EXHIBIT 13.1
RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Ameren Corporation is responsible for the information
and representations contained in the consolidated financial statements and in
other sections of this Annual Report. The consolidated financial statements have
been prepared in conformity with accounting principles generally accepted in the
United States of America. Other information included in this report is
consistent, where applicable, with the consolidated financial statements.
The Company maintains a system of internal accounting controls designed
to provide reasonable assurance as to the integrity of the financial records and
the protection of assets. Qualified personnel are selected and an organization
structure is maintained that provides for appropriate functional responsibility.
Written policies and procedures have been developed and are revised as
necessary. The Company maintains and supports an extensive program of internal
audits with appropriate management follow up.
The Board of Directors, through its Auditing Committee comprised of
outside directors, is responsible for ensuring that both management and the
independent accountants fulfill their respective responsibilities relative to
the financial statements. Moreover, the independent accountants have full and
free access to meet with the Auditing Committee, with or without management
present, to discuss auditing or financial reporting matters.
/s/ Charles W. Mueller /s/ Warner L. Baxter
Charles W. Mueller Warner L. Baxter
Chairman and Chief Executive Officer Senior Vice President, Finance
February 13, 2003 February 13, 2003
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF AMEREN CORPORATION:
In our opinion, the accompanying consolidated balance sheet and the
related consolidated statements of income, common stockholders' equity and cash
flows present fairly, in all material respects, the financial position of Ameren
Corporation and its subsidiaries at December 31, 2002, and 2001, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2002, 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 audits. We
conducted our audits 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
16
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Ameren Corporation is a public utility holding company registered under the
Public Utility Holding Company Act of 1935 (PUHCA) and is headquartered in St.
Louis, Missouri. Our 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. Our
primary subsidiaries 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 Central Illinois Public Service Company, which operates a rate-regulated
electric and natural gas transmission and distribution business in Illinois
as AmerenCIPS.
o Central Illinois Light Company, a subsidiary of CILCORP Inc., 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. We completed our 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 AmerenEnergy Generating
Company (Generating Company) that operates non rate-regulated electric
generation in Missouri and Illinois, AmerenEnergy Marketing Company
(Marketing Company), which markets power for periods over one year,
AmerenEnergy Fuels and Services Company, which procures fuel and manages
the related risks for our affiliated companies and AmerenEnergy Medina
Valley Cogen (No. 4), LLC which indirectly owns a 40 megawatt, gas-fired
electric generation plant. On February 4, 2003, we completed our
acquisition of AES Medina Valley Cogen (No. 4), LLC 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 our affiliated companies for transactions of
primarily less than one year.
o Electric Energy, Inc. (EEI), which operates electric generation and
transmission facilities in Illinois. We have a 60% ownership interest in
EEI and consolidate it for financial reporting purposes.
o Ameren Services Company, which provides shared support services to us and
our subsidiaries.
When we refer to Ameren, our, we or us, we are referring to Ameren
Corporation and its subsidiaries on a consolidated basis. In certain
circumstances, our subsidiaries are specifically referenced in order to
distinguish among their different business activities. The financial results of
CILCORP have not been included or discussed in this report except with regard to
certain forward looking information. All tabular dollar amounts are in millions,
unless otherwise indicated.
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.
With approximately 85% of our revenues directly subject to regulation by various
state and federal agencies, decisions by regulators can have a material impact
on the price we charge for our services. We principally utilize coal, nuclear
fuel, natural gas and oil in our operations. The prices for these commodities
can fluctuate significantly due to the world economic and political environment,
weather, production levels and many other factors. We do not have fuel cost
recovery mechanisms in Missouri or Illinois for our electric utility businesses,
but we do have gas cost recovery mechanisms in each state for our gas utility
businesses. In addition, our electric rates in Missouri and Illinois are largely
set through 2006. 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 transmission and distribution
systems, 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.
WWW.AMEREN.COM 17
RESULTS OF OPERATIONS
Earnings Summary
Our net income for 2002, 2001 and 2000, was $382 million ($2.61 per share
before dilution), $469 million ($3.41 per share before dilution), and $457
million ($3.33 per share), respectively. Net income in 2002 included voluntary
retirement and other restructuring charges (40 cents per share), which consisted
of a voluntary retirement program, the retirement of our Venice, Illinois plant,
and the temporary suspension of operation of two coal-fired generating units at
our Meredosia, Illinois plant. 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" (5 cents per share).
The following table reconciles our net income to net income excluding
voluntary retirement and restructuring charges and SFAS 133 adoption for the
years ended December 31, 2002, 2001, and 2000:
<Table>
<Caption>
2002 2001 2000
-------- -------- --------
Net income $ 382 $ 469 $ 457
Earnings per share - basic $ 2.61 $ 3.41 $ 3.33
Voluntary retirement and
other restructuring charges,
net of taxes 58 -- --
SFAS 133 adoption,
net of taxes -- 7 --
Cents per share $ 0.40 $ 0.05 $ --
-------- -------- --------
Net income excluding
restructuring charges
and SFAS 133 adoption $ 440 $ 476 $ 457
Earnings per share,
excluding restructuring
charges and SFAS 133
adoption - basic $ 3.01 $ 3.46 $ 3.33
======== ======== ========
</Table>
Excluding the charges discussed above, our net income in 2002 decreased $36
million from 2001, primarily due to the impact of the settlement of our Missouri
electric rate case (26 cents per share), increased costs of employee benefits
(15 cents per share), higher depreciation (17 cents per share), excluding the
effect of the rate case that is included in the 26 cents above, and a decline in
industrial sales due to the continued soft economy. Increased average shares
outstanding (8.8 million shares) and financing costs also reduced earnings per
share in 2002 (29 cents per share). Factors decreasing net income in 2002 were
partially offset by favorable weather conditions (24 cents per share), sales of
emission credits by EEI (10 cents per share) and organic growth.
Excluding the charges discussed above, our net income in 2001 increased $19
million from 2000, primarily due to a reduction in estimated credits to Missouri
customers (33 cents per share) and organic growth, partially offset by increased
costs of employee benefits (13 cents per share), higher depreciation and
interest expense, and a refueling outage at Callaway. There was not a refueling
at Callaway in 2000.
As a holding company, our net income and cash flows are primarily generated
by our principal operating subsidiaries, AmerenUE, AmerenCIPS and Generating
Company. These subsidiaries also file quarterly and annual reports with the
Securities and Exchange Commission (SEC). The contribution by our principal
operating subsidiaries to net income for the years ended December 31, 2002,
2001, and 2000 were as follows:
<Table>
<Caption>
2002 2001 2000
------ ------ ------
PRIMARILY RATE-REGULATED
OPERATIONS:
AmerenUE(a) $ 336 $ 365 $ 344
AmerenCIPS(b) 23 42 75
------ ------ ------
$ 359 $ 407 $ 419
------ ------ ------
PRIMARILY NON RATE-REGULATED
OPERATIONS:
Generating Company(a)(b)(c) 32 76 44
OTHER (9) (14) (6)
------ ------ ------
AMEREN NET INCOME $ 382 $ 469 $ 457
====== ====== ======
</Table>
(a) Includes earnings from interchange sales by AmerenEnergy that provided
approximately $20 million of AmerenUE's net income and $10 million of
Generating Company's net income in 2002.
(b) 2000 data represents the period from May 1, 2000 through December 31, 2000,
which was Generating Company's initial eight months of operation. Prior to
May 1, 2000, AmerenCIPS operated the generating facilities now operated by
Generating Company.
(c) Includes earnings from contracts to supply power to our rate-regulated
AmerenCIPS customers.
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, we completed our acquisition of
all of the outstanding common stock of CILCORP Inc. from AES. CILCORP is the
parent company of Peoria, Illinois-based Central Illinois Light Company, which
operated as CILCO. With the
18
acquisition, CILCO became an Ameren subsidiary, but remains a separate utility
company, operating as AmerenCILCO. On February 4, 2003, we also completed our
acquisition of AES Medina Valley Cogen (No. 4), LLC (Medina Valley) which
indirectly owns a 40 megawatt, gas-fired electric generation plant. With the
acquisition, Medina Valley became a wholly-owned subsidiary of Resources Company
which we renamed AmerenEnergy Medina Valley Cogen (No. 4), LLC. The CILCORP and
AmerenEnergy Medina Valley Cogen (No. 4), LLC financial statements will be
included in our consolidated financial statements effective with the January and
February 2003 acquisition dates.
We acquired CILCORP to complement our 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 our service territory. In
addition, 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 shares. See Common Stock
Offering below.
COMMON STOCK OFFERING
In early 2003, Ameren issued 6.325 million shares of common stock at $40.50
per share. We received net proceeds after fees of $248 million, which were used
to fund a portion of the purchase price for our acquisition of CILCORP and for
general corporate purposes.
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 Corporation'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 Corporation,
AmerenUE and AmerenCIPS and increased the ratings of Generating Company. At the
same time, Standard & Poor's changed the outlook assigned to all of Ameren's
ratings to stable. Moody's also lowered Ameren Corporation'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.
As of February 2003, the ratings by Moody's and Standard & Poor's were as
follows:
<Table>
<Caption>
Standard
Moody's & 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+
GENERATING COMPANY:
Unsecured debt A3/Baa2 A-
</Table>
Standard & Poor's increased the ratings of CILCORP and CILCO subsequent to
the acquisition of these entities by Ameren Corporation. 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 these ratings. Moody's also assigned a stable outlook to the
ratings for CILCORP and AmerenCILCO.
Any adverse change in 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.
WWW.AMEREN.COM 19
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:
<Table>
<Caption>
2002 2001
------ ------
OPERATING REVENUES:
Effect of abnormal weather(estimate) $ 82 $ 10
Growth and other (estimate) 22 118
2002 Missouri rate settlement (47) --
Credit to customers (10) 75
Interchange revenues (109) (168)
EEI 75 (54)
------ ------
Total variation in electric
operating revenues 13 (19)
------ ------
FUEL AND PURCHASED POWER:
Fuel:
Generation (46) 19
Price 5 (28)
Generation efficiencies and other 1 6
Purchased power 174 69
EEI (45) 45
------ ------
Total variation in fuel
and purchased power 89 111
------ ------
CHANGE IN ELECTRIC MARGIN $ 102 $ 92
====== ======
</Table>
Electric margin increased $102 million for the year ended December 31, 2002
compared to 2001. Increases in electric margin in 2002 were primarily
attributable to more favorable weather conditions and increased sales of
emission credits. Weather sensitive residential electric kilowatthour sales in
2002 increased 7% and commercial electric kilowatthour sales increased 2%.
However, industrial sales were approximately 5% lower in 2002 as compared to
2001 due primarily to the impact of the soft economy. Revenues were also reduced
by $47 million in 2002 due to the settlement of the Missouri electric rate case.
Contribution to electric margin from EEI increased in 2002 principally due to
EEI's sale of $38 million in emission credits, which is included in the overall
$75 million increase in EEI revenues. The remaining EEI increase was due to
increased sales to its principal customer, which also resulted in an increase in
fuel and purchased power. Interchange revenues decreased due to lower energy
prices and less low-cost generation available for sale, resulting primarily from
increased demand for generation from native load customers. Fuel and purchased
power were reduced in 2002 due primarily to lower energy prices, partially
offset by increased fuel and purchase power costs due to increased kilowatthour
sales and unscheduled coal plant outages. We expect that revenues will continue
to be negatively affected by the settlement of the Missouri rate case reached in
2002, which requires the phase-in of $30 million of electric rate reductions
effective April 1, 2003 and $30 million effective April 1, 2004. In addition, 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 did not have any impact on operating or net
income for any period or stockholders' equity. The operating revenues and costs
netted for the year ended December 31, 2002 were $738 million (2001 - $648
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 margin increased $92 million for the year ended December 31, 2001
compared to 2000, primarily due to a $75 million reduction in the estimated
credits to Missouri electric customers. During the year ended December 31, 2001,
we reduced the estimated credit previously recorded for the plan year ended June
30, 2001 by $10 million, compared to estimated credits of $65 million recorded
in 2000. In addition, industrial sales rose 11% primarily due
20
to a new electric service industrial contract that was effective August 2000.
Our residential sales were comparable to the prior year while commercial sales
rose 1%. These increases were partially offset by a 31% decrease in interchange
sales and reduced EEI sales. The $111 million decrease in fuel and purchased
power costs for 2001, compared to 2000, was primarily due to reduced interchange
sales.
Gas Operations
Our gas margin decreased $3 million in 2002 as compared to 2001 with
revenues decreasing by $27 million and costs decreasing by $24 million. The
decrease in margin was primarily due to the timing of revenue recovery under
purchased gas adjustment clauses and warmer winter weather early in 2002,
partially offset by increased gas sales due to colder than normal temperatures
in late 2002.
Gas margin in 2001 increased $6 million, compared to 2000, primarily due to
higher gas costs recovered through purchased gas adjustment clauses, partially
offset by lower total sales of 9% resulting from unusually warm winter weather.
Other Operating Expenses
OTHER OPERATIONS AND MAINTENANCE
Other operations and maintenance expenses increased $70 million in 2002
compared to 2001, primarily due to higher employee benefit costs ($35 million),
related to increasing healthcare costs and the investment performance of
employee benefit plans' assets, higher wages and higher plant maintenance
expenses. 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 $58 million in 2001
compared to 2000, primarily due to higher employee benefit costs in 2001 ($29
million), resulting from increasing healthcare costs and the investment
performance of employee benefit plans' assets, a refueling outage at Callaway in
2001 versus no refueling in 2000, and increased costs of professional services.
In 2000, we recorded a $25 million charge to earnings related to our withdrawal
from the Midwest Independent System Operator (Midwest ISO). The charge reduced
earnings $15 million, net of taxes, or 11 cents per share. See Regulatory
Matters.
RESTRUCTURING CHARGES
Voluntary retirement and other restructuring charges of $92 million in 2002
consisted primarily of a voluntary retirement program charge of $75 million
based on voluntary retirements of approximately 550 employees. 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 our
plans to retire 343 megawatts of rate-regulated capacity at AmerenUE's Venice,
Illinois plant and temporarily suspend operations of two coal-fired generating
units (126 megawatts) at Generating Company's Meredosia, Illinois plant, which
resulted in a total charge of approximately $17 million.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization expenses increased $25 million in 2002 and
$23 million in 2001 compared to the prior years. These net increases were
primarily due to our investment in combustion turbine electric generating plants
and coal-fired power plants. The increase in 2002 was partially offset by a
reduction of depreciation rates ($15 million) based on an updated analysis of
asset values, service lives and accumulated depreciation levels that was
included in our 2002 Missouri electric rate case settlement.
INCOME TAXES
Income tax expense decreased $50 million in 2002, compared to 2001,
primarily due to lower pretax income. Income tax expense for 2001 was comparable
to 2000.
OTHER TAXES
Other taxes expense in 2002 was comparable to 2001. Other tax expense
decreased $4 million in 2001, compared to 2000, primarily due to a decrease in
gross receipts taxes related to our Illinois jurisdiction.
Other Income and Deductions
Other income and deductions (excluding income taxes) decreased $48 million
in 2002, compared to the prior year. The decrease was primarily due to the cost
of economic development and energy assistance programs included in the
settlement of the Missouri electric rate case ($26 million) and an increase in
the deduction for minority interest earnings principally related to EEI's sale
of emission credits ($10 million). Other income and deductions (excluding income
taxes) increased $21 million in 2001, compared to 2000, primarily due to
contributions in aid of construction ($7 million), decreased charitable
contributions, and life insurance proceeds. See Note 10 - Miscellaneous, Net to
our Consolidated Financial Statements for further information.
WWW.AMEREN.COM 21
Interest
Interest expense increased $20 million in 2002, compared to 2001 primarily
due to the interest expense component associated with the $345 million of
adjustable conversion rate equity security units we issued in March 2002 and
Generating Company's issuance of $275 million of 7.95% notes in June 2002.
Proceeds from these offerings were used to repay lower cost short-term
borrowings and for general corporate purposes. Interest expense increased $19
million in 2001, compared to 2000, primarily due to increased debt related to
the construction and purchase of combustion turbine generating facilities,
partially offset by lower interest rates.
LIQUIDITY AND CAPITAL RESOURCES
Operating
Our cash flows provided by operating activities totaled $833 million for
2002, compared to $738 million for 2001, and $864 million for 2000. Cash
provided from operations increased in 2002, primarily as a result of higher cash
earnings resulting from favorable weather and the sale of emission credits.
These increases were partially offset by payments of customer sharing credits
under AmerenUE's now-expired electric alternative regulation plan ($40 million),
discretionary pension plan contributions ($31 million) and the timing of
payments on accounts payable and accrued taxes. Cash flow from operations
decreased in 2001, principally due to the timing of credits provided to
AmerenUE's Missouri electric customers and changes in working capital
requirements, partially offset by increased earnings.
The tariff-based gross margins of our rate-regulated utility operating
companies continue to be our principal source of cash from operating activities.
Our diversified retail customer mix of primarily rate-regulated residential,
commercial and industrial classes and a commodity mix of gas and electric
service provide a reasonably predictable source of cash flows. In addition, we
plan to utilize short-term debt to support normal operations and other temporary
capital requirements.
PENSION FUNDING
We made cash contributions totaling $31 million to our defined benefit
retirement plan during 2002. At December 31, 2002, we also 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 stockholders'
equity.
Based on the performance of plan assets through December 31, 2002, we
expect to be required under the Employee Retirement Income Security Act of 1974
to fund approximately $150 million to $175 million annually, including CILCORP,
in 2005, 2006 and 2007 in order to maintain minimum funding levels for our
pension plans. In addition, we estimate the pension funding for CILCORP to be
less than $1 million in 2003 and approximately $5 million in 2004. These amounts
are estimates and may change based on actual stock market performance, changes
in interest rates, and any pertinent changes in government regulations. See
Benefit Plan Accounting under Accounting Matters - Critical Accounting Policies
below.
Investing
Our net cash used in investing activities was $803 million in 2002 compared
to $1.1 billion in 2001 and $911 million in 2000. In 2002, construction
expenditures in our rate-regulated operations were $603 million (2001 - $671
million; 2000 - $369 million), primarily related to various upgrades at our coal
power plants and further construction of combustion turbine generating units.
Construction expenditures in our non rate-regulated operations were $184 million
in 2002 (2001 - $431 million; 2000 -$560 million), primarily related to the
construction of combustion turbine generating units. In 2002, we placed into
service 240 megawatts (approximately $135 million) of combustion turbine
electric generation capacity in our rate-regulated operations and approximately
470 megawatts (approximately $215 million) in our non rate-regulated operations.
In 2001 and 2000, we added approximately 850 megawatts (approximately $530
million) and approximately 690 megawatts (approximately $320 million),
respectively, of non rate-regulated combustion turbine generating capacity.
For the five-year period 2003 through 2007, construction expenditures are
estimated to approximate $3 billion - $3.3 billion, of which approximately $675
million is expected in 2003. This estimate includes capital expenditures related
to CILCORP's operations, the purchase of new combustion turbine generating
facilities at AmerenUE and the replacement of steam generators at AmerenUE's
Callaway nuclear plant. In addition, this estimate includes capital expenditures
for transmission, distribution and other generation-related activities, as well
as for compliance with new NO(x) (nitrogen oxide) control regulations, as
discussed in Environmental below.
22
As a part of the settlement of the Missouri electric rate case in 2002 (see
Regulatory Matters below), AmerenUE committed to making $2.25 billion to $2.75
billion in infrastructure investments from January 1, 2002 through June 30,
2006. These investments include, among other things, the addition of more than
700 megawatts of new generation capacity and the replacement of steam generators
at AmerenUE's Callaway nuclear plant. The requirements for 700 megawatts of new
generation are expected to be satisfied by 240 megawatts added in 2002, as
discussed above, and the proposed transfer at net book value to AmerenUE of
approximately 550 megawatts of generation assets from Generating Company, which
is subject to receipt of necessary regulatory approvals.
We intend to add 117 megawatts of capacity by 2005 and at least 330
megawatts of capacity by 2006 at AmerenUE. Total costs expected to be incurred
for these units approximate $175 million of which approximately $100 million was
committed as of December 31, 2002.
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 Ameren 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, transmission, and
distribution 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 NO(x) 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 NO(x) emission budget for each state, including
Illinois where most of Generating Company's facilities are located. The EPA rule
requires states to implement controls sufficient to meet their NO(x) budget by
May 31, 2004.
As a result of these state requirements, Generating Company estimates
spending an additional $40 million for pollution control capital expenditures
and NO(x) credits by 2006. A total of $90 million was spent in 2002 and 2001. In
February 2002, the EPA proposed similar rules for Missouri where the majority of
AmerenUE's facilities are located. Assuming the Missouri rules are ultimately
finalized, AmerenUE estimates spending approximately $170 million to comply with
these rules for NO(x) control on the AmerenUE generating system by 2006. In
summary, we currently estimate our future capital expenditures to comply with
the final NO(x) regulations could range from $200 million to $250 million. 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 14 - Commitments and Contingencies to our Consolidated Financial
Statements for further discussion of environmental matters and Note 15 -
Callaway Nuclear Plant to our Consolidated Financial Statements for a discussion
of Callaway Nuclear Plant decommissioning costs.
Financing
Our cash flows provided by financing activities totaled $531 million in
2002 and $307 million in 2001, compared to cash flows used in financing
activities of $22 million for 2000. Our principal financing activities for the
three year period included the issuance of long-term debt, adjustable
conversion-rate equity security units and common stock, partially offset by
redemptions of short-term debt, long-term debt and preferred stock, as well as
payments of dividends.
WWW.AMEREN.COM 23
Ameren Corporation, AmerenUE and AmerenCIPS are authorized by the SEC under
PUHCA to have up to an aggregate of $1.5 billion, $1 billion and $250 million,
respectively, of short-term unsecured debt instruments outstanding at any time.
In addition, Generating Company is authorized by the Federal Energy Regulatory
Commission (FERC) to have up to $300 million of short-term debt outstanding at
any time.
SHORT-TERM DEBT AND LIQUIDITY
Short-term debt consists of commercial paper and bank loans (maturities
generally within 1 to 45 days). At December 31, 2002, Ameren had committed
credit facilities, expiring at various dates between 2003 and 2005, totaling
$695 million, excluding EEI of $45 million and nuclear fuel lease facilities of
$120 million. All of these amounts were available for use by our rate-regulated
subsidiaries (AmerenUE and AmerenCIPS) and Ameren Services Company, and $600
million of this amount was available for use by Ameren Corporation and most of
our non rate-regulated subsidiaries including, but not limited to, Resources
Company, Generating Company, Marketing Company, AmerenEnergy Fuels and Services
Company and AmerenEnergy. These committed credit facilities are used to support
our commercial paper programs under which $250 million was outstanding at
December 31, 2002. At December 31, 2002, $445 million was unused and available
under these committed credit facilities.
In July 2002, Ameren Corporation entered into new committed credit
agreements for $400 million in revolving credit facilities to be used for
general corporate purposes, including support of our commercial paper programs.
The $400 million in new facilities includes a $270 million 364-day revolving
credit facility and a $130 million 3-year revolving credit facility. The 3-year
facility has a $50 million sub-limit for the issuance of letters of credit.
These new credit facilities replaced AmerenUE's $300 million revolving credit
facility. These amounts are included in the total committed credit facilities of
$695 million mentioned above.
Ameren Corporation had a $200 million committed credit facility which
matured in December 2002. We expect to replace this bank credit agreement with
two new credit facilities at AmerenUE, and we expect to extend or replace our
other committed credit facilities upon their respective maturities. These credit
facilities make borrowings available at various interest rates based on LIBOR,
agreed rates and other options.
We also have two bank credit agreements totaling $45 million that expire in
2003 at EEI. At December 31, 2002, $27 million was unused and available under
these committed credit facilities.
AmerenUE also has a lease agreement that provides for the financing of
nuclear fuel. At December 31, 2002, the maximum amount that could be financed
under the agreement was $120 million. At December 31, 2002, $113 million was
financed under the lease.
In addition to committed credit facilities, a further source of liquidity
for Ameren is available cash and cash equivalents. At December 31, 2002, we had
$628 million of cash. In early 2003, we paid a total of approximately $500
million of cash on hand to acquire CILCORP and Medina Valley.
We rely on access to short-term and long-term capital markets as a
significant source of funding for capital requirements not satisfied by our
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
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.
The following table summarizes available borrowing capacity under our
committed lines of credit and credit agreements as of December 31, 2002:
<Table>
<Caption>
Amount of Commitment Expiration Per Period
------------------------------------------
Less After
Total Than 1 1 - 3 4 - 5 5
Committed Year Years Years Years
--------- ------ ----- ----- -----
LINES OF CREDIT AND
CREDIT AGREEMENTS:
Ameren Corporation $ 600 $ 470 $ 130 $ -- $ --
AmerenUE (a) 200 80 120 -- --
AmerenCIPS 15 15 -- -- --
EEI 45 45 -- -- --
--------- ------ ----- ----- -----
TOTAL $ 860 $ 610 $ 250 $ -- $ --
========= ====== ===== ===== =====
</Table>
(a) Includes $120 million Gateway Fuel Company facility due February 2004 which
supports the nuclear fuel lease.
24
The following table summarizes our contractual obligations as of December
31, 2002:
<Table>
<Caption>
Less After
Than 1 1 - 3 4 - 5 5
Total Year Years Years Years
------ ------ ------ ------ ------
Long-term debt
and capital lease
obligations(a) $3,780 $ 339 $ 656 $ 546 $2,239
Short-term debt 271 271 -- -- --
Operating leases(b) 171 22 35 26 88
Other long-term
obligations(c) 2,441 706 981 370 384
------ ------ ------ ------ ------
TOTAL CASH
CONTRACTUAL
OBLIGATIONS $6,663 $1,338 $1,672 $ 942 $2,711
====== ====== ====== ====== ======
</Table>
(a) Amounts include our contractual obligation for fabricated nuclear fuel for
the years 2003 through 2006.
(b) Amounts related to certain real estate leases and railroad licenses have
indefinite payment periods. The $1 million annual obligation for these
items is 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.
(c) Represents purchase contracts for coal, gas, nuclear fuel (including our
contractual obligation for fabricated nuclear fuel for the years 2007
through 2012), and electric capacity.
INDENTURE AND CREDIT AGREEMENT PROVISIONS AND COVENANTS
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.
Covenants in Ameren Corporation'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 50%,
43% and 50% for Ameren Corporation, AmerenUE, and AmerenCIPS, respectively.
Ameren Corporation'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 Corporation (subject to definition in the
underlying credit agreements), other than certain project finance subsidiaries,
defaults in 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 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. While an updated valuation report will not
be available until the second half of 2003, we believe that the unfunded
liability status of our pension plans (as defined) could exceed $300 million
based on the investment performance of the pension plan assets and interest rate
changes since January 1, 2002. As a result, we may need to renegotiate the
facility provisions, terminate or replace the affected facilities, or fund any
unfunded liability shortfall. Should we elect to terminate these facilities, we
believe we would otherwise have sufficient liquidity to manage our short-term
funding requirements.
Generating Company's senior note indenture includes provisions that require
it 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 an
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
Generating Company from incurring any additional indebtedness, with the
exception of certain permitted indebtedness as defined in the indenture, unless
its senior debt service coverage ratio equals at least 2.5 to 1 for the most
recently ended four fiscal quarters and its 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 the ratings of Generating Company after
considering the additional indebtedness. As of December 31, 2002, Generating
Company's senior debt to total capital ratio was 55%.
WWW.AMEREN.COM 25
At December 31, 2002, Ameren Corporation and its subsidiaries were in
compliance with their indenture and credit agreement provisions and covenants.
OFF-BALANCE SHEET ARRANGEMENTS
At December 31, 2002, neither Ameren Corporation, nor any of its
subsidiaries, 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 AND EQUITY
The following table summarizes our issuances of common stock and the
issuances and redemptions of long-term debt for the years ended 2002, 2001 and
2000. For additional information related to the terms and uses of these
issuances and the sources of funds and terms for redemptions, see Note 8 -
Long-Term Debt and Capitalization to our Consolidated Financial Statements.
<Table>
<Caption>
Month Issued/
Redeemed 2002 2001 2000
------------- ----- ----- -----
ISSUANCES -
LONG-TERM DEBT:
Ameren Corporation:
5.70% Notes, due 2007 Jan $ 100 $ -- $ --
Senior notes, due 2007(a) Mar 345 -- --
Floating rate notes,
due 2003 Dec -- 150 --
AmerenUE:
5.25% Senior secured
notes, due 2012 Aug 173 -- --
Environ. improvement
revenue bonds Mar -- -- 187
Generating Company:
7.95% Senior notes,
due 2032 June 275 -- --
7.75% Senior notes,
due 2005 Nov -- -- 225
8.35% Senior notes,
due 2010 Nov -- -- 200
AmerenCIPS:
6.625%Senior secured
notes, due 2011 Jun -- 150 --
Pollution control
revenue bonds Mar -- -- 51
Electric Energy Inc.:
Bank term loan, due 2004 Jun -- -- 40
----- ----- -----
TOTAL LONG-TERM DEBT
ISSUANCES $ 893 $ 300 $ 703
===== ===== =====
EQUITY:
5,000,000 Shares at $39.50 Mar $ 198 $ -- $ --
750,000 Shares at $38.865 Mar 29 -- --
8,050,000 Shares at $42.00 Sep 338 -- --
DRPlus and employee
benefit plans(b) Various 93 33 --
----- ----- -----
TOTAL COMMON STOCK
ISSUANCES $ 658 $ 33 $ --
===== ===== =====
REDEMPTIONS -
LONG-TERM DEBT:
AmerenUE:
8.33% First mortgage bonds Dec $ 75 $ -- $ --
8.75% First mortgage bonds Sep 125 -- --
Environ. improvement
bonds, 7.40% series May -- -- 60
Environ. improvement
bonds, 1985 series Apr -- -- 127
Commercial paper, net Various -- 18 132
AmerenCIPS:
First mortgage bonds Various 32 30 35
Environ. improvement
bonds, 1990 A series Apr -- -- 20
Environ. improvement
bonds, 1990 B series Apr -- -- 32
Electric Energy Inc.:
1991 8.60% Senior MTNs,
amortization Dec 7 7 7
1994 6.61% Senior MTNs,
amortization Dec 8 8 8
----- ----- -----
TOTAL LONG-TERM DEBT
REDEMPTIONS $ 247 $ 63 $ 421
===== ===== =====
</Table>
(a) A component of the adjustable conversion-rate equity security units. See
Note 8 - Long-Term Debt and Capitalization for further discussion.
(b) Includes issuances of common stock of 2.3 million shares in 2002 and 0.8
million shares in 2001 under our dividend reinvestment and stock purchase
plan (DRPlus) and in connection with our 401(k) plans.
AMEREN CORPORATION
In August 2002, a shelf registration statement filed by Ameren Corporation
with the SEC on Form S-3 was declared effective. This statement authorized the
offering from time to time of up to $1.473 billion of various forms of
securities including long-term debt, and trust preferred and equity securities
to finance ongoing construction and maintenance programs, to redeem, repurchase,
repay, or retire outstanding debt, to finance strategic investments, including
our then pending acquisition of CILCORP, and for general corporate purposes. In
2002 and in
26
early 2003, $594 million was issued under the shelf registration statement. At
February 13, 2003, the amount remaining on the shelf registration statement was
approximately $879 million. See discussion of the 2003 common stock offering
under Recent Developments above.
We may sell all, or a portion of, the remaining registered securities under
the Ameren Corporation shelf registration statement if warranted by market
conditions and our capital requirements. Any offer and sale will be made only by
means of a prospectus meeting the requirements of the Securities Act of 1933 and
the rules and regulations thereunder.
In September 2001, we began issuing new shares of common stock under our
DRPlus, and in December 2001 we began issuing new shares of common stock in
connection with our 401(k) plans. Previously, these requirements were met by
purchasing outstanding common shares on the open market. We plan to continue to
issue new shares of common stock under our DRPlus and 401(k) plans in 2003.
Ameren expects to fund maturities of long-term debt and contractual
obligations through a combination of cash flow from operations and external
financing.
AMERENUE
In August 2002, a shelf registration statement filed by AmerenUE with the
SEC on Form S-3 was declared effective. This statement authorized the offering
from time to time of up to $750 million of various forms of long-term debt and
trust preferred securities to refinance existing debt and preferred stock, and
for general corporate purposes, including the repayment of short-term debt
incurred to finance construction expenditures and other working capital needs.
In 2002, AmerenUE issued $173 million under the shelf registration statement. At
February 13, 2003, the amount remaining under the shelf registration statement
was $577 million.
AMERENCIPS
In May 2001, a shelf registration statement filed by AmerenCIPS with the
SEC on Form S-3 was declared effective. This statement authorized the offering
from time to time of senior notes in one or more series with an offering price
not to exceed $250 million. In June 2001, AmerenCIPS issued $150 million of
senior notes under the shelf registration statement. At February 13, 2003, the
amount remaining on the shelf registration statement was $100 million.
DIVIDENDS
Common stock dividends paid in 2002 resulted in a payout rate of 98% of our
net income (85% of net income excluding voluntary retirement and other
restructuring charges) (75% - 2001; 76% - 2000). Dividends paid to common
stockholders in relation to net cash provided by operating activities for the
same periods were 45%, 47% and 40%.
The Board of Directors does not set specific targets or payout parameters
when declaring common stock dividends. However, the Board considers various
issues, including our historic earnings and cash flow; projected earnings; cash
flow and potential cash flow requirements; dividend payout rates at other
utilities; return on investments with similar risk characteristics; and overall
business considerations. On February 14, 2003, our Board of Directors declared a
quarterly common stock dividend of 63.5 cents per share to be paid on March 31,
2003 to shareholders of record on March 12, 2003.
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 Ameren can generate by marketing its excess power into the
interchange markets,
o Our revenues will be reduced by a rate settlement approved in 2002 by the
Missouri Public Service Commission (MoPSC) that requires the phase-in of
$110 million of electric rate reductions from 2002 through 2004,
o The adverse effects of rising employee benefit costs, higher insurance
costs and increased security costs associated with additional measures we
have taken, or may have to take, at our Callaway nuclear plant related to
world events,
o The incremental dilution from equity issued in both 2002 and 2003, and
o An assumed return to more normal weather patterns.
WWW.AMEREN.COM 27
In late 2002, we announced the following actions to mitigate the effect of
these challenges:
o A voluntary retirement program that was accepted by approximately 550
employees,
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,
o Suspension of operations at two 1940's-era generating plants to reduce
operating costs, and
o Reductions of 2003 expected capital expenditures.
We are pursuing gas rate increases of approximately $34 million in Illinois
and are considering a gas rate increase request in Missouri. We are also
considering additional actions, including modifications to active employee
benefits, further staffing reductions, accelerating synergy opportunities
related to the CILCORP acquisition and other initiatives.
In the ordinary course of business, we 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
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.
REGULATORY MATTERS
Missouri
From July 1, 1995 through June 30, 2001, our subsidiary, AmerenUE, operated
under experimental alternative regulation plans in Missouri that provided for
the sharing of earnings with customers if our regulatory return on equity
exceeded defined threshold levels. After AmerenUE's experimental alternative
regulation plan for its Missouri retail electric customers expired, the MoPSC
Staff and others sought to reduce our annual Missouri electric revenues by over
$300 million. The MoPSC Staff's recommendation was based on a return to
traditional cost of service ratemaking, a lowered return on equity, a reduction
in AmerenUE's depreciation rates and other cost of service adjustments.
In August 2002, a stipulation and agreement resolving this case became
effective following agreement by all parties to the case and approval by the
MoPSC. The stipulation and agreement includes the following principal features:
o The phase-in of $110 million of electric rate reductions through April
2004, $50 million of which was retroactively effective as of April 1, 2002,
$30 million of which will become effective on April 1, 2003, and $30
million of which will become effective on April 1, 2004.
o A rate moratorium providing for no changes in rates before June 30, 2006,
subject to certain statutory and other exceptions.
o A commitment to contribute $14 million to programs for low income energy
assistance and weatherization, promotion of energy efficiency and economic
development in AmerenUE's service territory in 2002, with additional
payments of $3 million made annually on June 30, 2003 through June 30,
2006. This entire obligation was expensed in 2002.
o A commitment to make $2.25 billion to $2.75 billion in critical energy
infrastructure investments from January 1, 2002 through June 30, 2006,
including, among other things, the addition of more than 700 megawatts of
new generation capacity and the replacement of steam generators at
AmerenUE's Callaway nuclear plant. The 700 megawatts of new generation is
expected to be satisfied by 240 megawatts that were added by AmerenUE in
2002 and the proposed transfer at net book value to AmerenUE of
approximately 550 megawatts of generation assets from Generating Company,
which is subject to receipt of necessary regulatory approvals.
o An annual reduction in AmerenUE's depreciation rates by $20 million,
retroactive to April 1, 2002, based on an updated analysis of asset values,
service lives and accumulated depreciation levels.
o A one-time credit of $40 million which was accrued during the plan period.
The entire amount was paid to AmerenUE's Missouri retail electric customers
in 2002 for the settlement of the final sharing period under the
alternative regulation plan that expired June 30, 2001.
See Note 2 - Rate and Regulatory Matters to our Consolidated Financial
Statements.
Illinois
See Note 2 - Rate and Regulatory Matters to our Consolidated Financial
Statements.
Federal - Electric Transmission
See Note 2 - Rate and Regulatory Matters to our Consolidated Financial
Statements.
28
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:
<Table>
<Caption>
Accounting Policy Uncertainties Affecting Application
Regulatory Mechanisms and Cost Recovery
We defer costs as regulatory assets in o Regulatory environment, external regulatory decisions
accordance with SFAS 71 and make investments and requirements
that we assume we will be able to collect in
future rates. o Anticipated future regulatory decisions and their impact
o Impact of deregulation and competition on ratemaking process
and ability to recover costs
BASIS FOR JUDGMENT
We determine that costs are recoverable based on previous rulings by state
regulatory authorities in jurisdictions where we operate or other factors that
lead us to believe that cost recovery is probable.
Nuclear Plant Decommissioning Costs
In our rates and earnings we assume the o Estimates of future decommissioning costs
Department of Energy will develop a permanent
storage site for spent nuclear fuel, the o Availability of facilities for waste disposal
Callaway nuclear plant will have a useful life of
40 years and estimated costs of approximately o Approved methods for waste disposal and decommissioning
$515 million to dismantle the plant are accurate.
See Note 15 - Callaway Nuclear Plant to our o Useful lives of nuclear plants
Consolidated Financial Statements.
BASIS FOR JUDGMENT
We determine that decommissioning costs are reasonable, or require adjustment,
based on third party decommissioning studies that are completed every three
years, the evaluation of our facilities by our engineers and the monitoring of
industry trends.
</Table>
Table Continued on Page 30
WWW.AMEREN.COM 29
Table Continued from Page 29
<Table>
<Caption>
Accounting Policy Uncertainties Affecting Application
Environmental Costs
We accrue for all known environmental o Extent of contamination
contamination where remediation can be
reasonably estimated, but some of our operations o Responsible party determination
have existed for over 100 years and previous
contamination may be unknown to us. o Approved methods for cleanup
o Present and future legislation and governmental regulations
and standards
o Results of ongoing research and development regarding
environmental impacts
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.
Unbilled Revenue
At the end of each period, we estimate, based on o Projecting customer energy usage
expected usage, the amount of revenue to record
for services that have been provided to customers, o Estimating impacts of weather and other usage-affecting
but not billed. This period can be up to one month. factors for the unbilled period
BASIS FOR JUDGMENT
We determine the proper amount of unbilled revenue to accrue each period based
on the volume of energy delivered as valued by a model of billing cycles and
historical usage rates and growth by customer class for our service area, as
adjusted for the modeled impact of seasonal and weather variations based on
historical results.
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 accordance with SFAS 87, 106 and 112. o Interest rates used in valuing benefit obligations
See Note 12 - Retirement Benefits to our
Consolidated Financial Statements. o Healthcare cost trend rates
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 value in o Market conditions in the energy industry, especially the
accordance with SFAS 133. The identification and effects of price volatility on contractual commodity
classification of a derivative, and the fair value of commitments
such derivative must be determined. We designate
certain derivatives as hedges of future cash flows. o Regulatory and political environments and requirements
See Note 3 - Derivative Financial Instruments to our
Consolidated Financial Statements. o Fair value estimations on longer term contracts
o Complexity of financial instruments and accounting 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.
</Table>
30
Impact of Future Accounting Pronouncements
See Note 1 - Summary of Significant Accounting Policies to our Consolidated
Financial Statements.
EFFECTS OF INFLATION AND CHANGING PRICES
Our rates for retail electric and gas utility service are regulated by the
MoPSC and the Illinois Commerce Commission (ICC). Non-retail electric rates are
regulated by the FERC. Our Missouri electric rates have been set through June
30, 2006, as part of the settlement of our Missouri electric rate case and our
Illinois electric rates are legislatively fixed through January 1, 2007.
Inflation affects our operations, earnings, stockholders' equity and financial
performance.
The current replacement cost of our utility plant substantially exceeds our
recorded historical cost. Under existing regulatory practice, only the
historical cost of plant is recoverable from customers. As a result, cash flows
designed to provide recovery of historical costs through depreciation might not
be adequate to replace plant in future years. Ameren's generation portion of its
business in its Illinois jurisdiction is non rate-regulated and therefore does
not have regulated recovery mechanisms.
In our retail electric utility jurisdictions, there are no provisions for
adjusting rates for changes in the cost of fuel for electric generation. In our
retail gas utility jurisdictions, changes in gas costs are generally reflected
in billings to gas customers through purchased gas adjustment clauses. We are
impacted by changes in market prices for natural gas to the extent we must
purchase natural gas 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. 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.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated
with both long-term and short-term variable-rate debt and fixed-rate debt,
commercial paper, auction-rate long-term debt and auction-rate preferred stock.
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.
Utilizing our debt outstanding at December 31, 2002, if interest rates
increased by 1%, our annual interest expense would increase by approximately $11
million and net income would decrease by approximately $7 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 trade accounts receivables and executory contracts with market
risk exposures. The risk associated with trade receivables is mitigated by the
large number of customers in a broad range of industry groups comprising our
customer base. No customer represents greater than 10% of our accounts
receivable. Our revenues are primarily derived from sales of electricity and
natural gas to customers in Missouri and Illinois. We analyze each
counterparty's
WWW.AMEREN.COM 31
financial condition prior to entering into sales, forwards, swaps, futures or
option contracts and monitor counterparty exposure associated with our leveraged
leases. As of December 31, 2002, we had approximately $29 million invested in
three leveraged leases. 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 natural gas, 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.
With regard to our natural gas utility business, our exposure to changing
market prices is in large part mitigated by the fact we have gas cost recovery
mechanisms in place in both Missouri and Illinois. These gas cost recovery
mechanisms allow us to pass on to retail customers our prudently incurred costs
of natural gas.
AmerenEnergy Fuels and Services Company is responsible for providing fuel
procurement and gas supply services on behalf of our operating subsidiaries, and
for managing fuel and natural gas 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 fuel supply contracts are
physical forward contracts. Since we do not have a provision similar to the
purchased gas adjustment clauses for our electric operations, we have entered
into long-term contracts with various suppliers to purchase coal and nuclear
fuel in order to manage our exposure to fuel prices. See Note 14 - Commitments
and Contingencies to our Consolidated Financial Statements for further
information. Approximately 98% of the required 2003 and over 80% 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 30% of our coal requirements for 2005 through 2007 were
covered by contracts. We have satisfied 77%, 11% and 2% of our historical needs
through coal, nuclear and hydro generation, respectively. With regard to our
electric generating operations, we are exposed to changes in market prices for
natural gas to the extent we must purchase natural gas to run our combustion
turbine generators. At December 31, 2002, approximately 36% of our 2003 natural
gas requirements for generation are covered by contracts. 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.
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
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. Ameren's electric marketing
strategy is to extract additional value from its 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 a subsidiary, AmerenEnergy, whose primary
responsibility includes managing market risks associated with changing market
prices for electricity purchased and sold on behalf of AmerenUE and Generating
Company. In addition, we have sold nearly all of our available non
rate-regulated peak generation capacity for the summer of 2003 at various
prices.
Equity Price Risk
Our costs of providing non-contributory defined benefit retirement and
post-retirement 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 our
plan assets has been affected by declines in the equity market since 2000 for
our pension and post-retirement plans. As a result, at
32
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 $102
million, net of taxes. The amount of the liability was the result of asset
returns experienced through 2002, interest rates and our contributions to the
plans 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
Consolidated Balance Sheet. See Liquidity and Capital Resources - Operating.
We also maintain trust funds, as required by the Nuclear Regulatory
Commission and Missouri and Illinois state laws, to fund certain costs of
nuclear decommissioning. See Note 15 - Callaway Nuclear Plant to our
Consolidated Financial Statements for further information. As of December 31,
2002, these funds were invested primarily in domestic equity securities (62%),
debt securities (35%), and cash and cash equivalents (3%) and totaled $172
million at fair value. By maintaining a portfolio that includes long-term equity
investments, we seek to maximize the returns to be utilized to fund nuclear
decommissioning costs. However, the equity securities included in our portfolio
are exposed to price fluctuations in equity markets and the fixed-rate,
fixed-income securities are exposed to changes in interest rates. We actively
monitor our portfolio by benchmarking the performance of our investments against
certain indices and by maintaining, and periodically reviewing, established
target allocation percentages of the assets of our trusts to various investment
options. Our exposure to equity price market risk is, in large part, mitigated,
due to the fact that we are currently allowed to recover decommissioning costs
in our rates.
Fair Value of Contracts
We utilize derivatives principally to manage the risk of changes in market
prices for natural gas, fuel, electricity and emission credits. Price
fluctuations in natural gas, 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 and natural gas inventories or purchased power to
differ from the cost of those commodities in inventory 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 3 - Derivative Financial Instruments to our
Consolidated Financial Statements 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:
<Table>
<Caption>
2002 2001
----- -----
FAIR VALUE OF CONTRACTS AT
BEGINNING OF PERIOD, NET $ (1) $ (30)
Contracts which were realized or
otherwise settled during the period (7) 30
Changes in fair values attributable to changes
in valuation techniques and assumptions -- --
Fair value of new contracts entered
into during the period 1 4
Other changes in fair value 14 (5)
----- -----
FAIR VALUE OF CONTRACTS OUTSTANDING
AT END OF PERIOD, NET $ 7 $ (1)
===== =====
</Table>
Maturities of contracts as of December 31, 2002 were as follows:
<Table>
<Caption>
Maturity
-----------------------------------
Less In Excess Total
Than 1 - 3 4 - 5 of 5 Fair
1 year Years Years Years Value(a)
------ ----- ----- --------- --------
SOURCES OF FAIR VALUE:
Prices actively quoted $ (1) $ -- $ -- $ -- $ (1)
Prices provided by
other external
sources(b) 3 -- -- -- 3
Prices based on
models and other
valuation methods(c) 4 1 -- -- 5
------ ----- ----- --------- --------
TOTAL $ 6 $ 1 $ -- $ -- $ 7
====== ===== ===== ========= ========
</Table>
(a) Contracts of approximately 7% of the absolute fair value were with
non-investment-grade rated counterparties.
WWW.AMEREN.COM 33
(b) Principally power forward values based on NYMEX prices for over-the-counter
contracts and natural gas swaps based on Inside FERC prices.
(c) Principally coal and sulfur dioxide option values based on a Black-Scholes
model that includes information from external sources and our estimates.
FORWARD LOOKING STATEMENTS
Statements made in this annual 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 the stipulation and agreement relating to the AmerenUE
Missouri electric excess earnings complaint case and other 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 due to, among other
things, deregulation of certain aspects of our business at both the state
and federal levels;
o the effects of participation in a FERC-approved Regional Transmission
Organization, including activities associated with the Midwest ISO;
o availability and future market prices for fuel and purchased power,
electricity and natural gas, including the use of financial and derivative
instruments and volatility of changes in market prices;
o average rates 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 operation of nuclear power facilities and decommissioning costs;
o the effects of strategic initiatives, including acquisitions and
divestitures;
o the impact of current environmental regulations on utilities and generating
companies and the expectation that more stringent requirements will be
introduced over time, which could potentially have a negative financial
effect;
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 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 difficulties in integrating CILCO with Ameren's other businesses;
o changes in the coal markets, environmental laws or regulations or other
factors adversely impacting synergy assumptions in connection with the
CILCORP acquisition;
o cost and availability of transmission capacity for the energy generated by
our generating facilities or required to satisfy energy sales made by
Ameren; and
o legal and administrative proceedings.
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.
34
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
<Table>
<Caption>
In Millions, Except Per Share Amounts Year Ended December 31, 2002 2001 2000
-------- -------- --------
OPERATING REVENUES:
Electric $ 3,520 $ 3,507 $ 3,526
Gas 315 342 324
Other 6 9 6
-------- -------- --------
TOTAL OPERATING REVENUES 3,841 3,858 3,856
-------- -------- --------
OPERATING EXPENSES:
Fuel and purchased power 825 914 1,025
Gas 198 222 210
Other operations and maintenance 1,160 1,090 1,032
Voluntary retirement and other restructuring charges (Note 9) 92 -- --
Depreciation and amortization 431 406 383
Income taxes 250 300 301
Other taxes 262 261 265
-------- -------- --------
TOTAL OPERATING EXPENSES 3,218 3,193 3,216
-------- -------- --------
OPERATING INCOME 623 665 640
-------- -------- --------
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used during construction 6 13 5
Miscellaneous, net -
Miscellaneous income (Note 10) 15 22 14
Miscellaneous expense (Note 10) (50) (16) (21)
Income taxes 13 (5) 3
-------- -------- --------
TOTAL OTHER INCOME AND (DEDUCTIONS) (16) 14 1
-------- -------- --------
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest 219 199 180
Allowance for borrowed funds used during construction (5) (8) (8)
Preferred dividends of subsidiaries 11 12 12
-------- -------- --------
NET INTEREST CHARGES AND PREFERRED DIVIDENDS 225 203 184
-------- -------- --------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 382 476 457
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF INCOME TAXES -- (7) --
-------- -------- --------
Net Income $ 382 $ 469 $ 457
======== ======== ========
EARNINGS PER COMMON SHARE - BASIC:
Income before cumulative effect of change in accounting principle $ 2.61 $ 3.46 $ 3.33
Cumulative effect of change in accounting principle, net of income taxes -- (0.05) --
-------- -------- --------
NET INCOME $ 2.61 $ 3.41 $ 3.33
======== ======== ========
EARNINGS PER COMMON SHARE - DILUTED:
Income before cumulative effect of change in accounting principle $ 2.60 $ 3.45 $ 3.33
Cumulative effect of change in accounting principle, net of income taxes -- (0.05) --
-------- -------- --------
NET INCOME $ 2.60 $ 3.40 $ 3.33
======== ======== ========
Average Common Shares Outstanding (Note 1) 146.1 137.3 137.2
======== ======== ========
</Table>
See Notes to Consolidated Financial Statements.
WWW.AMEREN.COM 35
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
<Table>
<Caption>
In Millions, Except Per Share Amounts December 31, 2002 2001
-------- --------
ASSETS:
PROPERTY AND PLANT, NET (Note 4) $ 8,914 $ 8,427
-------- --------
INVESTMENTS AND OTHER ASSETS:
Investments 38 39
Nuclear decommissioning trust fund 172 187
Other assets 233 114
-------- --------
TOTAL INVESTMENTS AND OTHER ASSETS 443 340
-------- --------
CURRENT ASSETS:
Cash and cash equivalents 628 67
Accounts receivable - trade (less allowance for doubtful
accounts of $7 and $9, respectively) 266 218
Unbilled revenue 176 171
Miscellaneous accounts and notes receivable 44 71
Materials and supplies, at average cost 299 295
Other current assets 39 41
-------- --------
TOTAL CURRENT ASSETS 1,452 863
-------- --------
REGULATORY ASSETS 690 771
-------- --------
Total Assets $ 11,499 $ 10,401
======== ========
CAPITAL AND LIABILITIES:
CAPITALIZATION:
Common stock, $.01 par value, 400.0 shares authorized -
shares outstanding of 154.1 and 138.0, respectively (Notes 6 and 8) $ 2 $ 1
Other paid-in capital, principally premium on common stock 2,203 1,614
Retained earnings 1,739 1,733
Accumulated other comprehensive income (93) 5
Other (9) (4)
-------- --------
Total common stockholders' equity 3,842 3,349
Preferred stock not subject to mandatory redemption (Note 6) 193 235
Long-term debt, net (Note 8) 3,433 2,835
-------- --------
TOTAL CAPITALIZATION 7,468 6,419
-------- --------
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES 15 4
-------- --------
CURRENT LIABILITIES:
Current maturities of long-term debt (Note 8) 339 139
Short-term debt (Note 7) 271 641
Accounts and wages payable 369 392
Accumulated deferred income taxes 5 58
Taxes accrued 45 132
Other current liabilities 172 219
-------- --------
TOTAL CURRENT LIABILITIES 1,201 1,581
-------- --------
Commitments and contingencies (Notes 1, 2, 14, and 15)
Accumulated deferred income taxes 1,707 1,563
Accumulated deferred investment tax credits 149 158
Regulatory liabilities 136 172
Accrued pension liabilities 377 88
Other deferred credits and liabilities 446 416
-------- --------
Total Capital and Liabilities $ 11,499 $ 10,401
======== ========
</Table>
See Notes to Consolidated Financial Statements.
36
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
<Table>
<Caption>
In Millions Year Ended December 31, 2002 2001 2000
------- ------- -------
CASH FLOWS FROM OPERATING:
Net income $ 382 $ 469 $ 457
Adjustments to reconcile net income to net cash provided by operating
activities:
Cumulative effect of change in accounting principle -- 7 --
Depreciation and amortization 431 406 383
Amortization of nuclear fuel 30 29 37
Amortization of debt issuance costs and premium/discounts 8 5 6
Allowance for funds used during construction (11) (21) (13)
Deferred income taxes, net 74 28 2
Deferred investment tax credits, net (9) (6) (7)
Voluntary retirement and other restructuring charges 92 -- --
Other 8 (1) (2)
Changes in assets and liabilities:
Receivables, net (26) 70 (140)
Materials and supplies (4) (68) 26
Accounts and wages payable (80) (71) 122
Taxes accrued 38 8 (31)
Assets, other (1) (54) (8)
Liabilities, other (99) (63) 32
------- ------- -------
NET CASH PROVIDED BY OPERATING ACTIVITIES 833 738 864
------- ------- -------
CASH FLOWS FROM INVESTING:
Construction expenditures (787) (1,102) (929)
Allowance for funds used during construction 11 21 13
Nuclear fuel expenditures (28) (24) (21)
Other 1 1 26
------- ------- -------
NET CASH USED IN INVESTING ACTIVITIES (803) (1,104) (911)
------- ------- -------
CASH FLOWS FROM FINANCING:
Dividends on common stock (376) (350) (349)
Capital issuance costs (35) -- (8)
Redemptions:
Nuclear fuel lease -- (64) (11)
Short-term debt (370) -- --
Long-term debt (247) (63) (421)
Preferred stock (42) -- --
Issuances:
Common stock 658 33 --
Nuclear fuel lease 50 13 9
Short-term debt -- 438 55
Long-term debt 893 300 703
------- ------- -------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 531 307 (22)
------- ------- -------
NET CHANGE IN CASH AND CASH EQUIVALENTS 561 (59) (69)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 67 126 195
------- ------- -------
Cash and Cash Equivalents at End of Year $ 628 $ 67 $ 126
======= ======= =======
Cash paid during the periods:
Interest $ 221 $ 187 $ 169
Income taxes, net 140 266 312
------- ------- -------
</Table>
See Notes to Consolidated Financial Statements.
WWW.AMEREN.COM 37
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
<Table>
<Caption>
In Millions Year Ended December 31, 2002 2001 2000
------- ------- -------
COMMON STOCK:
Beginning balance $ 1 $ 1 $ 1
Shares issued 1 -- --
------- ------- -------
2 1 1
------- ------- -------
OTHER PAID-IN CAPITAL:
Beginning balance 1,614 1,581 1,582
Shares issued (less issuance costs of $20, $-, and $-, respectively) 637 33 --
Contracted stock purchase payment obligations (46) -- --
Employee stock awards (2) -- (1)
------- ------- -------
2,203 1,614 1,581
------- ------- -------
RETAINED EARNINGS:
Beginning balance 1,733 1,614 1,506
Net income 382 469 457
Dividends (376) (350) (349)
------- ------- -------
1,739 1,733 1,614
------- ------- -------
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Beginning balance - derivative financial instruments 5 -- --
Change in derivative financial instruments in current period 4 5 --
------- ------- -------
9 5 --
------- ------- -------
Beginning balance - minimum pension liability -- -- --
Change in minimum pension liability in current period (102) -- --
------- ------- -------
(102) -- --
------- ------- -------
(93) 5 --
------- ------- -------
OTHER:
Beginning balance (4) -- --
Restricted stock compensation awards (7) (5) --
Compensation amortized and mark-to-market adjustments 2 1 --
------- ------- -------
(9) (4) --
------- ------- -------
TOTAL COMMON STOCKHOLDERS' EQUITY $ 3,842 $ 3,349 $ 3,196
======= ======= =======
COMPREHENSIVE INCOME, NET OF TAXES:
Net income $ 382 $ 469 $ 457
Unrealized net gain/(loss) on derivative hedging instruments,
net of income taxes of $3, $3, and $-, respectively 6 5 --
Reclassification adjustments for gains/(losses) included in net income,
net of income taxes of $(1), $7, and $-, respectively (2) 11 --
Cumulative effect of accounting change, net of income taxes
of $-, $(7), and $-, respectively -- (11) --
Minimum pension liability adjustment, net of income taxes
of $(62), $-, and $-, respectively (102) -- --
------- ------- -------
TOTAL COMPREHENSIVE INCOME, NET OF TAXES $ 284 $ 474 $ 457
======= ======= =======
COMMON STOCK SHARES AT BEGINNING OF PERIOD 138.0 137.2 137.2
Shares issued 16.1 0.8 --
------- ------- -------
COMMON STOCK SHARES AT END OF PERIOD 154.1 138.0 137.2
======= ======= =======
</Table>
See Notes to Consolidated Financial Statements.
38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren Corporation is a public utility holding company registered under the
Public Utility Holding Company Act of 1935 (PUHCA) and is headquartered in St.
Louis, Missouri. Our 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. Our
primary subsidiaries 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 Central Illinois Public Service Company, which operates a rate-regulated
electric and natural gas transmission and distribution business in Illinois
as AmerenCIPS.
o Central Illinois Light Company is a subsidiary of CILCORP Inc., 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. We completed our acquisition of
CILCORP on January 31, 2003 from The AES Corporation (AES). See Note 18 -
Subsequent Event for further information.
o AmerenEnergy Resources Company (Resources Company), which consists of non
rate-regulated operations. Subsidiaries include AmerenEnergy Generating
Company (Generating Company) that operates our non rate-regulated electric
generation in Missouri and Illinois, AmerenEnergy Marketing Company
(Marketing Company), which markets power for periods over one year,
AmerenEnergy Fuels and Services Company, which procures fuel and manages
the related risks for our affiliated companies and AmerenEnergy Medina
Valley Cogen (No. 4), LLC, which indirectly owns a 40 megawatt, gas-fired
electric generation plant. On February 4, 2003, we completed our
acquisition of AES Medina Valley Cogen (No. 4), LLC from AES and renamed it
AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Note 18 - Subsequent
Event for further information.
o AmerenEnergy, Inc. (AmerenEnergy) which serves as a power marketing and
risk management agent for our affiliated companies for transactions of
primarily less than one year.
o Electric Energy, Inc. (EEI), which operates electric generation and
transmission facilities in Illinois. We have a 60% ownership interest in
EEI and consolidate it for financial reporting purposes.
o Ameren Services Company, which provides shared support services to us and
our subsidiaries.
When we refer to Ameren, our, we or us, we are referring to Ameren
Corporation and its subsidiaries on a consolidated basis. In certain
circumstances, our subsidiaries are specifically referenced in order to
distinguish among their different business activities.
The consolidated financial statements include the accounts of Ameren
Corporation and its majority-owned subsidiaries. All significant intercompany
transactions have been eliminated. The financial results of CILCORP have not
been included or discussed in these financial statements, except with regard to
certain forward looking information. All tabular dollar amounts are in millions,
unless otherwise indicated.
The accounting policies of Ameren 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.
Regulation
We are subject to regulation by the Securities and Exchange Commission
(SEC). Certain of Ameren's subsidiaries are also regulated by the Missouri
Public Service Commission (MoPSC), Illinois Commerce Commission (ICC), Nuclear
Regulatory Commission (NRC) and the Federal Energy Regulatory Commission (FERC).
See Note 2 - Rate and Regulatory Matters for further information.
In accordance with Statement of Financial Accounting Standards (SFAS) No.
71 "Accounting for the Effects of Certain Types of Regulation," we defer certain
costs pursuant to actions of our regulators and are currently recovering such
costs in rates charged to customers.
WWW.AMEREN.COM 39
At December 31, 2002 and 2001, we had the following regulatory assets and
regulatory liabilities:
<Table>
<Caption>
2002 2001
---- ----
REGULATORY ASSETS:
Income taxes(a)(g) $526 $604
Callaway costs(b) 81 84
Unamortized loss on reacquired debt(c)(g) 32 28
Recoverable costs-
contaminated facilities(d)(g) 26 26
Other(e)(g) 25 29
---- ----
Regulatory assets $690 $771
==== ====
REGULATORY LIABILITIES:
Income taxes(f) $136 $172
==== ====
</Table>
(a) See Note 11 - Income Taxes for amortization period. Amount represents SFAS
109 deferred tax asset.
(b) Represents Callaway nuclear plant operations and maintenance expenses,
property taxes and carrying costs incurred between the plant in-service
date and the date the plant was reflected in rates. These costs are being
amortized over the remaining life of the plant's current operating license
through 2024.
(c) Represents losses related to refunded debt. These amounts are being
amortized over the lives of the related new debt issues or the remaining
lives of the old debt issues if no new debt was issued.
(d) Represents the recoverable portion of accrued environmental site
liabilities, which is primarily collected through a revenue rider in
Illinois.
(e) Represents Y2K expenses being amortized over 6 years starting in 2002 in
conjunction with the settlement of our Missouri electric rate case and a
Department of Energy Decommissioning assessment being amortized over 14
years through 2007. In addition, amount includes the portion of
merger-related expenses applicable to the Missouri retail jurisdiction,
which are being amortized through 2008 based on a MoPSC order.
(f) See Note 11- Income Taxes for amortization period. Represents unamortized
portion of investment tax credit and federal excess taxes.
(g) These assets do not earn a return.
We continually assess the recoverability of our regulatory assets. Under
current accounting standards, regulatory assets are written off to earnings when
it is no longer probable that such amounts will be recovered through future
revenues. Electric industry restructuring legislation may impact the
recoverability of regulatory assets in the future.
Property and Plant
The cost of additions to, and betterments of, units of property and plant
is capitalized. Cost includes labor, material, applicable taxes and overheads.
An allowance for funds used during construction is also added for our
rate-regulated assets, and interest during construction is added for non
rate-regulated 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 SFAS No. 143 "Accounting for Asset Retirement Obligations"
and Note 4 - Property and Plant, Net for further information.
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, 2001, and 2000 was approximately 3% of the
average depreciable cost.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFC) is a utility industry
accounting practice whereby the cost of borrowed funds and the cost of equity
funds (preferred and common stockholders' equity) applicable to rate-regulated
construction expenditures are capitalized as a cost of construction. AFC does
not represent a current source of cash funds. This accounting practice offsets
the effect on earnings of the cost of financing current construction, and treats
such financing costs in the same manner as construction charges for labor and
materials.
Under accepted ratemaking practice, cash recovery of AFC, as well as other
construction costs, occurs when completed projects are placed in service and
reflected in customer rates. The AFC ranges of rates used were 5% - 9% during
2002, 4% - 10% during 2001, and 6% - 10% during 2000.
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, premium and expense associated with long-term debt are amortized
over the lives of the related issues.
Revenue
We accrue an estimate of electric and gas revenues for service rendered,
but unbilled, at the end of each accounting period.
40
Interchange revenues included in Operating Revenues-Electric were $200
million for the year ended December 31, 2002 (2001 - $309 million, 2000 - $477
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 for further information.
Purchased Power
Purchased power included in Operating Expenses - Fuel and Purchased Power
was $116 million for the year ended December 31, 2002 (2001 - $290 million, 2000
- - $358 million). See EITF 02-3 discussion under Accounting Changes and Other
Matters for further information.
Fuel and Gas Costs
In our retail electric utility jurisdictions, there are no provisions for
adjusting rates for changes in the cost of fuel for electric generation. In our
retail gas utility jurisdictions, changes in gas costs are generally reflected
in billings to gas customers through purchased gas adjustment clauses.
The cost of nuclear fuel is amortized to fuel expense on a
unit-of-production basis. Spent fuel disposal cost is charged to expense, based
on net kilowatthours generated and sold.
Excise Taxes
Excise taxes on Missouri electric and gas, and Illinois gas customer bills
are imposed on us and are recorded gross in Operating Revenues and Other Taxes.
Excise taxes recorded in Operating Revenues and Other Taxes for 2002 were $116
million (2001- $113 million, 2000 - $119 million). Excise taxes applicable to
Illinois electric customer bills are imposed on the consumer and are recorded as
tax collections payable and included in Taxes Accrued on the Consolidated
Balance Sheet.
Income Taxes
We file a consolidated federal tax return. 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.
Earnings Per Share
The inclusion of assumed stock option conversions in the calculation of
earnings per share resulted in dilution of $0.01 for 2002 and 2001. There was no
difference between the basic and diluted earnings per share amounts in 2000.
Dilution resulted from assumed stock option conversions, which increased the
number of shares outstanding in the diluted earnings per share calculation by
332,909 shares in 2002, 331,813 shares in 2001 and 183,201 shares in 2000.
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 $7 million, net of taxes, to the income statement,
and a cumulative effect adjustment of $11 million net of taxes, to Accumulated
Other Comprehensive Income (OCI), which reduced common stockholders' equity. See
Note 3 - 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 our acquisition of CILCORP, Inc. and AES Medina Valley
Cogen (No. 4), LLC. See Note 18 - 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 additional asset
retirement obligations of approximately $220 million and a net increase in net
property and plant of approximately $75 million related
WWW.AMEREN.COM 41
primarily to the Callaway nuclear decommissioning costs and also to retirement
costs for a river structure and an ash pond. These asset retirement obligations
are in addition to liabilities we have previously recorded related to our future
obligation to decommission the Callaway nuclear plant.
The difference between the net asset and the liability recorded upon
adoption of SFAS 143 related to rate-regulated assets will be recorded as an
additional regulatory asset because we expect to continue to recover the cost of
Callaway nuclear decommissioning and other costs of removal in electric rates.
The difference between the net asset and the liability to be recorded upon
adoption related to non rate-regulated 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 requires a change in the depreciation methodology we have
historically utilized for our non rate-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 most likely substantially exceed the loss resulting
from adopting this standard discussed above. 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-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.
Like our non rate-regulated operations, the depreciation methodology
historically utilized by our rate-regulated operations has included an estimated
cost of dismantling and removing plant from service upon retirement. This
practice is currently required by regulators in the jurisdictions in which we
operate. As a result, though we are still assessing the impact of SFAS 143 on
our rate-regulated depreciation methodology, we do not believe any such impact
will affect our results of operations. However, if we are required to remove
accrued dismantling and removal costs from accumulated depreciation, where they
are currently embedded, our asset and liability balances could be materially
increased.
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 sales contracts within our power risk management program, on
a gross basis in Operating Revenues - Electric and in Operating
42
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.
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. The adoption of EITF 02-3, the rescission of
EITF 98-10 and the related transition guidance resulted in netting of certain
energy contracts, and lowered our reported revenues and costs with no impact on
earnings or stockholders' equity. The following table summarizes the impact of
energy contract netting for the years ended December 31, 2001 and 2000:
<Table>
<Caption>
2001 2000
------ ------
Previously reported
gross operating revenues $4,506 $3,856
Revenues and costs netted(a) 648 --
------ ------
Net operating revenues reported $3,858 $3,856
====== ======
</Table>
(a) Revenues and costs netted for the year ended December 31, 2002 were $738
million. SFAS 133 was adopted on January 1, 2001 and therefore no netting
was required for the year ended December 31, 2000.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure." SFAS 148 amends SFAS No. 123,
"Accounting for Stock-Based Compensation," to provide alternative methods of
transition for an entity that voluntarily changes to the fair value based method
of accounting for stock-based employee compensation. It also amends the
disclosure provisions to require disclosure about the effects on reported net
income of an entity's accounting policy decisions with respect to stock-based
employee compensation.
Prior to 2003, we accounted for our long-term incentive plan under the
recognition and measurement provisions of APB Opinion No. 25, "Accounting for
Stock Issued to Employees." No stock-based employee compensation cost was
reflected for options in 2002, 2001, and 2000 as all options granted under our
plan had an exercise price equal to the market value of the underlying common
stock on the date of grant. The pretax effect of weighted-average grant-date
fair value of options granted would have been approximately $2 million in each
of the years ended 2002, 2001, and 2000 had the fair value method under SFAS 123
been used for options. Effective January 1, 2003, we adopted the fair value
recognition provisions of SFAS 123 by using the prospective method of adoption
under SFAS 148. We do not expect SFAS 148 to have any effect on our financial
position, results of operations or liquidity in 2003. See Note 13 - Stock-Based
Compensation for further information.
NOTE 2 - RATE AND REGULATORY MATTERS
Missouri Electric
MOPSC RATE CASE
From July 1, 1995 through June 30, 2001, our subsidiary, AmerenUE, operated
under experimental alternative regulation plans in Missouri that provided for
the sharing of earnings with customers if our regulatory return on equity
exceeded defined threshold levels. After AmerenUE's experimental alternative
regulation plan for its Missouri retail electric customers expired, the MoPSC
Staff and others sought to reduce our annual Missouri electric revenues by over
$300 million. The MoPSC Staff's recommendation was based on a return to
traditional cost of service ratemaking, a lowered return on equity, a reduction
in AmerenUE's depreciation rates and other cost of service adjustments.
In August 2002, a stipulation and agreement resolving this case became
effective following agreement by all parties to the case and approval by the
MoPSC. The stipulation and agreement includes the following principal features:
o The phase-in of $110 million of electric rate reductions through April
2004, $50 million of which was retroactively effective as of April 1, 2002,
$30 million of which will become effective on April 1, 2003, and $30
million of which will become effective on April 1, 2004.
o A rate moratorium providing for no changes in rates before June 30, 2006,
subject to certain statutory and other exceptions.
o A commitment to contribute $14 million to programs for low income energy
assistance and weatherization, promotion of energy efficiency and economic
development in AmerenUE's service territory in 2002, with additional
payments of $3 million made annually on
WWW.AMEREN.COM 43
June 30, 2003 through June 30, 2006. This entire obligation was expensed in
2002.
o A commitment to make $2.25 billion to $2.75 billion in critical energy
infrastructure investments from January 1, 2002 through June 30, 2006,
including, among other things, the addition of more than 700 megawatts of
new generation capacity and the replacement of steam generators at
AmerenUE's Callaway nuclear plant. The 700 megawatts of new generation is
expected to be satisfied by 240 megawatts that were added by AmerenUE in
2002 and the proposed transfer at net book value to AmerenUE of
approximately 550 megawatts of generation assets from Generating Company,
which is subject to receipt of necessary regulatory approvals.
o An annual reduction in AmerenUE's depreciation rates by $20 million,
retroactive to April 1, 2002, based on an updated analysis of asset values,
service lives and accumulated depreciation levels.
o A one-time credit of $40 million which was accrued during the plan period.
The entire amount was paid to AmerenUE's Missouri retail electric customers
in 2002 for settlement of the final sharing period under the alternative
regulation plan that expired June 30, 2001.
MARKETING COMPANY - AMERENUE POWER SUPPLY AGREEMENTS
In order to satisfy AmerenUE's regulatory load requirements for 2001,
AmerenUE purchased, under a one year contract (the 2001 Marketing Company -
AmerenUE agreement), 450 megawatts of capacity and energy from Marketing
Company. This agreement was entered into through a competitive bidding process
and reflected market-based rates. For 2002, AmerenUE similarly entered into a
one year contract (the 2002 Marketing Company - AmerenUE agreement) with
Marketing Company for the purchase of 200 megawatts of capacity and energy. For
the four summer months of 2002, AmerenUE also entered into contracts with two
other power suppliers for an aggregate 200 megawatts of additional capacity and
energy.
In May 2001, the MoPSC filed a complaint with the SEC relating to the 2001
Marketing Company - AmerenUE agreement. The complaint requested an investigation
into the contractual relationship between AmerenUE, Marketing Company and
Generating Company, in the context of the 2001 Marketing Company - AmerenUE
agreement and requested that the SEC find that such relationship violates
Section 32(k) of PUHCA, which requires state utility commission approval of
power sales contracts between an electric utility company and an affiliated
exempt wholesale generator, like Generating Company. We have asserted that the
MoPSC's approval of the power sales agreement under PUHCA is not required
because Generating Company is not a party to the agreement. In its SEC
complaint, the MoPSC proposes that the SEC require AmerenUE to contract directly
with Generating Company and submit such contract to the MoPSC for review. On May
9, 2002, the MoPSC filed a similar complaint with the SEC relating to the 2002
Marketing Company - AmerenUE agreement. 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 PUHCA. However,
this commitment did not prevent AmerenUE from completing the purchases
contemplated by the 2001 and 2002 Marketing Company - AmerenUE agreement 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.
Also, with respect to the 2002 Marketing Company - AmerenUE agreement, on
May 31, 2002, the FERC accepted the agreement, subject to refund, and scheduled
the matter for a January 2003 hearing. In October 2002, Marketing Company and
the FERC Staff jointly reported to the FERC that they have negotiated a
settlement in principle of the issues that had been set for hearing. Other than
a slight modification to the procedures for establishing off-peak energy prices
under the agreement, the settlement in principle will have no impact on the
agreement's price, terms and conditions. The settlement in principle also
establishes guidelines for AmerenUE to follow when conducting future requests
for proposals for the purpose of pursuing long-term power purchases. On January
27, 2003, the settlement in principle between Marketing Company and the FERC
Staff was certified by the settlement judge and submitted to the FERC for
approval.
Until the SEC and the FERC take final action in these proceedings,
management is unable to predict their ultimate impact on our future financial
position, results of operations or liquidity.
Illinois Electric
In 2002, all of our 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),
44
a rate freeze is in effect through January 1, 2007. As a result of this
extension through January 1, 2007, we expect 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 we will be successful in securing a renewal or extension of this
agreement.
In October 2002, AmerenUE and AmerenCIPS filed with the ICC a proposal to
suspend collection of transition charges associated with the Illinois Law for
the period commencing June 2003 until at least June 2005. The Illinois Law
allows a utility to collect transition charges from customers that elect to move
from bundled retail rates to market-based rates. Utilities have the right to
collect transition charges throughout the transition period that ends January 1,
2007. The suspension of collection of transition charges is not expected to have
a material impact on either AmerenUE or AmerenCIPS.
Under the Illinois Law, we were subject to a residential electric rate
decrease of up to 5% in 2002 to the extent rates exceeded the Midwest utility
average. In 2002, 2001, and 2000, our Illinois electric rates were below the
Midwest utility average.
The Illinois Law also contains a provision requiring that one-half of
excess earnings from the Illinois jurisdiction for the years 1998 through 2006
be refunded to Ameren's Illinois customers. Excess earnings are defined as the
portion of the two-year average annual rate of return on common equity in excess
of 1.5% of the two-year average of an Index, as defined in the Illinois Law. The
Index is defined as the sum of the average for the twelve months ended September
30 of the average monthly yields of the 30-year U.S. Treasury bonds, plus
prescribed percentages ranging from 4% to 7%. AmerenCIPS' and AmerenUE's average
rates of return on common equity for the two year average at December 31, 2002
were 6% and 13%, respectively, as compared to the average index of 12.6%. No
refunds are expected to be required for the period of April 1, 2002 through
March 31, 2003. For the twelve months ended December 31, 1999, AmerenUE made
excess earnings refunds of $2.1 million from April 1, 2000 through March 31,
2001. For the twelve months ended December 31, 2000, AmerenUE made excess
earnings refunds of $1.5 million from April 1, 2001 through May 31, 2002. These
refunds were recorded as a reduction to Operating Revenues - Electric.
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 subsidiaries,
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 we left that
organization. We believed that the for-profit Alliance RTO business model was
superior to the not-for-profit Midwest ISO business model and provided us with a
more equitable return on our 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, Ameren made filings with the FERC
indicating that Ameren 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 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
WWW.AMEREN.COM 45
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 us 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 FERC in an order issued December 19, 2002. In the order, the FERC approved
the return of the $18 million exit fee paid by Ameren 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. In our filing, we
stated that GridAmerica is scheduled to become operational in April 2003.
Until the reliability and rate-barrier issues are resolved as ordered by
the FERC, and the tariffs and other material terms of our 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 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, we filed our initial comments on the NOPR with the FERC
expressing our concern with the potential impact of the proposed rules in their
current form on the cost and reliability of service to retail customers. We 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. We intend to file 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.
Illinois Gas
In November 2002, AmerenCIPS, AmerenUE, and CILCO filed requests with the
ICC to increase annual rates for natural gas service by approximately $16
million, $4 million, and $14 million, respectively. The ICC has until October
2003 to render a decision in these gas cases.
NOTE 3 - DERIVATIVE FINANCIAL INSTRUMENTS
We utilize derivatives principally to manage the risk of changes in market
prices for natural gas, fuel, electricity and emission credits. Price
fluctuations in natural gas, fuel and electricity cause:
o an unrealized appreciation or depreciation in the value 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 and natural gas inventories or purchased power to
differ from the cost of those commodities in inventory or under the firm
commitment; and
o actual cash outlays for the purchase of these commodities, in certain
circumstances, 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
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.
46
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 $8 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 $3
million loss for the year ended December 31, 2002 (2001 - $15 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 net gain of approximately $1 million (less than $1 million, net
of taxes).
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 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 that began in June
2002.
As of December 31, 2002, a gain of approximately $2 million ($1 million,
net of taxes) associated with natural gas swaps was included in OCI. The swaps
were a partial hedge of our index priced, baseload gas supply for the period of
December 2002 through March 2003. The swaps effectively fix the price on a
portion of our gas supply for that time period.
We also held three call options for coal with two suppliers. These options
to purchase coal expire October 2003, July 2004 and July 2005. As of December
31, 2002, a mark-to-market gain of approximately $6 million ($4 million, net of
taxes) associated with these options was included in OCI. The final value of the
options will be recognized as a reduction in fuel costs as the hedged coal is
burned.
Other Derivatives
We enter into option transactions to manage our positions in sulfur dioxide
allowances, coal, heating oil and electricity. Most of these transactions are
treated as non-hedge transactions under SFAS 133. The net change in the market
value of sulfur dioxide options is recorded as Operating Revenues - Electric,
while the net change in the market value of coal, heating oil and electricity
options is recorded as Operating Expense - Operations - Fuel and Purchased Power
in the income statement. The net change in the market values of sulfur dioxide,
coal, heating oil and electricity options was a gain of $5 million ($3 million,
net of taxes) for the year ended December 31, 2002 (2001 - loss of less than $1
million).
NOTE 4 - PROPERTY AND PLANT, NET
At December 31, 2002 and 2001, property and plant, net consisted of the
following:
<Table>
<Caption>
2002 2001
------- -------
PROPERTY AND PLANT, AT ORIGINAL COST:
Electric $14,495 $13,664
Gas 557 532
Other 219 105
------- -------
15,271 14,301
Less accumulated depreciation
and amortization 6,831 6,535
------- -------
8,440 7,766
CONSTRUCTION WORK IN PROGRESS:
Nuclear fuel in process 81 97
Other 393 564
------- -------
Property and plant, net $ 8,914 $ 8,427
======= =======
</Table>
WWW.AMEREN.COM 47
NOTE 5 - NUCLEAR FUEL LEASE
We have a lease agreement, expiring on August 31, 2031, that provides for
the financing of a portion of our nuclear fuel that is being processed for use
or being consumed in AmerenUE's Callaway nuclear plant. The lease agreement has
variable interest rates based on short-term commercial paper interest rates. At
December 31, 2002, the maximum amount that could be financed under the agreement
was $120 million, of which $113 million was utilized. The lessor, Gateway Fuel
Company, maintains a $120 million committed credit facility which supports the
financing of fuel under the lease. We consider available lease capacity, future
purchase commitments and upcoming in-service fuel requirements when determining
whether to utilize leased nuclear fuel. We are not required to pay the lessor,
an unrelated third party, unless nuclear fuel is removed from the lease,
consumed at our nuclear plant or the lease is terminated. Pursuant to the terms
of the lease, we assign to the lessor certain contracts for purchase of nuclear
fuel. The lessor obtains, through the issuance of commercial paper or from
direct loans under a committed revolving credit agreement from commercial banks,
the necessary funds to purchase the fuel and make interest payments when due.
We are obligated to reimburse the lessor for expenditures for nuclear fuel,
interest and related costs under the lease. As any leased nuclear fuel is
consumed at AmerenUE's Callaway nuclear plant, obligations under this lease
become due. No leased nuclear fuel was consumed in 2001. Therefore, no
reimbursements for amounts consumed under the lease occurred in 2001. Leased
nuclear fuel consumption re-commenced in the fourth quarter of 2002. The
corresponding reimbursement will occur in the first quarter of 2003. We
reimbursed $13 million during 2000 for amounts consumed under the lease.
We have capitalized the cost of the leased nuclear fuel incurred by the
lessor, plus certain interest costs, and have recorded the related lease
obligation. Total interest charges under the lease were $2 million in 2002, $4
million in 2001, and $8 million in 2000. Interest charges for these years were
based on average interest rates of approximately 2% for 2002, 5% for 2001 and 7%
for 2000. Interest charges of $2 million in 2002, $4 million in 2001, and $6
million in 2000 were capitalized.
NOTE 6 - SHAREHOLDER RIGHTS PLAN AND PREFERRED STOCK SUBSIDIARIES
In October 1998, our Board of Directors approved a share purchase rights
plan designed to assure shareholders of fair and equal treatment in the event of
a proposed takeover. The rights will be exercisable only if a person or group
acquires 15% or more of Ameren's common stock or announces a tender offer, the
consummation of which would result in ownership by a person or group of 15% or
more of the common stock. Each right will entitle the holder to purchase one
one-hundredth of a newly issued preferred stock at an exercise price of $180. If
a person or group acquires 15% or more of Ameren's outstanding common stock,
each right will entitle its holder (other than such person or members of such
group) to purchase, at the right's then-current exercise price, a number of
Ameren's common shares having a market value of twice such price. In addition,
if we are acquired in a merger or other business combination transaction after a
person or group has acquired 15% or more of our outstanding common stock, each
right will entitle its holder to purchase, at the right's then-current exercise
price, a number of the acquiring company's common shares having a market value
of twice such price. The acquiring person or group will not be entitled to
exercise these rights. The SEC approved the plan under PUHCA in December 1998.
The rights were issued as a dividend payable January 8, 1999, to shareholders of
record on that date; these rights expire in 2008. One right will accompany each
new share of Ameren common stock issued prior to such expiration date.
Outstanding preferred stock is entitled to cumulative dividends and is
redeemable, at the option of the issuer, at the prices shown in the following
table as of December 31, 2002 and 2001:
<Table>
<Caption>
Redemption Price
Shares (Per Share) 2002 2001
--------- ---------------- --------- ---------
PREFERRED STOCK OF SUBSIDIARIES NOT
SUBJECT TO MANDATORY REDEMPTION -
AmerenUE:
Without par value and stated
value of $100 per share,
25 million shares authorized
$7.64 Series 330,000 $ 103.82(a) $ 33 $ 33
$5.50 Series A 14,000 110.00 1 1
$4.75 Series 20,000 102.176 2 2
$4.56 Series 200,000 102.47 20 20
$4.50 Series 213,595 110.00(b) 21 21
$4.30 Series 40,000 105.00 4 4
$4.00 Series 150,000 105.625 15 15
$3.70 Series 40,000 104.75 4 4
$3.50 Series 130,000 110.00 13 13
Without par value and stated
value of $25 per share
$1.735 Series 1,657,500 25.00 -- 42
--------- ---------------- --------- ---------
</Table>
Continued on Page 49
48
<Table>
<Caption>
Redemption Price December 31,
Shares (Per Share) 2002 2001
--------- ---------------- --------- ---------
AMERENCIPS:
With par value of $100 per share,
4.6 million shares authorized
4.00% Series 150,000 $ 101.00 $ 15 $ 15
4.25% Series 50,000 102.00 5 5
4.90% Series 75,000 102.00 8 8
4.92% Series 50,000 103.50 5 5
5.16% Series 50,000 102.00 5 5
1993 Auction 300,000 100.00(c) 30 30
6.625% Series 125,000 100.00 12 12
--------- --------- --------- ---------
TOTAL PREFERRED STOCK OF SUBSIDIARIES
NOT SUBJECT TO MANDATORY REDEMPTION $ 193 $ 235
========= =========
</Table>
(a) Beginning February 15, 2003, declining to $100 per share in 2012.
(b) In the event of voluntary liquidation, $105.50.
(c) Dividend rates, and the periods during which such rates apply, vary
depending on our selection of certain defined dividend period lengths. The
average dividend rate during 2002 was 2.35%.
NOTE 7 - SHORT-TERM BORROWINGS
Our short-term borrowings consist of commercial paper and bank loans
(maturities generally within 1 to 45 days). At December 31, 2002, $271 million
(2001 - $641 million) of short-term borrowings was outstanding. The weighted
average interest rate on short-term borrowings outstanding at December 31, 2002
was 1.4% (2001 - 1.9%).
At December 31, 2002, Ameren had bank credit agreements totaling $695
million, excluding EEI facilities of $45 million and nuclear fuel lease
facilities of $21 million, expiring at various dates in 2003 and 2005. All of
these amounts were available for use by our rate-regulated subsidiaries
(AmerenUE and AmerenCIPS) and Ameren Services Company, and $600 million of this
amount was available for use by Ameren Corporation and most of our non
rate-regulated subsidiaries including, but not limited to, Resources Company,
Generating Company, Marketing Company, AmerenEnergy Fuels and Services Company
and AmerenEnergy. These committed credit facilities are used to support our
commercial paper programs under which $250 million was outstanding at December
31, 2002. At December 31, 2002, $445 million was unused and available under
these committed credit facilities.
We also have two bank credit agreements totaling $45 million that expire in
2003 at EEI. At December 31, 2002, $27 million was unused and available under
these committed credit facilities.
Certain of our bank credit agreements contain provisions which, among other
things, place restrictions on our ability to incur liens, sell assets, merge
with other entities and restrict and encumber upstream dividend payments of our
subsidiaries. Also, certain of our credit agreements contain a provision that
restricts Ameren's, AmerenUE's and AmerenCIPS' total indebtedness to 60% of
total capitalization. In addition, certain of our credit agreements contain
cross default provisions and material adverse change clauses, which require us
to represent that no such change has occurred before borrowings can be made. At
December 31, 2002, Ameren, AmerenUE and AmerenCIPS were in compliance with all
such provisions.
We have money pool agreements with and among our subsidiaries to coordinate
and provide for certain short-term cash and working capital requirements.
Separate money pools are maintained between rate-regulated and non
rate-regulated businesses. Interest is calculated at varying rates of interest
depending on the composition of internal and external funds in the money pools.
This debt and the related interest represent intercompany balances, which are
eliminated at the Ameren Corporation consolidated level.
NOTE 8 - LONG-TERM DEBT AND CAPITALIZATION
The following table summarizes our long-term debt outstanding at December
31, 2002 and 2001:
<Table>
<Caption>
2002 2001
------ ------
FIRST MORTGAGE BONDS - (a)
AmerenUE:
8.33% Series paid in 2002 $ -- $ 75
8 3/4% Series paid in 2002 -- 125
7.65% Series due 2003 100 100
6 7/8% Series due 2004 188 188
7 3/8% Series due 2004 85 85
6 3/4% Series due 2008 148 148
5.25% Series due 2012 173 --
8 1/4% Series due 2022 104 104
8% Series due 2022 85 85
7.15% Series due 2023 75 75
7% Series due 2024 100 100
5.45% Series due 2028(b) 44 44
AmerenCIPS:
6 3/8% Series Z due 2003 40 40
7 1/2% Series X due 2007 50 50
6.625% Series due 2011 150 150
7.61% 1997 Series due 2017 40 40
6.125% Series due 2028 60 60
Other 5.375% -7.05% due
2003 through 2008 60 93
------ ------
$1,502 $1,562
------ ------
</Table>
Continued on Page 50
WWW.AMEREN.COM 49
Continued from Page 49
<Table>
<Caption>
December 31,
2002 2001
------ ------
ENVIRONMENTAL IMPROVEMENT/
POLLUTION CONTROL REVENUE BONDS -
AmerenUE:
1991 Series due 2020(c) $ 43 $ 43
1992 Series due 2022(c) 47 47
1998 Series A due 2033(c) 60 60
1998 Series B due 2033(c) 50 50
1998 Series C due 2033(c) 50 50
2000 Series A due 2035(c) 64 64
2000 Series B due 2035(c) 63 63
2000 Series C due 2035(c) 60 60
AmerenCIPS:
2000 Series A 5.5% due 2014(d) 51 51
1993 Series C-1 5.95% due 2026(d) 35 35
1993 Series A 6 3/8% due 2028 35 35
Other 5% - 5.90% due
2026 through 2028(d) 60 60
------ ------
618 618
------ ------
SUBORDINATED DEFERRABLE
INTEREST DEBENTURES -
AmerenUE:
7.69% Series A due 2036(e) 66 66
------ ------
OTHER UNSECURED DEBT -
Ameren Corporation:
2001 Floating rate notes due 2003(f) 150 150
2002 5.70% Notes due 2007(g) 100 --
Senior note, due 2007 345 --
Generating Company:
2000 Senior notes series C
7 3/4% due 2005(h)(i) 225 225
2000 Senior notes series D
8.35% due 2010(i)(j) 200 200
2002 Senior notes series F
7.95% due 2032(i)(k) 275 --
Electric Energy, Inc.:
2000 Senior notes 7.61% due 2004 40 40
1991 II Senior medium term notes
8.60% due through 2005 20 27
1994 Senior medium term notes
6.61% due through 2005 23 31
------ ------
1,378 673
------ ------
CAPITAL LEASE OBLIGATIONS -
AmerenUE:
Nuclear fuel lease 113 63
City of Bowling Green lease 103 --
------ ------
216 63
------ ------
UNAMORTIZED DISCOUNT
AND PREMIUM ON DEBT (8) (8)
------ ------
MATURITIES DUE WITHIN ONE YEAR (339) (139)
------ ------
TOTAL LONG-TERM DEBT $3,433 $2,835
====== ======
</Table>
(a) At December 31, 2002, a majority of property and plant was mortgaged under,
and subject to liens of, the respective indentures pursuant to which the
bonds were issued. AmerenUE's and AmerenCIPS' first mortgage bond
indentures contain provisions that restrict the issuance of additional
bonds. These provisions restrict future first mortgage bond issuance to 60%
of unused net bondable property and previously retired bonds. In addition,
net earnings must be at least twice that of first mortgage bond interest to
be able to issue bonds under the indentures. AmerenCIPS' indenture also
requires a certain level of maintenance capital expenditures. At December
31, 2002, both AmerenUE and AmerenCIPS were in compliance with all such
provisions.
(b) Environmental Improvement Series backed by first mortgage bonds.
(c) Interest rates, and the periods during which such rates apply, vary
depending on our selection of certain defined rate modes. The average
interest rates for the year 2002 were as follows:
<Table>
1991 Series 1.64%
1992 Series 1.60%
1998 Series A 1.53%
1998 Series B 1.53%
1998 Series C 1.53%
2000 Series A 1.56%
2000 Series B 1.52%
2000 Series C 1.56%
</Table>
(d) Variable rate tax-exempt pollution control indebtedness that was converted
to long-term fixed rates.
(e) During the terms of the debentures, AmerenUE may, under certain
circumstances, defer the payment of interest for up to five years. Upon the
election to defer interest payments, dividend payments to Ameren
Corporation are prohibited.
(f) Interest is payable quarterly commencing March 12, 2002. Principal is
payable on December 12, 2003. The per annum interest rate on the notes for
each interest period will be a floating rate equal to three month LIBOR
plus a spread of 0.95%.
(g) Interest is payable semiannually in arrears on February 1 and August 1 of
each year, commencing August 1, 2002. Principal will be payable on February
1, 2007.
(h) 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.
(i) Generating Company's 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, Generating Company was
in compliance with all such provisions.
(j) 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.
(k) 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.
50
The following table summarizes the maturities of long-term debt at December
31, 2002:
<Table>
<Caption>
Ameren
Corporation AmerenUE AmerenCIPS
------------ ------------ ------------
2003 $ 150 $ 130 $ 45
2004 -- 306 --
2005 -- 36 20
2006 -- 27 20
2007 445 4 50
Thereafter -- 1,318 446
------------ ------------ ------------
TOTAL $ 595 $ 1,821 $ 581
============ ============ ============
</Table>
<Table>
<Caption>
Generating Electric Ameren
Company Energy, Inc. Consolidated
------------ ------------ ------------
2003 $ -- $ 14 $ 339
2004 -- 55 361
2005 225 14 295
2006 -- -- 47
2007 -- -- 499
Thereafter 475 -- 2,239
------------ ------------ ------------
TOTAL $ 700 $ 83 $ 3,780
============ ============ ============
</Table>
Ameren Corporation
In January 2002, Ameren Corporation issued $100 million of 5.70% notes due
February 1, 2007 in a private placement to qualified investors under rule 144A.
Ameren received net proceeds of $99.7 million, after debt discount and fees,
which were used to reduce short-term borrowings. Interest is payable
semi-annually on February 1 and August 1 of each year. In March 2002, Ameren
Corporation entered into interest rate swaps effectively converting the interest
rate associated with these notes to three month LIBOR plus 43 basis points. At
December 31, 2002, the effective interest rate for these notes was 2.13%.
In March 2002, Ameren Corporation issued $345 million of adjustable
conversion-rate equity security units and $227 million of common stock (5
million shares at $39.50 per share and 750,000 shares, pursuant to the exercise
of an option granted to the underwriters, at $38.865 per share). The $25
adjustable conversion-rate equity security units each consisted of an Ameren
Corporation senior unsecured note with a principal amount of $25 and a contract
to purchase, for $25, a fraction of a share of Ameren common stock on May 15,
2005. The senior unsecured notes were recorded at their fair value of $345
million and will mature on May 15, 2007. Total distributions on the equity
security units will be at an annual rate of 9.75%, consisting of quarterly
interest payments on the senior unsecured notes at the initial annual rate of
5.20% and adjustment payments under the stock purchase contracts at the annual
rate of 4.55%. The stock purchase contracts require holders to purchase between
8.7 million and 7.4 million shares of Ameren Corporation common stock on May 15,
2005 at the market price at that time, subject to a minimum share purchase price
of $39.50 and a maximum of $46.61. The stock purchase contracts include a pledge
of the senior unsecured notes as collateral for the stock purchase obligation.
The interest rate on the outstanding senior unsecured notes is subject to being
reset by a remarketing agent for quarterly payments after May 15, 2005 until
maturity. We recorded the net present value of the contracted stock purchase
payments of $46 million as an increase in Other Deferred Credits and Liabilities
to reflect our obligation and a decrease in Other Paid-in Capital to reflect the
fair value of the stock purchase contract. The liability for the contracted
stock purchase adjustment payments (December 31, 2002 - $35 million) will be
reduced as such payments are made through May 15, 2005. We used the net proceeds
from these offerings to repay short-term indebtedness and for general corporate
purposes.
In July 2002, Ameren Corporation entered into new committed credit
agreements for $400 million in revolving credit facilities to be used for
general corporate purposes, including support of our commercial paper programs.
The $400 million in new facilities includes a $270 million 364-day revolving
credit facility and a $130 million 3-year revolving credit facility. The 3-year
facility has a $50 million sub-limit for the issuance of letters of credit.
These new credit facilities replaced AmerenUE's $300 million revolving credit
facility.
In August 2002, a shelf registration statement filed by Ameren Corporation
with the SEC on Form S-3 was declared effective. This statement authorized the
offering from time to time of up to $1.473 billion of various forms of
securities including long-term debt, trust preferred and equity securities to
finance ongoing construction and maintenance programs, to redeem, repurchase,
repay, or retire outstanding debt, to finance strategic investments, including
our then pending acquisition of CILCORP, and for general corporate purposes.
In September 2002, Ameren Corporation issued, pursuant to the shelf
registration statement, $338 million of common stock (8.05 million shares at
$42.00 per share). Net proceeds were $327 million after fees, which were used to
fund part of the cash portion of the purchase price for our acquisition of
CILCORP. See Note 18 - Subsequent Event for further information.
In early 2003, Ameren issued, pursuant to the shelf registration statement,
6.325 million shares at $40.50 per share. We received net proceeds of $248
million after fees which were used to fund the remaining cash
WWW.AMEREN.COM 51
portion of the purchase price for our acquisition of CILCORP (see Note 18 -
Subsequent Event for further information) and for general corporate purposes.
We may sell all, or a portion of, the remaining registered securities under
the shelf registration statement if warranted by market conditions and our
capital requirements. Any offer and sale will be made only by means of a
prospectus meeting the requirements of the Securities Act of 1933 and the rules
and regulations thereunder. In 2002 and in early 2003, $594 million was issued
under the shelf registration statement. At February 13, 2003, the amount
remaining on the shelf registration statement was approximately $879 million.
In September 2001, we began issuing new shares of common stock under our
dividend reinvestment and stock purchase plan (DRPlus) and in December 2001, we
began issuing new shares of common stock in connection with our 401(k) plans.
Previously, these requirements were met by purchasing outstanding shares. Under
these plans, we issued 2.3 million shares of common stock in 2002 and 0.8
million shares in 2001 that were valued at $92 million and $33 million,
respectively.
In December 2001, Ameren Corporation issued Floating Rate Notes (FRNs)
totaling $150 million. Interest accrues on the FRNs at the three month LIBOR
(reset quarterly) plus 0.95% and is payable quarterly commencing in March 2002.
The FRNs are due in December 2003. The proceeds were used to reduce short-term
borrowings.
Ameren expects to fund maturities of long-term debt and contractual
obligations through a combination of cash flow from operations and external
financing.
At December 31, 2002, neither Ameren Corporation, nor any of its
subsidiaries, had any off-balance sheet financing arrangements, other than
operating leases entered into the ordinary course of business. We do not expect
to engage in any significant off-balance sheet financing arrangements in the
near future.
Amortization of debt issuance costs and any premium or discounts for the
years ended December 31, 2002 of $8 million (2001 - $5 million; 2000 - $6
million) were included in interest expense in the income statement.
AmerenUE
In August 2002, a shelf registration statement filed by AmerenUE with the
SEC on Form S-3 was declared effective. This statement authorized the offering
from time to time of up to $750 million of various forms of long-term debt and
trust preferred securities to refinance existing debt and preferred stock, and
for general corporate purposes, including the repayment of short-term debt
incurred to finance construction expenditures and other working capital needs.
In August 2002, AmerenUE issued, pursuant to the shelf registration
statement, $173 million of 5.25% Senior Secured Notes due September 1, 2012.
Interest is payable semi-annually on March 1 and September 1 of each year,
beginning March 1, 2003. Net proceeds were $172 million, after debt discount and
fees. These senior secured notes are secured by a related series of AmerenUE's
first mortgage bonds until the release date as described in the senior secured
note indenture. Proceeds were used to redeem, in September 2002, AmerenUE's $125
million principal amount 8.75% first mortgage bonds due December 1, 2021 at a
4.38% premium and AmerenUE's $42 million $1.735 series preferred stock at par.
We may sell all, or a portion of, the remaining registered securities under the
shelf registration statement if warranted by market conditions and our capital
requirements. Any offer and sale will be made only by means of a prospectus
meeting the requirements of the Securities Act of 1933 and the rules and
regulations thereunder. At December 31, 2002, the amount remaining on the shelf
registration statement was $577 million.
In December 2002, upon receipt of all the necessary federal and state
regulatory approvals, AmerenUE, pursuant to Missouri economic development
statutes, conveyed most of its Peno Creek combustion turbine generating facility
to the City of Bowling Green, Missouri in exchange for the issuance by the City
of a taxable industrial development revenue bond in the amount of $103.4
million. Concurrently, the City leased back the facility to AmerenUE for a term
of 20 years. The lease term is the same as the final maturity of the bond
purchased by AmerenUE. While the lease is a capital lease, no capital was raised
in the transaction. AmerenUE is responsible for making rental payments under the
lease in an amount sufficient to pay the debt service of the bond. The City's
ownership of the facility during the term of the bond and the lease is expected
to result in property tax savings to AmerenUE. Under the terms of the lease,
AmerenUE retains all operation and maintenance responsibilities for the facility
and ownership of the facility is returned to AmerenUE at the expiration of the
lease.
Generating Company
In June 2002, Generating Company issued $275 million of 7.95% Senior Notes,
Series E, due 2032 (Series E Notes) in a private placement to qualified
investors under Rule 144A. Interest is payable semi-annually on June 1 and
December 1 of each year, beginning December 1, 2002. Generating Company received
52
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 January 2003, all note
holders completed an exchange of the privately placed notes for new Series F
Notes, which are identical in all material respects to the Series E Notes,
except that the new series of notes were registered with the SEC and do not
contain transfer restrictions.
Generating Company's senior note indenture includes provisions that require
it 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 to Ameren or to make payments of principal or
interest under certain subordinate indebtedness excluding amounts payable under
an intercompany note payable with AmerenCIPS. For the four quarters ending
December 31, 2002, this ratio was 4.10 to 1. In addition, the indenture also
restricts Generating Company from incurring any additional indebtedness, with
the exception of certain permitted indebtedness as defined in the indenture,
unless its senior debt service coverage ratio equals at least 2.5 to 1 for the
most recently ended four fiscal quarters and its 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 the ratings of
Generating Company after considering the additional indebtedness. As of December
31, 2002, Generating Company's senior debt to total capital was 55%.
In November 2000, Generating Company issued $225 million of 7.75% Senior
Notes, Series A due 2005 and $200 million principal amount 8.35% Senior Notes,
Series B due 2010 in a private placement to qualified investors under Rule 144A.
In 2001, all holders completed an exchange of the privately placed Series A or B
Notes for respective new Series C and D Notes, which are identical in all
material respects, except that the new series of notes do not contain transfer
restrictions. Proceeds were used to reduce short-term borrowings incurred in
conjunction with the construction of combustion turbine generating facilities,
for the construction of subsequent combustion turbine facilities, and for
funding working capital and other capital expenditure needs.
AmerenCIPS
In May 2001, a shelf registration statement filed by AmerenCIPS with the
SEC on Form S-3 was declared effective. This registration statement enables
AmerenCIPS to offer from time to time senior notes in one or more series with an
offering price not to exceed $250 million. In June 2001, AmerenCIPS issued $150
million of senior notes due June 2011 with an interest rate of 6.625%. Until the
release date as described in the senior secured note indenture, the senior notes
will be secured by a related series of AmerenCIPS' first mortgage bonds. The
proceeds of these senior notes were used to repay short-term debt and first
mortgage bonds maturing in June 2001. At December 31, 2002, the amount remaining
on the shelf registration statement was $100 million.
NOTE 9 - VOLUNTARY RETIREMENT AND OTHER RESTRUCTURING CHARGES
Voluntary retirement and other restructuring charges were $92 million in
2002 or $58 million, net of taxes.
In December 2002, approximately 550 employees accepted a voluntary
retirement program that was offered to approximately 1,000 of our 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 $75 million ($47 million, net of taxes) in December 2002
related to the voluntary retirement program. These costs consisted primarily of
special termination benefits associated with our pension and post-retirement
benefit plans.
In December 2002, we also retired 343 megawatts of rate-regulated capacity
at AmerenUE's Venice, Illinois plant and announced that we were temporarily
suspending operation of two coal-fired generating units at Generating Company's
Meredosia, Illinois plant, representing 126 megawatts of non rate-regulated
power generation capacity. The capacity reductions and related severance charges
resulted in a charge of $17 million ($11 million, net of taxes) in December
2002.
WWW.AMEREN.COM 53
NOTE 10 - MISCELLANEOUS, NET
Miscellaneous, net for the years ended December 31, 2002, 2001, and 2000
consisted of the following:
<Table>
<Caption>
2002 2001 2000
---- ---- ----
MISCELLANEOUS INCOME:
Interest and dividend income $ 8 $ 4 $ 8
Gain on disposition of property 3 5 2
Contribution in aid of construction -- 7 --
Other 4 6 4
---- ---- ----
TOTAL MISCELLANEOUS INCOME $ 15 $ 22 $ 14
==== ==== ====
MISCELLANEOUS EXPENSE:
Minority interest in EEI $(14) $ (4) $ (4)
Loss on disposition of property -- (2) (1)
Donations, including 2002
rate settlement (26) (1) (6)
Other (10) (9) (10)
---- ---- ----
TOTAL MISCELLANEOUS EXPENSE $(50) $(16) $(21)
==== ==== ====
</Table>
NOTE 11 - INCOME TAXES
Total income tax expense for 2002 resulted in an effective tax rate of 38%
on earnings before income taxes (39% in 2001 and 2000).
The principal reasons such rates differ from the statutory federal rate for
the years ended December 31, 2002, 2001, and 2000 were as follows:
<Table>
<Caption>
2002 2001 2000
---- ---- ----
STATUTORY FEDERAL INCOME TAX RATE: 35% 35% 35%
Increases (decreases) from:
Depreciation differences 2 2 2
State tax 3 3 3
Other (2) (1) (1)
---- ---- ----
EFFECTIVE INCOME TAX RATE 38% 39% 39%
==== ==== ====
</Table>
Components of income tax expense for the years ended December 31, 2002,
2001, and 2000 were as follows:
<Table>
<Caption>
2002 2001 2000
----- ----- -----
TAXES CURRENTLY PAYABLE
(PRINCIPALLY FEDERAL):
Included in operating expenses $ 185 $ 280 $ 307
Included in other income (13) 5 (3)
----- ----- -----
172 285 304
DEFERRED TAXES (PRINCIPALLY FEDERAL):
Included in operating expenses:
Depreciation differences 83 9 (5)
Other (9) 19 7
Included in other income -- -- --
----- ----- -----
74 28 2
DEFERRED INVESTMENT TAX CREDITS,
AMORTIZATION:
Included in operating expenses (9) (8) (8)
----- ----- -----
TOTAL INCOME TAX EXPENSE $ 237 $ 305 $ 298
===== ===== =====
</Table>
In accordance with SFAS 109, "Accounting for Income Taxes," a regulatory
asset, representing the probable recovery from customers of future income taxes,
which is expected to occur when temporary differences reverse, was recorded
along with a corresponding deferred tax liability. Also, a regulatory liability,
recognizing the lower expected revenue resulting from reduced income taxes
associated with amortizing accumulated deferred investment tax credits was
recorded. Investment tax credits have been deferred and will continue to be
credited to income over the lives of the related property.
We adjust our deferred tax liabilities for changes enacted in tax laws or
rates. Recognizing that regulators will probably reduce future revenues for
deferred tax liabilities initially recorded at rates in excess of the current
statutory rate, reductions in the deferred tax liability were credited to the
regulatory liability.
Temporary differences gave rise to the following deferred tax assets and
deferred tax liabilities at December 31, 2002, 2001, and 2000:
<Table>
<Caption>
2002 2001
------- -------
ACCUMULATED DEFERRED INCOME TAXES:
Depreciation $ 1,161 $ 1,040
Regulatory assets, net 405 434
Capitalized taxes and expenses 237 184
Deferred benefit costs (79) (68)
Other (12) 31
------- -------
TOTAL NET ACCUMULATED DEFERRED
INCOME TAX LIABILITIES $ 1,712 $ 1,621
======= =======
</Table>
NOTE 12 - RETIREMENT BENEFITS
We have defined benefit and post-retirement benefit plans covering
substantially all employees of AmerenUE, AmerenCIPS and Ameren Services Company
and certain employees of Resources Company and its subsidiaries.
Pension
Pension benefits are based on the employees' years of service and
compensation. Our plans are funded in compliance with income tax regulations and
federal funding requirements. We made cash contributions totaling $31 million to
our defined benefit retirement plan during 2002. At December 31, 2002, we
recorded a minimum pension liability of $102 million after taxes, which resulted
in a charge to OCI and a reduction in stockholders' equity. Based on the
performance of plan assets through December 31, 2002, we expect to be required
under the Employee Retirement Income Security Act of 1974 to fund $150 million
to $175 million annually in 2005, 2006 and 2007 in order to maintain
54
minimum funding levels. These amounts are estimates and may change based on
actual stock market performance, changes in interest rates, and any changes in
government regulations.
As mentioned in Note 9 - Voluntary Retirement and Other Restructuring
Charges, approximately 550 employees accepted a voluntary retirement program in
December 2002. Special termination benefits for 2002 included in the table below
represent the enhanced improvement in benefits provided to the employees who
voluntarily retired in December 2002.
The funded status of Ameren's pension plan for the years ended December 31,
2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
------- -------
CHANGE IN BENEFIT OBLIGATION:
Net benefit obligation
at beginning of year $ 1,418 $ 1,362
Service cost 33 32
Interest cost 103 100
Actuarial loss 64 14
Special termination benefits 65 --
Benefits paid (96) (90)
------- -------
Net benefit obligation at end of year $ 1,587 $ 1,418
======= =======
CHANGE IN PLAN ASSETS:(a)
Fair value of plan assets
at beginning of year $ 1,225 $ 1,359
Actual return on plan assets (101) (45)
Employer contributions 31 1
Benefits paid (96) (90)
------- -------
Fair value of plan assets at end of year $ 1,059 $ 1,225
======= =======
Funded status - deficiency $ 528 $ 193
Unrecognized net actuarial loss (324) (33)
Unrecognized prior service cost (68) (77)
Unrecognized net transition asset 3 5
------- -------
ACCRUED PENSION COST AT DECEMBER 31 $ 139 $ 88
======= =======
</Table>
(a) Plan assets consist principally of common stocks (60%) and fixed income
securities (40%)
<Table>
AMOUNTS RECOGNIZED IN THE CONSOLIDATED
BALANCE SHEET CONSIST OF:
Accrued pension liability $ 377 $ 88
Intangible asset (74) --
Accumulated other
comprehensive income (164) --
------- -------
Accrued pension cost at December 31 $ 139 $ 88
======= =======
</Table>
Components of Ameren's net periodic pension benefit cost during 2002, 2001
and 2000 were as follows:
<Table>
<Caption>
2002 2001 2000
----- ----- -----
Service cost $ 33 $ 32 $ 30
Interest cost 103 100 98
Expected return on plan assets (114) (115) (110)
Amortization of:
Transition asset (1) (1) (1)
Prior service cost 9 9 7
Actuarial gain (12) (21) (21)
----- ----- -----
NET PERIODIC BENEFIT COST $ 18 $ 4 $ 3
===== ===== =====
NET PERIODIC BENEFIT COST, INCLUDING
SPECIAL TERMINATION BENEFITS $ 83 $ 4 $ 3
===== ===== =====
</Table>
Pension costs were $18 million for 2002, $4 million for 2001, and $3
million for 2000 of which 16%, 16% and 21%,were charged to construction
accounts, respectively.
Assumptions for actuarial present value of projected benefit obligations
during 2002, 2001, and 2000 were as follows:
<Table>
<Caption>
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%
======= ======= =======
</Table>
Post-Retirement
Our 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.
Post-retirement benefit costs were $74 million for 2002, $63 million for 2001
and $58 million for 2000 of which approximately 18%, 18%, and 17% were charged
to construction accounts, respectively. Ameren's transition obligation at
December 31, 2002 is being amortized over the next 12 years. The MoPSC and the
ICC allow the recovery of post-retirement benefit costs in rates to the extent
that such costs are funded.
Plan amendments included in the table below represent a favorable change to
our net benefit obligation and relate to increasing retiree premiums and placing
limits on healthcare benefits.
WWW.AMEREN.COM 55
The funded status of Ameren's post-retirement benefit plans at December 31,
2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
----- -----
CHANGE IN BENEFIT OBLIGATION:
Net benefit obligation
at beginning of year $ 701 $ 589
Service cost 26 23
Interest cost 51 47
Employee contributions 2 1
Plan amendments (186) --
Actuarial loss 211 80
Special termination benefits 8 --
Benefits paid (42) (39)
----- -----
Net benefit obligation at end of year $ 771 $ 701
===== =====
CHANGE IN PLAN ASSETS:(a)
Fair value of plan assets
at beginning of year $ 300 $ 290
Actual return on plan assets (26) (17)
Employer contributions 74 65
Employee contributions 2 1
Benefits paid (41) (39)
----- -----
Fair value of plan assets at end of year 309 300
===== =====
Funded status - deficiency 462 401
Unrecognized net actuarial loss (389) (134)
Unrecognized prior service cost 47 2
Unrecognized net transition obligation (21) (180)
----- -----
POST-RETIREMENT BENEFIT LIABILITY
AT DECEMBER 31 $ 99 $ 89
===== =====
</Table>
(a) Plan assets consisted principally of common stocks (49%), bonds (38%) and
money market instruments (13%).
Components of Ameren's net periodic post-retirement benefit cost as of
December 31, 2002, 2001, and 2000 were as follows:
<Table>
<Caption>
2002 2001 2000
---- ---- ----
Service cost $ 26 $ 23 $ 19
Interest cost 51 47 43
Expected return on plan assets (27) (25) (18)
Amortization of:
Transition obligation 16 16 16
Actuarial (gain)/loss 8 2 (2)
---- ---- ----
NET PERIODIC BENEFIT COST $ 74 $ 63 $ 58
==== ==== ====
NET PERIODIC BENEFIT COST, INCLUDING
SPECIAL TERMINATION BENEFITS $ 82 $ 63 $ 58
==== ==== ====
</Table>
Assumptions for the post-retirement benefit plan obligation measurements
for the years ended December 31, 2002, 2001, and 2000 were as follows:
<Table>
<Caption>
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%
======= ======= =======
</Table>
A 1% increase in the medical cost trend rate is estimated to increase the
net periodic cost and the accumulated post-retirement benefit obligation
approximately $7 million and $53 million, respectively. A 1% decrease in the
medical cost trend rate is estimated to decrease the net periodic cost and the
accumulated post-retirement benefit obligation approximately $6 million and $49
million, respectively.
NOTE 13 - STOCK-BASED COMPENSATION
We have a long-term incentive plan for eligible employees, which provides
for the grant of options, performance awards, restricted stock, dividend
equivalents and stock appreciation rights. We have not granted any stock options
since December 31, 2000, but did grant restricted stock awards in 2002 and 2001
as a component of our compensation programs. We applied APB 25 in accounting for
our stock-based compensation for the years ended December 31, 2002, 2001 and
2000. Effective January 1, 2003, we adopted SFAS 123. See Note 1 - Summary of
Significant Accounting Policies for further information.
Restricted Stock
Restricted stock awards may be granted under our long-term incentive plan.
Upon the achievement of certain performance levels, the restricted stock award
vests over a period of seven years, beginning at the date of grant, and includes
provisions requiring certain stock ownership levels based on position and
salary. An accelerated vesting provision is also included in this plan which
reduces the vesting period from seven years to three years. During 2002 and
2001, respectively, 154,678 and 141,788 restricted stock awards were granted.
The weighted-average fair value for restricted stock awards granted in 2002 and
2001 was $42.50 and $39.60 per share, respectively. We record unearned
compensation (as a component of stockholders' equity) equal to the market value
of the restricted stock on the date of grant and charge the unearned
compensation to expense over the vesting period. In accordance with SFAS 123, we
recorded compensation expense relating to restricted
56
stock awards of approximately $2 million in 2002 (which includes accelerated
expense of approximately $1 million related to our voluntary retirement program
offered in 2002) and approximately $1 million in 2001.
Stock Options
Options may be granted at a price not less than the fair market value of
the common shares at the date of grant. Granted options vest over a period of
five years, beginning at the date of grant, and provide for accelerated
exercising upon the occurrence of certain events, including retirement.
Outstanding options expire on various dates through 2010. Subject to adjustment,
four million shares have been authorized to be issued or delivered under our
long-term incentive plan. In accordance with APB 25, no compensation expense was
recognized related to our stock options for 2002, 2001 or 2000. The pretax
effect of weighted-average grant-date fair value of options granted would have
been approximately $2 million in each of the years ended 2002, 2001 and 2000 had
the fair value method under SFAS 123 been used for options. The fair value
method will be used prospectively beginning January 1, 2003. See Note 1 -
Summary of Significant Accounting Policies for further information.
The following table summarizes stock option activity during 2002, 2001 and
2000:
<Table>
<Caption>
2002
---------------------
Weighted
Average
Exercise
Shares Price
--------- ---------
Outstanding at beginning of year 2,241,107 $ 35.23
Granted -- --
Exercised 260,324 36.11
Cancelled or expired 3,330 43.00
--------- ---------
OUTSTANDING AT END OF YEAR 1,977,453 $ 35.10
========= =========
EXERCISABLE AT END OF YEAR 901,187 $ 36.97
========= =========
</Table>
<Table>
<Caption>
2001 2000
--------------------- ---------------------
Weighted Weighted
Average Average
Exercise Exercise
Shares Price Shares Price
--------- --------- --------- ---------
Outstanding at
beginning of year 2,430,532 $ 35.38 1,834,108 $ 38.22
Granted -- -- 957,100 31.00
Exercised 106,416 38.31 295,693 38.41
Cancelled or expired 83,009 35.77 64,983 37.38
--------- --------- --------- ---------
OUTSTANDING AT
END OF YEAR 2,241,107 $ 35.23 2,430,532 $ 35.38
========= ========= ========= =========
EXERCISABLE AT
END OF YEAR 572,092 $ 38.74 312,736 $ 39.58
========= ========= ========= =========
</Table>
The following table summarizes additional information about stock options
outstanding at December 31, 2002:
<Table>
<Caption>
Outstanding Weighted Average Exercisable
Exercise Price Shares Life (Years) Shares
- -------------- ----------- ---------------- -----------
$31.00 837,400 7.0 189,175
35.50 800 2.6 800
35.875 30,630 2.3 30,630
36.625 547,825 6.0 239,325
38.50 80,233 4.1 80,233
39.25 396,099 5.2 277,883
39.8125 5,300 5.5 3,975
43.00 79,166 3.0 79,166
=========== ================ ===========
</Table>
The fair values of stock options were estimated using a binomial
option-pricing model with the following assumptions:
<Table>
<Caption>
Grant Risk-free Option Expected Expected
Date Interest Rate Term Volatility Dividend Yield
- ------- ------------- -------- ---------- --------------
2/11/00 6.81% 10 years 17.39% 6.61%
2/12/99 5.44% 10 years 18.80% 6.51%
6/16/98 5.63% 10 years 17.68% 6.55%
4/28/98 6.01% 10 years 17.63% 6.55%
2/10/97 5.70% 10 years 13.17% 6.53%
2/7/96 5.87% 10 years 13.67% 6.32%
============= ======== ========== ==============
</Table>
NOTE 14 - 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 noted in the Notes to our Consolidated
Financial Statements, will not have an adverse material effect on our financial
position, results of operations or liquidity.
Capital Expenditures
We estimate our capital expenditures over the next five years will be
approximately $3 billion - $3.3 billion, including allowance for funds used
during construction and capitalized interest, as well as AmerenCILCO. This
estimate includes capital expenditures for the construction of new combustion
turbine generating facilities and for the replacement of steam generators at our
Callaway nuclear plant. In addition, this estimate includes capital expenditures
for transmission, distribution and other generation related activities, as well
as for compliance with new NO(x) (nitrogen oxide) control regulations, as
discussed later in this Note. Commitments of $2.25 billion to $2.75 billion were
agreed upon in relation to AmerenUE's recent Missouri electric rate case
settlement
WWW.AMEREN.COM 57
and to meet future rate-regulated generating capacity needs from January 1, 2002
through June 30, 2006.
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, changes in our existing nuclear plant to meet new regulatory
requirements, increasing costs of labor, equipment and materials, and cost of
capital.
We intend to transfer at net book value approximately 550 megawatts
(approximately $260 million) of generating capacity from our non rate-regulated
subsidiary, Generating Company, to our rate-regulated subsidiary, AmerenUE, to
comply with AmerenUE's recent Missouri electric rate case settlement and to meet
future rate-regulated generating capacity needs. In addition, we intend to
replace our retired 343 megawatts of rate-regulated capacity at AmerenUE's
Venice, Illinois plant (see Note 9 - Voluntary Retirement and Other
Restructuring Charges for further information) with the addition of 117
megawatts of capacity by 2005 and at least 330 megawatts of capacity by 2006 at
Venice. Total costs expected to be incurred for these units approximate $175
million of which approximately $100 million was committed as of December 31,
2002.
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 fossil
and nuclear fuel. 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:
<Table>
<Caption>
Electric
Coal Gas Nuclear Capacity
-------- -------- -------- --------
2003 $ 590 $ 81 $ 9 $ 35
2004 515 47 1 35
2005 307 44 9 33
2006 178 16 9 33
2007 107 2 1 33
Thereafter 253 4 20 107
-------- -------- -------- --------
TOTAL $ 1,950 $ 194 $ 49 $ 276
======== ======== ======== ========
</Table>
Nuclear Plant Insurance Coverage
Our insurance coverage at AmerenUE's Callaway nuclear plant at December 31,
2002, was as follows:
<Table>
<Caption>
Maximum
Assessments
Maximum for Single
Coverages Incidents
----------- -----------
TYPE AND SOURCE OF COVERAGE -
PUBLIC LIABILITY:
American Nuclear Insurers $ 200 $ --
Pool Participation 9,250 88(a)
----------- -----------
$ 9,450(b) $ 88
NUCLEAR WORKER LIABILITY:
American Nuclear Insurers $ 300(c) $ 4
PROPERTY DAMAGE:
Nuclear Electric Insurance Ltd. $ 2,750(d) $ 21
REPLACEMENT POWER:
Nuclear Electric Insurance Ltd. $ 490(e) $ 7
=========== ===========
</Table>
(a) Retrospective premium under the Price-Anderson liability provisions of the
Atomic Energy Act of 1954, as amended (Price-Anderson). This is subject to
retrospective assessment with respect to loss from an incident at any U.S.
reactor, payable at $10 million per year. Price-Anderson expired in August
2002 and renewal legislation is pending before Congress. Until
Price-Anderson is extended, its provisions continue to apply to existing
nuclear plants.
(b) Limit of liability for each incident under Price-Anderson.
(c) Industry limit for potential liability from workers claiming exposure to
the hazard of nuclear radiation.
(d) Includes premature decommissioning costs.
(e) Weekly indemnity of $3.5 million for 52 weeks, which commences after the
first 8 weeks of an outage, plus $2.8 million per week for 110 weeks
thereafter.
Price-Anderson limits the liability for claims from an incident involving
any licensed U.S. nuclear facility. The limit is based on the number of licensed
reactors and is adjusted at least every five years based on the Consumer Price
Index. Utilities owning a nuclear reactor cover this exposure through a
combination of private insurance and mandatory participation in a financial
protection pool, as established by Price-Anderson.
If losses from a nuclear incident at Callaway exceed the limits of, or are
not subject to, insurance, or if coverage is not available, we self-insure the
risk. Although we have no reason to anticipate a serious nuclear incident, if
one did occur, it could have a material, but indeterminable, adverse effect on
our financial position, results of operations or liquidity.
58
Leases
The following table summarizes our lease obligations at December 31, 2002:
<Table>
<Caption>
Less After
Than 1 1-3 4-5 5
Total Year Years Years Years
------ ------ ------ ------ ------
Capital leases(a) $ 216 $ 31 $ 70 $ 30 $ 85
Operating leases(b) 171 22 35 26 88
------ ------ ------ ------ ------
TOTAL LEASE OBLIGATIONS $ 387 $ 53 $ 105 $ 56 $ 173
====== ====== ====== ====== ======
</Table>
(a) See Note 5 - Nuclear Fuel Lease and Note 8 - Long-Term Debt and
Capitalization for further discussion.
(b) Amounts related to certain real estate leases and railroad licenses 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 $1 million annually for both the
real estate leases and the railroad licenses.
Ameren leases various facilities, office equipment, plant equipment and
railcars under operating leases. We also have capital leases relating to nuclear
fuel and combustion turbine generators. As of December 31, 2002, rental expense,
included in Other Operations and Maintenance expenses, totaled approximately $21
million (2001 - $22 million; 2000 - $34 million). See Note 5 - Nuclear Fuel
Lease and Note 8 - Long-Term Debt and Capitalization for further information.
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, transmission, and
distribution 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 NO(x) 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 NO(x) 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 NO(x) emission budget for each state, including
Illinois. The EPA rule requires states to implement controls sufficient to meet
their NO(x) budget by May 31, 2004.
As a result of these state requirements, Generating Company estimates
spending an additional $40 million for pollution control capital expenditures
and NO(x) credits by 2006. In February 2002, the EPA proposed similar rules for
Missouri where the majority of AmerenUE's facilities are located. Assuming the
Missouri rules are ultimately finalized, AmerenUE estimates spending
approximately $170 million to comply with these rules for NO(x) control on the
AmerenUE generating system by 2006. In summary, we currently estimate our future
capital expenditures to comply with the final NO(x) regulations could range from
$200 million to $250 million. 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, Generating Company
and AmerenUE have applied for Early Reduction NO(x) credits which would allow
them to manage compliance strategies by either purchasing
WWW.AMEREN.COM 59
NO(x) control equipment or utilizing credits. Generating Company and AmerenUE
are eligible for such credits due to the current low NO(x) emission rates
achieved on some of their boilers due to past NO(x) 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 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 NO(x) 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 the Ameren 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 NO(x) emissions. These rules could also add significant pollution
control costs to the Ameren 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
We are involved in a number of remediation actions to clean up hazardous
waste sites as required by federal and state law. Such statutes require that
responsible parties fund remediation actions regardless of fault, legality of
original disposal, or ownership of a disposal site. AmerenUE and AmerenCIPS have
been identified
60
by the federal or state governments as a potentially responsible party (PRP) at
several contaminated sites.
We own or are otherwise responsible for 14 former manufactured gas plant
(MGP) sites in Illinois. The ICC permits the recovery of remediation and
litigation costs associated with certain former MGP sites located in Illinois
from our Illinois electric and natural gas utility customers through
environmental adjustment rate riders. To be recoverable, such costs must be
prudently and properly incurred and are subject to annual reconciliation review
by the ICC. Through December 31, 2002, the total costs deferred, net of
recoveries from insurers and through environmental adjustment rate riders, were
$26 million.
In addition, we own or are otherwise responsible for 10 MGP sites in
Missouri and one in Iowa. Unlike Illinois, we do not have in effect in Missouri
a rate rider mechanism which permits remediation costs associated with MGP sites
to be recovered from utility customers, and we do not have any retail utility
operations in Iowa.
In June 2000, the EPA notified AmerenUE and numerous other companies that
former landfills and lagoons in Sauget, Illinois, may contain soil and
groundwater contamination. These sites are known as Sauget Area 1 and Sauget
Area 2. From approximately 1926 until 1976, AmerenUE operated a power generating
facility adjacent to Sauget Area 2 and currently owns and operates electric
transmission and distribution facilities in or near Sauget Areas 1 and 2.
In September 2000, the United States Department of Justice was granted
leave by the United States District Court - Southern District of Illinois to add
numerous additional parties, including AmerenUE, to a preexisting lawsuit
between the government and others. The government seeks recovery of response
costs under the Comprehensive Environmental Response Compensation Liability Act
of 1980 (CERCLA or Superfund), incurred in connection with the remediation of
Sauget Area 1. We believe the final resolution of this lawsuit and the
remediation of Sauget Area 1 will not have a material adverse effect on our
financial position, results of operations or liquidity.
In September 2001, the EPA proposed in the Federal Register that Sauget
Area 1 and Sauget Area 2 be listed on the National Priorities List (NPL). The
inclusion of a site on the NPL allows the EPA to access Superfund trust monies
to fund site remediations. With respect to Sauget Area 2, AmerenUE has joined
with other PRPs to evaluate the extent of potential contamination. We are unable
to predict the ultimate impact of the Sauget Area 2 site on our financial
position, results of operations or liquidity.
In October 2002, AmerenUE was included in a Unilateral Administrative Order
(UAO) list of potentially liable parties for groundwater contamination for a
portion of the Sauget Area 2 site. The UAO encompasses the groundwater
contamination releasing to the Mississippi River adjacent to a chemical
company's former chemical waste landfill and the resulting impact area in the
Mississippi River. AmerenUE is being asked to participate in response activities
that involve the installation of a barrier wall with three recovery wells. The
projected cost for this remedy method is $26 million. In November 2002, AmerenUE
sent a letter to the EPA asserting its defenses to the UAO and requested its
removal from the list of potentially responsible parties under the UAO.
In addition, our operations, or that of our predecessor companies, involve
the use, disposal and, in appropriate circumstances, the cleanup of substances
regulated under environmental protection laws. We are unable to determine the
impact these actions may have on our financial position, results of operations
or liquidity.
Labor Agreements
Certain employees of Ameren are represented by the International
Brotherhood of Electrical Workers (IBEW) and the International Union of
Operating Engineers (IUOE). These employees comprise approximately 63% of our
workforce. Labor agreements covering 7% of the employees extend through 2006.
Labor agreements covering most of the remaining 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.
Asbestos-Related Litigation
Ameren, AmerenCIPS and AmerenUE have been named, along with numerous other
parties, in a number of lawsuits which have been filed by certain plaintiffs
claiming varying degrees of injury from asbestos exposure. Most have been filed
in the Circuit Court of Madison County, Illinois. The number of total defendants
named in each case is significant with as many as 110 parties named in a case to
as few as six. However, the average number of parties is 54 in the cases that
are currently pending.
The claims filed against Ameren, AmerenCIPS and AmerenUE allege injury from
asbestos exposure during the plaintiffs' activities at our electric generating
plants (in the case of AmerenCIPS, its former plants are now owned by Generating
Company). In each lawsuit, the plaintiff seeks unspecified damages in excess of
WWW.AMEREN.COM 61
$50,000, which typically would be shared among the named defendants. A total of
121 such lawsuits have been filed against Ameren, AmerenCIPS and AmerenUE of
which 45 are pending, 14 have been settled and 62 have been dismissed.
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 15 - CALLAWAY NUCLEAR PLANT
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE)
is responsible for the permanent storage and disposal of spent nuclear fuel. The
DOE currently charges one mill, or 1/10 of one cent, per nuclear-generated
kilowatthour sold for future disposal of spent fuel. Pursuant to this Act,
AmerenUE collects one mill from its customers for each kilowatthour of
electricity that it generates from Callaway. Electric utility rates charged to
customers provide for recovery of such costs. The DOE is not expected to have
its permanent storage facility for spent fuel available until at least 2015. We
have sufficient storage capacity at Callaway until 2020 and have the capability
for additional storage capacity through the licensed life of the plant. The
delayed availability of the DOE's disposal facility is not expected to adversely
affect the continued operation of Callaway through its currently licensed life.
Electric utility rates charged to customers provide for recovery of
Callaway decommissioning costs over the life of the plant, based on an assumed
40-year life, ending with expiration of the plant's operating license in 2024.
The Callaway site is assumed to be decommissioned based on immediate
dismantlement method and removal from service. Decommissioning costs, including
decontamination, dismantling and site restoration, are estimated to be $515
million in current year dollars and are expected to escalate approximately 4%
per year through the end of decommissioning activity in 2033. Decommissioning
costs are charged to depreciation expense over Callaway's service life and
amounted to approximately $7 million in each of the years 2002, 2001 and 2000.
Every three years, the MoPSC and ICC require AmerenUE to file updated cost
studies for decommissioning Callaway, and electric rates may be adjusted at such
times to reflect changed estimates. The latest studies were filed in 2002. Costs
collected from customers are deposited in an external trust fund to provide for
Callaway's decommissioning. Fund earnings are expected to average approximately
9.5% annually through the date of decommissioning. If the assumed return on
trust assets is not earned, we believe it is probable that any such earnings
deficiency will be recovered in rates. Trust fund earnings, net of expenses,
appear on the consolidated balance sheet as increases in the nuclear
decommissioning trust fund and in the accumulated provision for nuclear
decommissioning.
The FASB issued SFAS 143 (see Note 1 - Summary of Significant Accounting
Policies for further information), which will result in a change to Ameren's
recognition, measurement, and classification of nuclear decommissioning costs.
NOTE 16 - 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.
Marketable Securities
The fair value is based on quoted market prices obtained from dealers or
investment managers.
Nuclear Decommissioning Trust Fund
The fair value is estimated based on quoted market prices for securities.
Preferred Stock of Subsidiaries
The fair value is estimated based on the quoted market prices for the same
or similar issues.
Long-Term Debt
The fair value is estimated based on the quoted market prices for same or
similar issues or on the current rates offered to Ameren 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.
62
Carrying amounts and estimated fair values of our financial instruments at
December 31, 2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
------------------- -------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
Long-term debt (including
current portion) $ 3,772 $ 4,014 $ 2,974 $ 3,052
Preferred stock 193 170 235 207
======== ======== ======== ========
</Table>
We have investments in debt and equity securities that are held in trust
funds for the purpose of funding the nuclear decommissioning of our Callaway
site. See Note 15 - Callaway Nuclear Plant for further information. We have
classified these investments in debt and equity securities as available for sale
and have recorded all such investments at their fair market value at December
31, 2002 and 2001. Investments by the nuclear decommissioning trust funds are
allocated 60% to 65% to equity securities with the balance invested in fixed
income securities. Fixed income investments are limited to U.S. government or
agency securities, municipal bonds or investment-grade corporate securities. The
proceeds from the sale of investments were $141 million in 2002 (2001 - $230
million; 2000 - $61 million). Using the specific identification method to
determine cost, the gross realized gains on those sales were approximately $35
million for 2002 (2001 - $4 million; 2000 - $1 million). Net realized and
unrealized gains and losses are reflected in the accumulated provision for
nuclear decommissioning on the consolidated balance sheet, which is consistent
with the method we use to account for the decommissioning costs recovered in
rates. Gains or losses on assets in the trusts could result in lower or higher
funding requirements for decommissioning costs, which we believe would be
reflected in electric rates paid by customers.
Costs and fair values of investments in debt and equity securities in the
nuclear decommissioning trust fund at December 31, 2002 and 2001 were as
follows:
<Table>
<Caption>
2002 Gross Unrealized
- ------------- -------------------------------------------------
Security Type Cost Gain (Loss) Fair Value
- ------------- ---------- ---------- ---------- ----------
Debt securities $ 57 $ 4 $ -- $ 61
Equity securities 89 17 -- 106
Cash equivalents 5 -- -- 5
---------- ---------- ---------- ----------
$ 151 $ 21 $ -- $ 172
========== ========== ========== ==========
</Table>
<Table>
<Caption>
2001 Gross Unrealized
- ------------- -------------------------------------------------
Security Type Cost Gain (Loss) Fair Value
- ------------- ---------- ---------- ---------- ----------
Debt securities $ 57 $ 2 $ -- $ 59
Equity securities 78 44 -- 122
Cash equivalents 6 -- -- 6
---------- ---------- ---------- ----------
$ 141 $ 46 $ -- $ 187
========== ========== ========== ==========
</Table>
The contractual maturities of investments in debt securities at December
31, 2002 were as follows:
<Table>
<Caption>
Cost Fair Value
---------- ----------
Less than 5 years $ 22 $ 23
5 years to 10 years 20 21
Due after 10 years 15 17
---------- ----------
$ 57 $ 61
========== ==========
</Table>
NOTE 17 - SEGMENT INFORMATION
Ameren's principal business segment is comprised of the utility operating
companies that provide electric and gas service in portions of Missouri and
Illinois. The other reportable segment includes the nonutility subsidiaries, as
well as our 60% interest in EEI.
The accounting policies of the segments are the same as those described in
Note 1 - Summary of Significant Accounting Policies. Segment data includes
intersegment revenues, as well as a charge allocating costs of administrative
support services to each of the operating companies. These costs are accumulated
in a separate subsidiary, Ameren Services Company, which provides a variety of
support services to Ameren and its subsidiaries. We evaluate the performance of
our segments and allocate resources to them, based on revenues, operating income
and net income.
The table below summarizes information about the reported revenues, net
income, and total assets of Ameren for the years ended December 31, 2002, 2001
and 2000:
<Table>
<Caption>
Utility Reconciling
Operations Other Items Total
----------- ----------- ----------- -----------
2002
Revenues $ 4,279 $ 320 $ (758)(a) $ 3,841
Net income 364 18 -- 382
Total assets 11,476 224 (201) 11,499
=========== =========== =========== ===========
2001
Revenues $ 4,415 $ 248 $ (805)(a) $ 3,858
Net income 467 2 -- 469
Total assets 11,171 240 (1,010) 10,401
=========== =========== =========== ===========
2000
Revenues $ 4,119 $ 294 $ (557)(a) $ 3,856
Net income 457 -- -- 457
Total assets 10,777 287 (1,350) 9,714
=========== =========== =========== ===========
</Table>
(a) Elimination of intercompany revenues.
WWW.AMEREN.COM 63
Specified items included in segment profit/loss for the years ended
December 31, 2002, 2001 and 2000:
<Table>
<Caption>
Utility Reconciling
Operations Other Items Total
----------- ----------- ----------- -----------
2002
Interest expense $ 239 $ 12 $ (32)(b) $ 219
Depreciation and
amortization expense 401 14 16 431
Income tax expense 224 19 (6) 237
=========== =========== =========== ===========
2001
Interest expense $ 231 $ 11 $ (43)(b) $ 199
Depreciation and
amortization expense 382 12 12 406
Income tax expense 299 7 (1) 305
=========== =========== =========== ===========
2000
Interest expense $ 205 $ 12 $ (37)(b) $ 180
Depreciation and
amortization expense 360 13 10 383
Income tax expense 294 4 -- 298
=========== =========== =========== ===========
</Table>
(b) Elimination of intercompany interest charges.
Specified item related to segment assets as of December 31, 2002, 2001 and
2000:
<Table>
<Caption>
Utility Reconciling
Operations Other Items Total
----------- ----------- ----------- -----------
2002
Expenditures for additions
to long-lived assets $ 758 $ 3 $ 26 $ 787
=========== =========== =========== ===========
2001
Expenditures for additions
to long-lived assets $ 1,058 $ 10 $ 34 $ 1,102
=========== =========== =========== ===========
2000
Expenditures for additions
to long-lived assets $ 872 $ 45 $ 12 $ 929
=========== =========== =========== ===========
</Table>
NOTE 18 - 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, we completed our acquisition of
all of the outstanding common stock of CILCORP Inc. 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, we also completed our acquisition of AES Medina Valley Cogen (No. 4), LLC
(Medina Valley) which indirectly owns a 40 megawatt, gas-fired electric
generation plant. With the acquisition, Medina Valley became a wholly-owned
subsidiary of Resources Company, which we 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 our consolidated financial
statements effective with the January and February 2003 acquisition dates.
We acquired CILCORP to complement our existing Illinois gas and electric
operations. The purchase includes 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 our service territory. In
addition, 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 shares of common stock which
generated aggregate net proceeds of $575 million.
For the year ended December 31, 2002, CILCORP had revenues of $782 million,
operating income of $109 million, and net income from continuing operations of
$31 million, and as of December 31, 2002, had total assets of $1.9 billion. For
the year ended December 31, 2001, CILCORP had revenues of $815 million,
operating income of $126 million, and net income from continuing operations of
$28 million, and as of December 31, 2001 had total assets of $1.8 billion. These
results may not be the same when consolidated with Ameren. (All amounts in this
paragraph are unaudited.)
64
SELECTED CONSOLIDATED FINANCIAL INFORMATION
<Table>
<Caption>
Millions of Dollars,
Except Share and Per Share Amounts and Ratios 2002 2001 2000 1999 1998
- --------------------------------------------- ------------ ------------ ------------ ------------ ------------
RESULTS OF OPERATIONS Year Ended December 31,
Operating revenues $ 3,841 $ 3,858 $ 3,856 $ 3,536 $ 3,318
Operating expenses 3,218 3,193 3,216 2,973 2,747
Operating income 623 665 640 563 571
Income before extraordinary charge
and cumulative effect of change
in accounting principle 382 476 457 385 386
Extraordinary charge and cumulative
effect of change in accounting
principle, net of income taxes -- 7 -- -- --
Net income $ 382 $ 469 $ 457 $ 385 $ 386
Average common shares outstanding 146,138,419 137,320,692 137,215,462 137,215,462 137,215,462
------------ ------------ ------------ ------------ ------------
ASSETS, OBLIGATIONS
AND EQUITY CAPITAL December 31,
Total assets $ 11,499 $ 10,401 $ 9,714 $ 9,178 $ 8,847
Long-term debt obligations 3,433 2,835 2,745 2,448 2,289
Preferred stock of subsidiaries not
subject to mandatory redemption 193 235 235 235 235
Common equity 3,842 3,349 3,197 3,090 3,056
------------ ------------ ------------ ------------ ------------
FINANCIAL INDICES Year Ended December 31,
Earnings per share of common stock
(based on average shares outstanding) $ 2.61 $ 3.41 $ 3.33 $ 2.81 $ 2.82
Dividend payout ratio 98% (a) 75% 76% 90% 90%
Return on average common stock equity 10.56% 14.54% 14.60% 12.56% 12.82%
Ratio earnings to fixed charges
Ameren Corporation 3.51 4.42 4.59 4.20 4.06
AmerenUE 5.82 6.08 5.33 5.64 4.99
AmerenCIPS 2.06 2.87 4.05 2.98 4.13
Generating Company 1.59 2.63 2.99 -- --
Book value per common share $ 24.94 $ 24.26 $ 23.30 $ 22.52 $ 22.27
------------ ------------ ------------ ------------ ------------
</Table>
(a) Excluding voluntary retirement and other restructuring charges, the dividend
payout ratio was 85%.
<Table>
CAPITALIZATION RATIOS December 31,
Common equity 51.6% 47.0% 50.8% 53.4% 53.0%
Preferred stock 2.6 3.3 3.7 4.1 4.1
Long-term debt 45.8 49.7 45.5 42.5 42.9
------------ ------------ ------------ ------------ ------------
100.0% 100.0% 100.0% 100.0% 100.0%
============ ============ ============ ============ ============
</Table>
WWW.AMEREN.COM 65
ELECTRIC OPERATING STATISTICS
<Table>
<Caption>
Year Ended December 31, 2002 2001 2000 1999 1998
- ----------------------- -------- -------- -------- -------- --------
ELECTRIC OPERATING REVENUES Millions
Residential $ 1,202 $ 1,133 $ 1,142 $ 1,097 $ 1,125
Commercial 1,024 1,020 997 956 966
Industrial 511 541 505 505 511
Wholesale 291 236 208 108 91
Other 23 23 24 24 23
-------- -------- -------- -------- --------
Native 3,051 2,953 2,876 2,690 2,716
Interchange 200 309 477 399 240
EEI 185 110 164 177 152
Miscellaneous 84 125 75 72 29
Credit to customers -- 10 (65) (38) (43)
-------- -------- -------- -------- --------
Total Electric Operating Revenues $ 3,520 $ 3,507 $ 3,527 $ 3,300 $ 3,094
======== ======== ======== ======== ========
KILOWATTHOUR SALES Millions
Residential 16,704 15,678 15,683 14,863 15,188
Commercial 17,224 16,873 16,644 15,418 15,555
Industrial 12,442 13,175 11,914 11,549 11,582
Wholesale 8,936 6,992 6,244 3,002 2,446
Other 280 284 307 303 303
-------- -------- -------- -------- --------
Native 55,586 53,002 50,792 45,135 45,074
Interchange 8,165 10,130 14,679 12,371 8,075
EEI 6,588 5,824 6,914 9,270 8,296
-------- -------- -------- -------- --------
Total Kilowatthour Sales 70,339 68,956 72,385 66,776 61,445
======== ======== ======== ======== ========
ELECTRIC CUSTOMERS End of Year in Thousands
Residential 1,319 1,312 1,307 1,298 1,289
Commercial 194 192 191 187 180
Industrial 6 6 6 6 6
Wholesale and other 4 4 4 4 4
-------- -------- -------- -------- --------
Total Electric Customers 1,523 1,514 1,508 1,495 1,479
======== ======== ======== ======== ========
RESIDENTIAL CUSTOMER DATA Average
Kilowatthours used 11,680 11,956 12,579 11,827 11,986
Annual electric bill $ 848.06 $ 869.25 $ 895.20 $ 859.53 $ 873.28
Revenue per kilowatthour 7.26(cent) 7.27(cent) 7.12(cent) 7.27(cent) 7.29(cent)
CAPABILITY AT TIME OF PEAK,
INCLUDING NET PURCHASES AND SALES Megawatts
AmerenUE 9,765 9,747 9,359 9,141 9,027
AmerenEnergy Resources/AmerenCIPS 4,223 3,549 3,560 2,556 2,417
GENERATING CAPABILITY AT TIME OF PEAK Megawatts
AmerenUE 8,647 8,618 8,320 8,352 8,282
AmerenEnergy Resources/AmerenCIPS 4,327 3,945 3,443 3,027 3,040
COAL BURNED Millions of Tons 27.1 24.5 25.3 23.6 23.0
PRICE PER TON OF COAL Average $ 18.06 $ 18.88 $ 18.94 $ 20.34 $ 21.29
SOURCE OF ENERGY SUPPLY
Fossil 76.7% 72.3% 83.2% 85.4% 83.5%
Nuclear 11.4 11.6 18.8 17.9 17.7
Hydro 1.6 1.4 1.6 3.1 3.8
Purchased and interchanged, net 10.3 14.7 (3.6) (6.4) (5.0)
-------- -------- -------- -------- --------
100.0% 100.0% 100.0% 100.0% 100.0%
======== ======== ======== ======== ========
</Table>
66
GAS OPERATING STATISTICS
<Table>
<Caption>
Year Ended December 31, 2002 2001 2000 1999 1998
- ----------------------- ------ ------ ------ ------ ------
NATURAL GAS OPERATING REVENUES Millions
Residential $ 192 $ 187 $ 204 $ 146 $ 135
Commercial 75 83 69 52 50
Industrial 37 40 17 18 19
Off system sales 4 6 18 4 3
Miscellaneous 7 26 16 8 10
------ ------ ------ ------ ------
Total Natural Gas Operating Revenues $ 315 $ 342 $ 324 $ 228 $ 217
====== ====== ====== ====== ======
MMBtu SALES Millions
Residential 21 19 25 21 21
Commercial 9 9 9 8 8
Industrial 8 7 3 4 6
Off system sales 1 1 4 1 1
------ ------ ------ ------ ------
Total MMBtu Sales 39 36 41 34 36
====== ====== ====== ====== ======
NATURAL GAS CUSTOMERS End of Year in Thousands
Residential 270 269 270 267 265
Commercial and Industrial 30 30 31 30 31
------ ------ ------ ------ ------
Total Natural Gas Customers 300 299 301 297 296
====== ====== ====== ====== ======
Peak day throughput Thousands of MMBtus
AmerenCIPS 142 188 226 247 229
AmerenUE 118 128 169 184 157
------ ------ ------ ------ ------
Total Peak Day Throughput 260 316 395 431 386
====== ====== ====== ====== ======
</Table>
SELECTED QUARTERLY INFORMATION
(Unaudited)
In Millions, Except Per Share Amounts
<Table>
<Caption>
QUARTER ENDED: Net Earnings Per
Operating Operating Income Common Share -
Revenues (a) Income (Loss) Basic
------------ --------- ------ --------------
March 31, 2002 $ 874 $ 111 $ 59 $ 0.42
March 31, 2001 927 116 58 0.43
------ ------ ------ ------
June 30, 2002 978 194 115 0.80
June 30, 2001 928 145 95 0.69
------ ------ ------ ------
September 30, 2002 1,166 297 240 1.64
September 30, 2001 1,206 311 267 1.94
------ ------ ------ ------
December 31, 2002 (b) 823 21 (32) (0.20)
December 31, 2001 797 93 49 0.35
====== ====== ====== ======
</Table>
(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 - $241 in first quarter, $133 in second quarter, $189 in third
quarter, and $175 in fourth quarter (2001 - $98 in first quarter, $129 in
second quarter, $225 in third quarter, and $196 in fourth quarter).
(b) Amounts include Voluntary Retirement and Other See Note 9 - Voluntary
Restructuring Charges of $92 million ($58 million, net Retirement of taxes).
and Other Restructuring Charges for further information.
Other impacts to quarterly earnings are due to the effect of weather on
sales and other factors, including the 2002 Missouri rate order, that are
characteristic of public utility operations.
WWW.AMEREN.COM 67
INVESTOR INFORMATION
COMMON STOCK
AND DIVIDEND INFORMATION
Ameren's common stock is listed on the New York Stock Exchange (ticker
symbol: AEE). AEE began trading on January 2, 1998, following the merger of
Union Electric Company and CIPSCO Incorporated on December 31, 1997.
Common stockholders of record totaled 96,437 for Ameren on December 31,
2002. The following includes the price ranges and dividends paid per common
share for AEE during 2002 and 2001.
AEE 2002
<Table>
<Caption>
Dividends
Quarter Ended High Low Close Paid
- ------------- ------ ------- ------- ---------
March 31 $43.85 $ 39.50 $ 42.75 63 1/2(cent)
June 30 45.20 40.20 43.01 63 1/2
September 30 45.14 34.72 41.65 63 1/2
December 31 42.69 38.75 41.57 63 1/2
</Table>
AEE 2001
<Table>
<Caption>
Dividends
Quarter Ended High Low Close Paid
- ------------- ------ ------- ------- ---------
March 31 $46.00 $ 37.31 $ 40.95 63 1/2(cent)
June 30 45.48 40.20 42.70 63 1/2
September 30 43.45 36.53 38.40 63 1/2
December 31 42.90 37.80 42.30 63 1/2
</Table>
ANNUAL MEETING
The annual meetings of Ameren, Union Electric Company and Central
Illinois Public Service Company stockholders will convene at 9 a.m., Tuesday,
April 22, 2003, at Powell Symphony Hall, 718 North Grand Boulevard, St. Louis,
Missouri. The annual meeting of Central Illinois Light Company stockholders will
convene at 9 a.m., Tuesday, May 20, 2003, at Ameren headquarters, 1901 Chouteau
Avenue, St. Louis, Missouri.
DRPLUS
Through DRPlus - Ameren's dividend reinvestment and stock purchase plan
- - any person of legal age or entity, whether or not an Ameren stockholder, is
eligible to participate in DRPlus. Participants can:
o make cash investments by check or automatic direct debit to their
bank accounts to purchase Ameren common stock, totaling up to
$120,000 annually.
o reinvest their dividends in Ameren common stock or receive Ameren
dividends in cash.
o place Ameren common stock certificates in safekeeping and receive
regular account statements.
For more information about DRPlus, you may obtain a prospectus from the
company's Investor Services representatives.
If you have not yet exchanged your Union Electric Company or CIPSCO
Incorporated common stock certificates for Ameren stock certificates, please
contact Investor Services. This is not an offer to sell, or a solicitation of an
offer to buy, any securities.
DIRECT DEPOSIT OF DIVIDENDS
All registered Ameren common and Union Electric Company, Central
Illinois Public Service Company and Central Illinois Light Company preferred
stockholders can have their cash dividends automatically deposited to their bank
accounts. This service gives stockholders immediate access to their dividend on
the dividend payment date and eliminates the possibility of lost or stolen
dividend checks.
AMEREN'S WEB SITE
To obtain AEE's daily stock price, recent financial statistics and
other information about the company, or to sign up for electronic notification
of company news and events, visit Ameren's home page on the Internet. Also
included on our web site is the written charter of the Auditing Committee of the
board. These materials are also available by writing Investor Services at the
address shown below. Ameren's web site address is:
http://www.Ameren.com
INVESTOR SERVICES
The company's Investor Services representatives are available to help
you each business day from 7:30 a.m. to 4:30 p.m. (Central Time). Please write
or call:
Ameren Services Company
Investor Services P.O. Box
66887 St. Louis, MO
63166-6887 St. Louis area
314-554-3502 Toll-free
1-800-255-2237
TRANSFER AGENT, REGISTRAR
AND PAYING AGENT
The Transfer Agent, Registrar and Paying Agent for Ameren Corporation
common stock and Union Electric Company and Central Illinois Public Service
Company preferred stock is Ameren Services Company. AmerenCILCO and Continental
Stock Transfer are the transfer agents; National City Bank is the registrar; and
AmerenCILCO is the paying agent for Central Illinois Light Company preferred
stock.
OFFICE
Ameren Corporation One
Ameren Plaza 1901
Chouteau Avenue St.
Louis, MO 63103
314-621-3222
WWW.AMEREN.COM 69