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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
( ) Transition report pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from to .
COMMISSION FILE NUMBER 1-3672
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)
Illinois 37-0211380
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
607 East Adams Street, Springfield, Illinois 62739
(Address of principal executive offices and Zip Code)
Registrant's telephone number, including area code: (217) 523-3600
Securities Registered Pursuant to Section 12(b) of the Act: None.
Securities Registered Pursuant to Section 12(g) of the Act:
Title Of Class
Cumulative Preferred Stock, par value $100 per share
Depositary Shares, each representing one-fourth of a share
of 6.625% Cumulative Preferred Stock, par value $100 per share
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. ( ).
Aggregate market value at March 5, 1999 of the voting stock held by
non-affiliates of Central Illinois Public Service Company (CIPS) - $24,725,000 -
Cumulative Preferred Stock (par value $100 per share) [Note: Excludes value of
400,000 shares of Cumulative Preferred Stock for which CIPS has been unable to
determine market value.]
Shares of Common Stock without par value, outstanding as of March 5, 1999:
25,452,373 shares (all owned by Ameren Corporation).
Documents incorporated by references.
Portions of the registrant's definitive proxy statement for the 1999 annual
meeting are incorporated by reference into Part III.
TABLE OF CONTENTS
PART I Page
Item 1-Business
General............................................................. 1
Capital Program and Financing....................................... 1
Rates............................................................... 2
Fuel Supply......................................................... 3
Regulation.......................................................... 3
Industry Issues..................................................... 4
Item 2-Properties........................................................... 5
Item 3-Legal Proceedings.................................................... 6
Item 4-Submission of Matters to a Vote of Security Holders
Executive Officers of the Registrant (Item 401(b) of Regulation S-K)........ 8
PART II
Item 5-Market for Registrant's Common Equity and Related
Stockholder Matters................................................. 8
Item 6-Selected Financial Data.............................................. 8
Item 7-Management's Discussion and Analysis of Financial Condition
and Results of Operations........................................... 9
Item 7A-Quantitative and Qualitative Disclosures about Market Risk.......... 17
Item 8-Financial Statements and Supplementary Data.......................... 19
Item 9-Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure............................................ 36
PART III
Item 10-Directors and Executive Officers of the Registrant2................. 36
Item 11-Executive Compensation.......................................... 36
Item 12-Security Ownership of Certain Beneficial Owners
and Management................................................. 36
Item 13-Certain Relationships and Related Transactions.................. 37
PART IV
Item 14-Exhibits, Financial Statement Schedules and Reports on Form 8-K.... 37
SIGNATURES ............................................................ 39
EXHIBITS ............................................................ 40
________________
Not applicable and not included herein.
Incorporated herein by reference.
PART I
ITEM 1.BUSINESS.
GENERAL
Central Illinois Public Service Company (CIPS, AmerenCIPS or the
Registrant) is a subsidiary of Ameren Corporation (Ameren), a holding company,
registered under the Public Utility Holding Company Act of 1935. On December 31,
1997, CIPSCO Incorporated (CIPSCO) and Union Electric Company (UE) combined with
the result that the common shareholders of CIPSCO and UE became the common
shareholders of Ameren, and Ameren became the owner of 100% of the common stock
of UE and CIPSCO's operating subsidiaries, Central Illinois Public Service
Company (CIPS) and CIPSCO Investment Company (the Merger).
The Registrant, an Illinois corporation, was organized in 1902. CIPS is a
public utility operating company engaged in the sale of electricity and natural
gas in portions of central and southern Illinois. The Registrant furnishes
electric service in 557 incorporated and unincorporated communities and adjacent
suburban and rural areas. The Registrant also furnishes natural gas service to
retail customers in 267 incorporated and unincorporated communities and adjacent
suburban and rural areas located in 41 counties of central and southern Illinois
and provides gas transportation service to end-users.
The CIPS service territory is predominantly made up of small towns and
rural areas. Of the communities served, only 5 have populations greater than
15,000. Customer density on the CIPS gas system is approximately 35 customers
per mile of main. The Registrant furnishes both electric and natural gas service
in 236 of the communities served by it.
The territory served by the Registrant, located in 66 counties in Illinois,
has an estimated population of 820,000 and is devoted principally to agriculture
and diversified industrial operations. Key industries include petroleum and
petrochemical industries, food processing, metal fabrication and coal mining.
For the year 1998, 85% of total operating revenues was derived from the
sale of electric energy and 15% from the sale of natural gas. Electric operating
revenues as a percentage of total operating revenues in both 1997 and 1996 were
82%.
The Registrant employed 1,799 persons at December 31, 1998. Approximately
70% of the Registrant's employees are represented by local unions affiliated
with the AFL-CIO. Labor agreements representing approximately 1,250 employees
will expire in 1999. One agreement covering six employees will expire in 2001.
CAPITAL PROGRAM AND FINANCING
The Registrant is engaged in a capital program under which capital
expenditures are expected to approximate $115 million in 1999. For the five-year
period 1999-2003, construction expenditures are estimated at $615 million. This
estimate includes any construction expenditures which may be incurred by the
Registrant to meet new air quality standards for ozone and particulate matter.
During the five-year period ended 1998, gross additions to the property of
the Registrant, including allowance for funds used during construction, were
approximately $440 million (including $69 million in 1998) and property
retirements were $252 million.
1
In addition to the funds required for construction during the 1999-2003
period, $203 million will be required to repay long-term debt as follows: $60
million in 1999; $35 million in 2000; $30 million in 2001; $33 million in 2002;
and $45 million in 2003.
For additional information on the Registrant's capital program and 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 and Notes 6 and 7 to the "Notes to Financial Statements" under Item 8
herein.
Financing Restrictions. The Mortgage Indenture of CIPS, as presently
operative, permits the issuance of additional first mortgage bonds up to 60% of
available net expenditures for bondable property, provided the "net earnings" of
CIPS (before income taxes and otherwise as provided in the Mortgage Indenture)
for a recent 12-month period equal at least twice the annual interest
requirements on all first mortgage bonds outstanding (and on all equally secured
and prior lien indebtedness) and on the bonds then to be issued. At December 31,
1998, the more restrictive of these requirements was the "net earnings" test.
The "net earnings" of CIPS for the year ended December 31, 1998, so computed,
were equal to 5.97 times the interest for one year on the aggregate amount of
bonds outstanding under the Mortgage Indenture at December 31, 1998. Based on
the "net earnings" of CIPS (so computed) for the year ended December 31, 1998,
and the bonds outstanding under the Mortgage Indenture at December 31, 1998, the
Registrant could have issued about $875 million of additional first mortgage
bonds under the foregoing interest coverage provision (assuming an annual
interest rate of 6.25% on such bonds).
The Articles of Incorporation of CIPS provide, in effect, that so long as
any CIPS preferred stock is outstanding, CIPS shall not, without the requisite
vote of the holders of preferred stock, unless the retirement of such stock is
provided for, (a) issue any preferred or equal ranking stock (except to retire
or in exchange for an equal amount thereof) unless the "gross income available
for interest" of CIPS for a recent 12-month period is at least one and one-half
(1-1/2) times the sum of (i) one year's interest on all funded debt and notes
maturing more than 12 months after the date of issuance of such shares and (ii)
one year's dividend requirement on all preferred stock to be outstanding after
such issue, or (b) issue or assume any unsecured debt securities maturing less
than two years from the date of issuance or assumption (except for certain
refunding or retirement purposes) if immediately after such issuance or
assumption the total amount of all such unsecured debt securities would exceed
20% of the sum of all secured debt securities and the capital and surplus of
CIPS. For the year ended December 31, 1998, the "gross income available for
interest" of CIPS equalled 2.78 times the sum of the annual interest charges and
dividend requirements on all such funded debt, notes and preferred stock
outstanding at December 31, 1998. Such "gross income available for interest" was
sufficient under the test to support the issuance of additional preferred stock
(assuming an annual dividend rate on such preferred stock of 5%) in an amount in
excess of the maximum amount ($185 million) of authorized and unissued preferred
stock under the Articles.
RATES
For the year 1998, approximately 82% of the Registrant's electric operating
revenues were based on rates regulated by the Illinois Commerce Commission (ICC)
and 18% were regulated by the Federal Energy Regulatory Commission (FERC) of the
U. S. Department of Energy.
The electric utility restructuring legislation in Illinois included a 5%
residential rate decrease for the Registrant's electric customers, effective
August 1, 1998. This rate decrease reduced electric revenues approximately $5
million in 1998 and is expected to reduce electric revenues by approximately $11
million annually thereafter, based on estimated levels of sales and assuming
normal weather conditions. See "Regulation" for additional reference to this
legislation.
2
As permitted by electric utility restructuring legislation in Illinois, in
February 1998, the Registrant filed to eliminate the fuel adjustment clause on
sales of electricity in Illinois, thereby including a historical level of fuel
costs in base rates. The ICC approved the Registrant's filing in March 1998.
In June 1998, the Registrant filed a request with the ICC to increase rates
for natural gas service. In February 1999, the ICC approved an $8 million annual
rate increase. The rate increase became effective in February 1999.
For additional information on "Rates", see Note 2 to the "Notes to
Financial Statements" under Item 8 herein.
FUEL SUPPLY
Cost of Fuels Year
- ------------- -------------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
Per Million BTU - Coal 152.738(cent) 163.000(cent) 171.000(cent) 176.000(cent) 165.000(cent)
Over 99% of the net kilowatthour generation of the Registrant in 1998 was
provided by coal-fired generating units and the remainder by an oil-fired unit.
Oil. The actual and prospective use of such oil is minimal, and the
Registrant has not experienced and does not expect to experience difficulty in
obtaining adequate supplies.
Coal. Because of uncertainties of supply due to potential work stoppages,
equipment breakdowns and other factors, the Company has a policy of maintaining
a coal inventory consistent with its expected burn practices.
For additional information on the Registrant'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 Registrant is subject to regulation by
the ICC as to rates, service, accounts, issuance of equity securities, issuance
of debt having a maturity of more than twelve months, mergers, and various other
matters. The Registrant is also subject to regulation by the FERC as to rates
and charges in connection with the transmission of electric energy in interstate
commerce and the sale of such energy at wholesale in interstate commerce,
mergers, and certain other matters. Authorization to issue debt having a
maturity of twelve months or less is obtained from the Securities and Exchange
Commission.
In December 1997, the Governor of Illinois signed the Electric Service
Customer Choice and Rate Relief Law of 1997 providing for electric utility
restructuring in Illinois. This legislation introduces competition into the
supply of electric energy in Illinois and, as a result, retail direct access,
which allows customers to choose their electric generation supplier, will be
phased in over several years. Access for commercial and industrial customers
will occur over a period from October 1999 to December 2000, and access for
residential customers will occur after May 1, 2002. For a discussion of the
Illinois legislation, see "Electric Industry Restructuring" in "Management's
Discussion and Analysis of Financial Condition and Results of Operations" under
Item 7 herein and Note 2 to the "Notes to Financial Statements" under Item 8
herein.
3
CIPS is regulated, in certain of its operations, by air and water pollution
and hazardous waste regulations at the city, county, state and federal levels.
The Registrant is in substantial compliance with such existing regulations.
Environmental Issues. On December 22, 1995, a complaint was filed in the
Circuit Court for the Seventh Judicial Circuit, Sangamon County, Illinois
against CIPS and several other defendants. The complaint seeks unspecified
monetary damages and alleges that, as a result of exposure to carcinogens
contained in coal tar at the CIPS Taylorville gas plant site, plaintiffs'
children had suffered from a rare form of childhood cancer known as
"neuroblastoma". The plaintiffs in this complaint are the plaintiffs who on
October 5, 1995 voluntarily dismissed claims in a similar complaint in the
Circuit Court for the Fourth Judicial Circuit, Christian County, Illinois. On
April 17, 1996, the Seventh Judicial Circuit Court, Sangamon County, Illinois
granted approval of the petition by CIPS requesting transfer of this case to the
Circuit Court for the Fourth Judicial Circuit, Christian County, Illinois. On
March 27, 1998, a jury awarded plaintiffs $3.2 million. CIPS continues to
believe it has meritorious defenses and has appealed the verdict. Management
believes that final disposition of this matter will not have a material adverse
effect on financial position, results of operations or liquidity of the Company.
On August 2, 1996, the Illinois Attorney General filed a complaint with the
Illinois Pollution Control Board alleging various violations of wastewater
discharge permit conditions and ground water standards at CIPS' Hutsonville
Power Station. The complaint seeks monetary penalties and the award of attorney
fees. CIPS, the Board and the Attorney General are continuing to work on a plan
to resolve these issues. While the Company cannot predict the final outcome of
this matter, it does not believe that the final resolution will have a material
adverse effect on financial position, results of operations or liquidity of the
Company.
See "Liquidity and Capital Resources" in "Management's Discussion and
Analysis of Financial Conditions and Results of Operations" under Item 7 herein
and Note 10 to the "Notes to Financial Statements" under Item 8 herein for a
further discussion of environmental issues.
Other aspects of the Registrant's business are subject to the jurisdiction
of various regulatory authorities and, for additional information on regulation
see "Electric Industry Restructuring" in "Management's Discussion and Analysis
of Financial Condition and Results of Operations" under Item 7 herein and Notes
2 and 10 to the "Notes to Financial Statements" under Item 8 herein.
INDUSTRY ISSUES
The Registrant is facing issues common to the electric and gas utility
industries which have emerged during the past several years. These issues
include: the potential for more intense competition and for changing the
structure of regulation; changes in the structure of the industry as a result of
changes in federal and state laws; on-going consideration of additional changes
of the industry by federal and state authorities; continually developing
environmental laws, regulations and issues, including proposed new air quality
standards; public concern about the siting of new facilities; proposals for
demand side management programs; public concerns about nuclear decommissioning
and the disposal of nuclear wastes; and global climate issues. The Registrant is
monitoring these issues and is unable to predict at this time what impact, if
any, these issues will have on its operations, financial condition, or
liquidity.
For additional information on certain of these issues, see "Electric
Industry Restructuring" in Management's Discussion and Analysis of Financial
Condition and Results of Operations" under Item 7 herein and Notes 2 and 10 to
the "Notes to Financial Statements" under Item 8 herein.
Year 2000 Issue. The Year 2000 Issue relates to how dates are stored and
used in computer systems, applications, and embedded systems. As the century
date change occurs, certain date-sensitive systems need to be able to recognize
the year as 2000 and not as 1900. This inability to recognize and
4
properly treat the year as 2000 may cause these systems to process critical
financial and operational information incorrectly. For information on this
issue, see "Year 2000 Issue" in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" under Item 7 herein.
ITEM 2. PROPERTIES.
In planning its construction program, the Registrant is presently utilizing
a forecast of kilowatthour sales growth of approximately 1.1% and peak load
growth of 1.5%, each compounded annually, and is providing for a minimum reserve
margin of approximately 15% to 18% above its anticipated peak load requirements.
The Registrant is a member of one of the ten regional electric reliability
councils organized for coordinating the planning and operation of the nation's
bulk power supply - MAIN (Mid-America Interconnected Network) operating
primarily in Wisconsin, Illinois and Missouri. The Registrant's bulk power
system is operated as an Ameren-wide control area and transmission system under
the FERC approved Joint Dispatch Agreement between CIPS and UE. The Registrant
has interconnections for transmission service and the exchange of electric
energy, directly and through the facilities of others, with twenty private
utilities and nine government utilities that operate control areas.
The Registrant owns 20% of the capital stock of Electric Energy, Inc.
(EEI), and its affiliate, UE, owns 40% of such stock. The balance is held by two
other sponsoring companies -- Kentucky Utilities Company (KU), and Illinova
Generating (IG). EEI owns and operates a generating plant with a nominal
capacity of 1,000 mW. 60% of the plant's output is committed to the Paducah
Project of the DOE, 20% to KU, 10% to UE and 5% each to IG and CIPS.
As of December 31, 1998 the Registrant owned approximately 4,700 circuit
miles of electric transmission lines. The Registrant also owned 4,800 miles of
natural gas transmission and distribution mains, four underground gas storage
fields and one propane-air gas plant used to supplement the available pipeline
supply of natural gas during periods of abnormally high demands. Other
properties of the Registrant include distribution lines, underground cable,
office buildings, warehouses, garages and repair shops.
CIPS has fee title to all principal plants and other important units of
property, or to the real property on which such facilities are located (subject
to mortgage liens securing outstanding indebtedness of the Registrant and to
permitted liens and judgment liens, as defined).
Substantially all of CIPS' property and plant is subject to the direct
first lien an Indenture of Mortgage or Deed of Trust dated October 1, 1941, as
amended and supplemented.
5
The following table sets forth information with respect to the
Registrant's generating facilities and capability at the time of the expected
1999 peak.
Gross Kilowatt
Energy Installed
Source Plant Location Capability
------ ----- -------- ----------
Coal Newton Newton, IL 1,170,000
Coffeen Coffeen, IL 950,000
Grand Tower Grand Tower, IL 202,000
Hutsonville
(Units 3 & 4) Hutsonville, IL 161,000
Meredosia
(Units 1, 2 & 3) Meredosia, IL 359,000
----------
Total Coal 2,842,000
Oil Hutsonville
(Diesel) Hutsonville, IL 3,000
Meredosia
(Unit 4) Meredosia, IL 182,000
----------
Total Oil 185,000
TOTAL 3,027,000
=========
All of the generating stations are located in Illinois on land owned in fee
by CIPS.
ITEM 3. LEGAL PROCEEDINGS.
During 1996, the Registrant restructured its contract with one of its major
coal suppliers. In 1997, the Registrant paid a $70 million restructuring payment
to the supplier, which allowed it to purchase at market prices low-sulfur,
non-Illinois coal through the supplier (in substitution for the high-sulfur
Illinois coal the Registrant was obligated to purchase under the original
contract); and to receive options for future purchases of low-sulfur,
non-Illinois coal from the supplier through 1999 at set negotiated prices.
By switching to low-sulfur coal, the Registrant was able to discontinue
operating a generating station scrubber. The benefits of the contract
restructuring include lower cost coal, avoidance of significant capital
expenditures to renovate the scrubber and elimination of scrubber operations and
maintenance costs (offset by scrubber retirement expenses). The net benefits of
restructuring are expected to exceed $100 million through 2007. In December
1996, the ICC entered an order approving the switch to non-Illinois coal,
recovery of the restructuring payment plus associated carrying costs
(Restructuring Charges) through the retail uniform fuel adjustment clause (FAC)
over six years, and continued recovery in rates of the undepreciated scrubber
investment plus costs of removal. Additionally, in May 1997 the FERC approved
recovery of the wholesale portion of the Restructuring Charges through the
wholesale FAC. As a result of the ICC and FERC order, the Registrant classified
the $72 million of the Restructuring Charges made to the coal supplier in
February 1997 as a regulatory asset and, through December 1997, recovered
approximately $10 million of the Restructuring Charges through the retail FAC
and from wholesale customers.
A group of industrial customers filed with the Illinois Third District
Appellate Court (the Court) in February 1997 an appeal of the December 1996
order of the ICC. In November 1997, the Court
6
reversed the ICC's December 1996 order, finding that the Restructuring
Charges were not direct costs of fuel that may be recovered through the retail
FAC, but rather should be considered as a part of a review of aggregate revenue
requirements in a full rate case. Restructuring Charges allocated to wholesale
customers (approximately $7 million) are not in question as a result of the
opinion of the Court. In December 1997, the Registrant requested a rehearing by
the Court; that request was denied. However, the Court did rule that all
revenues collected under the retail FAC in 1997 would not have to be refunded to
customers. The Registrant filed an appeal with the Illinois Supreme Court. In
December 1998, the Supreme Court issued its decision, reversing the Court's
opinion and affirming the ICC's order. The Supreme Court held that the
Restructuring Charges are recoverable through the retail FAC. No further
proceedings are anticipated.
The International Union of Operating Engineers Local 148 and the
International Brotherhood of Electrical Workers Local 702 filed unfair labor
practice charges with the National Labor Relations Board (NLRB), relating to the
legality of the 1993 lockout of both unions by CIPS. The NLRB issued complaints
against CIPS concerning its lockout. Both unions sought, among other things,
back pay and other benefits for the period of the lockout. At that time, the
Registrant estimated the amount of back pay and other benefits for both unions
to be approximately $17 million. In May 1996, an administrative law judge of the
NLRB ruled that the lockout was unlawful. In July 1996, the Registrant appealed
to the NLRB. In August 1998, a three-member panel of the NLRB reversed the
administrative law judge's decision and ruled that the lockout was lawful. Both
unions filed motions for review with the NLRB asking for reconsideration of this
decision. In December 1998, the NLRB denied the unions' motions for
reconsideration. Subsequently, in December 1998, the unions filed a joint motion
for a rehearing of their motions for reconsideration. On March 5, 1999, the NLRB
denied the unions' motion for reconsideration. The Registrant expects that the
unions will pursue a judicial appeal of the NLRB's decision.
The Registrant is involved in other legal and administrative proceedings
before various courts and agencies with respect to matters arising in the
ordinary course of business, some of which involve substantial amounts.
Management believes that the final disposition of these proceedings will not
have a material adverse effect on its financial position, results of operations
or liquidity.
For additional information on legal and administrative proceedings, see
"Rates" and "Regulation Environmental Issues" under Item 1 herein and Notes 2
and 10 to the "Notes to Financial Statements" under Item 8 herein.
_________________________
Statements made in this report which are not based on historical facts, are
forward-looking and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
forward-looking statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions and
financial performance and the Year 2000 Issue. In connection with the "Safe
Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the
Registrant is providing this cautionary statement to identify important factors
that could cause actual results to differ materially from those anticipated.
Factors include, but are not limited to, the effects of: regulatory actions;
changes in laws and other governmental actions; competition; future market
prices for fuel and purchased power, electricity, and natural gas, including the
use of financial instruments; average rates for electricity in the Midwest;
business and economic conditions; interest rates; weather conditions; fuel
prices and availability; generation plant performance; monetary and fiscal
policies; future wages and employee benefits costs; and legal and administrative
proceedings.
7
INFORMATION REGARDING EXECUTIVE OFFICERS REQUIRED BY ITEM 401(b) OF REGULATION S-K:
Age At Date First Elected
Name 12/31/98 Present Position or Appointed
---- -------- ---------------- ------------
G. L. Rainwater 52 President and
Chief Executive Officer 1/1/98
J. T. Birkett 61 Vice President 7/10/95
M. J. Montana 52 Vice President 4/28/98
G. W. Moorman 55 Vice President 6/1/88
C. D. Nelson 45 Vice President 4/28/98
T. R. Voss 51 Vice President 7/1/98
S. R. Sullivan 38 Vice President, General Counsel
and Secretary 11/7/98
W. L. Baxter 37 Controller 12/31/97
J. E. Birdsong 44 Treasurer 12/31/97
All officers are elected or appointed annually by the Board of Directors
following the election of such Board at the annual meeting of stockholders held
in April. Except for Messrs. Baxter and Sullivan, each of the above-named
executive officers has been employed by the Company or its affiliates for more
than five years in executive or management positions. Mr. Baxter was previously
employed by PricewaterhouseCoopers LLP. Mr. Sullivan was previously employed by
Anheuser Busch Companies, Inc.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
There is no market for the Registrant's Common Stock since all shares are
owned by its parent, Ameren.
ITEM 6. SELECTED FINANCIAL DATA.
For the Years Ended
December 31 (In Thousands) 1998 1997 1996 1995 1994
- -------------------------- ---- ---- ---- ---- ----
Operating revenues $ 847,424 $ 852,075 $ 881,102 $ 828,073 $ 835,882
Operating income 120,044 102,495 116,531 106,029 110,678
Net income 80,147 38,620 77,393 70,631 81,913
Preferred stock dividends 3,745 3,715 3,721 3,850 3,510
Net income after preferred
stock dividends 76,402 34,905 73,672 66,781 78,403
Common stock dividends 72,285 43,300 62,950 71,000 68,600
As of December 31,
Total assets $1,764,397 $1,788,707 $1,795,353 $1,759,838 $1,726,540
Long-term debt 528,446 558,474 421,228 478,926 474,619
Total common stockholder's equity 575,370 572,759 581,224 570,419 574,745
8
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
Central Illinois Public Service Company (AmerenCIPS or the Registrant) is a
subsidiary of Ameren Corporation (Ameren), a holding company registered under
the Public Utility Holding Company Act of 1935 (PUHCA). In December 1997, Union
Electric Company (AmerenUE) and CIPSCO Incorporated (CIPSCO) combined to form
Ameren, with AmerenUE and CIPSCO's subsidiaries, the Registrant and CIPSCO
Investment Company (CIC), becoming wholly-owned subsidiaries of Ameren (the
Merger).
RESULTS OF OPERATIONS
Earnings
Earnings for 1998, 1997 and 1996, were $76 million, $35 million and $74 million,
respectively. Earnings fluctuated due to many conditions, primarily: weather
variations, electric rate reductions, competitive market forces, sales growth,
fluctuating operating costs, merger-related expenses, changes in interest
expense, changes in income and property taxes, a charge for a targeted employee
separation plan in 1998 and an extraordinary charge in 1997.
In 1998, the Registrant recorded a nonrecurring charge to earnings in connection
with a targeted separation plan it offered to employees in July 1998. The charge
reduced earnings $4 million, net of income taxes, (see Note 3 Targeted
Separation Plan under Notes to Financial Statements for further information). In
addition, the Registrant recorded an extraordinary charge to earnings in the
fourth quarter of 1997 for the write-off of generation-related regulatory assets
and liabilities as a result of electric industry restructuring legislation
enacted in Illinois in December 1997. The write-off reduced earnings $25
million, net of income taxes. (See Note 2 - Regulatory Matters under Notes to
Financial Statements for further information.)
The significant items affecting revenues, expenses and earnings for the years
ended December 31, 1998, 1997 and 1996 are detailed in the following pages.
Electric Operations
Electric Revenues Variations from Prior Year
- ------------------------------------------------------------------------------------
(Millions of Dollars) 1998 1997 1996
- ------------------------------------------------------------------------------------
Rate Variations $ (5) $ - $ -
Growth and other 9 5 12
Effect of abnormal weather 13 (1) (5)
Interchange sales (1) (29) 20
- ------------------------------------------------------------------------------------
$ 21 $(25) $ 27
- ------------------------------------------------------------------------------------
Electric revenues for 1998 increased $21 million compared to 1997. Revenues
increased primarily due to higher sales to retail customers within the
Registrant's service territory, as a result of warm summer weather and economic
growth in the service area. Weather-sensitive residential and commercial sales
increased 6% and 4%, respectively, while industrial sales grew 4%. These
increases were partially offset by a 5% rate decrease to residential customers
beginning in August 1998 (see Note 2 - Regulatory Matters under Notes to
Financial Statements for further information).
Electric revenues for 1997 decreased primarily due to a 19% decrease in
interchange sales due to market conditions and differences in the classification
of certain interchange and purchased power transactions resulting from Federal
Energy Regulatory Commission (FERC) Order 888, as well as a 3% decline in
industrial sales. Residential sales remained constant with prior year levels,
while commercial sales increased 2% over the same period.
The increase in 1996 electric revenues was primarily the result of a 5% increase
in kilowatthour sales from the prior year. The kilowatthour sales increase
stemmed from colder weather early in the year, which increased sales to
residential and commercial customers and a 14% increase in interchange sales.
9
Fuel and Purchased Power Variations from Prior Year
- ---------------------------------------------------------------------------------------
(Millions of Dollars) 1998 1997 1996
- ---------------------------------------------------------------------------------------
Fuel:
Variation in generation $ (25) $ 7 $ 29
Price (2) (8) 3
Generation efficiencies and other (6) (4) -
Purchased power variation 21 (27) (6)
- ---------------------------------------------------------------------------------------
$ (12) $(32) $ 26
- ---------------------------------------------------------------------------------------
The $12 million decrease in fuel and purchased power costs for 1998, compared to
1997, was primarily driven by lower fuel costs due to lower fuel prices and
utilizing joint dispatch generation. Upon consummation of the Merger, AmerenUE
and AmerenCIPS began jointly dispatching generation, therefore allowing Ameren
to utilize the most cost efficient plants of both operating companies to serve
customers in either service territory. The decrease in 1997 fuel and purchased
power costs was driven mainly by a decrease in interchange sales and lower fuel
prices. The increase in 1996 fuel and purchased power costs reflected increased
kilowatthour sales.
While unprecedented prices for power purchases occurred in the marketplace
during the last week of June 1998, the Registrant was able to effectively manage
its power costs in the face of soaring wholesale electricity prices. Overall,
the abnormally high prices for power purchases in June had little impact on the
Registrant's financial results for 1998.
Gas Operations
Gas revenues in 1998 decreased $26 million compared to 1997, primarily due to a
7% decline in retail sales resulting from mild winter weather and lower gas
costs reflected in the Registrant's purchase gas adjustment clause.
Weather-sensitive residential and commercial sales decreased 9% and 13%,
respectively, from 1997. Industrial sales increased 8% from 1997. Gas revenues
in 1997 decreased $4 million primarily due to a 10% decline in retail sales
resulting from mild winter weather. Weather-sensitive residential and commercial
sales decreased 14% and 18%, respectively, from 1996. Industrial sales increased
31% from the same period. The introduction of off-system gas sales in 1997
offset the decrease in total sales to ultimate customers. Gas revenues grew $26
million in 1996 as a result of colder weather and higher gas costs. Residential,
commercial and industrial sales increased 13%, 17% and 9%, respectively, in 1996
versus 1995.
Gas costs in 1998 declined $28 million compared to 1997. This decrease in gas
costs was due to lower sales and lower gas prices. Gas costs for 1997 remained
relatively flat when compared to 1996 costs. Gas costs increased $22 million
between 1996 and 1995 due to increased demand related to colder weather, and an
increase in the price paid for gas in 1996 versus 1995.
Other Operating Expenses
Other operating expense variations in 1996 through 1998 reflected recurring
factors such as growth, inflation, and labor and benefit increases, in addition
to a charge for the targeted separation plan (TSP) as discussed below.
In March 1998, Ameren announced plans to reduce its other operating expenses,
including plans to eliminate approximately 400 employee positions by mid-1999
through a hiring freeze and the TSP. In July 1998, Ameren offered separation
packages to employees whose positions were to be eliminated through the TSP.
During the third quarter of 1998, the Registrant recorded a nonrecurring,
pre-tax charge of $7 million (which reduced earnings $4 million) representing
its share of costs incurred to implement the TSP. The elimination of these
positions, exclusive of the nonrecurring charge, reduced the Registrant's
operating expenses approximately $4 million in 1998, and the Registrant expects
operating expenses to be reduced approximately $6 million to $7 million annually
thereafter. See Note 3 - Targeted Separation Plan under Notes to Financial
Statements for further information.
The $19 million increase in other operations expenses in 1998, compared to 1997,
was primarily due to the charge for the TSP and increased information
system-related costs. In 1997, other operations expenses increased $15 million,
primarily due to increases in labor, various equipment purchases and rentals and
information system-related costs. In 1996, other operations expenses decreased
$9 million mainly due to several nonrecurring costs incurred in 1995, which
included the write-off of system development costs.
Maintenance expense changes between years are due to normal planning and
scheduling of major power plant maintenance outages. In 1998, maintenance
expenses decreased $4 million from the prior year. The 1997
10
maintenance expense increase of $14 million from the prior year can be
attributed to scheduled outages at three generating plants during 1997.
In 1998, depreciation and amortization expense decreased $8 million from the
prior year due to the write-off of generation-related regulatory assets in
Illinois during the fourth quarter of 1997. 1997 and 1996 depreciation and
amortization expense fluctuations relate primarily to property additions.
Taxes
Income tax expense from operations increased $12 million in 1998, compared to
1997, due to higher pre-tax income and a higher effective tax rate. Income tax
expense from operations decreased $14 million in 1997 principally due to lower
pre-tax income and a lower effective tax rate. Income tax expense from
operations increased $4 million in 1996 due primarily to higher pre-tax income.
Other Income and Deductions
In 1998, miscellaneous, net decreased $3 million primarily due to higher
merger-related expenses incurred in the prior year. Miscellaneous, net increased
$2 million between 1997 and 1996 primarily due to increased merger-related
expenses.
Interest
Interest expense increased $3 million in 1998, compared to 1997, due to a higher
amount of debt outstanding, partially offset by a decrease in other interest.
Balance Sheet
The $23 million decrease in accounts receivable at December 31, 1998, compared
to 1997, was due to lower sales and revenues in November and early December
1998, compared to the comparable time period in 1997, due to mild winter
weather. The Company's service territory experienced much colder weather in the
latter part of December 1998, resulting in higher sales and revenues at that
time compared to the comparable 1997 period. This increase in sales caused a $21
million increase in unbilled revenues. The $16 million increase in current
liabilities was primarily due to increased current maturities to long-term debt.
This increase was partially offset by decreased accounts payable caused by
payment timing differences between years and less short-term debt outstanding.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities totaled $123 million for 1998, compared to
$81 million for 1997 and $137 million in 1996, respectively.
Cash flows used in investing activities totaled $68 million, $111 million and
$80 million, for the years ended December 31, 1998, 1997 and 1996, respectively.
Expenditures in 1998 for constructing new or to improve existing facilities were
$69 million.
Capital expenditures are expected to approximate $115 million in 1999. For the
five-year period 1999-2003, construction expenditures are estimated at $615
million. This estimate includes any construction expenditures, which may be
incurred by the Registrant to meet new air quality standards for ozone and
particulate matter, as discussed below.
Under Title IV of the Clean Air Act Amendments of 1990, the Registrant is
required to significantly reduce total annual sulfur dioxide (SO2) and nitrogen
oxide (NOx) emissions by the year 2000. By switching to low-sulfur coal, the
Registrant 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.
In July 1997, the United States Environmental Protection Agency (EPA) issued
final regulations revising the National Ambient Air Quality Standards for ozone
and particulate matter. The new ambient standards may result in significant
additional reductions in SO2 and NOx emissions from the Registrant's power
plants. The new particulate matter standards may require SO2 reductions of up to
50% beyond that already required by Phase II acid rain control provisions of the
1990 Clean Air Act Amendments and could be required by 2007. The full details of
these requirements are under study by the Registrant. At this time, the
Registrant is unable to predict the ultimate impact of these revised air quality
standards on its future financial condition, results of operations or liquidity.
In an attempt to lower ozone levels across the eastern United States, the EPA
issued final regulations in September 1998 to reduce NOx emissions from
coal-fired boilers and other sources in 22 states, including Illinois (where all
of
11
the Registrant's coal-fired power plant boilers are located). Although
reduction requirements in NOx emissions from the Registrant's coal-fired boilers
are anticipated to exceed 75 percent from 1990 levels by the year 2003, it is
not yet possible to determine the exact magnitude of the reductions required
from the Registrant's power plants because each state has up to one year to
develop a plan to comply with the EPA rule. The NOx emissions reductions already
achieved on several of the Registrant's coal-fired power plants will help to
reduce the costs of compliance with this regulation. However, preliminary
analysis of the regulations indicate that selective catalytic reduction
technology will be required for some of the Registrant's units, as well as other
additional controls.
Currently, the Registrant estimates that its additional capital expenditures to
comply with the EPA's final regulations issued in September 1998 could range
from $125 million to $175 million over the period from 1999 to 2002. Associated
operations and maintenance expenditures could increase $5 million to $8 million
annually, beginning in 2003. The Registrant will explore alternatives to comply
with these new regulations in order to minimize, to the extent possible, its
capital costs and operating expenses. The Registrant is unable to predict the
ultimate impact of these standards on its future financial condition, results of
operations or liquidity.
In November 1998, the United States signed an agreement with numerous other
countries (the Kyoto Protocol) containing certain environmental provisions,
which would require decreases in greenhouse gases in an effort to address the
"global warming" issue. The Kyoto Protocol must be ratified by the United States
Senate before provisions are effective for the United States. Until ratification
is obtained, the Registrant is unable to predict what requirements, if any, will
be adopted in this country; however, implementation of the Kyoto Protocol in its
present form would likely result in significantly higher capital costs and
operations and maintenance expenses by the Registrant. At this time, the
Registrant is unable to determine the impact of these proposals on the
Registrant's future financial condition, results of operations or liquidity.
Cash flows used in financing activities were $74 million for 1998. This compares
to cash flows provided by financing activities of $48 million in 1997 and cash
flows used in financing activities of $57 million for 1996. The Registrant's
principal financing activities during 1998 included the issuance of $85 million
of long-term debt, offset by the redemption of $64 million of long-term debt and
dividend payments of $76 million.
The Registrant plans to continue utilizing short-term debt to support normal
operations and other temporary requirements. The Registrant is authorized by the
Securities and Exchange Commission under PUHCA to have up to $125 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, 1998, the Registrant had committed bank lines of credit aggregating $80
million (of which $80 million were unused and $33 million were available at such
date) which make available interim financing at various rates of interest based
on LIBOR, the bank certificate of deposit rate or other options. The lines of
credit are renewable annually at various dates throughout the year. At year-end,
the Registrant had $47 million of short-term borrowings.
Also, Ameren has a bank credit agreement due 2003, which permits the borrowing
of up to $200 million on a long-term basis. This credit agreement is available
to Ameren and its subsidiaries, including the Registrant. As of December 31,
1998, $190 million was available for the Registrant's use.
RATE MATTERS
See Note 2 - Regulatory Matters under Notes to Financial Statements for a
discussion of rate matters.
ELECTRIC INDUSTRY RESTRUCTURING
Changes enacted and being considered at the federal and state levels continue to
change the structure of the electric industry and utility regulation, as well as
encourage increased competition. At the federal level, the Energy Policy Act of
1992 reduced various restrictions on the operation and ownership of independent
power producers and gave the 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 AmerenCIPS, 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.
12
Order 889 established the standards of conduct and information requirements that
transmission owners must adhere to in doing business under the open access rule.
Under Order 889, utilities must obtain transmission service for their own use in
the same manner their customers will obtain service, thus mitigating market
power through control of transmission facilities. In addition, under Order 889,
utilities must separate their merchant function (buying and selling wholesale
power) from their transmission and reliability functions.
The Registrant believes that Order 888 and Order 889, which relate to its
wholesale business, will not have a material adverse effect on its financial
condition, results of operations or liquidity.
In 1998, the Registrant joined a group of ten other utility companies which
support the formation of the Midwest Independent System Operator (Midwest ISO).
An ISO operates, but does not own, transmission systems and maintains system
reliability and security while alleviating pricing issues associated with the
"pancaking" of rates. The Midwest ISO would be regulated by FERC. The FERC
conditionally approved the formation of the Midwest ISO in September 1998, and
it is expected to be operational by the year 2001. The Midwest ISO covers eight
states and represents portions of 40,000 miles of transmission line and 62,000
megawatts of electric power. Collectively, the member companies serve more than
seven million customers.
In December 1997, the Governor of Illinois signed the Electric Service Customer
Choice and Rate Relief Law of 1997 (the Law) providing for electric utility
restructuring in Illinois. This legislation introduces competition into the
supply of electric energy in Illinois.
Major provisions of the Law include the phasing-in through 2002 of retail direct
access, which allows customers to choose their electric generation supplier. In
addition, the Law includes a 5% rate decrease for residential customers
effective August 1998. The decrease reduced electric revenues by approximately
$5 million in 1998 and is expected to reduce electric revenues by approximately
$11 million annually thereafter, based on estimated levels of sales and assuming
normal weather conditions. In 1998, the Registrant eliminated its Uniform Fuel
Adjustment Clause (FAC) as allowed by the Law, which the Registrant expects to
benefit shareholders in the future. (See Note 1 - Summary of Significant
Accounting Policies under Notes to Financial Statements for further
information.) The Law contains a provision allowing for the potential recovery
of a portion of strandable costs, which represent costs which would not be
recoverable in a restructured environment, through a transition charge collected
from customers who choose an alternate electric supplier. In addition, the Law
contains a provision requiring a portion of excess earnings (as defined under
the Law) for the years 1998 through 2004 to be refunded to customers. See Note 2
- - Regulatory Matters under Notes to Financial Statements for further
information.
In December 1997, after evaluating the impact of the Law, the Registrant
determined that it was necessary to write-off the generation-related regulatory
assets and liabilities of its Illinois retail electric business. This
extraordinary charge reduced 1997 earnings $25 million, net of income taxes. The
Registrant has also concluded that its remaining net generation-related assets
are not impaired for financial reporting purposes and that no plant writedowns
are necessary at this time. See Note 2 - Regulatory Matters under Notes to
Financial Statements for further information.
In summary, the potential negative consequences associated with electric
industry restructuring could be significant and could include the impairment and
writedown of certain assets, including generation-related plant assets, lower
revenues, reduced profit margins and increased costs of capital and operations
expense. The Registrant is actively taking steps to mitigate these negative
consequences. Most importantly, the Registrant will continue to focus on cost
control to ensure that it maintains a competitive cost structure. The
Registrant's actions also include strengthening its marketing operations to
maintain its current customers and obtain new customers, as well as enhancing
its information systems. The Registrant is also actively involved in shaping the
policies of the Midwest ISO to protect shareholders' interests. At this time,
the Registrant is unable to predict the ultimate impact of electric industry
restructuring on the Registrant's future financial condition, results of
operations or liquidity.
YEAR 2000 ISSUE
The Year 2000 Issue relates to how dates are stored and used in computer
systems, applications, and embedded systems. As the century date change occurs,
certain date-sensitive systems need to be able to recognize the year as 2000 and
not as 1900. This inability to recognize or properly treat the year as 2000 may
cause these systems to process critical financial and operational information
incorrectly. The Registrant's primary concern is the potential for any
interruption in providing electric and gas service to customers, as well as the
potential inability to process critical financial and operational information on
a timely basis, including billing its customers, if appropriate steps
13
are not taken to address this issue. Management has developed a Year 2000 plan
(Plan) covering Ameren, including AmerenCIPS, and Ameren's Board of Directors
has been briefed about the Year 2000 Issue and how it may affect the Registrant.
Ameren's Plan to resolve the Year 2000 Issue involves three phases: assessment,
planning, and implementation/ testing. Implementation of the Plan is directly
supervised by each area's responsible Vice President. A Year 2000 Project
Director coordinates the implementation of the Plan among functional teams who
are addressing issues specific to a particular area, such as nuclear and
non-nuclear generation facilities, energy management systems, gas distribution,
etc. Ameren has also engaged certain outside consultants, technicians and other
external resources to aid in formulating and implementing the Plan.
Ameren has completed its assessment phase, which included analyzing
date-sensitive electronic hardware, software applications and embedded systems
and has developed a compliance plan to address issues that were identified. Many
of the major corporate computer systems at Ameren are relatively new and
therefore are either Year 2000 compliant or only require minor modifications.
Also, several of the operating hardware and embedded systems (i.e.,
microprocessor chips) use analog rather than digital technology and thus are
unaffected by the two-digit date issue. In addition, Ameren has contacted
hundreds of vendors and suppliers to verify compliance.
Ameren has also completed its planning phase. Items that have been identified
for remediation have been prioritized into groups based on their significance to
Ameren's operations. The implementation/testing phase for all
components/applications is approximately 45% complete as of December 31, 1998.
Ameren expects to complete remediation of its significant
components/applications by the end of the third quarter 1999.
With respect to third parties, for areas that interface directly with
significant vendors, Ameren has inventoried vendors and major suppliers and is
currently assessing their Year 2000 readiness through surveys, websites and
personal contact. Ameren plans to follow up with major suppliers and vendors and
verify Year 2000 compliance where appropriate. Ameren has queried its health
insurance providers. To date, Ameren is not aware of any problems that would
materially impact financial condition, results of operations or liquidity;
however, neither Ameren nor the Registrant has the means of ensuring that these
parties will be Year 2000 compliant. The inability of those parties to complete
their Year 2000 resolution process could materially impact Ameren and the
Registrant.
Ameren is also addressing the impact of electric power grid problems that may
occur outside of its own electric system. Ameren has started Year 2000 electric
power grid impact planning through the system's various electric interconnection
affiliations and is working with the Mid-American Interchange Network (MAIN) to
begin planning Year 2000 operational preparedness and restoration scenarios. As
of January 31, 1999 (the latest information available), MAIN was 99% complete
with its assessment phase, 94% complete with its planning phase and 53% complete
with its implementation/testing phase. In addition, Ameren provides monthly
status reports to the North American Electric Reliability Council (NERC) to
assist them in assessing Year 2000 readiness of the regional electric grid. As
of January 31, 1999 (the latest information available), NERC was 98% complete
with its assessment phase, 90% complete with its planning phase and 57% complete
with its implementation/testing phase. Through the Electric Power Research
Institute (EPRI), an industry-wide effort has been established to deal with Year
2000 problems affecting digital systems and equipment used by the nation's
electric power companies. Under this effort, participating utilities are working
together to assess specific vendors' system problems and test plans. The
assessment will be shared by the industry as a whole to facilitate Year 2000
problem solving.
In addressing the Year 2000 Issue, Ameren will incur internal labor costs as
well as external consulting and other expenses to prepare for the new century.
Ameren estimates that its external costs (consulting fees and related costs) for
addressing the Year 2000 Issue will range from $10 million to $15 million. As of
December 31, 1998, Ameren has expended approximately $2.4 million. Ameren's
plans to complete Year 2000 modifications are based on management's best
estimates, which are derived utilizing numerous assumptions of future events
including the continued availability of certain resources, and other factors.
However, there can be no guarantee that these estimates will be achieved and
actual results could differ materially from those plans. Specific factors that
might cause such material differences include, but are not limited to, the
availability and cost of personnel trained in this area, the ability to locate
and correct all relevant computer codes, and similar uncertainties.
Ameren believes that, with appropriate modifications to existing computer
systems/components, updates by vendors and trading partners, and conversion to
new software and hardware in the ordinary course of business, the Year 2000
Issue will not pose significant operational problems for the Registrant.
However, if such conversions are not completed in a proper and timely manner by
all affected parties, the Year 2000 Issue could result in material adverse
operational and financial consequences to the Registrant, and there can be no
assurance that Ameren's efforts, or
14
those of vendors and trading partners, interconnection affiliates, NERC or
EPRI to address the Year 2000 Issue will be successful. Ameren is in the process
of developing contingency plans to address potential risks, including risks of
vendor/trading partners noncompliance, as well as noncompliance of any of the
Registrant's material operating systems. The first operational contingency plan
addressing power grid issues is expected to be completed by the end of the first
quarter 1999. Contingency plans related to the business areas are expected to be
completed by the end of the second quarter 1999. At this time, the Registrant is
unable to predict the ultimate impact, if any, of the Year 2000 Issue on the
Registrant's financial condition, results of operations or liquidity; however,
the impact could be material.
CONTINGENCIES
See Note 10 - Commitments and Contingencies and Note 2 - Regulatory Matters
under Notes to Financial Statements for material issues existing at December 31,
1998.
MARKET RISK RELATED TO FINANCIAL INSTRUMENTS AND COMMODITY INSTRUMENTS
Market risk represents the risk of changes in value of a financial instrument,
derivative or non-derivative, caused by fluctuations in interest rates and
equity prices. The following discussion of Ameren's, including AmerenCIPS', risk
management activities includes forward-looking statements that involve risks and
uncertainties. Actual results could differ materially from those projected in
the forward-looking statements. Ameren handles market risks in accordance with
established policies, which may include entering into various derivative
transactions. In the normal course of business, Ameren also faces risks that are
either non-financial or non-quantifiable. Such risks principally include credit
risk and legal risk and are not represented in the following analysis.
Interest Rate Risk
The Registrant is exposed to market risk through changes in interest rates with
its issuance of long-term and short-term variable-rate debt, fixed-rate debt,
commercial paper and auction market preferred stock. The Registrant manages its
interest rate exposure by controlling the amount of these instruments it holds
within its total capitalization portfolio and by monitoring the effects of
market changes in interest rates.
If market rates increase 1% in 1999 as compared to 1998, the Registrant's
interest expense would increase and net income would decrease by approximately
$1 million. This amount has been determined using the assumptions that the
Registrant's outstanding variable-rate debt, commercial paper and auction market
preferred stock as of December 31, 1998, continued to be outstanding throughout
1999, and that the average interest rates for these instruments increased 1%
over 1998. The model does not consider the effects of the reduced level of
overall economic activity that would exist in such an environment. In the event
of a significant change in interest rates, management would likely take actions
to further mitigate its exposure to this market risk. However, due to the
uncertainty of the specific actions that would be taken and their possible
effects, the sensitivity analysis assumes no change in the Registrant's
financial structure.
Commodity Price Risk
The Registrant is exposed to changes in market prices for natural gas and fuel
and purchased power. With regard to its natural gas utility business, the
Registrant's exposure to changing market prices is in large part mitigated by
the fact that the Registrant has a Purchased Gas Adjustment Clause (PGA) in
place. The PGA allows the Registrant to pass on to its customers its prudently
incurred costs of natural gas.
Since the Registrant does not have a provision similar to the PGA for its
electric operations, the Registrant has entered into several long-term contracts
with various suppliers to purchase coal to manage its exposure to fuel prices.
(See Note 10 - Commitments and Contingencies under Notes to Financial Statements
for further information.) With regard to the Registrant's exposure to commodity
risk for purchased power, Ameren has established a subsidiary, AmerenEnergy,
Inc., whose primary responsibility includes managing market risks associated
with the changing market prices for purchased power for the Registrant.
AmerenEnergy utilizes several techniques to mitigate its market risk for
purchased power, including utilizing derivative financial instruments. A
derivative is a contract whose value is dependent on or derived from the value
of some underlying asset. The derivative financial instruments that AmerenEnergy
is allowed to utilize (which include forward contracts and futures contracts)
are dictated by a risk management policy, which has been reviewed with the
Auditing Committee of Ameren's Board of Directors. Compliance with the risk
management policy is the responsibility of a risk management steering committee,
consisting of Ameren officers and an independent risk management officer at
AmerenEnergy.
15
As of December 31, 1998, the fair value of derivative financial instruments
exposed to commodity price risk was immaterial. The Registrant expects an
increase in the derivative financial instruments used to manage risk in 1999 due
to expected growth at AmerenEnergy.
ACCOUNTING MATTERS
In its November 19, 1998 meeting, the Emerging Issues Task Force of the
Financial Accounting Standards Board (EITF) reached a consensus on EITF Issue
98-10, "Accounting for Energy Trading and Risk Management Activities." EITF
98-10 provides guidance on the accounting for energy contracts entered into for
the purchase or sale of electricity, natural gas, capacity and transportation.
The EITF reached a consensus in EITF 98-10 that sales and purchase activities
being performed need to be classified as either trading or non-trading.
Furthermore, transactions that are determined to be trading activities would be
recognized on the balance sheet measured at fair value, with gains and losses
included in earnings. EITF 98-10 includes factors or indicators to consider when
determining if a transaction is a trading or non-trading activity. EITF 98-10
will be effective beginning in 1999. Currently, AmerenEnergy enters into
contracts for the sale and purchase of energy on behalf of the Registrant. These
transactions are considered a non-trading activity and are accounted for using
the accrual or settlement method, which represents industry practice. Should any
of AmerenEnergy's future activities be considered trading activities based on
the indicators provided in EITF 98-10, the related transaction may need to be
measured at fair value and recognized in the balance sheet, with a gain or loss
included in earnings. EITF 98-10 is not expected to have a material impact on
the Registrant's financial position or results of operations upon adoption. Many
of the provisions of EITF 98-10 will likely be superceded by Statement of
Financial Accounting Standards (SFAS) 133, "Accounting for Derivative
Instruments and Hedging Activities" (see below).
In June 1998, the Financial Accounting Standards Board issued SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS 133
establishes accounting and reporting standards for derivative instruments and
for hedging activities and requires recognition of all derivatives on the
balance sheet measured at fair value. SFAS 133 is effective for all fiscal
quarters of all fiscal years beginning after June 15, 1999. Earlier application
is encouraged. SFAS 133 cannot be applied retroactively. At this time, the
Registrant is unable to determine the impact of SFAS 133 on its financial
position or results of operations upon adoption.
In March 1998, the Accounting Standards Executive Committee of the American
Institute of Certified Public Accountants issued Statement of Position (SOP)
98-1, "Accounting for the Costs of Computer Software Developed or Obtained for
Internal Use." SOP 98-1 provides guidance on accounting for the costs of
computer software developed or obtained for internal use. Under SOP 98-1,
certain costs, which are currently expensed by the Registrant, may be
capitalized and amortized over some future period. SOP 98-1 is effective for
fiscal years beginning after December 15, 1998. SOP 98-1 is not expected to have
a material impact on the Registrant's financial position or results of
operations upon adoption.
EFFECTS OF INFLATION AND CHANGING PRICES
The Registrant's rates for retail electric and gas service are regulated by
Illinois Commerce Commission. Non-retail electric rates are regulated by the
FERC.
The current replacement cost of the Registrant's utility plant substantially
exceeds its recorded historical cost. Under existing regulatory practice, only
the historical cost of plant is recoverable from customers. As a result, cash
flows designed to provide recovery of historical costs through depreciation
might not be adequate to replace plants in future years. Regulatory practice has
been modified for the Registrant's generation portion of its business (see Note
2 - Regulatory Matters under Notes to Financial Statements for further
information).
The cost of fuel for electric generation, which was previously reflected in
billings to customers through a fuel adjustment clause, has been added to base
rates as provided for in the Law (see Note 2 - Regulatory Matters under Notes to
Financial Statements for further information). Changes in gas costs are
generally reflected in billings to customers through a purchased gas adjustment
clause.
Inflation continues to be a factor affecting operations, earnings, stockholders'
equity and financial performance.
16
SAFE HARBOR STATEMENT
Statements made in this report which are not based on historical facts, are
forward-looking and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
forward-looking statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions,
financial performance and the Year 2000 Issue. In connection with the "Safe
Harbor" provisions of the Private Securities Litigation Reform Act of 1995, the
Registrant is providing this cautionary statement to identify important factors
that could cause actual results to differ materially from those anticipated.
Factors include, but are not limited to, the effects of regulatory actions;
changes in laws and other governmental actions; competition; future market
prices for fuel and purchased power, electricity, and natural gas, including the
use of financial instruments; average rates for electricity in the Midwest;
business and economic conditions; interest rates; weather conditions; fuel
prices and availability; generation plant performance; monetary and fiscal
policies; future wages and employee benefits costs; and legal and administrative
proceedings.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information required to be reported by this item is included under "Market
Risk Related to Financial Instruments and Commodity Instruments" in
"Management's Discussion and Analysis of Financial Conditions and Results of
Operations" under Item 7 herein.
17
REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------
To the Board of Directors and Shareholders
of Central Illinois Public Service Company
In our opinion, the financial statements listed in the index appearing under
Item 14(a)(1) on Page 37 present fairly, in all material respects, the financial
position of Central Illinois Public Service Company at December 31, 1998, and
the results of their operations and their cash flows for the year then ended 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 audit. We conducted our audit 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 the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for the opinion expressed
above. The financial statements of Central Illinois Public Service Company for
the year ended December 31, 1997 were audited by other independent accountants
whose report dated January 31, 1997 expressed an unqualified opinion on those
statements.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 4, 1999
18
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
---------------------------------------
BALANCE SHEET
-------------
(Thousands of Dollars, Except Shares)
December 31, December 31,
ASSETS 1998 1997
- ------ ---- ----
Property and plant, at original cost:
Electric $2,381,682 $2,311,364
Gas 259,656 249,499
-------------- ------------
2,641,338 2,560,863
Less accumulated depreciation and amortization 1,192,108 1,132,591
-------------- ------------
1,449,230 1,428,272
Construction work in progress 16,220 59,531
-------------- ------------
Total property and plant, net 1,465,450 1,487,803
-------------- ------------
Other assets 31,904 30,476
Current assets:
Cash and cash equivalents 10,180 28,140
Accounts receivable - trade (less allowance for doubtful
accounts of $1,714 and $1,200, respectively) 44,494 67,495
Unbilled revenue 53,120 31,708
Other accounts and notes receivable 16,486 7,760
Materials and supplies, at average cost -
Fossil fuel 38,102 24,919
Gas stored underground 12,689 14,275
Other 36,047 32,334
Other 8,214 10,537
-------------- ------------
Total current assets 219,332 217,168
-------------- ------------
Regulatory assets:
Deferred income taxes 24,797 28,052
Other 22,914 25,208
-------------- ------------
Total regulatory assets 47,711 53,260
-------------- ------------
TOTAL ASSETS $1,764,397 $1,788,707
============== ============
CAPITAL AND LIABILITIES
Capitalization:
Common stock, no par value, authorized 45,000,000 shares -
outstanding 25,452,373 shares $120,033 $121,282
Retained earnings 455,337 451,477
-------------- ------------
Total common stockholder's equity 575,370 572,759
Preferred stock not subject to mandatory redemption (Note 5) 80,000 80,000
Long-term debt (Note 7) 528,446 558,474
-------------- ------------
Total capitalization 1,183,816 1,211,233
-------------- ------------
Current liabilities:
Current maturity of long-term debt 60,000 9,000
Short-term debt 46,700 64,966
Accounts and wages payable 61,609 89,362
Accumulated deferred income taxes 21,386 20,285
Taxes accrued 13,201 15,869
Other 34,454 21,937
-------------- ------------
Total current liabilities 237,350 221,419
-------------- ------------
Commitments and Contingencies (Notes 2 and 10)
Accumulated deferred income taxes 234,119 237,629
Accumulated deferred investment tax credits 34,657 40,369
Regulatory liability 39,621 48,587
Other deferred credits and liabilities 34,834 29,470
============== ============
TOTAL CAPITAL AND LIABILITIES $1,764,397 $1,788,707
============== ============
See Notes to Financial Statements.
19
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
---------------------------------------
STATEMENT OF INCOME
-------------------
(Thousands of Dollars)
December 31, December 31, December 31,
For the year ended 1998 1997 1996
---- ---- ----
OPERATING REVENUES:
Electric $ 721,918 $ 700,517 $ 725,750
Gas 125,506 151,558 155,352
--------- --------- --------
Total operating revenues 847,424 852,075 881,102
OPERATING EXPENSES:
Operations
Fuel and purchased power 230,085 242,256 274,215
Gas 69,350 97,226 96,228
Other 179,477 160,201 145,332
--------- --------- --------
478,912 499,683 515,775
Maintenance 71,542 75,652 61,458
Depreciation and amortization 74,323 82,689 81,853
Income taxes 45,769 33,661 47,693
Other taxes 56,834 57,895 57,792
--------- --------- --------
Total operating expenses 727,380 749,580 764,571
Operating Income 120,044 102,495 116,531
OTHER INCOME AND DEDUCTIONS:
Allowance for equity funds used during
Construction 16 783 378
Miscellaneous, net (955) (3,800) (2,245)
--------- --------- --------
Total other income and deductions (939) (3,017) (1,867)
Income Before Interest Charges 119,105 99,478 114,664
INTEREST CHARGES:
Interest 40,039 36,791 37,754
Allowance for borrowed funds used during construction (1,081) (786) (483)
--------- --------- ---------
Net interest charges 38,958 36,005 37,271
Income Before Extraordinary Charge 80,147 63,473 77,393
--------- --------- ---------
Extraordinary Charge, net of income taxes (Note 2) -- (24,853) --
--------- --------- ---------
NET INCOME 80,147 38,620 77,393
--------- --------- ---------
Preferred Stock Dividends 3,745 3,715 3,721
--------- --------- ---------
NET INCOME AFTER PREFERRED
STOCK DIVIDENDS $ 76,402 $ 34,905 $ 73,672
========== ========= =========
See Notes to Financial Statements.
20
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
---------------------------------------
STATEMENT OF CASH FLOWS
-----------------------
(Thousands of Dollars)
December 31, December 31 December 31,
For the year ended 1998 1997 1996
---- ---- ----
Cash Flows From Operating:
Income before extraordinary charge $ 80,147 $ 63,473 $ 77,393
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 74,323 82,689 81,853
Allowance for funds used during construction (1,097) (1,569) (861)
Deferred income taxes, net (10,801) (1,686) 1,600
Deferred investment tax credits, net (5,712) (8,516) (3,349)
Changes in assets and liabilities:
Receivables, net (7,137) (2,076) (12,079)
Materials and supplies (15,310) 2,249 18,877
Regulatory assets - other 2,294 (50,693) (44,903)
Accounts and wages payable (27,753) 16,840 2,411
Taxes accrued (2,668) 1,926 2,788
Other, net 37,058 (21,922) 13,609
-------- -------- --------
Net Cash Provided By Operating Activities 123,344 80,715 137,339
Cash Flows From Investing:
Construction expenditures (68,848) (115,551) (106,601)
Allowance for funds used during construction 1,097 1,569 861
Other -- 3,182 25,874
-------- -------- --------
Net Cash Used In Investing Activities (67,751) (110,800) (79,866)
Cash Flows From Financing:
Dividends on common stock (72,285) (43,300) (62,950)
Dividends on preferred stock (4,002) (3,638) (3,637)
Redemptions -
Short-term debt (18,266) -- --
Long-term debt (64,000) (64,000) --
Issuances -
Short-term debt -- 7,198 9,847
Long-term debt 85,000 152,000 --
-------- -------- --------
Net Cash Provided By (Used In) Financing Activities (73,553) 48,260 (56,740)
Net Change In Cash And Cash Equivalents (17,960) 18,175 733
Cash And Cash Equivalents At Beginning Of Year 28,140 9,965 9,232
-------- -------- --------
Cash And Cash Equivalents At End Of Year $ 10,180 $ 28,140 $ 9,965
==============================================================================================
Cash paid during the periods:
- ----------------------------------------------------------------------------------------------
Interest (net of amount capitalized) $ 40,269 $ 35,363 $ 36,512
Income taxes $ 61,953 $ 36,763 $ 50,960
- ----------------------------------------------------------------------------------------------
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
Registrant's retail electric business as a result of electric industry
restructuring legislation enacted in Illinois in December 1997. The write-off
reduced earnings $25 million, net of income taxes. See Note 2 - Regulatory
Matters under Notes to Financial Statements for further information.
See Notes to Financial Statements.
21
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
---------------------------------------
STATEMENT OF RETAINED EARNINGS
(Thousands of Dollars)
- -----------------------------------------------------------------------------------
Year Ended December 31,
1998 1997 1996
- -----------------------------------------------------------------------------------
Balance at Beginning of Period $451,477 $459,942 $449,137
- -----------------------------------------------------------------------------------
Add:
Net income 80,147 38,620 77,393
- -----------------------------------------------------------------------------------
531,624 498,562 526,530
- -----------------------------------------------------------------------------------
Deduct:
Common stock cash dividends 72,285 43,300 62,950
Preferred stock cash dividends 4,002 3,785 3,638
- -----------------------------------------------------------------------------------
76,287 47,085 66,588
- -----------------------------------------------------------------------------------
Balance at End of Period $455,337 $451,477 $459,942
- -----------------------------------------------------------------------------------
SELECTED QUARTERLY INFORMATION (Unaudited)
(Thousands of Dollars)
- ----------------------------------------------------------------------------------------------
Operating Operating Net Net Income
Revenues Income Income (Loss) After
Quarter Ended (Loss) Preferred
Stock Dividends
- ----------------------------------------------------------------------------------------------
March 31, 1998 199,515 21,732 12,118 11,134
March 31, 1997 220,692 22,528 14,366 13,453
June 30, 1998 214,829 28,429 19,349 18,468
June 30, 1997 190,931 21,713 11,830 10,902
September 30, 1998 246,675 50,623 39,672 38,736
September 30, 1997 224,245 42,923 32,756 31,816
December 31, 1998 186,405 19,260 9,008 8,064
December 31, 1997 216,207 15,331 (20,332) (21,266)
- ----------------------------------------------------------------------------------------------
The third quarter of 1998 included a nonrecurring charge related to the
targeted separation plan, which reduced net income $4 million. See Note 3 -
Targeted Separation Plan under Notes to Financial Statements for further
information.
The fourth quarter of 1997 included merger costs of $5 million and an
extraordinary charge of $25 million, net of income taxes (see Note 3 -Regulatory
Matters under Notes to Financial Statements for further information).
Other changes in quarterly earnings are due to the effect of weather on sales
and other factors that are characteristic of public utility operations.
See Notes to Financial Statements.
22
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1998
NOTE 1 - Summary of Significant Accounting Policies
Basis of Presentation
Central Illinois Public Service Company (AmerenCIPS or the Registrant) is a
wholly-owned subsidiary of Ameren Corporation (Ameren), which is the parent
company of two utility operating companies, the Registrant and Union Electric
Company (AmerenUE). Ameren is a registered holding company under the Public
Utility Holding Company Act of 1935 (PUHCA) formed in December 1997 upon the
merger of CIPSCO Incorporated (the Registrant's former parent) and AmerenUE (the
Merger). Both Ameren Corporation 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 Illinois and Missouri. Contracts among the companies--dealing with
jointly-owned generating facilities, interconnecting transmission lines, and the
exchange of electric power--are regulated by the Federal Energy Regulatory
Commission (FERC) or the Securities and Exchange Commission (SEC).
Administrative support services are provided to the Registrant by a separate
Ameren subsidiary, Ameren Services Company. The Registrant serves 400,000
electric and 175,000 gas customers in a 20,000 square-mile region of central and
southern Illinois.
The Registrant also has a 20% interest in Electric Energy, Inc. (EEI), which is
accounted for under the equity method of accounting. EEI owns and operates an
electric generating and transmission facility in Illinois that supplies electric
power primarily to a uranium enrichment plant located in Paducah, Kentucky.
Regulation
In addition to the SEC, the Registrant is regulated by the Illinois Commerce
Commission (ICC) and the FERC. The accounting policies of the Registrant conform
to generally accepted accounting principles (GAAP). See Note 2 Regulatory
Matters for further information.
Property and Plant
The cost of additions to and betterments of units of property and plant is
capitalized. Cost includes labor, material, applicable taxes and overheads. An
allowance for funds used during construction is also added for the Registrant's
regulated assets, and interest incurred during construction is added for
non-regulated assets. Maintenance expenditures and the renewal of items not
considered units of property are charged to income as incurred. When units of
depreciable property are retired, the original cost and removal cost, less
salvage value, are charged to accumulated depreciation.
Depreciation
Depreciation is provided over the estimated lives of the various classes of
depreciable property by applying composite rates on a straight-line basis. The
provision for depreciation in 1998, 1997, and 1996 was approximately 3% of the
average depreciable cost.
Fuel and Gas Costs
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. (See Note 2 -
Regulatory Matters for further information.) In 1997 and 1996, changes in fuel
costs were generally reflected in billings to electric customers through the
fuel adjustment clause. Changes in gas costs are generally reflected in billings
to gas customers through a purchased gas adjustment clause.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments
purchased with an original maturity of three months or less.
23
Income Taxes
The Registrant is included in the consolidated federal income tax return filed
by Ameren. Income taxes are allocated to the individual companies based on their
respective taxable income or loss. Deferred tax assets and liabilities are
recognized for the tax consequences of transactions that have been treated
differently for financial reporting and tax return purposes, measured using
statutory tax rates expected to be in effect when the temporary differences
reverse.
Investment tax credits utilized in prior years were deferred and are being
amortized over the useful lives of the related properties.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFC) is a utility industry
accounting practice whereby the cost of borrowed funds and the cost of equity
funds (preferred and common stockholders' equity) applicable to the Registrant's
regulated construction program are capitalized as a cost of construction. AFC
does not represent a current source of cash funds. This accounting practice
offsets the effect on earnings of the cost of financing current construction,
and treats such financing costs in the same manner as construction charges for
labor and materials.
Under accepted ratemaking practice, cash recovery of AFC, as well as other
construction costs, occurs when completed projects are placed in service and
reflected in customer rates. The AFC rates used were 6% during 1998 and 8%
during 1997 and 1996.
Unamortized Debt Discount, Premium and Expense
Discount, premium, and expense associated with long-term debt are amortized over
the lives of the related issues.
Revenue
The Registrant accrues an estimate of electric and gas revenues for service
rendered but unbilled at the end of each accounting period.
Evaluation of Assets for Impairment
Statement of Financial Accounting Standards (SFAS) 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
prescribes general standards for the recognition and measurement of impairment
losses. The Registrant determines if long-lived assets are impaired by comparing
their undiscounted expected future cash flows to their carrying amount. An
impairment loss is recognized if the undiscounted expected future cash flows are
less than the carrying amount of the asset. SFAS 121 also requires that
regulatory assets which are no longer probable of recovery through future
revenues be charged to earnings (see Note 2 - Regulatory Matters for further
information). As of December 31, 1998, no impairment was identified.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires
management to make certain estimates and assumptions. Such estimates and
assumptions may affect reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reported period. Actual
results could differ from those estimates.
Reclassifications
Certain reclassifications have been made to prior-years financial statements to
conform with 1998 reporting.
NOTE 2 - Regulatory Matters
In June 1998, the Registrant filed a request with the ICC to increase rates for
natural gas service. In February 1999, the ICC approved an $8 million annual
rate increase. The rate increase became effective in February 1999.
In 1998, the Registrant joined a group of ten other companies which support the
formation of the Midwest Independent System Operator (Midwest ISO). An ISO
operates, but does not own, transmission systems and maintains system
reliability and security while alleviating pricing issues associated with the
"pancaking" of rates. The Midwest ISO would be regulated by FERC. The FERC
conditionally approved the Midwest ISO in September 1998, and it is expected to
be operational by the year 2001. The Midwest ISO covers eight states and
represents portions of 40,000 miles of transmission line and 62,000 megawatts of
electric power. Collectively, the member companies serve more than seven million
customers.
24
In December 1997, the Governor of Illinois signed the Electric Service Customer
Choice and Rate Relief Law of 1997 (the Law) providing for electric utility
restructuring in Illinois. This legislation introduces competition into the
supply of electric energy in Illinois.
Under the Law, retail direct access, which allows customers to choose their
electric generation supplier, will be phased in over several years. Access for
commercial and industrial customers will occur over a period from October 1999
to December 2000, and access for residential customers will occur after May 1,
2002.
The Law includes a 5% electric rate decrease for the Registrant's residential
customers, effective August 1, 1998. This rate decrease reduced electric
revenues by approximately $5 million in 1998 and is expected to reduce electric
revenues by approximately $11 million annually thereafter, based on estimated
levels of sales and assuming normal weather conditions. The Registrant may be
subject to additional 5% residential electric rate decreases in each of 2000 and
2002 to the extent its rates exceed the Midwest utility average at that time.
The Registrant's rates are currently below the Midwest utility average.
As a result of the Law, the Registrant filed a proposal with the ICC to
eliminate the electric fuel adjustment clause for Illinois retail customers,
thereby including a historical level of fuel costs in base rates. The ICC
approved the Registrant's filing in March 1998.
The Law contains a provision requiring one-half of excess earnings from the
Illinois regulated jurisdiction for the years 1998 through 2004 to be refunded
to the Registrant's customers. Excess earnings are defined as the excess of the
two-year average annual rate of return on common equity over the two-year
average of the average monthly yields of the 30-year U.S. Treasury bonds, plus
prescribed percentages ranging from 5.5% to 6.5%. Filings must be made with the
ICC on or before March 31 of each year 2000 through 2005. At this time, the
Registrant is unable to determine the impact of this provision on its future
financial condition, results of operations or liquidity.
Other provisions of the Law include (1) potential recovery of a portion of
strandable costs, which represent costs which would not be recoverable in a
restructured environment, through a transition charge collected from customers
who choose another electric supplier; (2) a mechanism to securitize certain
future revenues; (3) a requirement to file a delivery service tariff in March
1999 for customers who choose alternative suppliers; and (4) a provision
relieving the Registrant of the requirement to file an electric rate case or
alternative regulatory plan following the consummation of the Merger to reflect
the effects of net merger savings.
The Registrant's accounting policies and financial statements conform to GAAP
applicable to rate-regulated enterprises and reflect the effects of the
rate-making process in accordance with SFAS 71, "Accounting for the Effects of
Certain Types of Regulation." Such effects concern mainly the time at which
various items enter into the determination of net income in order to follow the
principle of matching costs and revenues. For example, SFAS 71 allows the
Registrant to record certain assets and liabilities (regulatory assets and
regulatory liabilities) which are expected to be recovered or settled in future
rates and would not be recorded under GAAP for non-regulated 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 applicable portion of the business that no longer meets 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 recoverable.
In addition, SFAS 121 establishes accounting standards for the impairment of
long-lived assets (see Note 1 - Summary of Significant Accounting Policies for
further information).
Due to the enactment of the Law, prices for the retail supply of electric
generation are expected to transition from cost-based, regulated rates to rates
determined in large part by competitive market forces in the state of Illinois.
As a result, the Registrant discontinued application of SFAS 71 for its
generating business (i.e., the portion of the Registrant's business related to
the supply of electric energy) in the fourth quarter of 1997. The Registrant has
25
evaluated the impact of the Law on the future recoverability of its regulatory
assets and liabilities related to the generation portion of its business and has
determined that it is not probable that such assets and liabilities will be
recovered through cash flows from the regulated portion of its business.
Accordingly, the Registrant's generation-related regulatory assets and
liabilities of its retail electric business were written off in the fourth
quarter of 1997, resulting in an extraordinary charge to earnings of $25
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 fuel contract restructuring costs, costs associated with an
abandoned scrubber at a fossil fuel plant, and income tax-related regulatory
assets and liabilities. In addition, the Registrant has evaluated whether the
recoverability of the costs associated with its remaining net generation-related
assets has been impaired as defined under SFAS 121. The Registrant has concluded
that impairment, as defined under SFAS 121, does not exist and that no plant
write-downs are necessary at this time. At December 31, 1998, the Registrant's
net investment in generation facilities approximated $625 million and was
included in electric plant in-service on the Registrant's balance sheet.
The provisions of the Law could also result in lower revenues, reduced profit
margins and increased costs of capital and operations expense. At this time, the
Registrant is unable to determine the impact of the Law on its future financial
condition, results of operations or liquidity.
In accordance with SFAS 71, the Registrant has deferred certain costs pursuant
to actions of its regulators, and is currently recovering such costs in electric
rates charged to customers.
At December 31, the Registrant had recorded the following regulatory assets and
regulatory liability:
- -------------------------------------------------------------------------------
(in millions) 1998 1997
- -------------------------------------------------------------------------------
Regulatory Assets:
Income taxes $25 $28
Unamortized loss on reacquired debt 8 6
Other 15 19
- -------------------------------------------------------------------------------
Regulatory Assets $48 $53
- -------------------------------------------------------------------------------
Regulatory Liability:
Income taxes $40 $49
- -------------------------------------------------------------------------------
Regulatory Liability $40 $49
- -------------------------------------------------------------------------------
Income Taxes: See Note 8 - Income Taxes.
Unamortized Loss on Reacquired Debt: Represents losses related to refunded debt.
These amounts are being amortized over the lives of the related new debt issues
or the remaining lives of the old debt issues if no new debt was issued.
The Registrant continually assesses the recoverability of its regulatory assets.
Under current accounting standards, regulatory assets are written off to
earnings when it is no longer probable that such amounts will be recovered
through future revenues.
In April 1996, the FERC issued Order 888 and Order 889 related to the industry's
wholesale electric business. In January 1998, Ameren filed a combined open
access tariff that conforms to the FERC's orders.
NOTE 3 - Targeted Separation Plan
In July 1998, Ameren offered separation packages to employees whose positions
were eliminated through a targeted separation plan (TSP). During the third
quarter of 1998, a nonrecurring, pre-tax charge of $7 million was recorded,
which reduced earnings $4 million, representing the Registrant's share of costs
incurred to implement the TSP. The remaining liability associated with the TSP
at December 31, 1998, was $3 million.
NOTE 4 - Concentration of Risk
Market Risk
The Registrant engages in price risk management activities related to
electricity. In addition to buying and selling these commodities, the Registrant
uses derivative financial instruments to manage market risks and reduce exposure
resulting from fluctuations in interest rates and the prices of electricity.
Derivative instruments used include futures and forward contracts. The use of
these types of contracts allows the Registrant to manage and hedge its
contractual commitments and reduce exposure related to the volatility of
commodity market prices.
26
Credit Risk
Credit risk represents the accounting loss that would be recognized if
counterparties fail to perform as contracted. New York Mercantile Exchange
(NYMEX) traded futures contracts are guaranteed by NYMEX and have nominal credit
risk. On all other transactions, the Registrant is exposed to credit risk in the
event of nonperformance by the counterparties in the transaction.
The Registrant's financial instruments subject to credit risk consist primarily
of trade accounts receivable and forward contracts. The risk associated with
trade receivables is mitigated by the large number of customers in a broad range
of industry groups comprising the Registrant's customer base. The Registrant's
revenues are primarily derived from sales of electricity and natural gas to
customers in Illinois. For each counterparty in forward contracts, the
Registrant analyzes the counterparty's financial condition prior to entering
into an agreement, establishes credit limits and monitors the appropriateness of
these limits on an ongoing basis.
NOTE 5 - Preferred Stock
At December 31, 1998 and 1997, AmerenCIPS had 4.6 million shares of authorized
preferred stock. There were 2 million shares of cumulative preferred and 2.6
million shares of preferred without par value (aggregate stated value not to
exceed $65 million) authorized.
Outstanding preferred stock is entitled to cumulative dividends and is
redeemable at the redemption prices shown below:
- -----------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------
Preferred Stock Not Subject to Mandatory Redemption:
(in millions)
- -----------------------------------------------------------------------------------------
Redemption Price December 31,
(per share) 1998 1997
Par value $100 Series--
4.00% Series - 150,000 shares $101.00 $15 $15
4.25% Series - 50,000 shares 102.00 5 5
4.90% Series - 75,000 shares 102.00 8 8
4.92% Series - 50,000 shares 103.50 5 5
5.16% Series - 50,000 shares 102.00 5 5
1993 Auction - 300,000 shares 100.00 - note(a) 30 30
6.625% Series - 125,000 shares 100.00 12 12
- -----------------------------------------------------------------------------------------
Total Preferred Stock Not
Subject to Mandatory Redemption $80 $80
- -----------------------------------------------------------------------------------------
(a) Dividend rates, and periods during which such rates apply, vary depending on
the Registrant's selection of certain defined dividend period lengths. The
average dividend rate during 1998 was 4.04%.
- -----------------------------------------------------------------------------------------
NOTE 6 - Short-Term Borrowings
Short-term borrowings of the Registrant consist of bank loans (maturities
generally on an overnight basis) and commercial paper (maturities generally
within 10-45 days). At December 31, 1998 and 1997, $47 million and $65 million
of short-term borrowings were outstanding, respectively. The weighted average
interest rates on borrowings outstanding at December 31, 1998 and 1997 were 4.9%
and 6.3%, respectively.
At December 31, 1998, the Registrant had committed bank lines of credit
aggregating $80 million (all of which was unused and $33 million was available)
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.
27
NOTE 7 - Long-Term Debt
Long-term debt outstanding at December 31, was:
- --------------------------------------------------------------------------------
(in millions) 1998 1997
- --------------------------------------------------------------------------------
First Mortgage Bonds - note (a)
- --------------------------------------------------------------------------------
8 1/2% Series W paid in 1998 $ - $ 33
7 1/8% Series W due 1999 50 50
6.00% Series Z due 2000 25 25
6.73% Series 1997-2 due 2001 20 20
6 3/4% Series Y due 2002 23 23
6 3/8% Series Z due 2003 40 40
6.49% Series 1995-1 due 2005 20 20
7.05% Series 1997-2 due 2006 20 20
7 1/2% Series X due 2007 50 50
7.61% Series 1997-2 due 2017 40 40
6.125% Series due 2028 60 -
Other 5.375% - 6.99% due 1999 through 2008 60 45
- --------------------------------------------------------------------------------
$408 $366
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Pollution Control Loan Obligations
- --------------------------------------------------------------------------------
1990 Series B 7.60% due 2013 32 32
1990 Series A 7.60% due 2014 20 20
1993 Series C-1 due 2026 - note (b) 35 35
1993 Series C-2 due 2026 - note (c) 25 25
1993 Series A 6 3/8% due 2028 35 35
Other 3.785% - 5.90% due 2028 35 35
- --------------------------------------------------------------------------------
$182 $182
- --------------------------------------------------------------------------------
Unsecured Loans - 21
- --------------------------------------------------------------------------------
Unamortized Discount and Premium on Debt (2) (2)
- --------------------------------------------------------------------------------
Maturities Due Within One Year (60) (9)
- --------------------------------------------------------------------------------
Total Long-Term Debt $528 $558
- --------------------------------------------------------------------------------
(a) At December 31, 1998, substantially all of the property and plant was
mortgaged under, and subject to liens of, the respective indentures pursuant to
which the bonds were issued.
(b) The interest rate for the year 1998 was 3.90%. Since August 15, 1998, the
actual interest rates vary since the bonds are currently in the weekly interest
rate mode. Interest rate modes can be changed by the Registrant at the end of
any interest rate mode period
(c) The interest rate for the year 1998 was 5.70%. These bonds are in a long-
term interest rate mode until August 15, 2003.
Maturities of long-term debt through 2003 are as follows:
- ------------------------------------------------------------------------
(in millions) Principal Amount
- ------------------------------------------------------------------------
1999 $60
2000 35
2001 30
2002 33
2003 45
- ------------------------------------------------------------------------
Also, Ameren has a bank credit agreement due 2003, which permits the borrowing
of up to $200 million on a long-term basis. This credit agreement is available
to Ameren and its subsidiaries, including the Registrant. As of December 31,
1998, $190 million was available for the Registrant's use.
28
NOTE 8 - Income Taxes
Total income tax expense for 1998 resulted in an effective tax rate of 36% on
earnings before income taxes (35% in 1997 and 38% in 1996).
Principal reasons such rates differ from the statutory federal rate:
- -------------------------------------------------------------------------------
1998 1997 1996
- -------------------------------------------------------------------------------
Statutory federal income 35% 35% 35%
tax rate
Increases (Decreases) from:
Depreciation Differences (3) - -
Amortization of Investment Tax Credit (2) (3) (3)
State tax 5 5 5
Other 1 (2) 1
- -------------------------------------------------------------------------------
Effective income tax rate 36% 35% 38%
- -------------------------------------------------------------------------------
Income tax expense components:
- -------------------------------------------------------------------------------
(in millions) 1998 1997 1996
- -------------------------------------------------------------------------------
Taxes currently payable (principally
federal):
Included in operating expenses $ 60 $39 $54
- -------------------------------------------------------------------------------
$ 60 $39 $54
- -------------------------------------------------------------------------------
Deferred taxes (principally federal):
Included in operating expenses--
Depreciation differences $(10) $(4) $ -
Other (1) 2 (3)
- -------------------------------------------------------------------------------
$(11) $(2) (3)
- -------------------------------------------------------------------------------
Deferred investment tax credits,
amortization
Included in operating expenses $ (3) $(3) (3)
- -------------------------------------------------------------------------------
Total income tax expense $ 46 $34 $48
- -------------------------------------------------------------------------------
In accordance with SFAS 109, "Accounting for Income Taxes," a regulatory asset,
representing the probable recovery from customers of future income taxes, which
is expected to occur when temporary differences reverse, was recorded along with
a corresponding deferred tax liability. Also, a regulatory liability,
recognizing the lower expected revenue resulting from reduced income taxes
associated with amortizing accumulated deferred investment tax credits, was
recorded. Investment tax credits have been deferred and will continue to be
credited to income over the lives of the related property.
The Registrant adjusts its deferred tax liabilities for changes enacted in tax
laws or rates. Recognizing that regulators will probably reduce future revenues
for deferred tax liabilities initially recorded at rates in excess of the
current statutory rate; reductions in the deferred tax liability were credited
to the regulatory liability.
Temporary differences gave rise to the following deferred tax assets and
deferred tax liabilities at December 31:
- --------------------------------------------------------------------------------
(in millions) 1998 1997
- --------------------------------------------------------------------------------
Accumulated Deferred Income Taxes:
Accelerated Depreciation $228 $235
Capitalized taxes and expenses 87 96
Regulatory liabilities, net (32) (42)
Prepayments (27) (32)
Other - 1
- --------------------------------------------------------------------------------
Total net accumulated deferred income tax liabilities $256 $258
- --------------------------------------------------------------------------------
29
NOTE 9 - Retirement Benefits
In 1998, the Registrant adopted SFAS 132, "Employers' Disclosures about Pension
and Other Postretirement Benefits," which resulted in revisions to the 1997 and
1996 information previously reported.
The Registrant has defined-benefit retirement plans covering substantially all
employees of AmerenCIPS as well as certain employees of Ameren Services Company.
Benefits are based on the employees' years of service and compensation. The
Registrant's plans are funded in compliance with income tax regulations and
federal funding requirements.
Pension costs for the years 1998, 1997 and 1996 were $9 million, $5 million and
$4 million, respectively, of which approximately 19% in 1998 and 15% in 1997 and
1996 was charged to construction accounts.
In 1998, the Registrant changed its measurement date for valuation of plan
assets and liabilities to December 31. 1997 amounts have been restated to
conform to the new date.
Funded Status of Pension Plans:
- --------------------------------------------------------------------------------
(in millions) 1998 1997
- --------------------------------------------------------------------------------
Change in benefit obligation
Net benefit obligation at beginning of year $249 $214
Service cost 8 7
Interest cost 17 16
Amendments 5 -
Actuarial loss 8 19
Special termination benefit charge 5 -
Benefits paid (31) (7)
- --------------------------------------------------------------------------------
Net benefit obligation at end of year 261 249
Change in plan assets *
Fair value of plan assets at beginning of year 319 265
Actual return on plan assets 38 52
Employer contributions 5 9
Benefits paid (31) (7)
- --------------------------------------------------------------------------------
Fair value of plan assets at end of year 331 319
Funded status - excess (70) (70)
Unrecognized net actuarial gain 73 65
Unrecognized prior service cost (13) (11)
Unrecognized net transition assets 2 3
- --------------------------------------------------------------------------------
Prepaid pension cost at December 31 $ (8) $ (13)
- --------------------------------------------------------------------------------
* Plan assets consist principally of common and preferred stocks, bonds, money
market instruments and real estate.
Components of Net Periodic Benefit Cost:
- ---------------------------------------------------------------------------
(in millions) 1998 1997 1996
- ---------------------------------------------------------------------------
Service cost $ 8 $ 7 $ 7
Interest cost 17 16 13
Expected return on plan assets (22) (19) (16)
Amortization of Prior service cost 1 1 -
Special termination benefit charge 5 - -
- ---------------------------------------------------------------------------
Net periodic benefit cost $ 9 $ 5 $ 4
- ---------------------------------------------------------------------------
Weighted-average Assumptions for Actuarial Present Value
of Projected Benefit Obligations:
- ----------------------------------------------------------------------------
1998 1997
- ----------------------------------------------------------------------------
Discount rate at measurement date 6.75% 7.25%
Expected return on plan assets 8.5% 8.5%
Increase in future compensation 4% 4.5%
- ----------------------------------------------------------------------------
30
In addition to providing pension benefits, the Registrant provides certain
health care and life insurance benefits for retired employees. The Registrant
accrues the expected postretirement benefit costs during employees' years of
service.
The Registrant's funding policy is to fund two Voluntary Employee Beneficiary
Association trusts (VEBA) and the 401(h) account established within the
Registrant's retirement income trust with the lesser of the net periodic cost or
the amount deductible for federal income tax purposes. In 1998, the Registrant
changed its measurement date for valuation of plan assets and liabilities to
December 31. 1997 amounts have been restated to conform to the new date.
Postretirement benefit costs were $6 million for 1998, $12 million for 1997 and
$16 million for 1996, of which approximately 20% was charged to construction
accounts in 1998, 17% in 1997, and 15 % in 1996. AmerenCIPS' transition
obligation at December 31, 1998 is being amortized over the next 14 years.
The ICC allows the recovery of postretirement benefit costs in rates to the
extent that such costs are funded.
Funded Status of the Plans:
- --------------------------------------------------------------------------------
(in millions) 1998 1997
- --------------------------------------------------------------------------------
Change in benefit obligation
Net benefit obligation at beginning of year $140 $139
Service cost 3 4
Interest cost 10 10
Actuarial (gain)/loss 4 (9)
Benefits paid (5) (4)
- --------------------------------------------------------------------------------
Net benefit obligation at end of year 152 140
Change in plan assets *
Fair value of plan assets at beginning of year 115 88
Actual return on plan assets 16 20
Employer contributions 4 12
401(h) transfer (2) (1)
Benefits paid (5) (4)
- --------------------------------------------------------------------------------
Fair value of plan assets at end of year 128 115
Funded status - deficiency 24 25
Unrecognized net actuarial gain 58 63
Unrecognized net transition obligation (76) (84)
- --------------------------------------------------------------------------------
Postretirement benefit liability at December 31 $ 6 $ 4
- --------------------------------------------------------------------------------
* Plan assets consist principally of common and preferred stocks, bonds, money
market instruments and real estate.
Components of Net Periodic Benefit Cost:
- --------------------------------------------------------------------------------
(in millions) 1998 1997 1996
- --------------------------------------------------------------------------------
Service cost $3 $4 $4
Interest cost 10 10 11
Expected return on plan assets (8) (5) (4)
Amortization of:
Transition obligation 5 5 6
Actuarial gain (4) (2) (1)
- --------------------------------------------------------------------------------
Net periodic benefit cost $6 $12 $16
- --------------------------------------------------------------------------------
Assumptions for the Obligation Measurements:
- ----------------------------------------------------------------------------
1998 1997
- ----------------------------------------------------------------------------
Discount rate at measurement date 6.75% 7.25%
Expected return on plan assets 8.5% 8.5%
Medical cost trend rate - initial 5.75% 8.5%
- ultimate 4.75% 5.5%
Ultimate medical cost trend rate expected in year 2000 2000
- ----------------------------------------------------------------------------
31
A 1% increase in the medical cost trend rate is estimated to increase the net
periodic cost and the accumulated postretirement benefit obligation
approximately $2 million and $22 million, respectively. A 1% decrease in the
medical cost trend rate is estimated to decrease the net periodic cost and the
accumulated postretirement benefit obligation approximately $2 million and $22
million, respectively.
NOTE 10 - Commitments and Contingencies
The Registrant is engaged in a capital program under which expenditures
averaging approximately $123 million, including AFC, are anticipated during each
of the next five years. This estimate includes expenditures that will be
incurred by the Registrant to meet new air quality standards for ozone and
particulate matter, as discussed later in this Note.
The Registrant has commitments for the purchase of coal under long-term
contracts. Coal contract commitments, including transportation costs, for 1999
through 2003 are estimated to total $493 million. Total coal purchases,
including transportation costs, for 1998, 1997 and 1996 were $189 million, $209
million and $217, respectively. The Registrant also has existing contracts with
pipeline and natural gas suppliers to provide natural gas for distribution and
electric generation. Gas-related contract commitments for 1999 through 2003 are
estimated at $65 million. Total delivered natural gas costs were $69 million for
1998 and $97 million for both 1997 and 1996.
During 1996, the Registrant restructured its contract with one of its major coal
suppliers. In 1997, the Registrant paid a $70 million restructuring payment to
the supplier, which allowed it to purchase at market prices low-sulfur,
non-Illinois coal through the supplier (in substitution for the high-sulfur
Illinois coal the Registrant was obligated to purchase under the original
contract); and would receive options for future purchases of low-sulfur,
non-Illinois coal from the supplier through 1999 at set negotiated prices.
By switching to low-sulfur coal, the Registrant was able to discontinue
operating a generating station scrubber. The benefits of the restructuring
include lower cost coal, avoidance of significant capital expenditures to
renovate the scrubber and elimination of scrubber operations and maintenance
costs (offset by scrubber retirement expenses). The net benefits of
restructuring are expected to exceed $100 million through 2007. In December
1996, the ICC entered an order approving the switch to non-Illinois coal,
recovery of the restructuring payment plus associated carrying costs
(Restructuring Charges) through the retail uniform fuel adjustment clause (FAC)
over six years, and continued recovery in rates of the undepreciated scrubber
investment plus costs of removal. Additionally, in May 1997 the FERC approved
recovery of the wholesale portion of the Restructuring Charges through the
wholesale FAC. As a result of the ICC and FERC orders, the Registrant classified
the $72 million of the Restructuring Charges made to the coal supplier in
February 1997 as a regulatory asset and, through December 1997, recovered
approximately $10 million of the Restructuring Charges through the retail FAC
and from wholesale customers.
A group of industrial customers filed with the Illinois Third District Appellate
Court (the Court) in February 1997 an appeal of the December 1996 order of the
ICC. In November, 1997, the Court reversed the ICC's December 1996 order,
finding that the Restructuring Charges were not direct costs of fuel that may be
recovered through the retail FAC, but rather should be considered as a part of a
review of aggregate revenue requirements in a full rate case. Restructuring
Charges allocated to wholesale customers (approximately $7 million) are not in
question as a result of the opinion of the Court. In December 1997, the
Registrant requested a rehearing by the Court; that request was denied. However,
the Court did rule that all revenues collected under the retail FAC in 1997
would not have to be refunded to customers.
The Registrant filed an appeal with the Illinois Supreme Court. In December
1998, the Supreme Court issued its decision, reversing the Court's opinion and
affirming the ICC's order. The Supreme Court held that the Restructuring Charges
are recoverable through the retail FAC. No further proceedings are anticipated.
The recoverability of the Restructuring Charges under the retail FAC in Illinois
was also impacted by the Law. Among other things, the Law provides utilities
with the option to eliminate the retail FAC and limits the ability of utilities
to file a full rate case for its aggregate revenue requirements. After
evaluating the impact of the Law on the future recoverability of the
Registrant's Restructuring Charges through future rates, the Registrant wrote
off the unamortized balance of the Illinois retail portion of its Restructuring
Charges as of December 31, 1997 ($34 million, net of income taxes). See Note 2 -
Regulatory Matters for further information.
Under Title IV of the Clean Air Act Amendments of 1990, the Registrant is
required to significantly reduce total annual sulfur dioxide (SO2) and nitrogen
oxide (NOx) emissions by the year 2000. By switching to low-sulfur coal,
32
the Registrant 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.
In July 1997, the United States Environmental Protection Agency (EPA) issued
final regulations revising the National Ambient Air Quality Standards for ozone
and particulate matter. The new ambient standards may result in significant
additional reductions in SO2 and NOx emissions from the Registrant's power
plants. The new particulate matter standards may require SO2 reductions of up to
50% beyond that already required by Phase II acid rain control provisions of the
1990 Clean Air Act Amendments and could be required by 2007. The full details of
these requirements are under study by the Registrant. At this time, the
Registrant is unable to predict the ultimate impact of these revised air quality
standards on its future financial condition, results of operations or liquidity.
In an attempt to lower ozone levels across the eastern United States, the EPA
issued final regulations in September 1998 pertaining to NOx emissions from
coal-fired boilers and other sources in 22 states, including Illinois (where all
of the Registrant's coal-fired power plant boilers are located). Although
reduction requirements in NOx emissions from the Registrant's coal-fired boilers
are anticipated to exceed 75 percent from 1990 levels by the year 2003, it is
not yet possible to determine the exact magnitude of the reductions required
from the Registrant's power plants because each state has up to one year to
develop a plan to comply with the EPA rule. The NOx emissions reductions already
achieved on several of the Registrant's coal-fired power plants will help to
reduce the costs of compliance with this regulation. However, preliminary
analysis of the regulations indicate that selective catalytic reduction
technology will be required for some of the Registrant's units, as well as other
additional controls.
Currently, the Registrant estimates that its additional capital expenditures to
comply with the EPA's final regulations issued in September 1998 could range
from $125 million to $175 million over the period from 1999 to 2002. Associated
operations and maintenance expenditures could increase $5 million to $8 million
annually, beginning in 2003. The Registrant will explore alternatives to comply
with these new regulations in order to minimize, to the extent possible, its
capital costs and operating expenses. The Registrant is unable to predict the
ultimate impact of these standards on its future financial condition, results of
operations or liquidity.
In November 1998, the United States signed an agreement with numerous other
countries (the Kyoto Protocol) containing certain environmental provisions,
which would require decreases in greenhouse gases in an effort to address the
"global warming" issue. The Kyoto Protocol must be ratified by the United States
Senate before provisions are effective for the United States. Until ratification
is obtained, the Registrant is unable to predict what requirements, if any, will
be adopted in this country; however, implementation of the Kyoto Protocol in its
present form would likely result in significantly higher capital costs and
operations and maintenance expenses by the Registrant. At this time, the
Registrant is unable to determine the impact of these proposals on the
Registrant's future financial condition, results of operations or liquidity.
As of December 31, 1998, the Registrant was designated as a potentially
responsible party (PRP) by federal and state environmental protection agencies
at three hazardous waste sites. Other hazardous waste sites have been identified
for which the Registrant may be responsible but has not been designated a PRP.
Costs relating to studies and remediation and associated legal and litigation
expenses at the sites located in Illinois are being accrued and deferred rather
than expensed currently, pending recovery through rates. Through December 31,
1998, the total of the costs deferred, net of recoveries from insurers and
through environmental adjustment clause rate riders approved by the ICC, was $12
million.
The ICC has instituted a reconciliation proceeding to review the Registrant's
environmental remediation activities from 1993 through 1997 and to determine
whether the revenues collected from customers under its environmental adjustment
clause rate riders were consistent with the amount of remediation costs
prudently and properly incurred. Amounts found to have been incorrectly included
under the riders would be subject to refund. Rulings from the ICC are still
pending with respect to these proceedings applicable to the years 1993 through
1996. The reconciliation proceedings relating to the Registrant's 1997
environmental remediation activities were commenced in April 1998, but have not
yet been submitted to the ICC for a decision.
The Registrant continually reviews remediation costs that may be required for
all of these sites. Any unrecovered environmental costs are not expected to have
a material adverse effect on the Registrant`s financial position, results of
operations or liquidity.
The International Union of Operating Engineers Local 148 and the International
Brotherhood of Electrical Workers Local 702 filed unfair labor practice charges
with the National Labor Relations Board (NLRB), relating to the
33
legality of the 1993 lockout of both unions by AmerenCIPS. The NLRB issued
complaints against AmerenCIPS concerning its lockout. Both unions sought, among
other things, back pay and other benefits for the period of the lockout. At that
time, the Registrant estimated the amount of back pay and other benefits for
both unions to be approximately $17 million. In May 1996, an administrative law
judge of the NLRB ruled that the lockout was unlawful. In July 1996, the
Registrant appealed to the NLRB. In August 1998, a three-member panel of the
NLRB reversed the administrative law judge's decision and ruled that the lockout
was lawful. Both unions filed motions for review with the NLRB asking for
reconsideration of this decision. In December 1998, the NLRB denied the unions'
motions for reconsideration. Subsequently, in December 1998, the unions filed a
joint motion for a rehearing of their motions for reconsideration. The
Registrant continues to believe that the lockout was both lawful and reasonable
and that the final resolution of the dispute will not have a material adverse
effect on its financial position, results of operations or liquidity.
Certain employees of the Registrant are represented by the International
Brotherhood of Electrical Workers and the International Union of Operating
Engineers. These employees comprise approximately 70% of the Registrant's
workforce. The collective bargaining agreements covering nearly all of these
represented employees expire in July 1999. Preliminary discussions with these
collective bargaining units are currently underway. At this time, the Registrant
is unable to predict the impact of these negotiations on its future financial
condition, results of operations or cash flows.
Regulatory changes enacted and being considered at the federal and state levels
continue to change the structure of the utility industry and utility regulation,
as well as encourage increased competition. At this time, the Registrant is
unable to predict the impact of these changes on the Registrant's future
financial condition, results of operations or liquidity. See Note 2 - Regulatory
Matters for further information.
The Registrant is involved in other legal and administrative proceedings before
various courts and agencies with respect to matters arising in the ordinary
course of business, some of which involve substantial amounts. The Registrant
believes that the final disposition of these proceedings will not have a
material adverse effect on its financial position, results of operations or
liquidity.
NOTE 11 - 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.
Preferred Stock
The fair value is estimated based on the quoted market prices for the same or
similar issues.
Long-Term Debt
The fair value is estimated based on the quoted market prices for same or
similar issues or on the current rates offered to the Registrant for debt of
comparable maturities.
Carrying amounts and estimated fair values of the Registrant's financial
instruments at December 31:
1998 1997
- --------------------------------------------------------------------------------
(in millions) Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------
Preferred stock $ 80 $75 $ 80 $ 71
Long-term debt (including
current portion) 588 636 567 600
- --------------------------------------------------------------------------------
34
NOTE 12 - Segment Information
In 1998, the Registrant adopted SFAS 131, "Disclosures about Segments of an
Enterprise and Related Information." AmerenCIPS' business segments provide
electric and gas service in portions of Illinois.
The accounting policies of the segments are the same as those described in Note
1 - Summary of Significant Accounting Policies. Segment data includes a charge
allocating costs of administrative support services to each of the segments.
These costs are accumulated in a separate Ameren subsidiary, Ameren Services
Company, which provides a variety of support services to the Registrant. The
Registrant evaluates the performance of its segments and allocates resources to
them, based on revenues and operating income.
The table below presents information about the reported revenues and operating
income of the Registrant for the years ended December 31:
- --------------------------------------------------------------------
(in millions) Electric Gas Total
- --------------------------------------------------------------------
- --------------------------------------------------------------------
1998
- --------------------------------------------------------------------
Revenues $ 722 $125 $ 847
Operating Income 115 5 120
- --------------------------------------------------------------------
- --------------------------------------------------------------------
1997
- --------------------------------------------------------------------
Revenues $ 700 $152 $ 852
Operating Income 95 7 102
- --------------------------------------------------------------------
- --------------------------------------------------------------------
1996
- --------------------------------------------------------------------
Revenues $ 726 $155 $ 881
Operating Income 106 11 117
- --------------------------------------------------------------------
Specified items included in segment profit/loss for the year ended December 31:
- --------------------------------------------------------------------------------
(in millions) Electric Gas Total
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1998
- --------------------------------------------------------------------------------
Depreciation, depletion
and amortization expense $66 $ 8 $ 74
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1997
- --------------------------------------------------------------------------------
Depreciation, depletion
and amortization expense $76 $ 7 $ 83
Extraordinary items (25) - (25)
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1996
- --------------------------------------------------------------------------------
Depreciation, depletion
and amortization expense $ 75 $ 7 $ 82
- --------------------------------------------------------------------------------
Specified item related to segment assets as of December 31:
- --------------------------------------------------------------------------------
(in millions) Electric Gas Total
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1998
- --------------------------------------------------------------------------------
Expenditures for Additions
To Long-Lived Assets $ 60 $ 9 $ 69
- --------------------------------------------------------------------------------
35
[CONTINUED]
- --------------------------------------------------------------------------------
1997
- --------------------------------------------------------------------------------
Expenditures for Additions
To Long-Lived Assets $105 $ 11 $ 116
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1996
- --------------------------------------------------------------------------------
Expenditures for Additions
To Long-Lived Assets $ 93 $ 14 $ 107
- --------------------------------------------------------------------------------
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.
On June 12, 1998, the Board of Directors of the Registrant's
parent, Ameren, approved the recommendation of the Board's Auditing Committee
and appointed PricewaterhouseCoopers LLP as auditors for the year 1998. Ameren's
appointment of PricewaterhouseCoopers LLP also covers auditing services for
Ameren's subsidiaries, which means that Registrant's previous certifying
accountant, Arthur Andersen LLP (Andersen), was, in effect, dismissed.
Andersen's report of the Registrant's financial statements for
either of the last two fiscal years did not contain an adverse opinion or a
disclaimer of opinion, and was not qualified or modified as to uncertainty,
audit scope, or accounting principles. Further, during such period, and through
the date of dismissal, there were no disagreements with Andersen on any matter
of accounting principles or practices, financial statement disclosure, or
auditing scope or procedure. Also, there was no occurrence of any kind of event
set out in paragraphs (a) (1) (v) (A) through (D) of Item 304 of Regulation S-K.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Any information concerning directors required to be reported by this item
is included under "Item (1): Election of Directors" in the CIPS' 1999 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 CIPS' 1999 definitive proxy statement filed pursuant to
Regulation 14A and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Any information required to be reported by this item is included under
"Security Ownership of Management" in CIPS' 1999 definitive proxy statement
filed pursuant to Regulation 14A and is incorporated herein by reference.
36
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 CIPS' 1999 definitive proxy statement filed
pursuant to Regulation 14A and is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements and Financial Statement Schedule Covered by
Report of Independent Accountants
Pages Herein
Report of Independent Accountants................................. 18
Balance Sheet - December 31, 1998 and 1997........................ 19
Statement of Income - Years 1998, 1997, and 1996.................. 20
Statement of Cash Flows - Years 1998, 1997, and 1996.............. 21
Statement of Retained Earnings - Years 1998, 1997, and 1996....... 22
Notes to Financial Statements..................................... 23
Valuation and Qualifying Accounts (Schedule II)
Years 1998, 1997, and 1996...................................... 38
2. Exhibits: See EXHIBITS beginning on Page 40
(b) Reports on Form 8-K. The Registrant filed a report on Form 8-K
dated October 8, 1998 reporting on the impact of Ameren
Corporation's (parent company of the Registrant) employee
separation plan and on the effect of the final rule issued in
September 1998 by the United States Environmental Protection
Agency pertaining
to nitrogen oxide emissions.
37
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Col. A Col. B Col. C Col. D Col. E
------ ------ ------ ------ ------
Additions
-----------------------------
(1) (2)
Balance at Charged to Balance at
beginning costs and Charged to end of
Description of period expenses other accounts Deductions period
----------- --------- ---------- -------------- ---------- ------
(Note)
Year ended December 31, 1998
Reserves deducted in the balance sheet from
assets to which they apply:
Allowance for doubtful accounts $1,200,000 $4,267,000 $3,752,768 $1,714,232
========== ========== ========== ==========
Year ended December 31, 1997
Reserves deducted in the balance sheet from
assets to which they apply:
Allowance for doubtful accounts $ 600,000 $1,788,812 $1,188,812 $1,200,000
========== ========== ========== ==========
Year ended December 31, 1996
Reserves deducted in the balance sheet from
assets to which they apply:
Allowance for doubtful accounts $ 600,000 $ - $ - $ 600,000
========== ========== ========== ==========
Note: Uncollectible accounts charged off, less recoveries.
38
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.
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
(Registrant)
G. L. RAINWATER
President and Chief Executive Officer
Date March 29, 1999 By /s/ Steven R. Sullivan
------------------- ------------------------
(Steven R. Sullivan, Attorney-in-Fact)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
Signature Title
--------- -----
/s/ G. L. Rainwater President, Chief Executive Officer and Director
- ------------------- (Principal Executive Officer)
G. L. RAINWATER
/s/ Jerre E. Birdsong Treasurer
- --------------------- (Principal Financial Officer)
JERRE E. BIRDSONG
/s/ Warner L. Baxter Controller
- -------------------- (Principal Accounting Officer)
WARNER L. BAXTER
/s/ Paul A. Agathen Director
- -------------------
PAUL A. AGATHEN
/s/ Donald E. Brandt Director
- --------------------
DONALD E. BRANDT
/s/ John L. Heath Director
- -----------------
JOHN L. HEATH
/s/ Robert W. Jackson Director
- ---------------------
ROBERT W. JACKSON
/s/ Charles W. Mueller Director
- ----------------------
CHARLES W. MUELLER
/s/ Charles J. Schukai Director
- ----------------------
CHARLES J. SCHUKAI
/s/ Thomas L. Shade Director
- -------------------
THOMAS L. SHADE
By /s/ Steven R. Sullivan March 29, 1999
-------------------------
(Steven R. Sullivan, Attorney-in-Fact)
39
EXHIBITS
Exhibits Filed Herewith
-----------------------
Exhibit No. Description
- ----------- -----------
3(ii) - By-Laws of the Company as amended effective February 11, 1999.
12 - Statement re Computation of Ratio of Earnings to Fixed Charges and
Preferred Stock Dividend Requirements.
23 - Consent of Independent Accountants.
24 - Powers of Attorney.
27 - Financial Data Schedule.
40
Exhibits Incorporated By Reference
----------------------------------
The following exhibits heretofore have been filed with the Securities and
Exchange Commission pursuant to requirements of the Acts administered by the
Commission. Such exhibits are identified by the references following the listing
of each such exhibit, and they are hereby incorporated herein by reference.
Exhibit No. Description
- ----------- -----------
2 - Agreement and Plan of Merger, dated as of August 11, 1995, by and among
CIPSCO Incorporated, Union Electric Company, Ameren Corporation and
Arch Merger Inc.(Exhibit 2(a) filed with CIPSCO's and CIPS' Form 10-Q/A
(Amendment No. 1) for the quarter ended June 30, 1995.)
3.01 - Restated Articles of Incorporation of CIPS. (Exhibit 3(b) filed with
CIPS' Form 10-Q for the quarter ended March 31, 1994.)
4 - Indenture of Mortgage or Deed of Trust dated October 1, 1941, from CIPS
to Continental Illinois National Bank and Trust Company of Chicago and
Edmond B.Stofft, as Trustees. (Exhibit 2.01 in File No. 2-60232.)
Supplemental Indentures dated, respectively September 1,1947, January
1, 1949, February 1, 1952, September 1, 1952, June 1, 1954, February 1,
1958, January 1, 1959, May 1, 1963, May 1, 1964, June 1, 1965, May 1,
1967, April 1, 1970, April 1, 1971, September 1, 1971, May 1, 1972,
December 1, 1973, March 1, 1974, April 1, 1975, October 1, 1976, Novem-
ber 1, 1976, October 1, 1978, August 1, 1979, February 1, 1980,
February 1, 1986, May 15, 1992, July 1, 1992, September 15, 1992, April
1, 1993, and June 1, 1995 between CIPS and the Trustees under the
Indenture of Mortgage or Deed of Trust referred to above (Amended Ex-
hibit 7(b) in File No. 2-7341; Second Amended Exhibit 7.03 in File No.
2-7795; Second Amended Exhibit 4.07 in File No. 2-9353; Amended Exhibit
4.05 in file No. 2-9802; Amended Exhibit 4.02 in File No. 2-10944;
Amended Exhibit 2.02 in File No. 2-13866; Amended Exhibit 2.02 in File
No. 2-14656; Amended Exhibit 2.02 in File No.2-21345; Amended Exhibit
2.02 in File No. 2-22326; Amended Exhibit 2.02 in File No. 2-23569;
Amended Exhibit 2.02 in File No. 2-26284; Amended Exhibit 2.02 in File
No. 2-36388; Amended Exhibit 2.02 in File No. 2-39587; Amended Exhibit
2.02 in File No. 2-41468; Amended Exhibit 2.02 in File No. 2-43912;
Exhibit 2.03 in File No. 2-60232; Amended Exhibit 2.02 in File No.
2-50146; Amended Exhibit 2.02 in File No. 2-52886; Second Amended
Exhibit 2.04 in File No. 2-57141; Amended Exhibit 2.04 in File No.
2-57557; Amended Exhibit 2.06 in File No. 2-62564; Exhibit 2.02(a)
in File No. 2-65914; Amended Exhibit 2.02(a) in File No. 2-66380; and
Amended Exhibit 4.02 in File No. 33-3188; Exhibit 4.02 to Form 8-K
dated May 15, 1992; Exhibit 4.02 to Form 8-K dated July 1,1992; Exhibit
4.02 to Form 8-K dated September 15, 1992; Exhibit 4.02 to Form 8-K
dated March 30, 1993; Exhibit 4.03 to Form 8-K dated June 5, 1995;
Exhibit 4.03 to Form 8-K dated March 15, 1997; Exhibit 4.03 to Form
8-K dated June 1, 1997; and Exhibit 4.02, Post-Effective Amendment No.
1 in File No. 333-18473.)
4.01 - Indenture dated as of December 1, 1998 from CIPS to the Bank of New
York relating to CIPS' Senior Notes, 5.375% due 2008 and 6.125% due
2028. (Exhibit 4.03, Post-Effective Amendment No. 1 to File No. 333-
18473.)
10.01 - Form of Deferred Compensation Agreement for Directors. (Exhibit 10.01
filed with 1990 Annual Report on Form 10-K.)
41
Exhibit No. Description
- ----------- -----------
10.02 - Amended Form of Deferred Compensation Agreement for Directors. (Exhibit
filed with 1993 Annual Report on Form 10-K.)
10.03 - Form of Director's Retirement Income Plan. (Exhibit 10.04 filed with
Annual Report on Form 10-K.)
10.04 - Form of Excess Benefit Plan. (Exhibit 10.10 filed with CIPSCO's and
CIPS' 1994 Annual Report on Form 10-K.)
10.05 - Amendment to Form of Excess Benefit Plan. (Exhibit 10.07 filed with
CIPSCO's and CIPS' 1995 Annual Report on Form 10-K.)
10.06 - Form of Special Executive Retirement Plan. (Exhibit 10.11 filed with
CIPSCO's and CIPS' 1994 Annual Report on Form 10-K.)
10.07 - Amendment to Form of Special Executive Retirement Plan. (Exhibit 10.09
filed with CIPSCO's and CIPS' 1995 Annual Report on Form 10-K.)
10.08 - Ameren Long-Term Incentive Plan of 1998. (Ameren's 1998 Form 10-K,
Exhibit 10.1.)
10.09 - Ameren Change of Control Severance Plan. ((Ameren's 1998 Form 10-K,
Exhibit 10.2.)
10.10 - Ameren Deferred Compensation Plan for Members of the Ameren Leadership
Team. (Ameren's 1998 Form 10-K, Exhibit 10.3.)
10.11 - Ameren Deferred Compensation Plan for Members of the Board of Directors
(Ameren's 1998 Form 10-K, Exhibit 10.4.)
Note: Reports of the Company on Forms 8-K, 10-Q and 10-K are on file with the
SEC under File Number 1-3672.
Reports of Ameren on Form 10-K are on file with the SEC under File
Number 1-14756.
42