bancorporation Inc., a bank holding company
Richard A. Liddy, Chairman, President and
Chief Executive Officer - General American
Life Insurance Company, a provider of
insurance products and services
John Peters MacCarthy, Retired Chairman and
Chief Executive Officer - Boatmen's Trust
Company
Paul L. Miller, Jr., President and Chief
Executive Officer, P.L. Miller and Associates,
a management consulting firm
Charles W. Mueller, President and
Chief Executive Officer
Robert H. Quenon, Retired Chairman of the
Board - Peabody Holding Company, Inc.
Gary L. Rainwater, President and
Chief Executive Officer - CIPS
Harvey Saligman, Retired Managing Partner -
Cynwyd Investments, a real estate partnership
Janet McAfee Weakley, President - Janet McAfee, Inc., a residential real estate
company
EXECUTIVE OFFICERS
Date First
Age At Elected or
Name 12/31/97 Present Position Appointed
Charles W. Mueller 59 President 7/1/93
Chief Executive Officer 1/1/94
and Director 6/11/93
Paul A. Agathen 50 Senior Vice President 2/16/96
Donald E. Brandt 43 Senior Vice President 7/1/88
Charles J. Schukai 63 Senior Vice President 7/1/88
M. Patricia Barrett 60 Vice President 3/1/91
Charles A. Bremer 53 Vice President 4/24/84
Donald W. Capone 62 Vice President 7/1/88
William J. Carr 60 Vice President 10/1/88
Jean M. Hannis 50 Vice President 1/1/96
William E. Jaudes 60 Vice President and 4/23/85
General Counsel 4/22/80
R. Alan Kelley 45 Vice President 7/1/88
Michael J. Montana 51 Vice President 7/1/88
Garry L. Randolph 49 Vice President 3/1/91
Robert J. Schukai 59 Vice President 7/1/88
William C. Shores 59 Vice President 7/1/88
Samuel E. Willis 53 Vice President 11/1/95
Ronald C. Zdellar 53 Vice President 7/1/88
Warner L. Baxter 36 Controller 8/1/96
James C. Thompson 58 Secretary 12/1/82
Jerre E. Birdsong 43 Treasurer 7/1/93
- 34 -
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 the Company except that Charles J. Schukai and Robert J.
Schukai are brothers. Except for Mr. Baxter, each of the above-named executive
officers has been employed by the Company for more than five years in executive
or management positions. Mr. Baxter was previously employed by Price Waterhouse
LLP.
Any additional information concerning directors required to be reported
by this item is included under "Item (1): Election of Directors" in the
Company's 1998 definitive proxy statement filed pursuant to Regulation 14A and
is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
Any information required to be reported by this item is included under
"Compensation" in the Company's 1998 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 the Company's 1998 definitive proxy
statement filed pursuant to Regulation 14A and is incorporated herein by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Any information required to be reported by this item is included under
"Item (1): Election of Directors" in the Company's 1998 definitive proxy
statement filed pursuant to Regulation 14A and is incorporated herein by
reference.
- 35 -
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 .................................... 14
Balance Sheet - December 31, 1997 and 1996 ........................... 15
Statement of Income - Years 1997, 1996, and 1995 ..................... 16
Statement of Cash Flows - Years 1997, 1996, and 1995 ................. 17
Statement of Retained Earnings - Years 1997, 1996, and 1995 .......... 18
Notes to Financial Statements ........................................ 19
Valuation and Qualifying Accounts (Schedule II)
Years 1997, 1996, and 1995 ......................................... 37
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 39
(b) Reports on Form 8-K. During the last quarter of 1997, the Company
filed a report on Form 8-K dated December 16, 1997 reporting the passage of
legislation designed to introduce pricebased competition into the supply of
electric energy in the State of Illinois and to provide a less regulated
structure for Illinois electric utilities. Further, the Company filed a Form 8-K
dated December 31, 1997 reporting completion of its merger transaction with
CIPSCO.
- 36 -
UNION ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
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
----------- ----------- ---------- -------------- ---------- ---------
Year ended December 31, 1997 (Note)
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
========== =========== =========== ==========
Year ended December 31, 1995
Reserves deducted in the balance sheet from assets to which they apply:
Allowance for doubtful accounts $6,277,378 $10,800,000 $10,152,413 $6,924,965
========== =========== =========== ==========
Note: Uncollectible accounts charged off, less recoveries.
- 37 -
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 25, 1998 By /s/ James C. Thompson
----------------------- ----------------------------
(James C. Thompson, 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
DONALD E. BRANDT (Principal Financial and Accounting Officer)
/s/ W. E. Cornelius
WILLIAM E. CORNELIUS Director
THOMAS A. HAYS Director
/s/ T. H. Jacobsen
THOMAS H. JACOBSEN Director
/s/ Richard A. Liddy
RICHARD A. LIDDY Director
JOHN PETERS MacCARTHY Director
/s/ Paul L. Miller, Jr.
PAUL L. MILLER, JR. Director
/s/ Robert H. Quenon
ROBERT H. QUENON Director
/s/ Gary L. Rainwater
GARY L. RAINWATER Director
/s/ Harvey Saligman
HARVEY SALIGMAN Director
/s/ Janet McAfee Weakley
JANET MCAFEE WEAKLEY Director
By /s/ James C. Thompson March 25, 1998
(James C. Thompson, Attorney-in-Fact)
- 38 -
EXHIBITS
Exhibits Filed Herewith
Exhibit No. Description
12(a) - Statement re Computation of Ratios of Earnings to Fixed Charges.
12(b) - Statement re Computation of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividend Requirements.
24 - Powers of Attorney.
27 - Financial Data Schedule.
- 39 -
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
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
- 40 -
Exhibit No. Description
Dated as of File Reference Exhibit No.
4.5 - (continued)
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
4.6 - Series A Agreement of Sale dated as of June 1, 1984 between the
State Environmental Improvement and Energy Resources Authority of
the State of Missouri and the Company, together with Letter of
Credit and Reimbursement Agreement dated as of June 1,1984 between
Citibank, N.A. and the Company and Series A Trust Indenture dated
as of June 1, 1984 between the Authority and Mercantile Trust
Company National Association, as trustee. (Registration No. 2-
96198, Exhibit 4.25.)
4.7 - Reimbursement Agreement dated as of April 21, 1992 among Swiss Bank
Corporation, various financial institutions, and the Company,
providing for an alternate letter of credit to serve as a source of
payment for bonds issued under the Series A Trust Indenture date
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 Authorit 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.)
- 41 -
Exhibit No. Description
4.13 - Series 1985 A Reaffirmation Agreement and Second Supplement to
Agreement of Sale dated as of June 1, 1985 between the State
Environmental Improvement and Energy Resources Authority of the
State of Missouri and the Company, together with Series 1985 A
Reimbursement Agreement dated as of June 1, 1985 between Union Bank
of Switzerland and the Company and Series 1985 A Trust Indenture
dated as of June 1, 1985 between the Authority and Mercantile Trust
Company National Association, as trustee and Texas Commerce Bank
National Association, as co-trustee. (June 30, 1985 Form 10-Q,
Exhibit 4.1.)
4.14 - Amendment and Extension Agreement dated as of June 1, 1988 revising
the Reimbursement Agreement dated as of June 1, 1985 between Union
Bank of Switzerland and the Company. (June 30, 1988 Form 10-Q,
Exhibit 4.4.)
4.15 - Amendment and Extension Agreement dated as of June 1, 1990 revising
the Reimbursement Agreement dated as of June 1, 1985, as amended
between Union Bank of Switzerland and the Company. (1990 Form 10-K
Exhibit 4.37.)
4.16 - Amendment and Extension Agreement dated as of June 1, 1991 to the
amended Reimbursement Agreement dated as of June 1, 1985 between
Union Bank of Switzerland and the Company. (1992 Form 10-K, Exhibit
4.32.)
4.17 - Amendment Agreement dated as of June 1, 1992 to the amended
Reimbursement Agreement dated as of June 1, 1985 between Union Bank
of Switzerland and the Company.(1992 Form 10-K, Exhibit 4.33.)
4.18 - Series 1985 B Reaffirmation Agreement and Third Supplement to
Agreement of Sale dated as of June 1, 1985 between the State
Environmental Improvement and Energy Resources Authority of the
State of Missouri and the Company, together with Series 1985 B
Reimbursement Agreement dated as of June 1, 1985 between The
Long-term Credit Bank of Japan, Limited and the Company and Series
1985 B Trust Indenture dated as of June 1, 1985 between the
Authority and Mercantile Trust Company National Association, as
trustee and Texas Commerce Bank National Association, as co-
trustee.(June 30, 1985 Form 10-Q, Exhibit 4.2.)
4.19 - Reimbursement Agreement dated as of February 1, 1993 between
Westdeutsche Landesbank Girozentrale and the Company, providing for
an alternate letter of credit to serve as a source of payment for
bonds issued under the Series 1985 B Trust Indenture dated as of
June 1, 1985. (1992 Form 10-K, Exhibit 4.35.)
4.20 - Loan Agreement dated as of May 1, 1990 between the State
Environmental Improvement and Energy Resources Authority of the
State of Missouri and the Company, together with Indenture of Trust
dated as of May 1, 1990 between the Authority and Mercantile Bank
of St. Louis, N.A., as trustee. (1990 Form 10-K, Exhibit 4.40.)
- 42 -
Exhibit No. Description
4.21 - Loan Agreement dated as of December 1, 1991 between the State
Environmental Improvement and Energy Resources Authority and the
Company, together with Indenture of Trust dated as of December 1,
1991 between the Authority and Mercantile Bank of St. Louis, N.A.,
as trustee. (1992 Form 10-K, Exhibit 4.37.)
4.22 - Loan Agreement dated as of December 1, 1992, between the State
Environmental Improvement and Energy Resources Authority and the
Company, together with Indenture of Trust dated as of December 1,
1992 between the Authority and Mercantile Bank of St. Louis, N.A.,
as trustee. (1992 Form 10-K, Exhibit 4.38.)
4.23 - Fuel Lease dated as of February 24, 1981 between the Company,
as lessee, and Gateway Fuel Company, as lessor, covering nuclear
fuel. (1980 Form 10-K, Exhibit 10.20.)
4.24 - Amendments to Fuel Lease dated as of May 8, 1984 and October 15,
1984, respectively, between the Company, as lessee, and Gateway
Fuel Company, as lessor, covering nuclear fuel. (Registration
No. 2-96198, Exhibit 4.28.)
4.25 - Amendment to Fuel Lease dated as of October 15, 1986 between the
Company, as lessee, and Gateway Fuel Company, as lessor, covering
nuclear fuel.(September 30, 1986 Form 10-Q, Exhibit 4.3.)
4.26 - Credit Agreement dated as of August 15, 1989 among the Company,
Certain Lenders, The First National Bank of Chicago, as Agent and
Swiss Bank Corporation, Chicago Branch, as Co-Agent. (September 30,
1989 Form 10-Q, Exhibit 4.)
4.27 - Amendment dated as of October 26, 1992, to the Credit Agreement
dated as of November 8,1991 between the Company, Certain Banks and
Chemical Bank, as Agent. (1992 Form 10-K, Exhibit 4.44.)
10.7 - Change of Control Severance Plan. (1995 Form 10-K, Exhibit 10.8.)
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.
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