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, 2002
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 333-56594
AMEREN ENERGY GENERATING COMPANY
(Exact name of registrant as specified in its charter)
Illinois
37-1395586
(State or other jurisdiction of
incorporation or organization) (I.R.S. Employer Identification No.)
1901 Chouteau Avenue, St. Louis, Missouri 63103
(Address of principal executive offices and Zip Code)
Registrant's telephone number, including area code: (314) 621-3222
Securities Registered Pursuant to Section 12(b) of the Act: None.
Securities Registered Pursuant to Section 12(g) of the Act: None.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes (X). No ( ).
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. (X).
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ( ). No (X).
As of June 28, 2002, all 2,000 outstanding shares of the registrant's
common stock were held by its parent, AmerenEnergy Development Company, an
indirect subsidiary of Ameren Corporation.
As of March 31, 2003, there was no established trading market for the
registrant's common stock.
As of March 31, 2003, there were 2,000 outstanding shares of common stock,
without par value, of the registrant, all of which were owned by the
registrant's parent, AmerenEnergy Development Company, an indirect subsidiary of
Ameren Corporation.
OMISSION OF CERTAIN INFORMATION
The Registrant meets the conditions set forth in General Instruction
(I)(1)(a) and (b) of Form 10-K as a wholly owned indirect subsidiary of Ameren
Corporation and is therefore filing this Form with the reduced disclosure format
allowed under that General Instruction.
DOCUMENTS INCORPORATED BY REFERENCE:
None.
TABLE OF CONTENTS
Page
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PART I
Item 1 Business
General........................................................................................... 1
Capital Program and Financing..................................................................... 3
Regulation........................................................................................ 3
Fuel Supply for Electric Generating Facilities.................................................... 4
Industry Issues................................................................................... 5
Available Information............................................................................. 5
Item 2 Properties............................................................................................. 6
Item 3 Legal Proceedings...................................................................................... 8
Item 4 Submission of Matters to a Vote of Security Holders.................................................... 9
PART II
Item 5 Market for Registrant's Common Equity and Related Stockholder Matters.................................. 9
Item 6 Selected Financial Data................................................................................ 9
Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 10
Item 7A Quantitative and Qualitative Disclosures About Market Risk............................................. 26
Item 8 Financial Statements and Supplementary Data............................................................ 27
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................... 51
PART III
Item 10 Directors and Executive Officers of the Registrant..................................................... 51
Item 11 Executive Compensation................................................................................. 51
Item 12 Security Ownership of Certain Beneficial Owners and Management......................................... 51
Item 13 Certain Relationships and Related Party Transactions................................................... 51
Item 14 Controls and Procedures................................................................................ 51
PART IV
Item 15 Exhibits, Financial Statement Schedules and Reports on Form 8-K........................................ 52
SIGNATURES................................................................................................................. 55
CERTIFICATIONS............................................................................................................. 55
EXHIBIT INDEX.............................................................................................................. 58
This Form 10-K contains "forward-looking statements" within the meaning of
Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking
statements should be read with the cautionary statements and important factors
included in this Form 10-K at pages 8 and 25 under the heading Forward-Looking
Statements. Forward-looking statements are all statements other than statements
of historical fact, including those statements that are identified by the use of
the words "anticipates," "estimates," "expects," "intends," "plans," "predicts,"
"projects" and similar expressions.
PART I
ITEM 1. BUSINESS.
GENERAL
AmerenEnergy Generating Company, headquartered in St. Louis, Missouri, is
an indirect wholly-owned subsidiary of Ameren Corporation (Ameren). We own and
operate a wholesale electric generation business in Illinois and Missouri. Much
of our business was formerly owned and operated by our affiliate, Central
Illinois Public Service Company, which operates as AmerenCIPS. We were
incorporated in the State of Illinois in March 2000. On May 1, 2000, we acquired
from AmerenCIPS at net book value five coal-fired electric generating stations,
which we refer to as the coal plants, all related fuel, supply, transportation,
maintenance and labor agreements, approximately 45% of AmerenCIPS' employees,
and other related rights, assets and liabilities. Since we commenced operations
in May 2000, we have acquired 25 combustion turbine generating units. As of
December 31, 2002, we had approximately 4,675 megawatts of total installed
generating capacity (4,663 of net kilowatt capability expected for 2003 summer
peak). We currently have no plans to develop additional capacity. For additional
information regarding our generating facilities, see Item 2.
When we refer to our, we, us or Generating Company, we are referring to
AmerenEnergy Generating Company and in some cases our agents, AmerenEnergy, Inc.
(AmerenEnergy) and AmerenEnergy Fuels and Services Company (Fuels Company).
Deregulation in Illinois
In December 1997, the Electric Service Customer Choice and Rate Relief Law
of 1997 (the Illinois Law) was enacted providing for electric utility
restructuring in Illinois. We were formed as part of Ameren's business strategy
to respond to the advent of customer choice in Illinois and the increasingly
competitive market for electric generation services in the Midwest brought about
by the Illinois Law and other factors. As allowed under the Illinois Law and as
part of a plan to divest itself of generating assets, AmerenCIPS transferred the
coal plants to us effective May 1, 2000. Major provisions of the Illinois Law
include the phasing-in through 2002 of retail direct access, which allows
customers to choose their electric generation suppliers. The phase-in of retail
direct access began on October 1, 1999, with large commercial and industrial
customers principally comprising the initial group that is entitled to choose
suppliers. Retail direct access was offered to the remaining commercial and
industrial customers on December 31, 2000 and was offered to residential
customers May 1, 2002. Regulated utilities, like AmerenCIPS, will continue to
provide "bundled service," that is, electricity supply as well as delivery, to
customers who do not choose a competitive supplier.
For additional information regarding our significant power supply
agreements, see Overview in Management's Discussion and Analysis of Financial
Condition and Results of Operations under Item 7 and Note 3 to our Financial
Statements under Item 8.
Ameren Corporation
Ameren is a public utility holding company registered with the Securities
and Exchange Commission (SEC) under the Public Utility Holding Company Act of
1935 (PUHCA), as amended, and is also headquartered in St. Louis, Missouri.
Ameren's principal business is the generation, transmission and distribution of
electricity, and the distribution of natural gas to residential, commercial,
industrial and wholesale users in the central United States. In addition to us,
Ameren's principal subsidiaries and our affiliates are as follows:
o Union Electric Company, which operates a rate-regulated electric
generation, transmission and distribution business, and a rate-regulated
natural gas distribution business in Missouri and Illinois as AmerenUE.
AmerenUE was incorporated in Missouri in 1922 and is successor to a number
of companies, the oldest of which was organized in 1881. It is the largest
electric utility in the State of Missouri and supplies electric and gas
service in parts of central and eastern Missouri and west central Illinois
having an estimated population of 2.6 million within an area of
approximately 24,500 square miles, including the greater St. Louis area.
AmerenUE supplies electric service to approximately 1.2 million customers
and natural gas service to approximately 130,000 customers.
o AmerenCIPS, which operates a rate-regulated electric and natural gas
transmission and distribution business in Illinois. AmerenCIPS was
incorporated in Illinois in 1902. It supplies electric and gas utility
service to portions of central and southern Illinois having an estimated
population of 820,000 within an area of
1
approximately 20,000 square miles. AmerenCIPS supplies electric service to
approximately 325,000 customers and natural gas service to approximately
170,000 customers.
o Central Illinois Light Company, a subsidiary of CILCORP, Inc. (CILCORP),
which operates a rate-regulated transmission and distribution business, an
electric generation business, and a rate-regulated natural gas distribution
business in Illinois as AmerenCILCO. AmerenCILCO was incorporated in
Illinois in 1913. It supplies electric and gas utility service to portions
of central and east central Illinois in an area of approximately 3,700 and
4,500 square miles, respectively. AmerenCILCO supplies electric service to
about 200,000 customers and natural gas service to about 205,000 customers.
See CILCORP Acquisition below for further information.
o AmerenEnergy Resources Company (Resources Company), which consists of non
rate-regulated operations. Subsidiaries include us, AmerenEnergy Marketing
Company (Marketing Company), which markets power for periods over one year,
Fuels Company, which procures fuel and manages the related risks for us and
our affiliates, AmerenEnergy Development Company (Development Company),
which, as our parent, develops and constructs generating facilities for us,
and AmerenEnergy Medina Valley Cogen (No. 4), LLC, which indirectly owns a
40 megawatt, gas-fired electric generation plant. On February 4, 2003,
Ameren completed its acquisition of AES Medina Valley Cogen (No. 4), LLC
(Medina Valley) from AES and renamed it AmerenEnergy Medina Valley Cogen
(No. 4), LLC. See CILCORP Acquisition below for further information.
o AmerenEnergy which serves as a power marketing and risk management agent
for us and our affiliates for transactions of primarily less than one year.
o Electric Energy, Inc. (EEI), which operates electric generation and
transmission facilities in Illinois. Ameren has a 60% ownership interest in
EEI, 40% owned by AmerenUE and 20% owned by Resources.
o Ameren Services Company (Ameren Services), which provides shared support
services to us and our affiliates.
For additional information regarding Ameren's acquisition of CILCORP and
Medina Valley, see Recent Developments in Management's Discussion and Analysis
of Financial Condition and Results of Operations under Item 7 and Notes 1 and 12
to our Financial Statements under Item 8.
For the year 2002, 99% (2001 - 98%; 2000 - 99%) of our operating revenues
were derived from the sale of electric energy and 0.1% (2001 - 0.2%; 2000 -
0.1%) came from other sources.
We employed approximately 700 employees at December 31, 2002. For
information on a voluntary retirement program offered in December 2002 and on
labor agreements and other labor matters, see Results of Operation and Outlook
in Management's Discussion and Analysis of Financial Condition and Results of
Operations under Item 7 and Notes 7 and 10 to our Financial Statements under
Item 8.
CILCORP Acquisition
On January 31, 2003, after receipt of the necessary regulatory agency
approvals and clearance from the Department of Justice under the
Hart-Scott-Rodino Antitrust Improvements Act, Ameren completed its acquisition
of all of the outstanding common stock of CILCORP from AES. CILCORP is the
parent company of Peoria, Illinois-based Central Illinois Light Company, which
operated as CILCO. With the acquisition, CILCO became an Ameren subsidiary, but
remains a separate utility company, operating as AmerenCILCO. On February 4,
2003, Ameren also completed its acquisition of Medina Valley, which indirectly
owns a 40 megawatt, gas-fired electric cogeneration plant. With the acquisition,
Medina Valley became a wholly-owned subsidiary of Resources Company and was
renamed as AmerenEnergy Medina Valley Cogen (No. 4), LLC. The CILCORP and
AmerenEnergy Medina Valley Cogen (No. 4), LLC financial statements will be
included in Ameren's consolidated financial statements effective with the
January and February 2003 acquisition dates.
Ameren acquired CILCORP to complement its existing Illinois electric and
gas operations. The purchase included CILCO's rate-regulated electric and
natural gas businesses in Illinois serving approximately 200,000 and 205,000
customers, respectively, of which approximately 150,000 are combination electric
and gas customers. CILCO's service territory is contiguous to Ameren's service
territory and accessible by our electric generation facilities. CILCO also has a
non rate-regulated electric and gas marketing business principally focused in
the Chicago, Illinois region. Finally, the purchase includes approximately 1,200
megawatts of largely coal-fired generating capacity, most of which is expected
to become non rate-regulated in 2003.
The total purchase price was approximately $1.4 billion and included the
assumption of CILCORP and Medina Valley debt and preferred stock at closing of
approximately $900 million, with the balance of the purchase price of
approximately $500 million paid with cash on hand. The purchase price is subject
to certain adjustments for
2
working capital and other changes pending the finalization of CILCORP's closing
balance sheet. The cashcomponent of the purchase price came from Ameren's
issuances in September 2002 of 8.05 million common shares and in early 2003 of
6.325 million common shares.
For additional information regarding our business operations, see
Management's Discussion and Analysis of Financial Condition and Results of
Operations under Item 7 and Note 1 to our Financial Statements under Item 8.
CAPITAL PROGRAM AND FINANCING
For information on our capital program and financial needs, see Liquidity
and Capital Resources in Management's Discussion and Analysis of Financial
Condition and Results of Operations under Item 7 and Notes 3, 6 and 10 to our
Financial Statements under Item 8.
REGULATION
General Regulatory Matters
As a holding company registered with the SEC under the PUHCA, Ameren is
subject to the regulatory provisions of the PUHCA, including provisions relating
to the issuance of securities, sales and acquisitions of securities and utility
assets, affiliate transactions, financial reporting requirements, the services
performed by Ameren Services and Fuels Company, and the activities of certain
other subsidiaries. Issuance of short-term and long-term debt and other
securities by Ameren and issuance of debt having a maturity of twelve months or
less by AmerenCIPS, AmerenUE and AmerenCILCO are subject to approval by the SEC
under the PUHCA.
We are certified by the Federal Energy Regulatory Commission (FERC) as an
"exempt wholesale generator" under the Energy Policy Act of 1992 and as a result
are not a "public utility company" under the PUHCA. As an exempt wholesale
generator, we are exempt from most of the provisions of the PUHCA that otherwise
would apply to us as a subsidiary of a registered holding company. Issuance of
securities by us is not subject to approval by the SEC under the PUHCA. The SEC
has no jurisdiction over the sale of electricity by us to affiliates or
non-affiliates. The SEC may impose limitations on Ameren in connection with its
financing for the purpose of investing in exempt wholesale generators and
foreign utility companies if Ameren's aggregate investment in those activities
exceeds 50% of its consolidated retained earnings. At December 31, 2002,
Ameren's aggregate investment in those entities was 23.7% of its consolidated
retained earnings.
We are not subject to regulation by the Illinois Commerce Commission (ICC)
or the Missouri Public Service Commission (MoPSC).
We are also subject to regulation by the FERC as to rates and charges in
connection with the wholesale sale of energy and transmission in interstate
commerce, mergers, affiliate transactions, and certain other matters. Issuance
of short-term and long-term debt by us is subject to approval by the FERC. We
currently have authority from the FERC to issue at any time prior to June 22,
2004 up to $225 million of long-term debt and to have up to $300 million of
short-term debt outstanding in the aggregate at any time.
In many states, including Illinois, companies that sell electricity
directly to retail customers pursuant to state statutes and regulations must be
registered or licensed. Marketing Company has obtained "alternative retail
electricity supplier" status in Illinois and plans to seek comparable status in
other states where retail competition is developing. AmerenCILCO is an Illinois
electric utility, and as such, is permitted to provide power and energy on a
competitive basis to retail customers located outside its service territory.
For additional discussion of regulatory matters, see Regulatory Matters in
Management's Discussion and Analysis of Financial Condition and Results of
Operations under Item 7 and Notes 2 and 10 to our Financial Statements under
Item 8.
Environmental Matters.
Certain of our operations are subject to federal, state and local
environmental regulations relating to the safety and health of personnel, the
public and the environment, including the identification, generation, storage,
handling, transportation, disposal, record keeping, labeling, reporting of and
emergency response in connection with
3
hazardous and toxic materials, safety and health standards, and environmental
protection requirements, includingstandards and limitations relating to the
discharge of air and water pollutants. Failure to comply with those statutes or
regulations could have material adverse effects on us, including the imposition
of criminal or civil liability by regulatory agencies or civil fines and
liability to private parties, and the required expenditure of funds to bring us
into compliance. We believe we are in material compliance with existing
regulations.
For additional discussion of environmental matters, see Liquidity and
Capital Resources in Management's Discussion and Analysis of Financial Condition
and Results of Operations under Item 7 and Note 7 to our Financial Statements
under Item 8.
FUEL SUPPLY FOR ELECTRIC GENERATING FACILITIES
Cost of Fuels Year
-----------------------------------------------------------------
2002 2001 2000 1999 1998
----------- ----------- ---------- ------------ ------------
AmerenEnergy Generating Company/AmerenCIPS(a)
Per Million BTU - Coal 125.456 121.791 123.770 139.700 152.738
- Natural Gas (b) 396.150 439.744 - - -
- Average - all fuels (c) 145.220 142.120 129.169 140.615 155.045
(a) On May 1, 2000, all of AmerenCIPS' electric generating facilities and
related fuel supply agreements were transferred to us (see General section
above).
(b) Prior to 2001, the use of natural gas was minimal. The fuel cost for
natural gas in 2002 and 2001 represents the actual cost of natural gas and
variable costs for transportation, storage, balancing and fuel losses for
delivery to the plant. In addition, the fixed costs for firm transportation
and firm storage capacity are included to calculate a "fully-loaded" fuel
cost for the generating facilities.
(c) Represents all fuels utilized in our electric generating facilities,
including coal, natural gas, oil, and handling.
Coal
We have a policy of maintaining coal inventory consistent with our
historical usage. We may adjust levels based on uncertainties of supply due to
potential work stoppages, delays in coal deliveries, equipment breakdowns and
other factors. As of December 31, 2002 and 2001, approximately 46 days and 63
days, respectively, supply of coal was in inventory. For the year ended December
31, 2002, coal represented approximately 88% of our fuel supply.
Natural Gas
The combustion turbine generator equipment (CTs), which we placed into
commercial operation in 2002, 2001 and 2000 are fueled by natural gas or have
the capability to use natural gas or oil. We use natural gas to supply our
generating facilities principally during peak generating periods. Our natural
gas procurement strategy is designed to ensure reliable and immediate delivery
of natural gas by optimizing transportation, storage, and balancing options and
minimizing cost and price risk by structuring various supply agreements to
maintain access to multiple gas pools and supply basins and reducing the impact
of price volatility. For the year ended December 31, 2002, natural gas
represented approximately 8% of our fuel supply. For additional information on
CTs and related fuel matters, see Liquidity and Capital Resources and
Quantitative and Qualitative Disclosures About Market Risk in Management's
Discussion and Analysis of Financial Condition and Results of Operations under
Item 7 and Note 10 to our Financial Statements under Item 8.
Oil
The actual and prospective use of oil is minimal, and we have not
experienced and do not expect to experience difficulty in obtaining adequate
supplies. For the year ended December 31, 2002, oil represented approximately 4%
of our fuel supply.
For additional information on our fuel supply, see Results of Operations,
Liquidity and Capital Resources, and Quantitative and Qualitative Disclosures
About Market Risk in Management's Discussion and Analysis of Financial Condition
and Results of Operations under Item 7 and Notes 1, 4, and 10 to our Financial
Statements under Item 8.
4
INDUSTRY ISSUES
We are facing issues common to the electric generating industry. These
issues include:
o the potential for more intense competition;
o the potential for changes in the structure of regulation;
o changes in the structure of the industry as a result of changes in
federal and state laws, including the formation of unregulated
generating entities and regional transmission organizations;
o weak power prices due to overbuilt capacity and a weak economy;
o numerous troubled companies within the energy sector and their impact
on energy marketing and access to the capital markets;
o on-going consideration of additional changes of the industry by
federal and state authorities;
o continually developing environmental laws, regulations and issues,
including proposed new air quality standards;
o public concern about the siting of new facilities;
o proposals for demand-side management programs; and
o global climate issues.
We are monitoring these issues and are unable to predict at this time what
impact, if any, these issues will have on our operations, financial condition or
liquidity. For additional information, see Outlook and Regulatory Matters in
Management's Discussion and Analysis of Financial Condition and Results of
Operations under Item 7 and Notes 2 and 10 to our Financial Statements under
Item 8.
AVAILABLE INFORMATION
We make available free of charge through Ameren's Internet website
(http://www.ameren.com) our annual report on Form 10-K, quarterly reports on
Form 10-Q, current reports on Form 8-K, and any amendments to those reports
filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange
Act of 1934 as soon as reasonably practicable after we electronically file such
material with, or furnish it to, the SEC. This information, for our affiliates,
Ameren, AmerenUE, AmerenCIPS, CILCORP, and AmerenCILCO is also available through
Ameren's Internet website.
We also make available free of charge through Ameren's Internet website the
code of business conduct for directors, officers and employees of Ameren and its
subsidiaries, including us, referred to as Ameren's Corporate Compliance Policy.
This document is also available in print upon written request to Secretary, P.O.
Box 66149, St. Louis, Missouri 63166-6149.
5
ITEM 2. PROPERTIES.
For information on our principal properties and planned transfers, see the
generating facilities table below, Liquidity and Capital Resources and
Regulatory Matters in Management's Discussion and Analysis of Financial
Condition and Results of Operations under Item 7 and Notes 2 and 10 to our
Financial Statements under Item 8. Our plans for managing the size and
composition of our generating asset portfolio are subject to market conditions,
regulatory factors, our results of operations, cash flows and financial
condition, availability of financing and other factors.
Our generating facilities are located in Illinois and Missouri within MAIN
(Mid-America Interconnected Network), which is one of the ten regional electric
reliability councils organized for coordinating the planning and operation of
the nation's bulk power supply. MAIN operates primarily in Wisconsin, Michigan,
Illinois and Missouri.
Our bulk power system is operated as an Ameren-wide control area and
transmission system under the FERC-approved amended joint dispatch agreement
between us and our Missouri-based affiliate, AmerenUE. The amended joint
dispatch agreement provides a basis upon which we and AmerenUE can participate
in the coordinated operation of AmerenUE's and AmerenCIPS' transmission
facilities with AmerenUE's and our generating facilities in order to achieve
economies consistent with the provision of reliable electric service and an
equitable sharing of the benefits and costs of that coordinated operation. In
2002, Ameren had more than 30 interconnections for transmission service and the
exchange of electric energy, directly and through the facilities of others. The
output of our generating facilities is sold by our affiliates, Marketing Company
and AmerenEnergy, which access Ameren's extensive transmission network pursuant
to FERC open access transmission tariffs. AmerenCILCO is currently expected to
continue to operate as a separate control area. As such, its generating plants
will not be jointly dispatched with the generating plants owned by AmerenUE and
us. AmerenCILCO is a transmission owning member of the Midwest Independent
System Operating (Midwest ISO) and has transferred functional control of its
system to the Midwest ISO. Transmission service on the AmerenCILCO transmission
system is provided pursuant to the terms of the Midwest ISO open access
transmission tariff on file with the FERC. For information on AmerenCIPS' and
AmerenUE's participation in the Midwest ISO and how we may be potentially
impacted, see Note 2 to our Financial Statements under Item 8.
6
The following table sets forth information with respect to our generating
facilities and capability at the time of our expected 2003 peak summer
electrical demand:
Our Generating Facilities
-------------------------
Primary
Fuel Name of Net Kilowatt Net Heat
Source Plant Location Capability(a) Rate(i)
- ------ ------- -------- ------------- --------
Coal Newton(d) Newton, IL 1,134,000 10,403
Coffeen(d) Coffeen, IL 900,000 10,368
Hutsonville(d)
(Units 3 & 4) Hutsonville, IL 153,000 10,371
Meredosia(d)
(Unit 3) Meredosia, IL 215,000 11,063
---------
Total Coal 2,402,000
Oil Meredosia(d)
(Unit 4) Meredosia, IL 186,000 11,186
Hutsonville(d)
(Diesel) Hutsonville, IL 3,000 11,408
---------
Total Oil 189,000
Natural Gibson City CTs 1 & 2(c) Gibson City, IL 234,000 11,490
Gas(b) Pinckneyville CTs
1 through 8 Pinckneyville, IL 320,000 10,921
Kinmundy CTs 1 & 2(c) Kinmundy, IL 232,000 11,488
Grand Tower CTs 1 & 2(e) Grand Tower, IL 516,000 7,515
Joppa 7B CTs 1, 2 & 3(f) Joppa, IL 162,000 11,550
Elgin CTs 1 through 4 Elgin, IL 468,000 11,488
Columbia CTs
1 through 4 Columbia, MO 140,000 12,298
---------
Total Natural Gas 2,072,000
TOTAL 4,663,000(g),(h)
(a) "Net Kilowatt Capability" represents generating capacity available for
dispatch from the facility into the electric transmission grid.
(b) The abbreviation "CT" represents combustion turbine generating unit.
(c) CT has the capability of operating on either oil or natural gas (dual
fuel).
(d) Facilities were transferred to us by AmerenCIPS on May 1, 2000 (see Item 1.
Business - General above).
(e) The Grand Tower Plant, which was a coal plant transferred to us by
AmerenCIPS on May 1, 2000, has been repowered with two gas-fired CTs.
(f) These CTs are owned by us and leased to our parent, Development Company.
The operating lease is for a minimum term of 15 years expiring September
30, 2015. We receive rental payments under the lease in fixed monthly
amounts that vary over the term of the lease and range from $0.8 - $1.0
million.
(g) Excludes approximately 126 megawatts of two coal-fired generating units at
our Meredosia facility which were mothballed in December 2002.
(h) Approximately 550 megawatts of generating capacity (Pinckneyville CTs 1
through 8 and Kinmundy CTs 1 and 2) are expected to be sold by us to
AmerenUE subject to receipt of necessary regulatory approvals.
(i) "Net Heat Rate" represents the amount of energy to produce a given unit of
output and is expressed as BTU per kilowatthour.
As identified in the above table, on May 1, 2000, AmerenCIPS transferred
all of its generating facilities and related assets to us. As a part of this
transfer, AmerenCIPS' generating property and plant were released from the lien
of the indenture securing its first mortgage bonds and such property and plant
are presently unencumbered. For
7
additional information on this asset transfer, see General section under Item 1.
None of our properties are subject to any mortgage or other encumbrance in favor
of our outstanding indebtedness.
ITEM 3. LEGAL PROCEEDINGS.
We are involved in legal and administrative proceedings before various
courts and agencies with respect to matters arising in the ordinary course of
business, some of which involve substantial amounts. We believe that the final
disposition of these proceedings, except as otherwise noted in this report, will
not have a material adverse effect on our financial position, results of
operations or liquidity.
For additional information on legal and administrative proceedings, see
Regulation under Item 1, Liquidity and Capital Resources and Regulatory Matters
in Management's Discussion and Analysis of Financial Condition and Results of
Operations under Item 7 and Notes 2, 10 and 12 to our Financial Statements under
Item 8.
FORWARD-LOOKING STATEMENTS
Statements made in this report which are not based on historical facts are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
"forward-looking" statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions and
financial performance. In connection with the "safe harbor" provisions of the
Private Securities Litigation Reform Act of 1995, we are providing this
cautionary statement to identify important factors that could cause actual
results to differ materially from those anticipated. The following factors, in
addition to those discussed elsewhere in this report and in subsequent
securities filings, could cause results to differ materially from management
expectations as suggested by such "forward-looking" statements:
o the effects of regulatory actions, including changes in regulatory policy;
o changes in laws and other governmental actions, including monetary and
fiscal policies;
o the impact on us of current regulations related to the opportunity for
customers to choose alternative energy suppliers in Illinois;
o the effects of increased competition in the future;
o the effects of Ameren's participation in a FERC-approved Regional
Transmission Organization, including activities associated with the Midwest
Independent System Operator;
o availability and future market prices for fuel and purchased power and
electricity, including the use of financial and derivative instruments and
volatility of changes in market prices;
o the cost of commodities, such as natural gas, used in the production of
electricity and our ability to recover such increased costs;
o wholesale and retail pricing for electricity in the Midwest;
o business and economic conditions;
o the impact of the adoption of new accounting standards on the application
of appropriate technical accounting rules and guidance;
o interest rates and the availability of capital;
o actions of rating agencies and the effects of such actions;
o weather conditions;
o generation plant construction, installation and performance;
o the effects of strategic initiatives, including acquisitions and
divestitures;
o the impact of current environmental regulations on generating companies and
the expectation that more stringent requirements will be introduced over
time, which could potentially have a negative financial effect;
o future wages and employee benefit costs including changes in returns of
benefit plan assets;
o disruptions of the capital markets or other events making Ameren's or our
access to necessary capital more difficult or costly;
o competition from other generating facilities, including new facilities that
may be developed in the future;
o cost and availability of transmission capacity for the energy generated by
our generating facilities or required to satisfy energy sales made on our
behalf; and
o legal and administrative proceedings.
8
Given these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
This item is omitted in reliance on General Instruction (I)(2) of Form
10-K.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
There is no established trading market for our common stock. As of March
31, 2003, our parent, Development Company, was the only shareholder of record of
our common stock.
ITEM 6. SELECTED FINANCIAL DATA.
The historical operating data presented below reflects our operations since
inception on May 1, 2000. The historical financial data presented below is
derived from our audited financial statements included elsewhere in this report.
================================================================================
For the Years Ended
December 31 (in millions) 2002(a) 2001(a) 2000(b)
- --------------------------------------------------------------------------------
Operating revenues $ 743 $ 730 $ 480
Operating income 139 195 103
Net income 32 76 44
As of December 31,
Total assets $2,010 $1,756 $1,394
Long-term debt 698 424 424
Subordinated intercompany notes 462 508 602
Total common stockholder's equity 280 274 44
================================================================================
(a) Revenues were netted with costs upon adoption of EITF 02-3 and the
rescission of EITF 98-10. See Note 1 - Summary of Significant Accounting
Policies to our Financial Statements under Item 8 for further information.
The amount netted was as follows: 2002 - $253 million (2001 - $256
million).
(b) On May 1, 2000, AmerenCIPS transferred its electric generating assets and
related liabilities, at net book value, to us, in exchange for a
subordinated promissory note from us in the principal amount of $552
million and 1,000 shares of our common stock.
9
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
OVERVIEW
AmerenEnergy Generating Company, headquartered in St. Louis, Missouri, is
an indirect wholly-owned subsidiary of Ameren Corporation (Ameren). We own and
operate a wholesale electric generation business in Illinois and Missouri. Much
of our business was formerly owned and operated by our affiliate, Central
Illinois Public Service Company, which operates as AmerenCIPS. We were
incorporated in the State of Illinois in March 2000. On May 1, 2000, we acquired
from AmerenCIPS at net book value five coal-fired electric generating stations,
which we refer to as the coal plants, all related fuel, supply, transportation,
maintenance and labor agreements, approximately 45% of AmerenCIPS' employees,
and other related rights, assets and liabilities.
Ameren is a public utility holding company registered with the Securities
and Exchange Commission (SEC) under the Public Utility Holding Company Act of
1935 (PUHCA), as amended, and is also headquartered in St. Louis, Missouri.
Ameren's principal business is the generation, transmission and distribution of
electricity, and the distribution of natural gas to residential, commercial,
industrial and wholesale users in the central United States. Ameren's principal
subsidiaries and our affiliates are as follows:
o Union Electric Company, which operates a rate-regulated electric
generation, transmission and distribution business, and a rate-regulated
natural gas distribution business in Missouri and Illinois as AmerenUE.
o AmerenCIPS, which operates a rate-regulated electric and natural gas
transmission and distribution business in Illinois.
o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP)
which operates a rate-regulated transmission and distribution business, an
electric generation business, and a rate-regulated natural gas distribution
business in Illinois as AmerenCILCO. Ameren completed its acquisition of
CILCORP on January 31, 2003 from The AES Corporation (AES). See Recent
Developments for further information.
o AmerenEnergy Resources Company (Resources Company), which consists of non
rate-regulated operations. Subsidiaries include us, AmerenEnergy Marketing
Company (Marketing Company), which markets power for periods over one year,
AmerenEnergy Fuels and Services Company (Fuels Company), which procures
fuel and manages the related risks for us and our affiliates, AmerenEnergy
Development Company (Development Company), which, as our parent, develops
and constructs generating facilities for us, and AmerenEnergy Medina Valley
Cogen (No. 4), LLC, which indirectly owns a 40 megawatt, gas-fired electric
generation plant. On February 4, 2003, Ameren completed its acquisition of
AES Medina Valley Cogen (No. 4), LLC (Medina Valley) from AES and renamed
it AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Recent Developments
for further information.
o AmerenEnergy, Inc. (AmerenEnergy) which serves as a power marketing and
risk management agent for us and our affiliates for transactions of
primarily less than one year.
o Electric Energy, Inc. (EEI), which operates electric generation and
transmission facilities in Illinois. Ameren has a 60% ownership interest in
EEI, 40% owned by AmerenUE and 20% owned by Resources.
o Ameren Services Company (Ameren Services), which provides shared support
services to us and our affiliates.
When we refer to our, we, us or Generating Company, we are referring to
AmerenEnergy Generating Company and in some cases our agents, AmerenEnergy and
Fuels Company. All tabular dollar amounts are in millions, unless otherwise
indicated.
We have an agreement to supply all of our power to Marketing Company
(Generating Company - Marketing Company agreement). Marketing Company then
provides all the power required for AmerenCIPS' native load requirements
(Marketing Company - AmerenCIPS agreement) and to serve its obligations under
various long-term wholesale and retail contracts. The agreement with Marketing
Company and Marketing Company's agreement with AmerenCIPS expire on December 31,
2004, but Marketing Company and AmerenCIPS plan to seek the necessary regulatory
approvals to extend these agreements to January 1, 2007. If we have any power in
excess of Marketing Company's needs, then AmerenEnergy sells it on our behalf to
the extent it is economical. See Illinois Electric in Note 2 - Rate and
Regulatory Matters and Note 3 - Related Party Transactions to our Financial
Statements under Item 8 for additional information.
We jointly dispatch generation with our affiliate, AmerenUE. This joint
dispatch agreement requires each company to serve its load requirements from its
own least-cost generation first, but then allows access to any available excess
generation from the other company at cost. All of our sales to Marketing Company
are considered
10
load requirements. The agreement has no expiration, but either party may give a
one year notice of termination beginning January 1, 2004.
Our results of operations and financial position are impacted by many
factors, including both controllable and uncontrollable factors. Weather,
economic conditions, and the actions of key customers or competitors can
significantly impact the demand for our services. Our results are also impacted
by seasonal fluctuations caused by winter heating, and summer cooling, demand.
We principally utilize coal in 11 power generating units (approximately 2,570
megawatts) and natural gas in our 25 combustion turbine units (approximately
2,105 megawatts) that are primarily used for peaking power. The prices for these
commodities can fluctuate significantly due to the world economic and political
environment, weather, production levels and many other factors. We employ
various risk management strategies in order to try to reduce our exposure to
commodity risks and other risks inherent in our business. The reliability of our
power plants, and the level of operating and administrative costs and capital
investment are key factors that we seek to control in order to optimize our
results of operations, cash flows and financial position.
RESULTS OF OPERATIONS
Earnings Summary
Our financial statements are available only for the period since May 1,
2000. Prior to that date, all operations of the coal plants now owned by us were
fully integrated with, and therefore results of operations were consolidated
into the financial statements of AmerenCIPS, whose business was to generate,
transmit and distribute electricity and to provide other utility customer
support services.
Our net income for 2002, 2001 and the period May 1, 2000 through December
31, 2000, was $32 million, $76 million, and $44 million, respectively. Net
income in 2002 included voluntary retirement and other restructuring charges ($6
million, net of taxes), which consisted of a voluntary retirement program ($5
million, net of taxes) and the temporary suspension of operation of two
coal-fired generating units at our Meredosia, Illinois coal plant ($1 million,
net of taxes). In 2001, net income was reduced by the adoption of Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ($2 million).
The following table reconciles our net income to net income excluding
voluntary retirement and other restructuring charges and SFAS 133 adoption for
the years ending December 31, 2002 and 2001, and for the period May 1, 2000
through December 31, 2000:
================================================================================================================
- ----------------------------------------------------------------------------------------------------------------
2002 2001 2000
---- ---- ----
Net income $ 32 $ 76 $ 44
Voluntary retirement and other restructuring charges, net of taxes 6 - -
SFAS 133 adoption, net of taxes - 2 -
- ----------------------------------------------------------------------------------------------------------------
Net income excluding restructuring charges and SFAS 133 adoption $ 38 $ 78 $ 44
================================================================================================================
Excluding the charges discussed above, our net income decreased $40 million
in 2002 compared to 2001 due to a decrease in electric margin ($10 million, net
of taxes) primarily from the absence of the one year 450 megawatt power supply
agreement between Marketing Company and AmerenUE for 2001 for which we supplied
the power (2001 Marketing Company - AmerenUE agreement). The absence of this
agreement was partially offset by a new one year 200 megawatt power supply
agreement between Marketing Company and AmerenUE for 2002 for which we supplied
the power (2002 Marketing Company - AmerenUE agreement) and increases in sales
to new and existing wholesale customers. Earnings also decreased due to
increased depreciation ($10 million, net of taxes) associated with the addition
of new combustion turbine generating units during 2001 and the fourth quarter of
2002, increased costs associated with efficiency improvements made at our power
plants, higher employee wages and benefits and other general operations costs
($10 million, net of taxes). We also experienced increased interest costs ($7
million, net of taxes) associated with borrowing additional funds at higher
interest rates for previous capacity additions and for general corporate
purposes.
Our net income increased $34 million in 2001 compared to the period from
May 1, 2000 through December 31, 2000 primarily due to comparing a twelve month
operating period for 2001 to the eight month operating period for 2000, as well
as higher average period sales volumes in 2001 versus 2000. In addition, the
increased interest costs were due to borrowing funds to support our 2001
capacity additions.
11
Recent Developments
CILCORP Acquisition
On January 31, 2003, after receipt of the necessary regulatory agency
approvals and clearance from the Department of Justice under the
Hart-Scott-Rodino Antitrust Improvements Act, Ameren completed its acquisition
of all of the outstanding common stock of CILCORP from AES. CILCORP is the
parent company of Peoria, Illinois-based Central Illinois Light Company, which
operated as CILCO. With the acquisition, CILCO became an Ameren subsidiary, but
remains a separate utility company, operating as AmerenCILCO. On February 4,
2003, Ameren also completed its acquisition of Medina Valley which indirectly
owns a 40 megawatt, gas-fired electric cogeneration plant. With the acquisition,
Medina Valley became a wholly-owned subsidiary of Resources Company and was
renamed as AmerenEnergy Medina Valley Cogen (No. 4), LLC. The CILCORP and
AmerenEnergy Medina Valley Cogen (No. 4), LLC financial statements will be
included in Ameren's consolidated financial statements effective with the
January and February 2003 acquisition dates.
Ameren acquired CILCORP to complement its existing Illinois electric and
gas operations. The purchase included CILCO's rate-regulated electric and
natural gas businesses in Illinois serving approximately 200,000 and 205,000
customers, respectively, of which approximately 150,000 are combination electric
and gas customers. CILCO's service territory is contiguous to Ameren's service
territory and accessible by our electric generation facilities. CILCO also has a
non rate-regulated electric and gas marketing business principally focused in
the Chicago, Illinois region. Finally, the purchase includes approximately 1,200
megawatts of largely coal-fired generating capacity, most of which is expected
to become non rate-regulated in 2003.
The total purchase price was approximately $1.4 billion and included the
assumption of CILCORP and Medina Valley debt and preferred stock at closing of
approximately $900 million, with the balance of the purchase price of
approximately $500 million paid with cash on hand. The purchase price is subject
to certain adjustments for working capital and other changes pending the
finalization of CILCORP's closing balance sheet. The cash component of the
purchase price came from Ameren's issuances in September 2002 of 8.05 million
common shares and in early 2003 of 6.325 million common shares.
Credit Ratings
In April 2002, as a result of AmerenUE's then pending Missouri electric
earnings complaint case and the CILCORP transaction and related assumption of
debt, credit rating agencies placed Ameren's and its subsidiaries' debt under
review. Following the completion of the acquisition of CILCORP in January 2003,
Standard & Poor's lowered the ratings of Ameren, AmerenUE and AmerenCIPS and
increased our ratings. At the same time, Standard & Poor's changed the outlook
assigned to all of Ameren's ratings to stable. Moody's also lowered Ameren's and
AmerenUE's ratings subsequent to the acquisition and changed the outlook on
these ratings to stable. These actions were consistent with the actions the
rating agencies disclosed they were considering following the announcement of
the CILCORP acquisition.
12
As of February 2003, the ratings by Moody's and Standard & Poor's were as
follows:
================================================================================
Moody's Standard & Poor's
- --------------------------------------------------------------------------------
Ameren Corporation:
Issuer/Corporate credit rating A3 A-
Unsecured debt A3 BBB+
Commercial paper P-2 A-2
AmerenUE:
Secured debt A1 A-
Unsecured debt A2 BBB+
Commercial paper P-1 A-2
AmerenCIPS:
Secured debt A1 A-
Unsecured debt A2 BBB+
AmerenEnergy Generating Company:
Senior Notes - due 2005 A3 A-
Senior Notes - due 2010 and 2032 Baa2 A-
================================================================================
Standard & Poor's increased the ratings of CILCORP and CILCO subsequent to
the acquisition of these entities by Ameren. As of February 2003, the unsecured
debt ratings of CILCORP were BBB+ and Baa2 from Standard & Poor's and Moody's,
respectively. The secured debt ratings of AmerenCILCO were A- and A2 from
Standard & Poor's and Moody's, respectively. Standard & Poor's assigned stable
outlooks to the ratings. Moody's also assigned a stable outlook to the ratings
for CILCORP and AmerenCILCO.
Any adverse change in our or Ameren's ratings may reduce our access to
capital and/or increase the costs of borrowings resulting in a negative impact
on earnings. A credit rating is not a recommendation to buy, sell or hold
securities and should be evaluated independently of any other rating. Ratings
are subject to revision or withdrawal at any time by the assigning rating
organization.
Electric Operations
The following table represents the favorable (unfavorable) impact on
electric margin versus the prior periods for the years ended December 31, 2002
and 2001:
================================================================================
2002 2001(a)
- --------------------------------------------------------------------------------
Electric Revenues:
Wholesale revenues $ 5 $ 283
Interchange revenues 8 (45)
Other 3 2
- --------------------------------------------------------------------------------
Total variation in electric operating revenues 16 240
- --------------------------------------------------------------------------------
Fuel and Purchased Power:
Fuel:
Generation (52) (47)
Price (4) (14)
Generation efficiencies and other 5 (3)
Purchased power 18 (6)
- --------------------------------------------------------------------------------
Total variation in fuel and purchased power (33) (70)
- --------------------------------------------------------------------------------
Change in electric margin $ (17) $ 170
================================================================================
(a) This column represents the comparison between the year ended December 31,
2001 and the period May 1, 2000 through December 31, 2000.
Electric margins decreased $17 million for the year ended December 31, 2002
compared to 2001. Decreases in electric margin in 2002 were primarily due to
lower power prices and the reduction of indirect sales to our affiliate,
AmerenUE, under the 2001 and 2002 Marketing Co - AmerenUE agreements, partially
offset by increases in other wholesale and interchange revenues and increases in
use of lower cost generation due to better availability. Revenues increased in
2002 due to an increase in the volume of interchange sales for the year,
although these sales provided lower margins due to lower electricity prices. In
addition, a net increase in new wholesale customers
13
added by Marketing Company and an increase in sales to existing wholesale
customers due to warmer weather increased revenues. Fuel increased in 2002 due
primarily to increased use of lower cost generation stations due to fewer forced
and maintenance outages at our coal plants. Reduced purchased power costs were
due to lower energy prices. We expect power prices in the energy markets to
remain generally soft, which will impact the margins we can generate by
marketing our power into the interchange markets.
During 2002, we adopted the provisions of Emerging Issues Task Force (EITF)
Issue 02-3, "Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and Contracts Involved in Energy Trading and Risk Management
Activities," that required revenues and costs associated with certain energy
contracts to be shown on a net basis in the income statement. Prior to adopting
EITF 02-3 and the rescission of EITF Issue No. 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities," our accounting
practice was to present all settled energy purchase or sale contracts within our
power risk management program on a gross basis in Operating Revenues - Electric
and in Operating Expenses - Fuel and Purchased Power. This meant that revenues
were recorded for the notional amount of the power sale contracts with a
corresponding charge to income for the costs of the energy that was generated,
or for the notional amount of a purchased power contract. Upon adoption, EITF
02-3 requires that prior periods also be netted to conform to the current year
presentation. Adoption of this EITF 02-3 did not have any impact on operating or
net income for any period or stockholder's equity. The operating revenues and
costs netted for the year ended December 31, 2002 were $253 million (2001 - $256
million), which reduced interchange revenues and purchased power costs by equal
amounts. SFAS 133 was adopted on January 1, 2001 and therefore, no netting was
required for the year ended December 31, 2000.
Electric margins increased $170 million for the year ended December 31,
2001 compared to the period May 1, 2000 through December 31, 2000 primarily due
to the longer operating period, as well as higher average sales volumes in 2001
versus 2000 associated with sales through Marketing Company, the 2001 Marketing
Company - AmerenUE agreement, and through AmerenEnergy. Electric revenues from
AmerenEnergy's marketing efforts increased $211 million or 201% for the year
2001 compared to the eight month period in the prior year as kilowatthours sold
increased 228%.
Other Operating Expenses
Other Operations and Maintenance
Other operations and maintenance expenses increased $17 million in 2002
compared to 2001, primarily due to higher employee benefit costs related to
increasing healthcare costs and the investment performance of employee benefit
plans' assets ($4 million), higher wages, higher injuries and damages expenses
based on claims experience ($4 million), incremental increases associated with
the combustion turbine generating units added during 2001, costs for efficiency
improvements made at the coal plants and timing of plant outages between years.
See also "Equity Price Risk" below for a discussion of our expectations and
plans regarding trends in employee benefit costs. Other operations and
maintenance expenses increased $57 million in 2001 compared to the period May 1,
2000 through December 31, 2000 primarily due to the longer operating period ($43
million) as well as due to higher employee benefit costs in 2001 ($3 million),
resulting from increasing healthcare costs, and the investment performance of
employee benefit plans' assets and increased operating costs associated with the
combustion turbine generating units added in 2001.
Ameren Services and AmerenEnergy provided services to us, including wages,
employee benefits and professional services that were included in other
operations and maintenance expenses. See Note 3 - Related Party Transactions to
our Financial Statements under Item 8 for further information.
Restructuring Charges
Voluntary retirement and other restructuring charges of $10 million in 2002
consisted primarily of a charge related to Ameren's voluntary retirement program
of $8 million based on voluntary retirements of approximately 35 of our
employees and additional employees providing support functions to us through
Ameren Services. These costs consisted primarily of special termination benefits
associated with our pension and post-retirement benefit plans. Most of the
employees who voluntarily retired will leave Ameren by March 2003. In addition,
in December 2002, we announced plans to temporarily suspend operations of two
coal-fired generating units (126 megawatts) at our Meredosia, Illinois plant,
which resulted in a total charge of approximately $2 million. See Note 7 -
Voluntary Retirement and Other Restructuring Charges to our Financial Statements
under Item 8 for further information.
14
Depreciation and Amortization
Depreciation and amortization expense increased $16 million in 2002
compared to 2001 and $25 million in 2001 compared to the period May 1, 2000
through December 31, 2000. These net increases were primarily due to our
investment in combustion turbine generating units and coal-fired power plants in
2001 and 2002 in addition to the longer operating period in 2001 compared to
2000.
Other Taxes
Other taxes expense in 2002 decreased $7 million compared to 2001,
primarily due to reduced property tax assessments partially offset by increased
property taxes in 2002 associated with the combustion turbine generating units
added in the prior year. Other taxes expense in 2001 increased $6 million
compared to the period May 1, 2000 through December 31, 2000, primarily due to
the longer operating period.
Interest
Interest expense increased $11 million in 2002 compared to 2001, primarily
due to our issuance of $275 million of 7.95% Senior Notes in June 2002 and
additional borrowings, prior to the issuance of the Senior Notes, from Ameren's
non-utility money pool at higher interest rates, compared to the prior year.
These increases were partially offset by a reduction in the principal amounts
outstanding on our subordinated intercompany promissory notes to AmerenCIPS and
Ameren, therefore reducing associated interest costs in the current year
compared to the prior year. Proceeds from the Senior Notes offering were used to
repay lower cost short-term borrowings and for general corporate purposes.
Interest expense increased $40 million in 2001, compared to the period May 1,
2000 through December 31, 2000, primarily due to the longer operating period, as
well as our issuance of $425 million of Senior Notes in November 2000. See Note
6 - Long-Term Debt and Intercompany Notes Payable to our Financial Statements
under Item 8 for further discussion of our Senior Notes.
Income Taxes
Income tax expense decreased $27 million in 2002, compared to 2001,
primarily due to lower pretax income. Income tax expense increased $20 million
in 2001, compared to the period May 1, 2000 through December 31, 2000, primarily
due to higher pretax income associated with the longer operating period.
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our net cash flows provided by operating activities totaled $111 million
for 2002, compared to $130 million for 2001, and $98 million for the period from
May 1, 2000 through December 31, 2000. Cash provided from operations decreased
$19 million in 2002, primarily due to increased funds used in accounts and wages
payable compared to the same year ago period due to timing of payment of funds
to and from our affiliates. These decreases were partially offset by an increase
in cash flows from accounts receivable, intercompany due to the timing of
receipt of payments to and from our affiliates. Cash flow from operations
increased in 2001 due to the longer operating period, higher average period
sales volumes in 2001 versus 2000 due to increased available generating capacity
and a change in working capital requirements.
Pension Funding
Ameren made cash contributions totaling $31 million to Ameren's defined
benefit retirement plan during 2002. Our share of the cash contribution was
approximately $4 million. At December 31, 2002, Ameren recorded a minimum
pension liability of $102 million, net of taxes, which resulted in a charge to
Accumulated Other Comprehensive Income (OCI) and a reduction to stockholder's
equity. Our share of the minimum pension liability was $6 million, net of taxes.
Based on the performance of plan assets through December 31, 2002, Ameren
expects to be required under the Employee Retirement Income Security Act of 1974
(ERISA) to fund approximately $150 million to $175 million annually, including
CILCORP, in 2005, 2006 and 2007 in order to maintain minimum funding levels for
Ameren's pension plan. In addition, Ameren estimates the pension funding for
CILCORP to be less than $1 million in 2003 and approximately $5 million in 2004.
We expect our share of the annual funding in 2005, 2006, and 2007 to be between
approximately $18 million to $21 million which includes our share related to
employees of Ameren
15
Services. These amounts are estimates and may change based on actual stock
market performance, changes in interest rates, and any pertinent changes in
government regulations. At December 31, 2002, Ameren's Net Benefit Obligation
was $1,587 million and its Fair Value of Plan Assets was $1,059 million. See
Benefit Plan Accounting under Accounting Matters - Critical Accounting Policies
below.
Investing
Our cash flows used in investing activities was $442 million in 2002
compared to $247 million in 2001 and $570 million for the period May 1, 2000
through December 31, 2000. Construction expenditures were $442 million in 2002
(2001 - $347 million; 2000 - $470 million) primarily related to construction of
combustion turbine generating units and various upgrades at our coal plants. In
2002, we placed into service approximately 470 megawatts of combustion turbine
generating capacity (approximately $215 million) at Elgin, Illinois. Also in
2002, we paid approximately $140 million to Development Company for a combustion
turbine generating unit purchased and in accounts payable at December 2001. In
addition, Selective Catalytic Reduction technology was added on units 1 and 2 of
our Coffeen coal plant at a cost of approximately $42 million. We added
approximately 850 megawatts (approximately $530 million) in 2001 and
approximately 595 megawatts (approximately $275 million) in 2000 of combustion
turbine generating capacity.
For the five-year period 2003 through 2007, construction expenditures are
estimated to approximate $200 - $230 million, of which approximately $50 million
is expected in 2003. This estimate includes capital expenditures for upgrades to
existing coal and gas fired facilities and other generation-related activities,
as well as for compliance with new NOx (nitrogen oxide) control regulations, as
discussed below. We do not have any plans at this time to purchase or construct
additional power generating units.
We intend to sell at net book value approximately 550 megawatts
(approximately $260 million) of our combustion turbine generating units located
at Pinckneyville and Kinmundy, Illinois to our regulated affiliate, AmerenUE,
which wants them to comply with AmerenUE's recent Missouri electric rate case
settlement and to meet its future regulated generating capacity needs. The
transfer is subject to receipt of necessary regulatory approvals and is expected
to be completed in 2003. Cash proceeds from the sale will be applied toward
reducing our short-term money pool borrowings and for other general operating
activities. The indenture for our Senior Notes imposes limitations on the use of
proceeds of the sale of our generating units if the net book value of the sold
assets (together with prior assets sales since November 1, 2000) exceeds 25% of
consolidated tangible assets (as defined in the indenture) as of the first day
of the most recently ended fiscal quarter prior to the date the assets are sold.
We do not expect that the sale of the Pinckneyville and Kinmundy units would
exceed the 25% amount. If the sale proceeds did exceed the limitation, they
would have to be (1) reinvested in our business within 12 months, (2) used to
repay indebtedness or (3) retained by us. This transfer is expected to reduce
operating and depreciation costs for 2003. Taking into account this sale and the
temporary suspension of Meredosia units as previously mentioned, we expect to
maintain our generation capacity at approximately 4,125 megawatts for the
foreseeable future.
We continually review our generation portfolio and expected electrical
needs and, as a result, we could modify our plan for generation asset purchases,
which could include the timing of when certain assets will be added to, or
removed from our portfolio, the type of generation asset technology that will be
employed, or whether capacity may be purchased, among other things. Any changes
that we may plan to make for future generating needs could result in significant
capital expenditures or losses being incurred, which could be material.
Environmental
We are subject to various environmental regulations by federal, state, and
local authorities. From the beginning phases of siting and development, to the
ongoing operation of existing or new electric generating facilities, our
activities involve compliance with diverse laws and regulations that address
emissions and impacts to air and water, special, protected, and cultural
resources (such as wetlands, endangered species, and archeological/historical
resources), chemical and waste handling, and noise impacts. Our activities
require complex and often lengthy processes to obtain approvals, permits, or
licenses for new, existing, or modified facilities. Additionally, the use and
handling of various chemicals or hazardous materials (including wastes) requires
preparation of release prevention plans and emergency response procedures. As
new laws or regulations are promulgated, we assess their applicability and
implement the necessary modifications to our facilities or their operations, as
required.
The U.S. Environmental Protection Agency (EPA) issued a rule in October
1998 requiring 22 Eastern states and the District of Columbia to reduce
emissions of NOx in order to reduce ozone in the Eastern United States. Among
other things, the EPA's rule establishes an ozone season, which runs from May
through September, and a NOx
16
emission budget for each state, including Illinois where most of our facilities
are located. The EPA rule requires states to implement controls sufficient to
meet their NOx budget by May 31, 2004. In addition, the Illinois EPA already has
a rule which will require additional NOx controls by the summer of 2003. We
expect to have the NOx controls in operation by the summer of 2003 to meet both
regulatory requirements.
As a result of these state requirements, we estimate spending an additional
$40 million for pollution control capital expenditures and NOx credits by 2006.
A total of $90 million was spent in 2002 and 2001. This estimate includes the
assumption that the regulations will require the installation of Selective
Catalytic Reduction technology on some of our units, as well as additional
controls.
See Note 10 - Commitments and Contingencies to our Financial Statements
under Item 8 for further discussion of environmental matters.
Financing
Our cash flows provided by financing activities totaled $332 million in
2002, $118 million in 2001 and $467 million for the period from May 1, 2000
through December 31, 2000. Our principal financing activities for the periods
included the issuance of long-term debt, additional short-term borrowings from
Ameren's non-utility money pool, and receipt of a cash contribution from Ameren
of $150 million, partially offset by redemptions of intercompany notes payable
and payment of dividends.
Notes Payable -Intercompany and Liquidity
Our gross margins from power supply contracts with affiliated companies
continue to be the principal source of cash from operating activities. We plan
to utilize short-term debt to support normal operations and other temporary
capital requirements. We have the ability to borrow up to $600 million from
Ameren through a non-utility money pool agreement. However, the total amount
available to us at any time is reduced by the amount of borrowings from Ameren
by our affiliates and is increased to the extent other Ameren non-regulated
companies advance surplus funds to the non-utility money pool or external
sources are used by Ameren to increase the available amounts. At December 31,
2002, $445 million was available through the non-utility money pool not
including additional funds available through invested cash balances at Ameren
and uncommitted bank lines. The non-utility money pool was established to
coordinate and provide for short-term cash and working capital requirements of
Ameren's non-regulated activities and is administered by Ameren Services.
Interest is calculated at varying rates of interest depending on the composition
of internal and external funds in the non-utility money pool. The average
interest rate for borrowings from the non-utility money pool was 7.60% in 2002
(2001 - 4.08%) and 6.52% for the period from May 1, 2000 through December 31,
2000. These rates are based on the cost of Ameren's funds used to fund money
pool advances. We incurred $6 million in net intercompany interest expense
associated with outstanding borrowings from the non-utility money pool in 2002
(2001 - $2 million) and $1 million for the period from May 1, 2000 through
December 31, 2000. At December 31, 2002, we had borrowings of $191 million from
the non-utility money pool.
We and Ameren rely on access to the capital markets as a significant source
of funding for capital requirements not satisfied by operating cash flows. The
inability by us to raise capital on favorable terms, particularly during times
of uncertainty in the capital markets, could negatively impact our ability to
maintain and grow our businesses. Based on our and Ameren's current credit
ratings, we believe that we will continue to have access to the capital markets.
However, events beyond our control may create uncertainty in the capital markets
such that our cost of capital would increase or our ability to access the
capital markets would be adversely affected.
17
The following table summarizes available borrowing capacity under our
committed lines of credit and credit agreements as of December 31, 2002:
Amount of commitment expiration per period:
====================================================================================================================
Total Less than 1 1 - 3 4 - 5 After 5
committed year years years years
- --------------------------------------------------------------------------------------------------------------------
Lines of credit and credit agreements:
- --------------------------------------------------------------------------------------------------------------------
Guarantees (a) $ 463 $ - $ 463 $ - $ -
Other commercial commitments (b) 600 470 130 - -
- --------------------------------------------------------------------------------------------------------------------
Total $ 1,063 $ 470 $ 593 $ - $ -
- --------------------------------------------------------------------------------------------------------------------
(a) Ameren's "aggregate investment" in Exempt Wholesale Generators (EWGs)
(such as us) and foreign utility companies is limited under PUHCA to
an amount not greater than 50% of Ameren's consolidated retained
earnings unless regulatory approval is obtained to make additional
investments. Aggregate investment includes all amounts invested, or
committed to be invested, for which there is recourse, directly or
indirectly, to the registered holding company and includes guarantees
by Ameren of our obligations. At December 31, 2002, Ameren had
capacity to increase its aggregate investment in EWGs by $463 million.
(b) Available through the non-utility money pool.
The following table summarizes our contractual obligations as of December
31, 2002:
====================================================================================================================
Less than 1 1 - 3 4 - 5 After 5
Total year years years years
- --------------------------------------------------------------------------------------------------------------------
Long-term debt $ 700 $ - $ 225 $ - $ 475
Subordinated notes payable - intercompany 462 50 412 - -
Notes payable - intercompany 191 191 - - -
Operating leases (a) 8 1 1 1 5
Other long-term obligations (b) 813 185 284 175 169
- --------------------------------------------------------------------------------------------------------------------
Total cash contractual obligations $2,173 $ 427 $ 921 $ 176 $ 649
- --------------------------------------------------------------------------------------------------------------------
(a) Amounts related to certain real estate leases have indefinite payment
periods. The amounts for these items are included in the less than 1 year,
1-3 years and 4-5 years. Amounts for after 5 years are not included in the
total amount due to the indefinite periods.
(b) Represents purchase contracts for coal and gas.
Indenture and Credit Agreement Provisions and Covenants
Ameren's and our financial agreements include customary default or cross
default provisions that could impact the continued availability of credit or
result in the acceleration of repayment. Many of Ameren's committed credit
facilities require the borrower to represent in connection with any borrowing
under the facility that no material adverse change has occurred since certain
dates. Ameren's financing arrangements do not contain credit rating triggers,
with the exception of certain ratings triggers within CILCO's financing
arrangements.
Covenants in Ameren's committed credit facilities require the maintenance
of the percentage of total debt to total capital of 60% or less for Ameren,
AmerenUE and AmerenCIPS. As of December 31, 2002, this ratio was approximately
50%, 43% and 50% for Ameren, AmerenUE, and AmerenCIPS, respectively. Ameren's
committed credit facilities also include indebtedness cross default provisions
that could trigger a default under these facilities in the event any subsidiary
of Ameren (subject to definition in the underlying credit agreements), other
than certain project finance subsidiaries, defaults on indebtedness in excess of
$50 million.
Most of Ameren's committed credit facilities include provisions related to
the funded status of Ameren's pension plan. These provisions either require
Ameren to meet minimum ERISA funding requirements or limit the unfunded
liability status of the plan. Under the most restrictive of these provisions
impacting Ameren facilities totaling $400 million, an event of default will
result if the unfunded liability status (as defined in the underlying credit
agreements) of Ameren's pension plan exceeds $300 million in the aggregate.
Based on the most recent valuation report available to Ameren at December 31,
2002, which was based on January 2002 asset and liability valuations, the
unfunded liability status (as defined) was $31 million. However, based on stock
market and interest rate performance during 2002, Ameren believes an excess
unfunded liability may occur. As a result, Ameren may need to terminate or
replace the affected facilities, renegotiate the facility provisions or fund any
unfunded liability shortfall. Should Ameren elect to terminate these facilities,
Ameren believes it would otherwise have sufficient liquidity to manage its
short-term funding requirements.
Our Senior Note indenture includes provisions that require us to maintain a
senior debt service coverage ratio of at least 1.75 to 1 (for both the prior
four fiscal quarters and for the next succeeding four, six-month periods) in
order to pay dividends, or to make payments of principal or interest under
certain subordinate indebtedness, excluding
18
amounts payable under our intercompany note payable with AmerenCIPS. For the
four quarters ended December 31, 2002, this ratio was 4.10 to 1. In addition,
the indenture also restricts us from incurring any additional indebtedness, with
the exception of certain permitted indebtedness as defined in the indenture,
unless our senior debt service coverage ratio equals at least 2.5 to 1 for the
most recently ended four fiscal quarters and our senior debt to total capital
ratio would not exceed 60%, both after giving effect to the additional
indebtedness on a pro-forma basis. This debt incurrence requirement is
disregarded in the event certain rating agencies reaffirm our ratings after
considering the additional indebtedness. As of December 31, 2002, our senior
debt to total capital ratio was 55%.
At December 31, 2002, Ameren and its subsidiaries were in compliance with
their credit agreement provisions and covenants.
Off-Balance Sheet Arrangements
At December 31, 2002, neither Ameren, nor any of its subsidiaries,
including us, had any off-balance sheet financing arrangements, other than
operating leases entered into in the ordinary course of business. We do not
expect to engage in any significant off-balance sheet financing arrangements in
the near future.
Long-Term Debt
The following table summarizes our issuances of long-term debt for the
years ended 2002, 2001 and for the period May 1, 2000 through December 31, 2000.
For additional information related to the terms and uses of these issuances and
the sources of funds and terms for redemptions, see Note 6 - Long-Term Debt and
Intercompany Notes Payable to our Financial Statements under Item 8.
================================================================================
Month
Issuances - Issued 2002 2001 2000
- --------------------------------------------------------------------------------
Long-term Debt
7.95% Series F, senior notes, due 2032 June $ 275 $ - $ -
7.75% Series C, senior notes, due 2005 November - - 225
8.35% Series D, senior notes, due 2010 November - - 200
- --------------------------------------------------------------------------------
Total long-term debt issuances $ 275 $ - $ 425
- --------------------------------------------------------------------------------
We expect to fund maturities of long-term debt and contractual obligations
through a combination of cash flow from operations and external financing.
OUTLOOK
We believe there will be challenges to earnings in 2003 and beyond due to
industry-wide trends and company-specific issues. The following are expected to
put pressure on earnings in 2003 and beyond:
o Weak economic conditions, which impacts native load demand,
o Generally soft power prices in the Midwest are expected to limit the
amount of revenues we can generate by marketing our excess power into
the interchange markets,
o The adverse effects of rising employee benefit costs and higher
insurance costs, and
o An assumed return to more normal weather patterns.
In late 2002, we and Ameren announced the following actions to mitigate the
effect of these challenges:
o A voluntary retirement program that was accepted by approximately 550
Ameren employees, including approximately 35 of our employees and
additional employees providing support functions to us through Ameren
Services,
o Modifications to retiree employee benefit plans to increase
co-payments and limit our overall cost,
o A wage freeze in 2003 for all management employees, including our
employees,
o Suspension of operations at two 1940's-era generating plants,
including two units at our Meredosia coal plant, to reduce operating
costs, and
o Reductions of 2003 expected capital expenditures.
We are considering additional actions, including modifications to active
employee benefits, further staffing reductions and other initiatives.
19
In the ordinary course of business, we and Ameren evaluate strategies to
enhance our financial position, results of operations and liquidity. These
strategies may include potential acquisitions, divestitures, and opportunities
to reduce costs or increase revenues, and other strategic initiatives in order
to increase Ameren's shareholder value. We are unable to predict which, if any,
of these initiatives will be executed, as well as the impact these initiatives
may have on our future financial position, results of operations or liquidity.
Labor Agreements
Certain of our employees are represented by the International Brotherhood
of Electrical Workers (IBEW) and the International Union of Operating Engineers
(IUOE). These employees comprise approximately 70% of our workforce. Labor
agreements covering the majority of employees represented by IBEW and IUOE
expire by June 2003. We cannot predict what issues may be raised by the
collective bargaining units and, if raised, whether negotiations concerning such
issues will be successfully concluded.
REGULATORY MATTERS
Illinois Electric
See Note 2 - Rate and Regulatory Matters to our Financial Statements under
Item 8.
Federal - Electric Transmission
See Note 2 - Rate and Regulatory Matters to our Financial Statements under
Item 8.
ACCOUNTING MATTERS
Critical Accounting Policies
Preparation of the financial statements and related disclosures in
compliance with generally accepted accounting principles requires the
application of appropriate technical accounting rules and guidance, as well as
the use of estimates. Our application of these policies involves judgments
regarding many factors, which, in and of themselves, could materially impact the
financial statements and disclosures. A future change in the assumptions or
judgments applied in determining the following matters, among others, could have
a material impact on future financial results. In the table below, we have
outlined those accounting policies that we believe are most difficult,
subjective or complex:
Accounting Policy Uncertainties Affecting Application
- ----------------- -----------------------------------
Environmental Costs
We accrue for all known environmental o Extent of contamination
contamination where remediation can be o Responsible party determination
reasonably estimated. However, we are o Approved methods for cleanup
contractually indemnified by AmerenCIPS for o Present and future legislation and governmental
remediation costs that we incur at the sites of regulations and standards
our coal plants relating to environmental o Results of ongoing research and development
contamination that occurred prior to the regarding environmental impacts
AmerenCIPS' transfer of the coal plants to us on
May 1, 2000.
Basis for Judgment
We determine the proper amounts to accrue for environmental contamination based
on internal and third party estimates of clean-up costs in the context of
current remediation standards and available technology.
Benefit Plan Accounting
Based on actuarial calculations, we accrue o Future rate of return on pension and other plan assets
costs of providing future employee benefits in o Interest rates used in valuing benefit obligations
accordance with SFAS 87, 106 and 112. See o Healthcare cost trend rates
Note 9 - Retirement Benefits to our Financial
20
Statements under Item 8. o Timing of employee retirements
Basis for Judgment
We utilize a third party consultant to assist us in evaluating and recording the
proper amount for future employee benefits. Our ultimate selection of the
discount rate, healthcare trend rate and expected rate of return on pension
assets is based on our review of available current, historical and projected
rates, as applicable.
Derivative Financial Instruments
We record all derivatives at their fair market o Market conditions in the energy industry, especially
value in accordance with SFAS 133. The the effects of price volatility on contractual
identification and classification of a derivative o commodity commitments
and the fair value of such derivative must be o Regulatory and political environments and
determined. We designate certain derivatives requirements
as hedges of future cash flows. See Note 4 - o Fair value estimations on longer term contracts
Derivative Financial Instruments to our o Complexity of financial instruments and accounting
Financial Statements under Item 8. rules
o Effectiveness of our derivatives that have been
designated as hedges
Basis for Judgment
We determine whether a transaction is a derivative versus a normal purchase or
sale based on historical practice and our intention at the time we enter a
transaction. We utilize actively quoted prices, prices provided by external
sources, and prices based on internal models, and other valuation methods to
determine the fair market value of derivative financial instruments.
Impact of Future Accounting Pronouncements
See Note 1 - Summary of Significant Accounting Policies to our Financial
Statements under Item 8.
EFFECTS OF INFLATION AND CHANGING PRICES
Under the Marketing Company - AmerenCIPS agreement which we supply the
power for, our rates are fixed through January 1, 2004. In 2002, legislation was
passed in Illinois to extend the rate freeze period through January 1, 2007 from
the original expiration of January 1, 2005. As a result of this extension,
Marketing Company expects to seek to renew or extend the Marketing Company -
AmerenCIPS agreement through the same period. In addition, Marketing Company
also has several wholesale customers under fixed energy and capacity contracts
ranging from less than one year to eleven years which we also supply the power
to serve. As a result, inflation affects our operations, earnings, stockholder's
equity and financial performance.
We have no provisions for adjusting prices for changes in the cost of fuel
for electric generation. In the short-term, we are impacted by changes in market
prices for natural gas we must purchase to run our combustion turbine electric
generators. We have structured various supply agreements to maintain access to
multiple gas pools and supply basins to minimize the impact to the financial
statements. In the long-term, we are impacted by the price of coal, which we
purchase under short-term and long-term fixed price contracts through 2010. See
discussion below under Commodity Price Risk for further information.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the risk of changes in value of a physical asset or
a financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g., interest rates, etc.). The following discussion of our
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. We handle market risks in
accordance with established policies, which may include entering into various
derivative transactions. In the normal course of business, we also face risks
that are either non-financial or non-quantifiable. Such risks principally
include business, legal and operational risks and are not represented in the
following discussion.
Our risk management objective is to optimize our physical generating assets
within prudent risk parameters. Our risk management policies are set by a Risk
Management Steering Committee, which is comprised of senior-level Ameren
officers.
21
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated
with the issuance of both long-term and short-term variable-rate debt and
fixed-rate debt. We manage our interest rate exposure by controlling the amount
of these instruments we hold within our total capitalization portfolio and by
monitoring the effects of market changes in interest rates. At December 31,
2002, we had $191 million of variable rate non-utility money pool borrowings
outstanding.
Utilizing our variable rate debt outstanding at December 31, 2002, if
interest rates increased by 1%, our annual interest expense would increase by
approximately $2 million and net income would decrease by approximately $1
million. The model does not consider the effects of the reduced level of
potential overall economic activity that would exist in such an environment. In
the event of a significant change in interest rates, management would likely
take actions to further mitigate our 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 our financial
structure.
Credit Risk
Credit risk represents the loss that would be recognized if counterparties
fail to perform as contracted. New York Mercantile Exchange (NYMEX) traded
futures contracts are supported by the financial and credit quality of the
clearing members of the NYMEX and have nominal credit risk. On all other
transactions, we are exposed to credit risk in the event of nonperformance by
the counterparties in the transaction.
Our physical and financial instruments are subject to credit risk
consisting of accounts receivable and executory contracts with market risk
exposures. Our revenues are primarily derived from the sales of electricity to
Marketing Company as described in Note 3 - Related Party Transactions to our
Financial Statements under Item 8. At December 31, 2002, approximately $52
million of our accounts receivable are related party receivables from Marketing
Company. No other customer represents greater than 10% of our accounts
receivable. We analyze each counterparty's financial condition prior to entering
into sales, forwards, swaps, futures or option contracts. We also establish
credit limits for these counterparties and monitor the appropriateness of these
limits on an ongoing basis through a credit risk management program which
involves daily exposure reporting to senior management, master trading and
netting agreements, and credit support management such as letters of credit and
parental guarantees.
Commodity Price Risk
We are exposed to changes in market prices for fuel and electricity. We
utilize several techniques to mitigate risk, including utilizing derivative
financial instruments. A derivative is a contract whose value is dependent on,
or derived from, the value of some underlying asset. The derivative financial
instruments that we use (primarily forward contracts, futures contracts, option
contracts and financial swap contracts) are dictated by risk management
policies.
Fuels Company is responsible for providing fuel procurement services on our
behalf and for managing fuel price risks. Fixed price forward contracts, as well
as futures, options, and financial swaps are all instruments, which may be used
to manage these risks. The majority of our coal supply contracts are physical
forward contracts. We have entered into several long-term contracts with various
suppliers to purchase coal in order to manage our exposure to fuel prices. See
Note 10 - Commitments and Contingencies to our Financial Statements under Item 8
for further information. We have satisfied 67% of our 2002 power supply needs
through coal. All of the required 2003 and over 90% of the required 2004 supply
of coal for our coal-fired power plants has been acquired at fixed prices. As
such, we have minimal coal price risk for 2003 and 2004. At December 31, 2002,
approximately 52% of our coal requirements for 2005 through 2007 were covered by
contracts. We are exposed to changes in market prices for natural gas we must
purchase to run our combustion turbine generators. Our natural gas procurement
strategy is designed to ensure reliable and immediate delivery of natural gas to
our intermediate and peaking units by optimizing transportation and storage
options and minimizing cost and price risk by structuring various supply
agreements to maintain access to multiple gas pools and supply basins and
reducing the impact of price volatility. For 2002, 2001 and for the period from
May 1, 2000 through December 31, 2000, natural gas costs were approximately $44
million, $30 million and $5 million, respectively. At December 31, 2002,
approximately 36% of our 2003 natural gas requirements for generation were
covered by contracts.
Although we cannot completely eliminate the effects of gas price
volatility, our strategy is designed to minimize the effect of market conditions
on our results of operations. Our gas procurement strategy includes procuring
22
natural gas under a portfolio of agreements with price structures, including
fixed price, indexed price and embedded price hedges such as caps and collars.
Our strategy also utilizes physical assets through storage, operator and
balancing agreements to minimize price volatility. Our electric marketing
strategy is to extract additional value from our generation facilities by
selling energy in excess of needs into the long-term and short-term markets for
term sales and purchasing energy when the market price is less than the cost of
generation. Our primary use of derivatives has involved transactions that are
expected to reduce price risk exposure for us.
With regard to our exposure to commodity price risk for purchased power and
excess electricity sales, we have an affiliate, AmerenEnergy, whose primary
responsibility includes managing market risks associated with changing market
prices for electricity purchased and sold on our behalf.
Electricity Price Risk
We measure our electricity position as total generating resources
available, given historical forced outage rates, planned outages and forward
market prices, less projected fixed price load requirements. We consider the
contracts in place through the end of 2004 to supply full requirements to
AmerenCIPS' native load and fixed price market-based retail customers plus
Marketing Company's wholesale contract commitments to be load requirements. Our
electricity and capacity price risks are primarily mitigated by the Generating
Company - Marketing Company agreement, the Marketing Company - AmerenCIPS
agreement, and Marketing Company's fixed price wholesale and retail contract
commitments and are therefore the largest single protection against falling
electricity and capacity prices. For the year ended December 31, 2002, revenues
generated from the Generating Company - Marketing Company agreement was 85%
(2001 - 87%).
The portion of our capacity which is not covered by the agreements and
contracts discussed above will be managed either by Marketing Company (generally
for wholesale transactions over one year and retail sales) or AmerenEnergy
(generally for wholesale transactions under one year). Our strategy is to
continue to utilize Marketing Company to offer most of our output under
long-term wholesale contracts as more of our capacity and energy become
available for resale as existing contracts expire. AmerenEnergy expects to
extract additional value from the generating facilities by selling energy in
excess of the needs of Marketing Company. Also, AmerenEnergy will purchase power
on our behalf when power is available for purchase at lower cost than the cost
of our generation. Such power would be purchased to satisfy our delivery
requirements under our agreements with Marketing Company, which Marketing
Company will use to meet its obligations under the load requirements discussed
above.
The amended joint dispatch agreement includes a sharing mechanism which
provides a benefit to us when we are able to use relatively low-cost generation
available from AmerenUE to meet our long-term fixed price sales obligations as
an alternative or supplement to our own generating resources. Conversely, we
forgo some of the potential gain that would arise from high peak power prices in
short-term or spot markets because AmerenUE has the right to use our available
energy (e.g., energy not sold by us to Marketing Company) to the extent such
energy is less expensive than energy produced from AmerenUE's next most
economically dispatchable generating unit. The price payable to us in these
circumstances would likely be lower than peak market prices. Under the amended
joint dispatch agreement, we also share revenues with AmerenUE when sales are
made from our or AmerenUE's generating facilities to third parties on a
short-term or spot basis. See Note 3 - Related Party Transactions to our
Financial Statements under Item 8 for further information.
23
Equity Price Risk
We, along with other subsidiaries of Ameren, are a participant in Ameren's
defined benefit plans and postretirement benefit plans and are responsible for
our proportional share of the costs. Ameren's costs of providing
non-contributory defined benefit retirement and postretirement benefit plans are
dependent upon a number of factors, such as the rates of return on plan assets,
discount rate, the rate of increase in health care costs and contributions made
to the plans. The market value of Ameren's plan assets has been affected by
declines in the equity market since 2000 for the pension and postretirement
plans. As a result, at December 31, 2002, we recognized an additional minimum
pension liability as prescribed by SFAS No. 87, "Employers' Accounting for
Pensions." The liability resulted in a reduction to equity as a result of a
charge to OCI of $6 million, net of taxes. The amount of the liability was the
result of asset returns experienced through 2002, interest rates and Ameren's
contributions to the plan during 2002. In future years, the liability recorded,
the costs reflected in net income, or OCI, or cash contributions to the plans
could increase materially without a recovery in equity markets in excess of our
assumed return on plan assets. If the fair value of the plan assets were to grow
and exceed the accumulated benefit obligations in the future, then the recorded
liability would be reduced and a corresponding amount of equity would be
restored in the Balance Sheet. See Liquidity and Capital Resources - Operating
above.
Fair Value of Contracts
We, through AmerenEnergy and Fuels Company acting as agents on our behalf,
utilize derivatives principally to manage the risk of changes in market prices
for fuel, electricity and emission credits. Price fluctuations in fuel and
electricity cause:
o an unrealized appreciation or depreciation of our firm commitments to
purchase or sell when purchase or sales prices under the firm commitment
are compared with current commodity prices;
o market values of fuel inventories or purchased power to differ from the
cost of those commodities in inventory and under firm commitment; and
o actual cash outlays for the purchase of these commodities to differ from
anticipated cash outlays.
The derivatives that we use to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. We continually assess our supply and delivery commitment positions
against forward market prices and internally forecast forward prices and modify
our exposure to market, credit and operational risk by entering into various
offsetting transactions. In general, we believe these transactions serve to
reduce our price risk. See Note 4 - Derivative Financial Instruments to our
Financial Statements under Item 8 for further information.
The following table summarizes the favorable (unfavorable) changes in the
fair value of all contracts marked to market during 2002 and 2001:
=============================================================================================================
2002 2001
- -------------------------------------------------------------------------------------------------------------
Fair value of contracts at beginning of period, net $ 2 $ (9)
Contracts which were realized or otherwise settled during the period (2) 9
Changes in fair values attributable to changes in valuation techniques and -
assumptions (a)
Fair value of new contracts entered into during the period (a) (a)
Other changes in fair value (a) 2
- -------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net $ (a) $ 2
=============================================================================================================
(a) Less than $1 million.
24
Maturities of contracts as of December 31, 2002 were as follows:
=============================================================================================================
Maturity Maturity in
less than Maturity Maturity excess of 5 Total fair
Sources of fair value 1 year 1-3 years 4-5 years years value (a)
- -------------------------------------------------------------------------------------------------------------
Prices actively quoted $ - $ - $ - $ - $ -
Prices provided by other external
sources (b) 1 - - - 1
Prices based on models and other
valuation methods (c) (d) (1) - - (1)
- -------------------------------------------------------------------------------------------------------------
Total $ 1 $ (1) $ - $ - $ (d)
=============================================================================================================
(a) Contracts of approximately 47% of the absolute fair value were with
non-investment-grade rated counterparties.
(b) Principally power forward values based on NYMEX prices for over-the-counter
contracts.
(c) Principally power forwards and SO2 options valued on information from
external sources and our estimates. (d) Less than $1 million.
(d) Less than $1 million.
FORWARD-LOOKING STATEMENTS
Statements made in this report which are not based on historical facts are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
"forward-looking" statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions and
financial performance. In connection with the "safe harbor" provisions of the
Private Securities Litigation Reform Act of 1995, we are providing this
cautionary statement to identify important factors that could cause actual
results to differ materially from those anticipated. The following factors, in
addition to those discussed elsewhere in this report and in subsequent
securities filings, could cause results to differ materially from management
expectations as suggested by such "forward-looking" statements:
o the effects of regulatory actions, including changes in regulatory policy;
o changes in laws and other governmental actions, including monetary and
fiscal policies;
o the impact on us of current regulations related to the opportunity for
customers to choose alternative energy suppliers in Illinois;
o the effects of increased competition in the future;
o the effects of Ameren's participation in a FERC-approved Regional
Transmission Organization, including activities associated with the Midwest
Independent System Operator;
o availability and future market prices for fuel and purchased power and
electricity, including the use of financial and derivative instruments and
volatility of changes in market prices;
o the cost of commodities, such as natural gas, used in the production of
electricity and our ability to recover such increased costs;
o wholesale and retail pricing for electricity in the Midwest;
o business and economic conditions;
o the impact of the adoption of new accounting standards on the application
of appropriate technical accounting rules and guidance;
o interest rates and the availability of capital;
o actions of rating agencies and the effects of such actions;
o weather conditions;
o generation plant construction, installation and performance;
o the effects of strategic initiatives, including acquisitions and
divestitures;
o the impact of current environmental regulations on generating companies and
the expectation that more stringent requirements will be introduced over
time, which could potentially have a negative financial effect;
o future wages and employee benefit costs including changes in returns of
benefit plan assets;
o disruptions of the capital markets or other events making Ameren's or our
access to necessary capital more difficult or costly;
o competition from other generating facilities, including new facilities that
may be developed in the future;
o cost and availability of transmission capacity for the energy generated by
our generating facilities or required to satisfy energy sales made on our
behalf; and
o legal and administrative proceedings.
25
Given these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information required to be reported by this item is included under
Quantitative and Qualitative Disclosures About Market Risk in Management's
Discussion and Analysis of Financial Condition and Results of Operations under
Item 7 and Note 4 - Derivative Financial Instruments and Note 11 - Fair Value of
Financial Instruments to our Financial Statements under Item 8.
26
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholder
of AmerenEnergy Generating Company:
In our opinion, the financial statements listed in the index appearing under
Item 15(A)(1) on Page 52 present fairly, in all material respects, the financial
position of AmerenEnergy Generating Company at December 31, 2002 and 2001, and
the results of their operations and their cash flows for the years ended
December 31, 2002 and 2001 and for the period May 1, 2000 to December 31, 2000,
in conformity with accounting principles generally accepted in the United States
of America. 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 auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 13, 2003
27
AMEREN ENERGY GENERATING COMPANY
BALANCE SHEET
(In millions, except shares)
December 31, December 31,
2002 2001
--------------- --------------
ASSETS:
Property and plant, net (Note 5) $ 1,767 $ 1,512
Current assets:
Cash and cash equivalents 3 2
Accounts receivable 10 8
Accounts receivable - intercompany 68 121
Other receivables 2 -
Materials and supplies, at average cost -
Fossil fuel 50 40
Other 27 20
Taxes receivable 71 -
Other - 2
--------------- --------------
Total current assets 231 193
--------------- --------------
Deferred income taxes, net (Note 8) - 38
Other 12 13
--------------- --------------
Total Assets $ 2,010 $ 1,756
=============== ==============
CAPITAL AND LIABILITIES:
Capitalization:
Common stock, no par value, 10,000 shares authorized -
2,000 shares outstanding $ - $ -
Other paid-in capital 150 150
Retained earnings 131 120
Accumulated other comprehensive income (1) 4
--------------- --------------
Total common stockholder's equity 280 274
--------------- --------------
Subordinated notes payable - intercompany (Note 6) 412 461
Long-term debt (Note 6) 698 424
--------------- --------------
Total capitalization 1,390 1,159
--------------- --------------
Current liabilities:
Current portion of subordinated notes payable - intercompany (Note 6) 50 47
Accounts and wages payable 55 63
Accounts and wages payable - intercompany 32 181
Notes payable - intercompany 191 62
Current portion of income taxes payable - intercompany 13 18
Income taxes payable - 12
Interest payable 8 6
Interest payable - intercompany 7 6
Other 2 3
--------------- --------------
Total current liabilities 358 398
--------------- --------------
Commitments and contingencies (Note 1, 2, and 10)
Deferred income taxes, net (Note 8) 66 -
Accumulated deferred investment tax credits 15 17
Income tax payable - intercompany 162 177
Other deferred credits and liabilities 19 5
--------------- --------------
Total Capital and Liabilities $ 2,010 $ 1,756
=============== ==============
See Notes to Financial Statements.
28
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF INCOME
(In millions)
For the period
May 1, 2000
Year Ended through
December 31, December 31,
---------------------------- -------------
2002 2001 2000
------------- ------------- -------------
OPERATING REVENUES:
Electric - intercompany $ 671 $ 657 $ 372
Electric 62 60 105
Other - intercompany 10 13 3
------------- ------------- -------------
Total operating revenues 743 730 480
------------- ------------- -------------
OPERATING EXPENSES:
Fuel and purchased power 339 306 236
Other operations and maintenance 174 157 100
Voluntary retirement and other restructuring charges (Note 6) 10 - -
Depreciation and amortization 69 53 28
Other taxes 12 19 13
------------- ------------- -------------
Total operating expenses 604 535 377
------------- ------------- -------------
OPERATING INCOME 139 195 103
OTHER INCOME AND (DEDUCTIONS):
Miscellaneous, net -
Miscellaneous income (1) 5 3
Miscellaneous expense - - -
------------- ------------- -------------
Total other income and (deductions) (1) 5 3
------------- ------------- -------------
INTEREST CHARGES:
Interest expense - intercompany 40 41 30
Interest expense 46 34 5
------------- ------------- -------------
Total interest charges 86 75 35
------------- ------------- -------------
INCOME TAXES 20 47 27
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 32 78 44
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES - (2) -
------------- ------------- -------------
NET INCOME $ 32 $ 76 $ 44
============= ============= =============
See Notes to Financial Statements.
29
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF CASH FLOWS
(In millions)
For the period
May 1, 2000
Year Ended through
December 31, December 31,
--------------------- --------------
2002 2001 2000
---------- --------- --------------
Cash Flows From Operating:
Net income $ 32 $ 76 $ 44
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of change in accounting principle - 2 -
Depreciation and amortization 69 53 28
Deferred income taxes, net 63 29 6
Deferred investment tax credits, net (2) (1) (1)
Voluntary retirement and other restructuring charges 10 - -
Other - 1 -
Changes in assets and liabilities:
Accounts receivable (2) 49 (11)
Accounts receivable - intercompany 51 (84) (58)
Materials and supplies (17) (16) 10
Taxes receivable, net (39) (14) 26
Accounts and wages payable (24) (39) 24
Accounts and wages payable - intercompany (11) 89 23
Current portion of income taxes payable-intercompany (20) (16) (8)
Interest payable 2 - 6
Interest payable - intercompany 1 3 4
Assets, other (5) (8) 2
Liabilities, other 3 6 3
---------- --------- ------------
Net cash provided by operating activities 111 130 98
---------- --------- ------------
Cash Flows Used In Investing:
Construction expenditures (442) (347) (470)
Notes receivable - intercompany - 100 (100)
---------- --------- ------------
Net cash used in investing activities (442) (247) (570)
---------- --------- ------------
Cash Flows From Financing:
Paid in capital - 150 -
Dividends paid to Ameren (21) - -
Debt issuance costs (4) - (7)
Redemptions:
Subordinated notes payable - intercompany (46) (94) -
Current portion of subordinated notes payable - intercompany - - -
Issuances:
Notes payable - intercompany 129 62 -
Subordinated notes payable - intercompany - - 50
Long-term debt 274 - 424
---------- --------- ------------
Net cash provided by financing activities 332 118 467
---------- --------- ------------
Net change in cash and cash equivalents 1 1 (5)
Cash and cash equivalents at beginning of year 2 1 6
---------- --------- ------------
Cash and cash equivalents at end of period $ 3 $ 2 $ 1
========== ========= ============
Cash paid during the periods:
Interest $ 45 $ 34 $ -
Interest - intercompany 38 39 26
Income taxes 1 36 14
See Notes to Financial Statements for further information including
non-cash transactions.
30
AMEREN ENERGY GENERATING COMPANY
STATEMENT OF COMMON STOCKHOLDER'S EQUITY
(In millions)
For the period
May 1, 2000
Year Ended through
December 31, December 31,
------------------------ ---------------
2002 2001 2000
----------- ----------- ---------------
Common stock $ - $ - $ -
Other paid-in capital
Beginning balance 150 - -
Change in current period - 150 -
----------- ----------- ------------
150 150 -
----------- ----------- ------------
Retained earnings
Beginning balance 120 44 -
Net income 32 76 44
Dividends paid to Ameren (21) - -
----------- ----------- ------------
131 120 44
----------- ----------- ------------
Accumulated other comprehensive income
Beginning balance 4 - -
Change in derivative financial instruments in current period 1 4 -
----------- ----------- ------------
5 4 -
----------- ----------- ------------
Beginning balance - minimum pension liability - - -
Change in minimum pension liability in current period (6) - -
----------- ----------- ------------
(1) 4 -
----------- ----------- ------------
Total common stockholder's equity $ 280 $ 274 $ 44
=========== =========== ============
Comprehensive income, net of taxes
Net income $ 32 $ 76 $ 44
Unrealized net gain/(loss) on derivative hedging instruments,
net of income taxes of $-, $3, and $-, respectively - 4 -
Reclassification adjustments for gains/(losses) included in net income
net of income taxes of $1, $2, and $-, respectively 1 3 -
Cumulative effect of accounting change net of income taxes of
$-, $(2), and $-, respectively - (3) -
Minimum pension liability adjustment, net of income taxes of
$3, $-, and $-, respectively (6) - -
----------- ----------- ------------
Total comprehensive income, net of taxes $ 27 $ 80 $ 44
=========== =========== ============
See Notes to Financial Statements.
31
AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31, 2002
NOTE 1 - Summary of Significant Accounting Policies
General
AmerenEnergy Generating Company, headquartered in St. Louis, Missouri, is
an indirect wholly-owned subsidiary of Ameren Corporation (Ameren). We own and
operate a wholesale electric generation business in Illinois and Missouri. Much
of our business was formerly owned and operated by our affiliate, Central
Illinois Public Service Company, which operates as AmerenCIPS. We were
incorporated in the State of Illinois in March 2000. On May 1, 2000, we acquired
from AmerenCIPS at net book value five coal-fired electric generating stations,
which we refer to as the coal plants, all related fuel, supply, transportation,
maintenance and labor agreements, approximately 45% of AmerenCIPS' employees,
and other related rights, assets and liabilities.
Ameren is a public utility holding company registered with the Securities
and Exchange Commission (SEC) under the Public Utility Holding Company Act of
1935 (PUHCA), as amended, and is also headquartered in St. Louis, Missouri.
Ameren's principal business is the generation, transmission and distribution of
electricity, and the distribution of natural gas to residential, commercial,
industrial and wholesale users in the central United States. Ameren's principal
subsidiaries and our affiliates are as follows:
o Union Electric Company, which operates a rate-regulated electric
generation, transmission and distribution business, and a rate-regulated
natural gas distribution business in Missouri and Illinois as AmerenUE.
o AmerenCIPS, which operates a rate-regulated electric and natural gas
transmission and distribution business in Illinois.
o Central Illinois Light Company, a subsidiary of CILCORP Inc. (CILCORP),
which operates a rate-regulated transmission and distribution business, an
electric generation business, and a rate-regulated natural gas distribution
business in Illinois as AmerenCILCO. Ameren completed its acquisition of
CILCORP on January 31, 2003 from The AES Corporation (AES). See Recent
Developments for further information.
o AmerenEnergy Resources Company (Resources Company), which consists of non
rate-regulated operations. Subsidiaries include us, AmerenEnergy Marketing
Company (Marketing Company), which markets power for periods over one year,
AmerenEnergy Fuels and Services Company (Fuels Company), which procures
fuel and manages the related risks for us and our affiliates, AmerenEnergy
Development Company (Development Company), which, as our parent, develops
and constructs generating facilities for us, and AmerenEnergy Medina Valley
Cogen (No. 4), LLC, which indirectly owns a 40 megawatt, gas-fired electric
generation plant. On February 4, 2003, Ameren completed its acquisition of
AES Medina Valley Cogen (No. 4), LLC (Medina Valley) from AES and renamed
it AmerenEnergy Medina Valley Cogen (No. 4), LLC.
o AmerenEnergy, Inc. (AmerenEnergy), which serves as a power marketing and
risk management agent for us and our affiliates for transactions of
primarily less than one year.
o Electric Energy, Inc. (EEI), which operates electric generation and
transmission facilities in Illinois. Ameren has a 60% ownership interest in
EEI, 40% owned by AmerenUE and 20% owned by Resources.
o Ameren Services Company (Ameren Services), which provides shared support
services to us and our affiliates.
When we refer to our, we, us or Generating Company, we are referring to
AmerenEnergy Generating Company and in some cases our agents, AmerenEnergy and
Fuels Company. All tabular dollar amounts are in millions, unless otherwise
indicated.
Our accounting policies conform to generally accepted accounting principles
in the United States (GAAP). Our financial statements reflect all adjustments
(which include normal, recurring adjustments) necessary, in our opinion, for a
fair presentation of our results. The preparation of financial statements in
conformity with GAAP requires management to make certain estimates and
assumptions. Such estimates and assumptions affect reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities at the date
of the financial statements and the reported amounts of revenues and expenses
during the reported period. Actual results could differ from those estimates.
Certain reclassifications have been made to prior years' financial statements to
conform to 2002 reporting.
Our financial statements are available only for the period since May 1,
2000. Prior to that date, all operations of the coal plants now owned by us were
fully integrated with, and therefore results of operations were consolidated
32
into the financial statements of AmerenCIPS, whose business was to generate,
transmit and distribute electricity and to provide other utility customer
support services.
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.
Interest during construction is added for our assets. Maintenance expenditures
and the renewal of items not considered units of property are expensed as
incurred. When units of depreciable property are retired, the original cost and
removal cost, less salvage value, are charged to accumulated depreciation. See
Accounting Changes and Other Matters relating to Statement of Financial
Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement
Obligations."
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 2002 and 2001 and for the period from May 1, 2000
through December 31, 2000 was approximately 3% of the average depreciable costs.
Interest Capitalized
Interest is capitalized in accordance with SFAS No. 34, "Capitalization of
Interest Cost." For 2002, interest expense capitalized was $1.2 million (2001 -
$1.3 million, 2000 - $0.8 million).
Impairment of Long-Lived Assets
We evaluate long-lived assets for impairment when events or changes in
circumstances indicate that the carrying value of such assets may not be
recoverable. The determination of whether impairment has occurred is based on an
estimate of undiscounted cash flows attributable to the assets, as compared with
the carrying value of the assets. If impairment has occurred, the amount of the
impairment recognized is determined by estimating the fair value of the assets
and recording a provision for loss if the carrying value is greater than the
fair value. See Accounting Changes and Other Matters relating to SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets."
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.
Unamortized Debt Discount, Premium and Expense
Discount and expense associated with long-term debt are amortized over the
lives of the related issues.
Revenue
We accrue an estimate of electric revenues for service rendered, but
unbilled, at the end of each accounting period.
Interchange revenues included in Operating Revenues - Electric and Electric
Intercompany were $100 million for the year ended December 31, 2002 (2001 - $92
million, 2000 - $137 million). See Emerging Issues Task Force (EITF) Issue 02-3
"Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities" discussion under Accounting Changes and Other Matters below for
further information.
Purchased Power
Purchased power included in Operating Expenses - Fuel and Purchased Power
was $107 million for the year ended December 31, 2002 (2001 - $125 million, 2000
- - $119 million). See EITF 02-3 discussion under Accounting Changes and Other
Matters for further information.
33
Income Taxes
We are included in the consolidated federal income tax return filed by
Ameren. As a subsidiary of Ameren, we could be considered jointly and severally
liable for assessments of additional tax on the consolidated group. Income taxes
are allocated to the individual companies based on their respective taxable
income or loss. Our provision for income taxes has been presented based on
federal and state taxes we would have presented on a stand-alone company basis.
Deferred tax assets and liabilities are recognized for the tax consequences of
transactions that have been treated differently for financial reporting and tax
return purposes, measured using statutory tax rates.
Investment tax credits utilized in prior years were deferred and are being
amortized over the useful lives of the related properties.
Accounting Changes and Other Matters
In January 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The impact of that adoption resulted in a
cumulative effect charge of $2 million, net of taxes, to the income statement,
and a cumulative effect adjustment of $3 million, net of taxes, to Accumulated
Other Comprehensive Income (OCI), which reduced common stockholder's equity. See
Note 4 - Derivative Financial Instruments for further information.
In January 2002, we adopted SFAS No. 141, "Business Combinations," and SFAS
No. 142, "Goodwill and Other Intangible Assets." SFAS 141 requires business
combinations to be accounted for under the purchase method of accounting, which
requires one party in the transaction to be identified as the acquiring
enterprise and for that party to allocate the purchase price to the assets and
liabilities of the acquired enterprise based on fair market value. SFAS 142
requires goodwill and indefinite-lived intangible assets recorded in the
financial statements to be tested for impairment at least annually, rather than
amortized over a fixed period, with impairment losses recorded in the income
statement. SFAS 141 and SFAS 142 did not have any effect on our financial
position, results of operations or liquidity upon adoption. SFAS 141 and SFAS
142 were utilized for Ameren's acquisition of CILCORP, Inc. and AES Medina
Valley Cogen (No. 4), LLC. See Note 12 - Subsequent Event for further
information.
We are adopting SFAS 143 in the first quarter of 2003. SFAS 143 provides
the accounting requirements for asset retirement obligations associated with
tangible, long-lived assets. SFAS 143 requires us to record the estimated fair
value of legal obligations associated with the retirement of tangible long-lived
assets in the period in which the liabilities are incurred and to capitalize a
corresponding amount as part of the book value of the related long-lived asset.
In subsequent periods, we are required to adjust asset retirement obligations
based on changes in estimated fair value, and the corresponding increases in
asset book values are depreciated over the useful life of the related asset.
Uncertainties as to the probability, timing or cash flows associated with an
asset retirement obligation affect our estimate of fair value.
Upon adoption of this standard, we expect to recognize asset retirement
obligations of approximately $5 million related primarily to retirement costs
for an ash pond. The difference between the net asset and the liability to be
recorded upon adoption related to our assets will be recorded as a loss of
approximately $2 million, net of taxes, for a change in accounting principle.
In addition to these obligations, we have determined that certain other
asset retirement obligations exist. However, we are unable to estimate the fair
value of those obligations because the probability, timing or cash flows
associated with the obligations are indeterminable. We do not believe that these
obligations, when incurred, will have a material adverse impact on our financial
position, results of operations or liquidity.
SFAS 143 also may require a change in the depreciation methodology we have
historically utilized for our non-regulated operations. Historically, we have
included an estimated cost of dismantling and removing plant from service upon
retirement in the basis upon which our depreciation rates were determined. SFAS
143 requires us to exclude costs of dismantling and removal upon retirement from
the depreciation rates applied to non rate-regulated plant balances. Further, we
are required to remove accumulated provisions for dismantling and removal costs
from accumulated depreciation, where they are currently embedded, and reflect
such adjustment as a gain upon adoption of this standard, to the extent such
dismantling and removal activities are not considered obligations as defined by
SFAS 143. At this time we have not finalized our determination of the gain to be
recorded upon adoption of SFAS 143 for our non rate-regulated operations;
however, it will likely substantially exceed the loss resulting from adopting
this standard. Additionally, beginning in January 2003, depreciation rates for
non rate-regulated assets will be reduced to reflect the discontinuation of the
accrual of dismantling and removal costs. As a result, non rate-
34
regulated asset removal costs will be expensed as incurred. The impact of this
change in accounting will result in a decrease in depreciation expense and an
increase in operations and maintenance expense, the net impact of which is
indeterminable, but not expected to be material.
On January 1, 2002, we adopted SFAS 144. SFAS 144 addresses the financial
accounting and reporting for the impairment or disposal of long-lived assets and
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of." SFAS 144 retains the guidance related
to calculating and recording impairment losses, but adds guidance on the
accounting for discontinued operations, previously accounted for under
Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations
- - Reporting the Effects of a Segment of a Business, and Extraordinary, Unusual
and Infrequently Occurring Events and Transactions." SFAS 144 did not have any
effect on our financial position, results of operations or liquidity in 2002.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS 146 requires an entity to
recognize, and measure at fair value, a liability for a cost associated with an
exit or disposal activity in the period in which the liability is incurred and
nullifies EITF Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (Including Certain
Costs Incurred in a Restructuring)." SFAS 146 is effective for exit or disposal
activities that are initiated after December 31, 2002.
During 2002, we adopted the provisions of EITF 02-3 that required revenues
and costs associated with certain energy contracts to be shown on a net basis in
the income statement. Prior to adopting EITF 02-3 and the rescission of EITF
Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities," our accounting practice was to present all settled
energy purchase or sale contracts within our power risk management program on a
gross basis in Operating Revenues - Electric and in Operating Expenses - Fuel
and Purchased Power. This meant that revenues were recorded for the notional
amount of the power sales contracts with a corresponding charge to income for
the costs of the energy that was generated, or for the notional amount of a
purchased power contract.
In October 2002, the EITF reached a consensus to rescind EITF No. 98-10.
The effective date for the full rescission of EITF 98-10 was for fiscal periods
beginning after December 15, 2002, with early adoption permitted. In addition,
the EITF reached a consensus in October 2002 that all SFAS 133 trading
derivatives (subsequent to the rescission of EITF 98-10) should be shown net in
the income statement, whether or not physically settled. This consensus applies
to all energy and non-energy related trading derivatives that meet the
definition of a derivative pursuant to SFAS 133. We have adopted and applied
this guidance to 2002 and 2001, which had no impact on previously reported
earnings or stockholder's equity. The adoption of EITF 02-3, rescission of EITF
98-10 and the related transition guidance resulted in netting of energy
contracts and lowered our reported revenues and costs with no impact on
earnings. The following table summarizes the impact of energy contract netting
for the year ended December 31, 2001 and for the period May 1, 2000 through
December 31, 2000:
================================================================================
2001 2000
- --------------------------------------------------------------------------------
Previously reported gross operating revenues $ 986 $ 480
Revenues and costs netted (a) 256 -
- --------------------------------------------------------------------------------
Net operating revenues reported $ 730 $ 480
================================================================================
(a) Revenues and costs netted for the year ended December 31, 2002 were $253
million. SFAS 133 was adopted on January 1, 2001 and therefore, no netting was
required for the year ended December 31, 2000.
NOTE 2 - Rate and Regulatory Matters
Missouri Electric
Marketing Company - AmerenUE Power Supply Agreements
In order to satisfy its regulatory load requirements for 2001 and 2002,
AmerenUE purchased, under a one-year contract 450 megawatts of capacity and
energy (the 2001 Marketing Company - AmerenUE agreement) and 200 megawatts of
capacity and energy (the 2002 Marketing Company - AmerenUE agreement) from
Marketing Company. These agreements were entered into through a competitive
bidding process and reflected market-based rates. We supplied the power for
these agreements under our power supply agreement with Marketing Company.
35
The Federal Energy Regulatory Commission (FERC) accepted the 2001 Marketing
Company - AmerenUE agreement as filed. The 2002 Marketing Company - AmerenUE
agreement was set for hearing to determine that the contract terms were just and
reasonable. On March 12, 2003, a settlement between Marketing Company and the
FERC Staff was approved by the FERC effectively resolving all issues concerning
the 2002 Marketing Company - AmerenUE agreement set for hearing. While the FERC
order contains a standard refund report requirement, no refunds are due under
the settlement as approved.
In May 2001 and May 2002, the Missouri Public Service Commission (MoPSC)
filed complaints with SEC relating to these agreements. While the complaints
were pending, the MoPSC and AmerenUE reached an agreement for resolving these
disputes. The agreement requires AmerenUE to not enter into any new contracts to
purchase wholesale electric energy from any Ameren affiliate that is an exempt
wholesale generator without first obtaining, on a timely basis, the
determinations required of the MoPSC that are specified in Section 32(k) of the
PUHCA. However, this commitment did not prevent AmerenUE from completing the
purchases contemplated by the 2001 and 2002 Marketing Company - AmerenUE
agreements and does not prevent AmerenUE from making short term energy purchases
(less than 90 days) from an Ameren affiliate, without prior MoPSC determination,
to prevent or alleviate system emergencies. As part of this agreement, the MoPSC
has agreed to terminate its SEC complaints.
Illinois Electric
In 2002, all of Ameren's Illinois residential, commercial and industrial
customers had choice in electric suppliers.
As a provision of the legislation related to the restructuring of the
Illinois electric industry (the Illinois Law), a rate freeze is in effect
through January 1, 2007. As a result of this extension through January 1, 2007,
Marketing Company expects to seek to renew or extend a power supply agreement
between AmerenCIPS and Marketing Company through the same period. A renewal or
extension of the power supply agreement will depend on compliance with
regulatory requirements in effect at the time, and we cannot predict whether
Marketing Company will be successful in securing a renewal or extension of this
agreement.
Federal - Electric Transmission
Regional Transmission Organization
In December 1999, the FERC issued Order 2000 requiring all utilities,
subject to FERC jurisdiction, to state their intentions for joining a regional
transmission organization (RTO). RTOs are independent organizations that will
functionally control the transmission assets of utilities and are designed to
improve the wholesale power market. Beginning in January 2001, our affiliates,
AmerenUE and AmerenCIPS, along with several other utilities, sought approval
from the FERC to participate in an RTO known as the Alliance RTO. The Ameren
companies had previously been members of the Midwest Independent System Operator
(Midwest ISO) and recorded a pretax charge to earnings in 2000 of $25 million
($15 million, net of taxes) for an exit fee and other costs when they left that
organization. Ameren believed that the for-profit Alliance RTO business model
was superior to the not-for-profit Midwest ISO business model and provided
Ameren with a more equitable return on its transmission assets.
In late 2001, the FERC issued an order that rejected the formation of the
Alliance RTO and ordered the Alliance RTO companies and the Midwest ISO to
discuss how the Alliance RTO business model could be accommodated within the
Midwest ISO. In April 2002, after the Alliance RTO and Midwest ISO failed to
reach an agreement, and after a series of filings by the two parties with the
FERC, the FERC issued a declaratory order setting forth the division of
responsibilities between the Midwest ISO and National Grid (the managing member
of the transmission company formed by the Alliance companies) and approved the
rate design and the revenue distribution methodology proposed by the Alliance
companies. However, the FERC denied a request by the Alliance companies and
National Grid to purchase certain services from the Midwest ISO at incremental
cost rather than Midwest ISO's full tariff rates. The FERC also ordered the
Midwest ISO to return the exit fee paid by the Ameren companies to leave the
Midwest ISO, provided the Ameren companies return to the Midwest ISO and agree
to pay their proportional share of the startup and ongoing operational expenses
of the Midwest ISO. Moreover, the FERC required the Alliance companies to select
the RTO in which they will participate within thirty days of the order.
Following the April 2002 FERC order, the Ameren companies made filings with
the FERC indicating that they would return to the Midwest ISO through a new
independent transmission company, GridAmerica LLC, that was agreed to be formed
by AmerenCIPS and AmerenUE, and subsidiaries of FirstEnergy Corporation and
NiSource
36
Inc. Upon receipt of final FERC approval of the definitive agreements
establishing GridAmerica, a subsidiary of National Grid will serve as the
managing member of GridAmerica and will manage the transmission assets of the
three companies and participate in the Midwest ISO on behalf of GridAmerica.
Other Alliance RTO companies announced their intentions to join the PJM
Interconnection LLC (PJM) RTO. On July 25, 2002, the Ameren companies filed a
motion with the FERC requesting that it condition the approval of the choices of
other Illinois utilities to join the PJM RTO on Midwest ISO and PJM entering
into an agreement addressing important reliability and rate-barrier issues. On
July 31, 2002, the FERC issued an order accepting the formation of GridAmerica
as an independent transmission company under the Midwest ISO subject to further
compliance filings ordered by the FERC. The FERC also issued an order accepting
the elections made by the other Illinois utilities to join the PJM RTO on the
condition PJM and Midwest ISO immediately begin a process to address the
reliability and rate-barrier issues raised by the Ameren companies and other
market participants in previous filings.
The compliance filing to facilitate the formation and operation of
GridAmerica as an independent transmission company within the Midwest ISO, as
contemplated in the July 31, 2002 order of the FERC, was conditionally accepted
by the FERC in an order issued December 19, 2002. In the order, the FERC
approved the return of the $18 million exit fee paid by the Ameren companies to
leave the Midwest ISO with interest once GridAmerica becomes operational. The
FERC also approved, subject to further filings, reimbursement of $36 million to
the GridAmerica companies for expenses incurred to form the Alliance RTO.
GridAmerica is scheduled to become operational in spring 2003. Ameren's
participation in GridAmerica remains subject to MoPSC approval. An order from
the MoPSC is expected during the third quarter of 2003.
We do not own transmission assets. However, we pay AmerenUE and AmerenCIPS
for the use of their transmission lines to transmit power. Until the reliability
and rate-barrier issues are resolved as ordered by the FERC, and the tariffs and
other material terms of Ameren's participation in GridAmerica, and GridAmerica's
participation in the Midwest ISO, are finalized and approved by the FERC, we are
unable to predict the impact that on-going RTO developments will have on our
financial position, results of operations or liquidity.
Standard Market Design Notice of Proposed Rulemaking (NOPR)
On July 31, 2002, the FERC issued a Standard Market Design NOPR. The NOPR
proposes a number of changes to the way the current wholesale transmission
service and energy markets are operated. Specifically, the NOPR calls for all
jurisdictional transmission facilities to be placed under the control of an
independent transmission provider (similar to an RTO), proposes a new
transmission service tariff that provides a single form of transmission service
for all users of the transmission system including bundled retail load, and
proposes a new energy market and congestion management system that uses
locational marginal pricing as its basis. On November 15, 2002, Ameren filed its
initial comments on the NOPR with the FERC expressing its concern with the
potential impact of the proposed rules in their current form on the cost and
reliability of service to retail customers. Ameren also proposed that certain
modifications be made to the proposed rules in order to protect transmission
owners from the possibility of trapped transmission costs that might not be
recoverable from ratepayers as a result of inconsistent regulatory policies.
Ameren filed additional comments on the remaining sections of the NOPR during
the first quarter of 2003. Until the FERC issues a final rule, we are unable to
predict the ultimate impact on our future financial position, results of
operations or liquidity.
NOTE 3 - Related Party Transactions
We have transactions in the normal course of business with Ameren, our
ultimate parent company, and Ameren's other subsidiaries. These transactions
primarily consist of power purchases and sales, services received or rendered,
borrowings and lendings. The transactions with these affiliates are reported as
intercompany transactions.
37
Transfer of Assets
On May 1, 2000, AmerenCIPS transferred its electric generating assets and
related liabilities, at net book value, to us, in exchange for a subordinated
promissory note from us in the principal amount of $552 million and 1,000 shares
of our common stock (Transfer). The transferred assets represented generating
capacity of approximately 2,860 megawatts at the time of the transfer.
Approximately 45% of AmerenCIPS' employees were transferred to us as part of the
transaction. The significant components of net assets transferred are as
follows:
===================================================================
-------------------------------------------------------------------
Cash $ 6
Other receivable - intercompany 26
Material and supplies 54
Other current assets 6
Property and plant, net 635
-------------------------------------------------------------------
Total assets transferred $727
-------------------------------------------------------------------
Accounts payable $ 6
Other current liabilities 3
Other deferred credits 2
Deferred investment tax credits 20
Deferred tax liabilities, net 144
-------------------------------------------------------------------
Total liabilities transferred $175
-------------------------------------------------------------------
-------------------------------------------------------------------
Net assets transferred $552
===================================================================
Capital Additions
During 2000, we acquired nine combustion turbine generating units at
Pinckneyville, Gibson City, and Joppa, Illinois from Development Company and an
affiliate at their historical net book value. The total installed cost of these
combustion turbine generating units was approximately $275 million. These units
represent approximately 595 megawatts of capacity.
During 2001, we acquired twelve combustion turbine generating units at
Kinmundy, Pinckneyville, and Grand Tower, Illinois and Columbia, Missouri from
Development Company at Development Company's historical net book value. The
total installed cost of the combustion turbine generating units was
approximately $530 million. These units represent approximately 850 megawatts of
capacity.
During 2002, we acquired four combustion turbine generating units at Elgin,
Illinois from Development Company at Development Company's historical net book
value. The total installed cost of the combustion turbine generating units was
approximately $215 million. These units represent approximately 470 megawatts of
capacity.
See Note 10 - Commitments and Contingencies for further information
regarding our intention to sell our Pinckneyville and Kinmundy, Illinois
combustion turbine generating units to our affiliate, AmerenUE.
Operating Lease
We entered into an operating lease agreement with Development Company for
the units at the Joppa, Illinois site wherein the three combustion turbine
generating units (totaling approximately 185 megawatts of capacity) were leased
to Development Company for a minimum term of fifteen years expiring September
30, 2015. We receive rental payments under the lease in fixed monthly amounts
that vary over the term of the lease and range from $0.8 - $1.0 million per
month. Development Company is entitled to all of the output produced from the
three units and is responsible for all operating expenses. Development Company
entered into an agreement with Midwest Electric Power, Inc., an affiliate, under
which Midwest Electric Power, Inc. provides operations and maintenance services
at the Joppa site. On November 1, 2000, Development Company and Marketing
Company entered into an electric power supply agreement, referred to as the
Development Company - Marketing Company agreement. This agreement entitles
Marketing Company to all of the output from the Joppa site. This agreement also
contains a monthly capacity charge that approximates the lease payments
Development Company makes to us and an energy charge equal to the variable costs
of operating the combustion turbine generating units.
38
Electric Power Supply Agreements
We have a power supply agreement with Marketing Company, which we refer to
as the Generating Company - Marketing Company agreement. Marketing Company, in
turn, has a power supply agreement with AmerenCIPS, which we refer to as the
Marketing Company - AmerenCIPS agreement. Under these power supply agreements,
we agree to supply to Marketing Company, and Marketing Company, in turn, agrees
to supply to AmerenCIPS, all of the energy and capacity needed by AmerenCIPS to
fulfill its obligations to offer service to its retail customers. For capacity
and energy needed to meet its obligations to retail tariff customers, AmerenCIPS
pays Marketing Company fixed prices. For its fixed-price retail contracts,
AmerenCIPS pays Marketing Company the price it receives under these contracts.
Under the Generating Company - Marketing Company agreement, Marketing Company
"passes through" to us the amounts received under the Marketing Company -
AmerenCIPS agreement. The Marketing Company - AmerenCIPS agreement will
terminate December 31, 2004. The Generating Company - Marketing Company
agreement will remain in effect unless terminated by either party upon at least
one year's notice, but may not be terminated prior to December 31, 2004. See
Illinois Electric in Note 2 for information regarding a possible renewal or
extension of the Marketing Company - AmerenCIPS agreement through January 1,
2007. Electric revenues derived under the Generating Company - Marketing Company
agreement were $626 million for 2002 (2001 - $623 million) and $341 million for
the period from May 1, 2000 through December 31, 2000. No other customer
represents greater than 10% of our revenues.
Joint Dispatch Agreement
We jointly dispatch generation with AmerenUE under an amended joint
dispatch agreement. Under the amended agreement, both of us are entitled to
serve our load requirements from our own least-cost generation first, and then
allow the other company access to any available excess generation. All of our
sales to Marketing Company are considered load requirements. Sales made by us to
other customers through AmerenEnergy, as our agent, are not considered load
requirements. The agreement has no expiration, but either party may give a one
year notice of termination beginning January 1, 2004. Termination of this
agreement could have a material adverse impact on our business.
Electric revenues derived through sales of available generation through
AmerenEnergy were $56 million for 2002 (2001- $55 million) and $105 million for
the period from May 1, 2000 through December 31, 2000. These amounts are
inclusive of the adjustments made in accordance with EITF Issue 02-3. See Note 1
- - "Summary of Significant Accounting Policies." Electric revenues derived
through sales of available generation to AmerenUE through the amended joint
dispatch agreement were $40 million for 2002 (2001- $33 million) and $31 million
for the period from May 1, 2000 through December 31, 2000.
Purchased power derived from AmerenEnergy was $30 million for 2002 (2001 -
$41 million) and $67 million for the period from May 1, 2000 through December
31, 2000. Intercompany power purchases from the amended joint dispatch agreement
between AmerenUE and us and other agreements for 2002 were $77 million (2001-
$84 million) and $52 million for the period from May 1, 2000 through December
31, 2000.
Other Electric Revenues - Intercompany
Electric revenues derived through sales of available generation to our
affiliate EEI were $4 million for 2002 (2001 - less than $1 million) and less
than $1 million for the period from May 1, 2000 through December 31, 2000.
Ameren Services and AmerenEnergy Charges
Support services provided by our affiliates, Ameren Services and
AmerenEnergy, including wages, employee benefits, professional services and
other expenses are based on actual costs incurred. Other operating expenses
provided by Ameren Services and AmerenEnergy, for 2002 were $35 million (2001 -
$28 million) and $18 million for the period May 1, 2000 through December 31,
2000.
Non-Utility Money Pool
Our gross margins from power supply contracts with affiliated companies
continue to be the principal source of cash from operating activities. We plan
to utilize short-term debt to support normal operations and other temporary
capital requirements. We have the ability to borrow up to $600 million from
Ameren through a non-utility money pool agreement. However, the total amount
available to us at any time is reduced by the amount of borrowings from Ameren
by our affiliates and is increased to the extent other Ameren non-regulated
companies advance surplus
39
funds to the non-utility money pool or external sources are used by Ameren to
increase the available amounts. At December 31, 2002, $445 million was available
through the non-utility money pool not including additional funds available
through invested cash balances at Ameren and uncommitted bank lines. The
non-utility money pool was established to coordinate and provide for short-term
cash and working capital requirements of Ameren's non-regulated activities and
is administered by Ameren Services. Interest is calculated at varying rates of
interest depending on the composition of internal and external funds in the
non-utility money pool. The average interest rate for borrowings from the
non-utility money pool was 7.60% in 2002 (2001 - 4.08%) and 6.52% for the period
from May 1, 2000 through December 31, 2000. These rates are based on the cost of
Ameren's funds used to fund money pool advances. We incurred $6 million in net
intercompany interest expense associated with outstanding borrowings from the
non-utility money pool in 2002 (2001 - $2 million) and $1 million for the period
from May 1, 2000 through December 31, 2000. At December 31, 2002, we had
borrowings of $191 million from the non-utility money pool.
Ameren's and our financial agreements include customary default or cross
default provisions that could impact the continued availability of credit or
result in the acceleration of repayment. Many of Ameren's committed credit
facilities require the borrower to represent, in connection with any borrowing
under the facility that no material adverse change has occurred since certain
dates. Ameren's financing arrangements do not contain credit rating triggers,
with the exception of certain ratings triggers within CILCO's financing
arrangements.
Covenants in Ameren's committed credit facilities require the maintenance
of the percentage of total debt to total capital of 60% or less for Ameren,
AmerenUE and AmerenCIPS. As of December 31, 2002, this ratio was approximately
50%, 43% and 50% for Ameren, AmerenUE, and AmerenCIPS, respectively. Ameren's
committed credit facilities also include indebtedness cross default provisions
that could trigger a default under these facilities in the event any subsidiary
of Ameren (subject to definition in the underlying credit agreements), other
than certain project finance subsidiaries, defaults on indebtedness in excess of
$50 million.
Most of Ameren's committed credit facilities include provisions related to
the funded status of Ameren's pension plan. These provisions either require
Ameren to meet minimum ERISA funding requirements or limit the unfunded
liability status of the plan. Under the most restrictive of these provisions
impacting Ameren facilities totaling $400 million, an event of default will
result if the unfunded liability status (as defined in the underlying credit
agreements) of Ameren's pension plan exceeds $300 million in the aggregate.
Based on the most recent valuation report available to Ameren at December 31,
2002, which was based on January 2002 asset and liability valuations, the
unfunded liability status (as defined) was $31 million. However, based on stock
market and interest rate performance during 2002, Ameren believes an excess
unfunded liability may occur. As a result, Ameren may need to terminate or
replace the affected facilities, renegotiate the facility provisions or fund any
unfunded liability shortfall. Should Ameren elect to terminate these facilities,
Ameren believes it would otherwise have sufficient liquidity to manage its
short-term funding requirements.
Other
See Note 6 - Long-Term Debt and Intercompany Notes Payable for further
information regarding our intercompany notes payable to AmerenCIPS and Ameren.
NOTE 4 - Derivative Financial Instruments
We, through AmerenEnergy and Fuels Company acting as agents on our behalf,
utilize derivatives principally to manage the risk of changes in market prices
for fuel, electricity and emission credits. Price fluctuations in fuel and
electricity cause:
o an unrealized appreciation or depreciation of our firm commitments to
purchase or sell when purchase or sales prices under the firm commitment
are compared with current commodity prices;
o market values of fuel inventories or purchased power to differ from the
cost of those commodities in inventory and under firm commitment; and
o actual cash outlays for the purchase of these commodities to differ from
anticipated cash outlays.
The derivatives that we use to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. We continually assess our supply and delivery commitment positions
against forward market prices and internal forecasts of forward prices. We
actively manage our exposure to power price risk through our power risk
management program carried out under our risk management guidelines to modify
40
our exposure to market, credit and operational risk by entering into various
offsetting transactions. In general, we believe these transactions serve to
reduce price risk for us.
In addition, we may purchase additional power, again within risk management
guidelines, in anticipation of power requirements and future price changes.
Certain derivative contracts we enter into on a regular basis as part of our
power risk management program do not qualify for hedge accounting or the normal
purchase and sale exceptions under SFAS 133. Accordingly, these contracts are
recorded at fair value with changes in the fair value charged or credited to the
income statement in the period in which the change occurred. Contracts we enter
into as part of our power risk management program may be settled by either
physical delivery or net settled with the counterparty. See also Note 1 -
Summary of Significant Accounting Policies for further information.
As of December 31, 2002, we recorded the fair value of derivative financial
instrument assets of $1 million in Other Assets and the fair value of derivative
financial instrument liabilities of $1 million in Other Deferred Credits and
Liabilities.
Cash Flow Hedges
We routinely enter into forward purchase and sales contracts for
electricity based on forecasted levels of economic generation and customer
requirements. The relative balance between customer requirements and economic
generation varies throughout the year. The contracts typically cover a period of
twelve months or less. The purpose of these contracts is to hedge against
possible price fluctuations in the spot market for the period covered under the
contracts. We formally document all relationships between hedging instruments
and hedged items, as well as our risk management objective and strategy for
undertaking various hedge transactions. The mark-to-market value of cash flow
hedges will continue to fluctuate with changes in market prices up to contract
expiration.
The pretax net gain or loss on power forward derivative instruments, which
represented the impact of discontinued cash flow hedges, the ineffective portion
of cash flow hedges, as well as the reversal of amounts previously recorded in
OCI due to transactions going to delivery or settlement, was approximately a $1
million loss for 2002 (2001 - $4 million gain).
As of December 31, 2002, we had hedged a portion of the electricity price
exposure for the upcoming twelve-month period. The mark-to-market value
accumulated in OCI for the effective portion of hedges of electricity price
exposure was a gain of less than $1 million.
As of December 31, 2002, a gain of approximately $6 million ($4 million,
net of taxes) associated with interest rate swaps was included in OCI. The swaps
were a partial hedge of the interest rate on long-term debt that was issued in
June 2002. The swaps covered the first ten years of debt that has a 30-year
maturity and the gain in OCI is being amortized over a ten-year period beginning
in June 2002.
NOTE 5 - Property and Plant, Net
At December 31, 2002 and 2001, property and plant, net consisted of the
following:
================================================================================
2002 2001
- --------------------------------------------------------------------------------
Property and plant, at original cost:
Electric $ 2,462 $ 2,141
Less accumulated depreciation and amortization 745 689
- --------------------------------------------------------------------------------
1,717 1,452
Construction work in progress: 50 60
- --------------------------------------------------------------------------------
Property and plant, net $ 1,767 $ 1,512
================================================================================
41
NOTE 6 - Long-Term Debt and Intercompany Notes Payable
The following tables summarize our long-term debt and intercompany notes
payable at December 31, 2002 and 2001:
================================================================================
2002 2001
- --------------------------------------------------------------------------------
Subordinated intercompany notes payable
- --------------------------------------------------------------------------------
2000 AmerenCIPS note 7% due 2005 (a) $ 419 $ 462
2000 Ameren note 7% due 2005 (b) 43 46
================================================================================
462 508
- --------------------------------------------------------------------------------
Unsecured notes
- --------------------------------------------------------------------------------
2000 Senior Notes Series C 7.75% due 2005 (c) (f) (g) 225 225
2000 Senior Notes Series D 8.35% due 2010 (d) (f) (g) 200 200
2002 Senior Notes Series F 7.95% due 2032 (e) (f) (g) 275 -
- --------------------------------------------------------------------------------
700 425
- --------------------------------------------------------------------------------
Unamortized discount and premium on debt (2) (1)
- --------------------------------------------------------------------------------
Maturities due within one year (50) (47)
- --------------------------------------------------------------------------------
Total long-term debt and intercompany notes payable $ 1,110 $ 885
================================================================================
(a) Interest is payable on February 1, May 1, August 1, and November 1 of each
year commencing August 1, 2000. Partial principal payments are payable
annually on May 1 with the remaining principal due May 1, 2005.
(b) Interest is payable on February 1, May 1, August 1, and November 1 of each
year commencing August 1, 2000. Partial principal payments are payable
annually on May 1 with the remaining principal due May 1, 2005.
(c) Interest is payable semiannually in arrears on May 1 and November 1 of each
year, commencing May 1, 2001. Principal will be payable on November 1,
2005.
(d) Interest is payable semiannually in arrears on May 1 and November 1 of each
year, commencing May 1, 2001. Principal will be payable on November 1,
2010.
(e) Interest is payable semiannually in arrears on June 1 and December 1 of
each year, commencing December 1, 2002. Principal will be payable on June
1, 2032.
(f) Our senior note indenture contains covenants which, among other things,
restrict dividend payments, subordinated debt interest payments and future
bond issuance if certain financial conditions are not met. These conditions
include minimum interest coverage ratios and a maximum debt to capital
ratio. At December 31, 2002, we were in compliance with all such
provisions.
(g) We may redeem these notes, in whole or in part, at any time at a redemption
price equal to 100% of the principal amount of the notes to be redeemed
plus accrued interest, if any, plus a make-whole premium, calculated using
a discount rate equal to the interest rate on comparable U.S. treasury
securities plus 25 basis points.
(h) We may redeem these notes, in whole or in part, at any time at a redemption
price equal to 100% of the principal amount of the notes to be redeemed
plus accrued interest, if any, plus a make-whole premium, calculated using
a discount rate equal to the interest rate on comparable U.S. treasury
securities plus 37.5 basis points.
The following table summarizes maturities of long-term debt and
intercompany notes payable at December 31, 2002:
========================================
----------------------------------------
2003 $ 50
2004 53
2005 584
2006 -
2007 -
----------------------------------------
Thereafter 475
----------------------------------------
Total $ 1,162
----------------------------------------
On June 6, 2002, we issued $275 million of 7.95% Senior Notes, Series E due
June 1, 2032 (Series E Notes) in a Rule 144A transaction sold to institutional
investors. Interest is payable semi-annually on June 1 and December 1 of each
year, beginning December 1, 2002. We received net proceeds of $271 million,
after debt discount and fees, that were used to reduce short-term borrowings
incurred to finance previous generating capacity additions and for general
corporate purposes. In the fourth quarter of 2002, we filed a registration
statement on Form S-4 to register the Senior Notes under the Securities Act of
1933, as amended, to permit an exchange offer of the Senior Notes. In January
2003, all holders completed their exchange of the Senior Notes for new Series F
Notes which were identical in all material respects to the Series E Notes except
that the new series of notes do not contain transfer restrictions and are
registered.
On November 1, 2000, we issued $225 million of Senior Notes, Series A due
November 1, 2005 (Series A Notes) and $200 million of Senior Notes, Series B due
November 1, 2010 (Series B Notes) (collectively, the Senior Notes) in a Rule
144A transaction sold to institutional investors. The proceeds received from the
Senior Notes were $423.6
42
million before transaction costs. In the first quarter of 2001, we filed a
registration statement on Form S-4 to register the Senior Notes under the
Securities Act of 1933, as amended, to permit an exchange offer of the Senior
Notes. In June 2001, all holders completed their exchange of the Senior Notes
for new Series C Notes and Series D Notes which are identical in all material
respects to the Series A Notes and Series B Notes, respectively, except that the
new series of notes do not contain transfer restrictions and are registered.
On May 1, 2000, AmerenCIPS transferred its electric generating assets and
related liabilities, at net book value, to us in exchange for a subordinated
promissory note from us in the principal amount of $552 million and 1,000 shares
of our common stock. On June 30, 2000, we issued a second subordinated
intercompany note in the amount of $50 million to Ameren. This note is
subordinated to all senior debt as well as to the subordinated note held by
AmerenCIPS. The two subordinated intercompany notes each have a term of five
years and bear interest at 7% based on a 10-year amortization schedule.
Our Senior Note indenture includes provisions that require us to maintain a
senior debt service coverage ratio of at least 1.75 to 1 (for both the prior
four fiscal quarters and for the next succeeding four, six-month periods) in
order to pay dividends, or to make payments of principal or interest under
certain subordinate indebtedness, excluding amounts payable under our
intercompany note payable with AmerenCIPS. For the four quarters ended December
31, 2002, this ratio was 4.10 to 1. In addition, the indenture also restricts us
from incurring any additional indebtedness, with the exception of certain
permitted indebtedness as defined in the indenture, unless our senior debt
service coverage ratio equals at least 2.5 to 1 for the most recently ended four
fiscal quarters and our senior debt to total capital ratio would not exceed 60%,
both after giving effect to the additional indebtedness on a pro-forma basis.
This debt incurrence requirement is disregarded in the event certain rating
agencies reaffirm our ratings after considering the additional indebtedness. As
of December 31, 2002, our senior debt to total capital ratio was 55%. At
December 31, 2002, we were in compliance with our Senior Note indenture and
covenants.
Amortization of debt issuance costs and premium/discount for the years
ended December 31, 2002 of $1 million (2001 - $1 million; 2000 - less than $1
million) were included in interest expense in the income statement.
NOTE 7 - Voluntary Retirement and Other Restructuring Charges
Voluntary retirement and other restructuring charges were $10 million in
2002 or $6 million, net of tax.
In December 2002, approximately 550 employees, which includes approximately
35 of our employees and additional employees providing support functions to us
through Ameren Services, accepted a voluntary retirement program that was
offered to approximately 1,000 of Ameren's 7,400 employees. Eligible employees
had to be age 50 or over, regular, full-time employees and have at least 10
years of service with Ameren. While we expect to realize significant long-term
savings as a result of this program, we incurred a pretax charge of $8 million
($5 million, net of taxes) in December 2002 related to the voluntary retirement
program. These costs consisted primarily of special termination benefits
associated with Ameren's pension and post-retirement benefit plans.
In December 2002, we announced that we were temporarily suspending
operation of two coal-fired generating units at our Meredosia, Illinois plant,
representing 126 megawatts of power generation capacity. The capacity reductions
and related severance charges resulted in a charge of $2 million ($1 million,
net of taxes) in December 2002.
43
NOTE 8 - Income Taxes
Total income tax expense for 2002 resulted in an effective tax rate of 39%
on earnings before income taxes (38% in 2001 and 38% for the period from May 1,
2000 through December 31, 2000).
Principal reasons such rates differ from the statutory federal rate for the
years ended December 31, 2002, 2001 and for the period from May 1, 2000 through
December 31, 2000 were as follows:
================================================================================
2002 2001 2000
- --------------------------------------------------------------------------------
Statutory federal income tax rate: 35% 35% 35%
Increases (decreases) from:
Depreciation differences (1) 1 -
Amortization of investment tax credit (3) (1) (2)
State income tax 5 3 5
Other 3 - -
- --------------------------------------------------------------------------------
Effective income tax rate 39% 38% 38%
- --------------------------------------------------------------------------------
Components of income tax expense for the years ended December 31, 2002,
2001 and for the period May 1, 2000 through December 31, 2000 were as follows:
================================================================================
2002 2001 2000
- --------------------------------------------------------------------------------
Taxes currently payable (principally federal):
Included in operating expenses $ (41) $ 18 $ 23
Included in other income--
Miscellaneous, net - 1 -
- --------------------------------------------------------------------------------
$ (41) $ 19 $ 23
Deferred taxes (principally federal):
Included in operating expenses--
Depreciation differences $ 60 $ 22 $ 2
Other 3 7 3
- --------------------------------------------------------------------------------
$ 63 $ 29 $ 5
Deferred investment tax credits, amortization:
Included in operating expenses $ (2) $ (1) $ (1)
- --------------------------------------------------------------------------------
Total income tax expense $ 20 $ 47 $ 27
================================================================================
In accordance with SFAS 109, "Accounting for Income Taxes," the step-up in
basis for tax purposes of the transferred assets from AmerenCIPS to us in May
2000, resulted in an additional tax basis for us and a deferred intercompany tax
gain for AmerenCIPS of approximately $552 million, resulting in a deferred tax
asset for us of approximately $219 million and an equivalent income tax payable
- - intercompany balance. This transaction was recorded as a non-cash transaction.
The deferred tax asset and intercompany tax payable are being amortized and
paid, respectively, over twenty years, the approximate remaining life of the
transferred assets.
Temporary differences gave rise to the following deferred tax assets and
deferred tax liabilities at December 31, 2002 and 2001:
================================================================================
2002 2001
- --------------------------------------------------------------------------------
Accumulated deferred income taxes:
Accelerated depreciation $ 200 $ 132
Tax basis step-up (175) (196)
Investment tax credits (6) (7)
Capitalized taxes and expenses 49 34
Deferred benefits (4) (1)
Other 2 -
- --------------------------------------------------------------------------------
Total net accumulated deferred income tax liability (asset) $ 66 $ (38)
================================================================================
44
NOTE 9 - Retirement Benefits
Pension
Ameren has defined benefit retirement plans covering substantially all of
our employees. Benefits are based on the employees' years of service and
compensation. Ameren's plans are funded in compliance with income tax
regulations and federal funding requirements. We, along with other subsidiaries
of Ameren, are a participant in Ameren's plans and are responsible for our
proportional share of the costs. Our share of the pension costs for 2002, were
$2 million (2001 and 2000 were less than $1 million) of which approximately 3%
(2001 - 4%; 2000 - 1%) was charged to construction accounts.
Ameren made cash contributions totaling $31 million to Ameren's defined
benefit retirement plan during 2002. Our share of the cash contribution was
approximately $4 million. At December 31, 2002, Ameren recorded a minimum
pension liability of $102 million, net of taxes, which resulted in a charge to
OCI and a reduction in stockholder's equity. Our share of the minimum pension
liability was $6 million, net of taxes. Based on the performance of plan assets
through December 31, 2002, Ameren expects to be required under the Employee
Retirement Income Security Act of 1974 to fund annually $150 million to $175
million in 2005, 2006 and 2007 in order to maintain minimum funding levels. In
addition, Ameren estimates the pension funding for CILCORP to be less than $1
million in 2003 and approximately $5 million in 2004. We expect our share of the
annual funding in 2005, 2006, and 2007 to be between $18 million to $21 which
includes our share related to employees of Ameren Services. These amounts are
estimates and may change based on actual stock market performance, changes in
interest rates and any changes in government regulations. At December 31, 2002,
Ameren's Net Benefit Obligation was $1,587 million and its Fair Value of Plan
Assets was $1,059 million.
Ameren's assumptions for actuarial present value of projected benefit
obligations during 2002, 2001 and 2000 were as follows:
================================================================================
2002 2001 2000
- --------------------------------------------------------------------------------
Discount rate at measurement date 6.75% 7.25% 7.50%
Expected return on plan assets 8.50% 8.50% 8.50%
Increase in future compensation 3.75% 4.25% 4.50%
- --------------------------------------------------------------------------------
Post-Retirement
Ameren's funding policy for post-retirement benefits is to annually fund
the Voluntary Employee Beneficiary Association trusts (VEBA) with the lesser of
the net periodic cost or the amount deductible for federal income tax purposes.
We, along with other subsidiaries of Ameren, are a participant in the VEBA,
which covers substantially all of our employees, and are responsible for our
proportional share of the costs. Our share of the postretirement benefit costs
for 2002 were $4 million (2001 - $3 million; 2000 - $2 million) of which
approximately 16% (2001 - 5%) were charged to construction accounts.
Ameren's assumptions for the post-retirement benefit plan obligation
measurements for the years ended December 31, 2002, 2001 and 2000 were as
follows:
================================================================================
2002 2001 2000
- --------------------------------------------------------------------------------
Discount rate at measurement date 6.75% 7.25% 7.50%
Expected return on plan assets 8.50% 8.50% 8.50%
Medical cost trend rate (initial) 10.00% 5.25% 5.00%
Medical cost trend rate (ultimate) 5.25% 5.25% 5.00%
================================================================================
NOTE 10 - Commitments and Contingencies
As a result of issues generated in the course of daily business, we are
involved in legal, tax and regulatory proceedings before various courts,
regulatory commissions and governmental agencies, some of which involve
substantial amounts of money. We believe that the final disposition of these
proceedings, except as otherwise disclosed in this Report and in the Notes to
our Financial Statements, will not have an adverse material effect on our
financial position, results of operations or liquidity.
45
Capital Expenditures
We estimate our capital expenditures over the next five years will be
approximately $200 million - $230 million, including capitalized interest. This
estimate includes capital expenditures for upgrades to existing coal and gas
fired facilities and other generation related activities, as well as for
compliance with new NOx (nitrogen oxide) control regulations, as discussed later
in this Note.
Our capital program is subject to periodic review and revision, and actual
capital costs may vary from the above estimate because of numerous factors.
These factors include changes in business conditions, acquisition of additional
generating assets, revised load growth estimates, changes in environmental
regulations, increasing costs of labor, equipment and materials, and cost of
capital.
We intend to sell at net book value approximately 550 megawatts
(approximately $260 million) of our combustion turbine generating units located
at Pinckneyville and Kinmundy, Illinois to our regulated affiliate, AmerenUE,
which wants them to comply with AmerenUE's recent Missouri electric rate case
settlement and to meet its future regulated generating capacity needs. The
transfer is subject to receipt of necessary regulatory approvals and is expected
to be completed in 2003. Cash proceeds from the sale will be applied toward
reducing our short-term money pool borrowings and for other general operating
activities. The indenture for our Senior Notes imposes limitations on the use of
proceeds of the sale of our generating units if the net book value of the sold
assets (together with prior assets sales since November 1, 2000) exceeds 25% of
consolidated tangible assets (as defined in the indenture) as of the first day
of the most recently ended fiscal quarter prior to the date the assets are sold.
We do not expect that the sale of the Pinckneyville and Kinmundy units would
exceed the 25% amount. If the sale proceeds did exceed the limitation, they
would have to be (1) reinvested in our business within 12 months, (2) used to
repay indebtedness or (3) retained by us. This transfer is expected to reduce
operating and depreciation costs for 2003.
Fuel Purchase Commitments
To supply a portion of the fuel requirements of our generating plants, we
have entered into various long-term commitments for the procurement of coal and
natural gas. In addition, we have entered into various long-term commitments for
the purchase of electricity. Total estimated fuel purchase commitments at
December 31, 2002 were as follows:
================================================================================
Coal Gas
- --------------------------------------------------------------------------------
2003 $174 $11
2004 157 4
2005 120 3
2006 96 2
2007 77 -
- --------------------------------------------------------------------------------
Thereafter 165 4
- --------------------------------------------------------------------------------
Total $789 $24
================================================================================
Leases
The following table summarizes our lease obligations at December 31, 2002:
================================================================================
Less than 1 - 3 4 - 5 After 5
Total 1 year years years years
- --------------------------------------------------------------------------------
Operating leases (a) $ 8 $ 1 $ 1 $ 1 $ 5
- --------------------------------------------------------------------------------
(a) Amounts related to certain real estate leases have indefinite payment
periods. The amounts for these items are included in the less than 1
year, 1-3 years and 4-5 years. Amounts for after 5 years are not
included in the total amount due to the indefinite periods. The
estimated obligation for after 5 years is less than $1 million
annually for the real estate leases.
We lease various facilities, office equipment, plant equipment and railcars
under operating leases. As of December 31, 2002, rental expense, included in
Other Operations and Maintenance expenses, totaled approximately $2 million
(2001 - $4 million; 2000 - $4 million).
46
Environmental Matters
We are subject to various environmental regulations by federal, state, and
local authorities. From the beginning phases of siting and development, to the
ongoing operation of existing or new electric generating facilities, our
activities involve compliance with diverse laws and regulations that address
emissions and impacts to air and water, special, protected, and cultural
resources (such as wetlands, endangered species, and archeological/historical
resources), chemical and waste handling, and noise impacts. Our activities
require complex and often lengthy processes to obtain approvals, permits, or
licenses for new, existing, or modified facilities. Additionally, the use and
handling of various chemicals or hazardous materials (including wastes) requires
preparation of release prevention plans and emergency response procedures. As
new laws or regulations are promulgated, we assess their applicability and
implement the necessary modifications to our facilities or their operations, as
required. The more significant matters are discussed below.
Clean Air Act
The Clean Air Act affects both existing generating facilities and new
projects. The Clean Air Act and many state laws require significant reductions
in SO2 (sulfur dioxide) and NOx emissions that result from burning fossil fuels.
The Clean Air Act also contains other provisions that could materially affect
some of our projects. Various provisions require permits, inspections, or
installation of additional pollution control technology or may require the
purchase of emission allowances. Certain of these provisions are described in
more detail below.
The Clean Air Act creates a marketable commodity called an SO2 "allowance."
All generating facilities over 25 megawatts that emit SO2 must obtain allowances
in order to operate after 1999. Each allowance gives the owner the right to emit
one ton of SO2. All existing generating facilities have been allocated
allowances based on a facility's past production and the statutory emission
reduction goals. If additional allowances are needed for new generating
facilities, they can be purchased from facilities having excess allowances or
from SO2 allowance banks. Our generating facilities comply with the SO2
allowance caps through the purchase of allowances or use of low sulfur fuels.
The additional costs of obtaining allowances needed for future generation
projects should not materially affect our ability to build, acquire, and operate
them.
The U.S. Environmental Protection Agency (EPA) issued a rule in October
1998 requiring 22 Eastern states and the District of Columbia to reduce
emissions of NOx in order to reduce ozone in the Eastern United States. Among
other things, the EPA's rule establishes an ozone season, which runs from May
through September, and a NOx emission budget for each state, including Illinois
where most of our facilities are located. The EPA rule requires states to
implement controls sufficient to meet their NOx budget by May 31, 2004. In
addition, the Illinois EPA already has a rule which will require additional NOx
controls by the summer of 2003. We expect to have the NOx controls in operation
by the summer of 2003 to meet both regulatory requirements.
As a result of these state requirements, we estimate spending an additional
$40 million for pollution control capital expenditures and NOx credits by 2006.
This estimate includes the assumption that the regulations will require the
installation of Selective Catalytic Reduction technology on some of our units,
as well as additional controls.
Under both Illinois and Missouri regulatory programs, we have applied for
Early Reduction NOx credits which would allow us to manage compliance strategies
by either purchasing NOx control equipment or utilizing credits. We are eligible
for such credits due to the current low NOx emission rates achieved on some of
our boilers due to past NOx control efforts.
On December 31, 2002, the EPA published in the Federal Register revisions
to the New Source Review (NSR) programs under the Clean Air Act, including
changes to the routine maintenance, repair and replacement exclusions. Various
Northeastern states have filed a petition with the United States District Court
for the District of Columbia challenging the legality of the revisions to the
NSR programs. It is likely that various industries and environmental groups will
seek to intervene in that challenge. At this time, we are unable to predict the
impact of this challenge on our future financial position, results of
operations, or liquidity.
National Ambient Air Quality Standards
In July 1997, the EPA issued regulations revising the National Ambient Air
Quality Standards for ozone and particulate matter. The standards were
challenged by industry and some states, and arguments were eventually
47
heard by the U.S. Supreme Court. In February 2001, the Supreme Court upheld the
standards in large part, but remanded a number of significant implementation
issues back to the EPA for resolution. The EPA is currently working on a new
rulemaking to address the issues raised by the Supreme Court. New ambient
standards may require significant additional reductions in SO2 and NOx emissions
from our power plants by 2008. At this time, we are unable to predict the
ultimate impact of these revised air quality standards on our future financial
position, results of operations or liquidity.
Mercury and Regional Haze Regulations
In December 1999, the EPA issued a decision to regulate mercury emissions
from coal-fired power plants by 2008. The EPA is scheduled to propose
regulations by 2004. These regulations have the potential to add significant
capital and/or operating costs to our generating systems after 2005. The EPA is
scheduled to issue Best Available Retrofit Technology (BART) guidelines to
address visibility impairment (so called "Regional Haze") across the United
States from sources of air pollution, including coal-fired power plants. The
guidelines are to be used by states to mandate pollution control measures for
SO2 and NOx emissions. These rules could also add significant pollution control
costs to our generating systems between 2008 and 2012.
Multi-Pollutant Legislation
The United States Congress has been working on legislation to consolidate
the numerous air pollution regulations facing the utility industry. This
"multi-pollutant" legislation is expected to be deliberated in Congress in 2003.
While the cost to comply with such legislation, if enacted, could be
significant, it is anticipated that the costs would be less than the combined
impact of the new National Ambient Air Quality Standards, mercury and Regional
Haze regulations, discussed above. Pollution control costs under such
legislation are expected to be incurred in phases from 2007 through 2015. At
this time, we are unable to predict the ultimate impact of the above expected
regulations and this legislation on our future financial position, results of
operations, or liquidity; however, the impact could be material.
Future initiatives regarding greenhouse gas emissions and global warming
continue to be the subject of much debate. The related Kyoto Protocol was signed
by the United States but has since been rejected by the President, who instead
has asked for an 18% decrease in carbon intensity on a voluntary basis. Future
initiatives on this issue and the ultimate effects of the Kyoto Protocol and the
President's initiatives on us are unknown. As a result of our diverse fuel
portfolio, our contribution to greenhouse gases varies. Coal-fired power plants,
however, are significant sources of carbon dioxide emissions, a principal
greenhouse gas. Therefore, our compliance costs with any mandated federal
greenhouse gas reductions in the future could be material.
Clean Water Act
In April 2002, the EPA proposed rules under the Clean Water Act that
require that cooling water intake structures reflect the best technology
available for minimizing adverse environmental impacts. These rules pertain to
existing generating facilities that currently employ a cooling water intake
structure whose flow exceeds 50 million gallons per day. A final action on the
proposed rules is expected by August 2003. The proposed rule may require us to
install additional intake screens or other protective measures, as well as
extensive site specific study and monitoring requirements. There is also the
possibility that the proposed rules may lead to the installation of cooling
towers on some of our facilities. Our compliance costs associated with the final
rules are unknown, but could be material.
Remediation
On July 30, 2002, the Illinois Attorney General's Office advised us that it
would be commencing an enforcement action concerning an inactive waste disposal
site near Coffeen, Illinois, which is the location of a disposal facility
permitted by the Illinois Environmental Protection Agency (IEPA) to receive fly
ash from the Coffeen power plant. The Illinois Attorney General also notified
the disposal facility's current and former owners as to the proposed enforcement
action. The Attorney General advised that it may initiate an action under CERCLA
to recover past costs incurred at the site ($322,000) and to obtain a
declaratory judgment as to liability for future costs. Neither us, the current
owner of the Coffeen power plant, nor AmerenCIPS, the prior owner of the Coffeen
power plant, owned or operated the disposal facility. We believe that this
matter will not have a material adverse effect on our financial position,
results of operations or liquidity.
48
Our affiliate, AmerenCIPS, is involved in a number of remediation actions
to clean up hazardous waste sites as required by federal and state law. Several
of these sites involve facilities currently owned by us. Such statutes require
that responsible parties fund remediation actions regardless of fault, legality
of original disposal, or ownership of a disposal site. We accrue for all known
environmental contamination where remediation can be reasonably estimated. As
part of the Transfer, AmerenCIPS has contractually agreed to indemnify us for
remediation costs associated with pre-existing environmental contamination at
the sites of our coal plants.
Labor Agreements
Certain of our employees are represented by the International Brotherhood
of Electrical Workers (IBEW) and the International Union of Operating Engineers
(IUOE). These employees comprise approximately 70% of our workforce. Labor
agreements covering the majority of employees represented by IBEW and IUOE
expire by June 2003. We cannot predict what issues may be raised by the
collective bargaining units and, if raised, whether negotiations concerning such
issues will be successfully concluded.
Regulation
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, we are
unable to predict the impact of these changes on our future financial position,
results of operations or liquidity. See Note 2 - Rate and Regulatory Matters for
further information.
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.
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 us for debt of comparable
maturities.
Derivative Financial Instruments
Market prices used to determine fair value are based on management's
estimates, which take into consideration factors like closing exchange prices,
over-the-counter prices, and time value of money and volatility factors. All
derivative financial instruments are carried at fair value on the consolidated
balance sheet.
Carrying amounts and estimated fair values of our financial instruments at
December 31, 2002 and 2001 were as follows:
2002 2001
===================================================================================================================
Carrying Fair Carrying Fair
Amount Value Amount Value
- -------------------------------------------------------------------------------------------------------------------
Long-term debt (including current portion) $700 $783 $424 $451
- -------------------------------------------------------------------------------------------------------------------
NOTE 12 - Subsequent Event
On January 31, 2003, after receipt of the necessary regulatory agency
approvals and clearance from the Department of Justice under the
Hart-Scott-Rodino Antitrust Improvements Act, Ameren completed its acquisition
of all of the outstanding common stock of CILCORP from AES. CILCORP is the
parent company of Peoria, Illinois-based Central Illinois Light Company, which
operated as CILCO. With the acquisition, CILCO became an Ameren subsidiary, but
remains a separate utility company, operating as AmerenCILCO. On February 4,
2003, Ameren also completed its acquisition of Medina Valley, which indirectly
owns a 40 megawatt, gas-fired electric
49
cogeneration plant. With the acquisition, Medina Valley became a wholly-owned
subsidiary of Resources Company and was renamed as AmerenEnergy Medina Valley
Cogen (No. 4), LLC. The CILCORP and AmerenEnergy Medina Valley Cogen (No. 4),
LLC financial statements will be included in Ameren's consolidated financial
statements effective with the January and February 2003 acquisition dates.
Ameren acquired CILCORP to complement its existing Illinois electric and
gas operations. The purchase included CILCO's rate-regulated electric and
natural gas businesses in Illinois serving approximately 200,000 and 205,000
customers, respectively, of which approximately 150,000 are combination electric
and gas customers. CILCO's service territory is contiguous to Ameren's service
territory and accessible by our electric generation facilities. CILCO also has a
non rate-regulated electric and gas marketing business principally focused in
the Chicago, Illinois region. Finally, the purchase includes approximately 1,200
megawatts of largely coal-fired generating capacity, most of which is expected
to become non rate-regulated in 2003.
The total purchase price was approximately $1.4 billion and included the
assumption of CILCORP and Medina Valley debt and preferred stock at closing of
approximately $900 million, with the balance of the purchase price of
approximately $500 million paid with cash on hand. The purchase price is subject
to certain adjustments for working capital and other changes pending the
finalization of CILCORP's closing balance sheet. The cash component of the
purchase price came from Ameren's issuances in September 2002 of 8.05 million
common shares and in early 2003 of 6.325 million common shares.
50
SELECTED QUARTERLY INFORMATION (Unaudited)
- -------------------------------
(In Millions)
================================================================================
Operating Operating Net
Quarter Ended: Revenues(a) Income Income
- --------------------------------------------------------------------------------
March 31, 2002 $ 176 $ 38 $ 13
March 31, 2001 164 43 13
June 30, 2002 175 26 2
June 30, 2001 162 37 12
September 30, 2002 207 49 15
September 30, 2001 236 88 43
December 31, 2002 (b) 185 26 2
December 31, 2001 168 27 8
- --------------------------------------------------------------------------------
(a) Revenues were netted with costs upon adoption of EITF 02-3 and the
rescission of EITF 98-10. See Note 1 - Summary of Significant Accounting
Policies for further information. The amount netted for each quarter is as
follows: 2002 - $87 in first quarter, $44 in second quarter, $60 in third
quarter, and $62 in fourth quarter (2001 - $43 in first quarter, $49 in
second quarter, $90 in third quarter, and $74 in fourth quarter).
(b) Amounts include Voluntary Retirement and Other Restructuring Charges of $10
million ($6 million, net of taxes). See Note 7 - Voluntary Retirement and
Other Restructuring Charges for further information.
Other impacts to quarterly earnings are due to the effect of weather on
sales and other factors that are characteristic of public utility wholesale
electric generation operations.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
This item is omitted in reliance on General Instruction (I)(2) of Form
10-K.
ITEM 11. EXECUTIVE COMPENSATION.
This item is omitted in reliance on General Instruction (I)(2) of Form
10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
This item is omitted in reliance on General Instruction (I)(2) of Form
10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS.
This item is omitted in reliance on General Instruction (I)(2) of Form
10-K.
ITEM 14. CONTROLS AND PROCEDURES.
Within 90 days prior to the date of this report, we carried out an
evaluation, under the supervision and with participation of our management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14 under the Securities Exchange Act of 1934, as
amended. Based upon that evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that our disclosure controls and procedures are
effective in timely alerting them to material information relating to
AmerenEnergy Generating Company which is required to be included in our periodic
SEC filings.
51
There have been no significant changes in our internal controls or in other
factors which could significantly affect internal controls subsequent to the
date we carried out our evaluation.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K.
(A) Financial Statements:
Pages Herein
(1) Financial Statements of Ameren Energy Generating Company which
are included at Item 8 of this report.
(a) Report of Independent Accountants........................................................................... 27
(b) Balance Sheet - December 31, 2002 and 2001.................................................................. 28
(c) Statement of Income - Years Ended December 31, 2002 and 2001 and for the Period May
1, 2000 through December 31, 2000......................................................................... 29
(d) Statement of Cash Flows - Years Ended December 31, 2002 and 2001 and for the Period
May 1, 2000 through December 31, 2000..................................................................... 30
(e) Statement of Common Stockholder's Equity - Years Ended December 31, 2002 and 2001
and for the Period May 1, 2000 through December 31, 2000.................................................. 31
(f) Notes to Financial Statements............................................................................... 32
(2) Financial Statement Schedule
None.
(3) Exhibits filed with this report are listed on the "Exhibit Index".
(B) Reports on Form 8-K
None.
(C) Exhibits.
Exhibit
Number Description
------- -----------
3.1 Articles of Incorporation of AmerenEnergy Generating Company
(Generating Company), filed March 2, 2000 (incorporated by
reference to Exhibit 3.1 to Generating Company's Registration
Statement on Form S-4 (Commission File No. 333-56594)).
3.2 Amendment to Articles of Incorporation of Generating Company,
filed April 19, 2000 (incorporated by reference to Exhibit 3.2 to
Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
3.3** By-laws of Generating Company (as amended effective January 21,
2003).
4.1 Indenture dated as of November 1, 2000, between Generating
Company and The Bank of New York, as Trustee, relating to senior
notes (Indenture) (incorporated by reference to Exhibit 4.1 to
Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
4.2 First Supplemental Indenture to the Indenture, dated as of
November 1, 2000 (including as exhibit the form of Notes)
(incorporated by reference to Exhibit 4.2 to Generating Company's
Registration Statement on Form S-4 (Commission File No.
333-56594)).
4.3 Form of Second Supplemental Indenture to the Indenture, dated as
of June 12, 2001 (including as exhibit the form of Exchange Note)
(incorporated by reference to Exhibit 4.3 to Generating Company's
Registration Statement on Form S-4 (Commission File No.
333-56594)).
52
Exhibit
Number Description
------- -----------
4.4 Third Supplemental Indenture to the Indenture, dated as of June
1, 2002 (including as exhibit the form of Note) (incorporated by
reference to Exhibit 4.1 to Generating Company's quarterly report
on Form 10-Q for the quarter ended June 30, 2002).
4.5** Fourth Supplemental Indenture to the Indenture, dated as of
January 15, 2003 (including as exhibit the form of Exchange
Note).
10.1 Asset Transfer Agreement between Generating Company and Central
Illinois Public Service Company d/b/a AmerenCIPS (AmerenCIPS)
(incorporated by reference to Exhibit 10 to AmerenCIPS' quarterly
report on Form 10-Q for the quarter ended June 30, 2000).
10.2 Amended Electric Power Supply Agreement between Generating
Company and AmerenEnergy Marketing Company (Marketing Company)
(incorporated by reference to Exhibit 10.2 to Generating
Company's Registration Statement on Form S-4 (Commission File No.
333-56594)).
10.3 Second Amended Electric Power Supply Agreement between Generating
Company and Marketing Company (incorporated by reference to
Exhibit 10.1 to Ameren Corporation's (Ameren's) quarterly report
on Form 10-Q for the quarter ended March 31, 2001).
10.4 Electric Power Supply Agreement between Marketing Company and
AmerenCIPS (incorporated by reference to Exhibit 10.3 to
Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
10.5 Amended Electric Power Supply Agreement between Marketing Company
and AmerenCIPS (incorporated by reference to Exhibit 10.2 to
Ameren's quarterly report on Form 10-Q for the quarter ended
March 31, 2001).
10.6 Power Sales Agreement between Marketing Company and Union
Electric Company d/b/a AmerenUE (AmerenUE) (incorporated by
reference to Exhibit 10.1 to AmerenUE's quarterly report on Form
10-Q for the quarter ended September 30, 2001).
10.7 Amended Joint Dispatch Agreement among Generating Company,
AmerenCIPS and AmerenUE (incorporated by reference to Exhibit
10.4 to Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
10.8 Agency Agreement among Generating Company, AmerenUE, Marketing
Company and AmerenEnergy, Inc. (incorporated by reference to
Exhibit 10.5 to Generating Company's Registration Statement on
Form S-4 (Commission File No. 333-56594)).
10.9 General Services Agreement between Ameren Services Company
(Ameren Services) and AmerenEnergy Resources Company (Resources)
(incorporated by reference to Exhibit 10.6 to Generating
Company's Registration Statement on Form S-4 (Commission File No.
333-56594)).
10.10 Fuel Services Agreement between AmerenEnergy Fuels and Services
Company and Resources (incorporated by reference to Exhibit 10.7
to Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
10.11 Form of Parallel Operating Agreement between Generating Company
and Ameren Services (incorporated by reference to Exhibit 10.8 to
Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
10.12 Committed Unit Contribution Agreement between Generating Company
and Resources (on behalf of itself and AmerenEnergy Development
Company (Development Company) (incorporated by reference to
Exhibit 10.9 to Generating Company's Registration Statement on
Form S-4 (Commission File No. 333-56594)).
10.13 Lease Agreement between Generating Company and Development
Company (incorporated by reference to Exhibit 10.10 to Generating
Company's Registration Statement on Form S-4 (Commission File No.
333-56594)).
53
Exhibit
Number Description
------- -----------
10.14 Amended and Restated Appendix I ITC Agreement dated February 14,
2003 between the Midwest Independent Transmission System
Operator, Inc. (Midwest ISO) and GridAmerica LLC (GridAmerica)
(incorporated by reference to Exhibit 10.17 of Ameren's annual
report on Form 10-K for the year ended December 31, 2002).
10.15 Amended and Restated Limited Liability Company Agreement of
GridAmerica dated February 14, 2003 (incorporated by reference to
Exhibit 10.18 of Ameren's annual report on Form 10-K for the year
ended December 31, 2002).
10.16 Amended and Restated Master Agreement by and among GridAmerica,
GridAmerica Holdings Inc., GridAmerica Companies and National
Grid USA dated February 14, 2003 (incorporated by reference to
Exhibit 10.19 of Ameren's annual report on Form 10-K for the year
ended December 31, 2002).
10.17 Amended and Restated Operation Agreement by and among AmerenUE,
AmerenCIPS, American Transmission Systems, Inc., Northern Indiana
Public Service Company and GridAmerica dated February 14, 2003
(incorporated by reference to Exhibit 10.20 of Ameren's annual
report on Form 10-K for the year ended December 31, 2002).
10.18 Power Sales Agreement between Marketing Company and AmerenUE
(incorporated by reference to Exhibit 10.1 to Generating
Company's quarterly report on Form 10-Q for the quarter ended
March 31, 2002).
10.19* Long-Term Incentive Plan of 1998 (incorporated by reference to
Exhibit 10.1 to Ameren's annual report on Form 10-K for the year
ended December 31, 1998).
10.20* Change of Control Severance Plan (incorporated by reference to
Exhibit 10.2 to Ameren's annual report on Form 10-K for the year
ended December 31, 1998).
10.21* Ameren's Deferred Compensation Plan for Members of the Ameren
Leadership Team as amended and restated effective January 1, 2001
(incorporated by reference to Exhibit 10.1 to Ameren's annual
report on Form 10-K for the year ended December 31, 2000).
10.22* Ameren's Deferred Compensation Plan for Members of the Board of
Directors (incorporated by reference to Exhibit 10.4 to Ameren's
annual report on Form 10-K for the year ended December 31, 1998).
10.23* Ameren's Executive Incentive Compensation Program Elective
Deferral Provisions for Members of the Ameren Leadership Team as
amended and restated effective January 1, 2001 (incorporated by
reference to Exhibit 10.2 to Ameren's annual report on Form 10-K
for the year ended December 31, 2000).
12.1** Statement of Computation of Ratio of Earnings to Fixed Charges.
99.1** Certificate of Chief Executive Officer required by Section 906 of
the Sarbanes-Oxley Act of 2002.
99.2** Certificate of Chief Financial Officer required by Section 906 of
the Sarbanes-Oxley Act of 2002.
- ---------------------------
* Management compensatory plan or arrangement.
** Filed herewith.
Note: Reports of Ameren Corporation on Forms 10-K, 10-Q and 8-K are on file
with the Securities and Exchange Commission (the "SEC") under File No.
1-14756.
Reports of Union Electric Company on Forms 10-K, 10-Q and 8-K are on file
with the SEC under File No. 1-2967.
Reports of Central Illinois Public Service Company on Forms 10-K, 10-Q
and 8-K are on file with the SEC under File No. 1-3672.
Reports of CILCORP Inc. on Forms 10-K, 10-Q, and 8-K are on file with the
SEC under File No. 1-8946.
Reports of Central Illinois Light Company on Forms 10-K, 10-Q and 8-K are
on file with the SEC under File No. 1-2732.
54
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.
AMEREN ENERGY GENERATING COMPANY
(Registrant)
Date: March 31, 2003 By /s/ DANIEL F. COLE
--------------------------------
Daniel F. Cole
President
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 Date
--------- ----- ----
/s/ DANIEL F. COLE President and Director March 31, 2003
- ------------------------ (Principal Executive Officer
Daniel F. Cole
/s/ PAUL A. AGATHEN Senior Vice President and March 31, 2003
- ------------------------ Director
Paul A. Agathen
/s/ WARNER L. BAXTER Senior Vice President and March 31, 2003
- ------------------------ Director
Warner L. Baxter (Principal Financial Officer)
/s/ MARTIN J. LYONS Vice President and Controller March 31, 2003
- ------------------------ (Principal Accounting Officer)
Martin J. Lyons
CERTIFICATIONS
I, Daniel F. Cole, certify that:
1. I have reviewed this annual report on Form 10-K of Ameren Energy
Generating Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
55
CERTIFICATIONS (CONTINUED)
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in
this annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 31, 2003 /s/ Daniel F. Cole
----------------------------------
Daniel F. Cole
Chief Executive Officer
I, Warner L. Baxter, certify that:
1. I have reviewed this annual report on Form 10-K of Ameren Energy
Generating Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
56
CERTIFICATIONS (CONTINUED)
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 31, 2003 /s/ Warner L. Baxter
----------------------------------
Warner L. Baxter
Chief Financial Officer
57
EXHIBIT INDEX
Exhibit
Number Description
------- -----------
3.1 Articles of Incorporation of AmerenEnergy Generating Company
(Generating Company), filed March 2, 2000 (incorporated by
reference to Exhibit 3.1 to Generating Company's Registration
Statement on Form S-4 (Commission File No. 333-56594)).
3.2 Amendment to Articles of Incorporation of Generating Company,
filed April 19, 2000 (incorporated by reference to Exhibit 3.2 to
Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
3.3** By-laws of Generating Company (as amended effective January 21,
2003).
4.1 Indenture dated as of November 1, 2000, between Generating
Company and The Bank of New York, as Trustee, relating to senior
notes (Indenture) (incorporated by reference to Exhibit 4.1 to
Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
4.2 First Supplemental Indenture to the Indenture, dated as of
November 1, 2000 (including as exhibit the form of Notes)
(incorporated by reference to Exhibit 4.2 to Generating Company's
Registration Statement on Form S-4 (Commission File No.
333-56594)).
4.3 Form of Second Supplemental Indenture to the Indenture, dated as
of June 12, 2001 (including as exhibit the form of Exchange Note)
(incorporated by reference to Exhibit 4.3 to Generating Company's
Registration Statement on Form S-4 (Commission File No.
333-56594)).
4.4 Third Supplemental Indenture to the Indenture, dated as of June
1, 2002 (including as exhibit the form of Note) (incorporated by
reference to Exhibit 4.1 to Generating Company's quarterly report
on Form 10-Q for the quarter ended June 30, 2002).
4.5** Fourth Supplemental Indenture to the Indenture, dated as of
January 15, 2003 (including as exhibit the form of Exchange
Note).
10.1 Asset Transfer Agreement between Generating Company and Central
Illinois Public Service Company d/b/a AmerenCIPS (AmerenCIPS)
(incorporated by reference to Exhibit 10 to AmerenCIPS' quarterly
report on Form 10-Q for the quarter ended June 30, 2000).
10.2 Amended Electric Power Supply Agreement between Generating
Company and AmerenEnergy Marketing Company (Marketing Company)
(incorporated by reference to Exhibit 10.2 to Generating
Company's Registration Statement on Form S-4 (Commission File No.
333-56594)).
10.3 Second Amended Electric Power Supply Agreement between Generating
Company and Marketing Company (incorporated by reference to
Exhibit 10.1 to Ameren Corporation's (Ameren's) quarterly report
on Form 10-Q for the quarter ended March 31, 2001).
10.4 Electric Power Supply Agreement between Marketing Company and
AmerenCIPS (incorporated by reference to Exhibit 10.3 to
Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
10.5 Amended Electric Power Supply Agreement between Marketing Company
and AmerenCIPS (incorporated by reference to Exhibit 10.2 to
Ameren's quarterly report on Form 10-Q for the quarter ended
March 31, 2001).
10.6 Power Sales Agreement between Marketing Company and Union
Electric Company d/b/a AmerenUE (AmerenUE) (incorporated by
reference to Exhibit 10.1 to AmerenUE's quarterly report on Form
10-Q for the quarter ended September 30, 2001).
10.7 Amended Joint Dispatch Agreement among Generating Company,
AmerenCIPS and AmerenUE (incorporated by reference to Exhibit
10.4 to Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
10.8 Agency Agreement among Generating Company, AmerenUE, Marketing
Company and AmerenEnergy, Inc. (incorporated by reference to
Exhibit 10.5 to Generating Company's Registration Statement on
Form S-4 (Commission File No. 333-56594)).
58
Exhibit
Number Description
------- -----------
10.9 General Services Agreement between Ameren Services Company
(Ameren Services) and AmerenEnergy Resources Company (Resources)
(incorporated by reference to Exhibit 10.6 to Generating
Company's Registration Statement on Form S-4 (Commission File No.
333-56594)).
10.10 Fuel Services Agreement between AmerenEnergy Fuels and Services
Company and Resources (incorporated by reference to Exhibit 10.7
to Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
10.11 Form of Parallel Operating Agreement between Generating Company
and Ameren Services (incorporated by reference to Exhibit 10.8 to
Generating Company's Registration Statement on Form S-4
(Commission File No. 333-56594)).
10.12 Committed Unit Contribution Agreement between Generating Company
and Resources (on behalf of itself and AmerenEnergy Development
Company (Development Company) (incorporated by reference to
Exhibit 10.9 to Generating Company's Registration Statement on
Form S-4 (Commission File No. 333-56594)).
10.13 Lease Agreement between Generating Company and Development
Company (incorporated by reference to Exhibit 10.10 to Generating
Company's Registration Statement on Form S-4 (Commission File No.
333-56594)).
10.14 Amended and Restated Appendix I ITC Agreement dated February 14,
2003 between the Midwest Independent Transmission System
Operator, Inc. (Midwest ISO) and GridAmerica LLC (GridAmerica)
(incorporated by reference to Exhibit 10.17 of Ameren's annual
report on Form 10-K for the year ended December 31, 2002).
10.15 Amended and Restated Limited Liability Company Agreement of
GridAmerica dated February 14, 2003 (incorporated by reference to
Exhibit 10.18 of Ameren's annual report on Form 10-K for the year
ended December 31, 2002).
10.16 Amended and Restated Master Agreement by and among GridAmerica,
GridAmerica Holdings Inc., GridAmerica Companies and National
Grid USA dated February 14, 2003 (incorporated by reference to
Exhibit 10.19 of Ameren's annual report on Form 10-K for the year
ended December 31, 2002).
10.17 Amended and Restated Operation Agreement by and among AmerenUE,
AmerenCIPS, American Transmission Systems, Inc., Northern Indiana
Public Service Company and GridAmerica dated February 14, 2003
(incorporated by reference to Exhibit 10.20 of Ameren's annual
report on Form 10-K for the year ended December 31, 2002).
10.18 Power Sales Agreement between Marketing Company and AmerenUE
(incorporated by reference to Exhibit 10.1 to Generating
Company's quarterly report on Form 10-Q for the quarter ended
March 31, 2002).
10.19* Long-Term Incentive Plan of 1998 (incorporated by reference to
Exhibit 10.1 to Ameren's annual report on Form 10-K for the year
ended December 31, 1998).
10.20* Change of Control Severance Plan (incorporated by reference to
Exhibit 10.2 to Ameren's annual report on Form 10-K for the year
ended December 31, 1998).
10.21* Ameren's Deferred Compensation Plan for Members of the Ameren
Leadership Team as amended and restated effective January 1, 2001
(incorporated by reference to Exhibit 10.1 to Ameren's annual
report on Form 10-K for the year ended December 31, 2000).
10.22* Ameren's Deferred Compensation Plan for Members of the Board of
Directors (incorporated by reference to Exhibit 10.4 to Ameren's
annual report on Form 10-K for the year ended December 31, 1998).
Ameren's Executive Incentive Compensation Program Elective
10.23* Deferral Provisions for Members of the Ameren Leadership Team as
amended and restated effective January 1, 2001 (incorporated by
reference to Exhibit 10.2 to Ameren's annual report on Form 10-K
for the year ended December 31, 2000).
12.1** Statement of Computation of Ratio of Earnings to Fixed Charges.
59
Exhibit
Number Description
------- -----------
99.1** Certificate of Chief Executive Officer required by Section 906 of
the Sarbanes-Oxley Act of 2002.
99.2** Certificate of Chief Financial Officer required by Section 906 of
the Sarbanes-Oxley Act of 2002.
- -----------------------
* Management compensatory plan or arrangement.
** Filed herewith.
Note: Reports of Ameren Corporation on Forms 10-K, 10-Q and 8-K are on file
with the Securities and Exchange Commission (the "SEC") under File No.
1-14756.
Reports of Union Electric Company on Forms 10-K, 10-Q and 8-K are on file
with the SEC under File No. 1-2967.
Reports of Central Illinois Public Service Company on Forms 10-K, 10-Q
and 8-K are on file with the SEC under File No. 1-3672.
Reports of CILCORP Inc. on Forms 10-K, 10-Q, and 8-K are on file with the
SEC under File No. 1-8946.
Reports of Central Illinois Light Company on Forms 10-K, 10-Q and 8-K are
on file with the SEC under File No. 1-2732.
60