UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
(X) Annual report pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
for the fiscal year ended December 31, 2003
OR
( ) Transition report pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
for the transition period from _______ to _______.
Exact Name of Registrant as specified in its charter;
Commission State of Incorporation; IRS Employer
File Number Address and Telephone Number Identification No.
----------- ---------------------------- -----------------
1-14756 Ameren Corporation 43-1723446
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
1-2967 Union Electric Company 43-0559760
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
1-3672 Central Illinois Public Service Company 37-0211380
(Illinois Corporation)
607 East Adams Street
Springfield, Illinois 62739
(217) 523-3600
333-56594 Ameren Energy Generating Company 37-1395586
(Illinois Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
2-95569 CILCORP Inc. 37-1169387
(Illinois Corporation)
300 Liberty Street
Peoria, Illinois 61602
(309) 677-5230
1-2732 Central Illinois Light Company 37-0211050
(Illinois Corporation)
300 Liberty Street
Peoria, Illinois 61602
(309) 677-5230
Securities Registered Pursuant to Section 12(b) of the Securities Exchange Act of 1934:
Each of the following classes or series of securities is registered
pursuant to Section 12(b) of the Securities Exchange Act of 1934 and is
registered on the New York Stock Exchange.
Registrant Title of each class
---------- -------------------
Ameren Corporation Common Stock, $0.01 par value per share and
Preferred Share Purchase Rights; Normal Units
Union Electric Company Preferred Stock, cumulative, no par value,
Stated value $100 per share -
$4.56 Series
$4.50 Series
$4.00 Series
$3.50 Series
Central Illinois Light Company Preferred Stock, cumulative, $100 par value per share -
4 1/2% Series
Securities Registered Pursuant to Section 12(g) of the Securities Exchange Act of 1934:
Registrant Title of each class
---------- -------------------
Central Illinois Public Service Company Preferred Stock, cumulative, $100 par value per share -
6.625% Series
5.16% Series
4.92% Series
4.90% Series
4.25% Series
4.00% Series
Depository Shares, each representing one-fourth of a
share of 6.625% Preferred Stock, cumulative,
$100 par value per share
Ameren Energy Generating Company and CILCORP Inc. do not have securities
registered under either Section 12(b) or 12(g) of the Securities Exchange Act of
1934.
Indicate by check mark whether the Registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) have been subject to such
filing requirements for the past 90 days. Yes (X) No ( )
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of each Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
Ameren Corporation ( )
Union Electric Company ( )
Central Illinois Public Service Company ( )
Ameren Energy Generating Company (X)
CILCORP Inc. (X)
Central Illinois Light Company ( )
Indicate by check mark whether each Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Ameren Corporation Yes (X) No ( )
Union Electric Company Yes ( ) No (X)
Central Illinois Public Service Company Yes ( ) No (X)
Ameren Energy Generating Company Yes ( ) No (X)
CILCORP Inc. Yes ( ) No (X)
Central Illinois Light Company Yes ( ) No (X)
As of June 30, 2003, Ameren Corporation had 161,661,514 shares of its $0.01
par value common stock outstanding. The aggregate market value of these shares
of common stock (based upon the closing price of these shares on the New York
Stock Exchange on that date) held by non-affiliates was $7,129,272,767. The
shares of common stock of the other Registrants were held by affiliates as of
June 30, 2003.
The number of shares outstanding of each Registrant's classes of common
stock as of February 13, 2004 was as follows:
Ameren Corporation Common stock, $.01 par value - 182,025,564
Union Electric Company Common stock, $5 par value, held by Ameren
Corporation (parent company of the Registrant)-
102,123,834
Central Illinois Public Service Company Common stock, no par value, held by Ameren
Corporation (parent company of the Registrant)-
25,452,373
Ameren Energy Generating Company Common stock, no par value, held by Ameren Energy
Development Company (parent company of the Registrant
and indirect subsidiary of Ameren Corporation)- 2,000
CILCORP Inc. Common stock, no par value, held by Ameren
Corporation (parent company of the Registrant) - 1,000
Central Illinois Light Company Common stock, no par value, held by CILCORP Inc.
(parent company of the Registrant and subsidiary of
Ameren Corporation) - 13,563,871
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the definitive proxy statements of Ameren Corporation, Union
Electric Company, Central Illinois Public Service Company and Central Illinois
Light Company for the 2004 annual meetings of shareholders are incorporated by
reference into Part III of this Form 10-K.
OMISSION OF CERTAIN INFORMATION
Ameren Energy Generating Company and CILCORP Inc. meet the conditions set
forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this form with the reduced disclosure format allowed under that General
Instruction.
This combined Form 10-K is separately filed by Ameren Corporation, Union
Electric Company, Central Illinois Public Service Company, Ameren Energy
Generating Company, CILCORP Inc. and Central Illinois Light Company. Each
Registrant hereto is filing on its own behalf all of the information contained
in this annual report that relates to such Registrant. Each Registrant hereto is
not filing any information that does not relate to such Registrant, and
therefore makes no representation as to any such information.
Prior to the quarterly report on Form 10-Q for the period ended September
30, 2003, separate filings were made by each Registrant, except CILCORP Inc. and
Central Illinois Light Company, which made a combined filing. Ameren Corporation
and its subsidiaries changed to a combined filing in order to improve disclosure
and to simplify administrative processes.
TABLE OF CONTENTS
Page
----
GLOSSARY OF TERMS AND ABBREVIATIONS..................................................................... 5
Forward-looking Statements............................................................................. 8
PART I
Item 1 Business
General............................................................................. 9
Capital Program and Financing....................................................... 9
Rates and Regulation................................................................ 10
Supply for Electric Power........................................................... 12
Natural Gas Supply for Distribution................................................. 14
Industry Issues..................................................................... 15
Risk Factors........................................................................ 15
Operating Statistics................................................................ 22
Available Information............................................................... 23
Item 2 Properties.................................................................................. 24
Item 3 Legal Proceedings........................................................................... 27
Item 4 Submission of Matters to a Vote of Security Holders......................................... 27
Executive Officers of the Registrants (Item 401(b) of Regulation S-K)................................... 27
PART II
Item 5 Market for Registrants' Common Equity and Related
Stockholder Matters................................................................. 37
Item 6 Selected Financial Data..................................................................... 37
Item 7 Management's Discussion and Analysis of Financial Condition
and Results of Operations........................................................... 40
Item 7A Quantitative and Qualitative Disclosures About Market Risk.................................. 71
Item 8 Financial Statements and Supplementary Data................................................. 77
Item 9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure............................................................ 177
Item 9A Controls and Procedures..................................................................... 178
PART III
Item 10 Directors and Executive Officers of the Registrants......................................... 178
Item 11 Executive Compensation...................................................................... 179
Item 12 Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters...................................... 179
Item 13 Certain Relationships and Related Transactions.............................................. 179
Item 14 Principal Accountant Fees and Services...................................................... 179
PART IV
Item 15 Exhibits, Financial Statement Schedules, and Reports on Form 8-K............................ 180
SIGNATURES ............................................................................................. 183
EXHIBIT INDEX .......................................................................................... 189
This Form 10-K contains "forward-looking" statements within the meaning of
Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking
statements should be read with the cautionary statements and important factors
included at page 8 of this Form 10-K under the heading Forward-looking
Statements. Forward-looking statements are all statements other than statements
of historical fact, including those statements that are identified by the use of
the words "anticipates," "estimates," "expects," "intends," "plans," "predicts,"
"projects" and similar expressions.
4
GLOSSARY OF TERMS AND ABBREVIATIONS
AERG - AmerenEnergy Resources Generating Company, a subsidiary of CILCO, which
operates a non rate-regulated electric generation business in Illinois and which
was formerly known as Central Illinois Generation, Inc.
AES - The AES Corporation.
AFS - Ameren Energy Fuels and Services Company, a subsidiary of Resources
Company, which procures fuel and gas and manages the related risks for the
Ameren Companies.
Ameren - Ameren Corporation and its subsidiaries on a consolidated basis. When
referring to financing or acquisition activities, Ameren is defined as Ameren
Corporation, the parent.
Ameren Companies - The individual Registrants within the Ameren consolidated
group.
Ameren Energy - Ameren Energy, Inc., a subsidiary of Ameren Corporation, which
serves as a power marketing and risk management agent for the Ameren Companies
for transactions of primarily less than one year.
Ameren Services - Ameren Services Company, a subsidiary of Ameren Corporation,
which provides a variety of support services to Ameren and its subsidiaries.
APB - Accounting Principles Board.
Btu - British Thermal Unit, which is a standard unit for measuring the quantity
of heat energy required to raise the temperature of one pound of water by one
degree Fahrenheit.
CERCLA (Superfund) - Comprehensive Environmental Response Compensation Liability
Act of 1980, which is federal environmental legislation that addresses
remediation of contaminated sites.
CILCO - Central Illinois Light Company, a subsidiary of CILCORP, which operates
a rate-regulated transmission and distribution business, an electric generation
business, and a rate-regulated natural gas distribution business in Illinois as
AmerenCILCO. CILCO owns all the common stock of AERG.
CILCORP - CILCORP Incorporated, a subsidiary of Ameren Corporation, which
operates as a holding company for CILCO.
CIPS - Central Illinois Public Service Company, a subsidiary of Ameren
Corporation, which operates a rate-regulated electric and natural gas
transmission and distribution business in Illinois as AmerenCIPS.
CIPSCO - CIPSCO Incorporated, the former parent of CIPS.
Cooling Degree Days - The summation of positive differences between the mean
daily temperature and the 65o Fahrenheit base. This statistic is useful as an
indicator of demand for electricity for summer space cooling for residential and
commercial customers.
CT - Combustion turbine generation equipment.
Development Company - Ameren Energy Development Company, a subsidiary of
Resources Company, which develops and constructs generating facilities for
Genco.
DOE - Department of Energy, a governmental agency of the United States of
America.
DOJ - Department of Justice, a governmental agency of the United States of
America.
DRPlus - Ameren Corporation's dividend reinvestment and stock purchase plan.
5
Dynegy - Dynegy Inc., the indirect parent company of Illinois Power.
EEI - Electric Energy, Inc., a 60%-owned subsidiary of Ameren Corporation, which
is 40% owned by UE and 20% owned by Resources Company, which operates electric
generation and transmission facilities in Illinois.
EITF - Emerging Issues Task Force, an organization that is designed to assist
the FASB in improving financial reporting through the identification, discussion
and resolution of financial issues within the framework of existing
authoritative literature.
EPA - Environmental Protection Agency, a governmental agency of the United
States of America.
ERISA - Employee Retirement Income Security Act of 1974, as amended.
Exchange Act - Securities Exchange Act of 1934, as amended.
FASB - Financial Accounting Standards Board, a rulemaking organization that
establishes financial accounting and reporting standards in the United States of
America.
FERC - Federal Energy Regulatory Commission, a governmental agency of the United
States of America that, among other things, regulates interstate transmission
and wholesale sales of electricity and gas and related matters.
FIN - FASB Interpretation intended to clarify accounting pronouncements
previously issued by the FASB.
Fitch - Fitch Ratings, a leading global rating agency.
GAAP - Generally accepted accounting principles in the United States of America.
Genco - Ameren Energy Generating Company, a subsidiary of Development Company,
which operates a non rate-regulated electric generation business in Illinois and
Missouri.
GridAmerica Companies - UE, CIPS, American Transmission Systems, Inc., a
subsidiary of FirstEnergy Corp., and Northern Indiana Public Service Company, a
subsidiary of NiSource, Incorporated.
Heating Degree Days - The summation of negative differences between the mean
daily temperature and the 65o Fahrenheit base. This statistic is useful as an
indicator of demand for electricity and natural gas for winter space heating for
residential and commercial customers.
IBEW - International Brotherhood of Electrical Workers.
ICC - Illinois Commerce Commission, a state agency that regulates the Illinois
utility businesses and operations of UE, CIPS and CILCO.
Illinois Customer Choice Law - Illinois Electric Service Customer Choice and
Rate Relief Law of 1997, which provides for electric utility restructuring and
introduces competition into the retail supply of electric energy in Illinois.
Illinois Power - Illinois Power Company, a wholly owned subsidiary of Illinova
Corporation, which is a subsidiary of Dynegy.
ITC - Independent Transmission Company.
IUOE - International Union of Operating Engineers.
MAIN - Mid-America Interconnected Network, Inc., one of the regional electric
reliability councils organized for coordinating the planning and operation of
the nation's bulk power supply.
6
Marketing Company - Ameren Energy Marketing Company, a subsidiary of Resources
Company, which markets power for periods primarily over one year.
Medina Valley - AmerenEnergy Medina Valley Cogen (No. 4), LLC and its
subsidiaries, which are subsidiaries of Resources Company, which indirectly own
a 40 megawatt, gas-fired electric generation plant.
MGP - Manufactured Gas Plant.
Midwest ISO - Midwest Independent System Operator.
MMBtu - One million Btus.
Moody's - Moody's Investors Service, Inc., a leading global rating agency.
MoPSC - Missouri Public Service Commission, a state agency that regulates the
Missouri utility business and operations of UE.
NOPR - Notice of Proposed Rulemaking issued by the FERC.
NOx - Nitrogen oxide.
NRC - Nuclear Regulatory Commission, a governmental agency of the United States
of America.
NSR - New Source Review programs under the federal Clean Air Act.
NYMEX - New York Mercantile Exchange.
OATT - Open Access Transmission Tariff.
OCI - Other Comprehensive Income (Loss) as defined by GAAP.
Peak Day Throughput - The maximum daily quantity of gas used during a stated
period of time, such as a year.
PGA - Purchased Gas Adjustment tariffs, which impact UE, CIPS and CILCO natural
gas utility customers.
PUHCA - Public Utility Holding Company Act of 1935, as amended.
Resources Company - Ameren Energy Resources Company, a subsidiary of Ameren
Corporation, which consists of non rate-regulated operations, including
Development Company, Genco, Marketing Company, AFS and Medina Valley.
RTO - Regional Transmission Organization.
S&P - Standard and Poor's Inc., a leading global rating agency.
SEC - Securities and Exchange Commission, a governmental agency of the United
States of America.
SFAS - Statement of Financial Accounting Standards, the accounting and financial
reporting rules issued by the FASB.
SO2 - Sulfur dioxide.
UE - Union Electric Company, a subsidiary of Ameren Corporation, 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.
7
When we refer to our, we or us, it indicates that the referenced
information relates to all Ameren Companies. When we refer to financing or
acquisition activities, we are defining Ameren as the parent holding company.
When appropriate, subsidiaries of Ameren are specifically referenced in order to
distinguish among their different business activities.
FORWARD-LOOKING STATEMENTS
Statements made in this report which are not based on historical facts are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
"forward-looking" statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions and
financial performance. In connection with the "safe harbor" provisions of the
Private Securities Litigation Reform Act of 1995, we are providing this
cautionary statement to identify important factors that could cause actual
results to differ materially from those anticipated. The following factors, in
addition to those discussed elsewhere in this report and in filings with the
SEC, could cause actual results to differ materially from management
expectations as suggested by such "forward-looking" statements:
o the closing and timing of Ameren's acquisition of Illinois Power and the
impact of any conditions imposed by regulators in connection with their
approval thereof;
o the effects of the stipulation and agreement relating to the UE 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 policy;
o the impact on the company 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 the company's business at both
the state and federal levels;
o the effects of participation in a FERC-approved RTO, including activities
associated with the Midwest ISO;
o the availability of fuel for the production of electricity, such as coal
and natural gas, and purchased power and natural gas for distribution, and
the level and volatility of future market prices for such commodities,
including the ability to recover any increased costs;
o the use of financial and derivative instruments;
o average rates for electricity in the Midwest;
o business and economic conditions;
o the impact of the adoption of new accounting standards and the application
of appropriate technical accounting rules and guidance;
o interest rates and the availability of capital;
o actions of ratings agencies and the effects of such actions; weather
conditions; generation plant construction, installation and performance;
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 benefits costs, including changes in returns on
benefit plan assets;
o disruptions of the capital markets or other events making the company's
access to necessary capital more difficult or costly;
o competition from other generating facilities, including new facilities that
may be developed;
o difficulties in integrating CILCO and Illinois Power 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 and Illinois Power acquisitions;
o cost and availability of transmission capacity for the energy generated by
the company's generating facilities or required to satisfy energy sales
made by the company;
o and legal and administrative proceedings.
8
Given these uncertainties, undue reliance should not be placed on these
forward-looking statements. Except to the extent required by the federal
securities laws, we undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
PART I
ITEM 1. BUSINESS.
GENERAL
Ameren, headquartered in St. Louis, Missouri, is a public utility holding
company registered with the SEC under the PUHCA. Ameren's primary asset is the
common stock of its subsidiaries. Ameren's subsidiaries operate rate-regulated
electric generation, transmission and distribution businesses, rate-regulated
natural gas distribution businesses and non rate-regulated electric generation
businesses in Missouri and Illinois. Dividends on Ameren's common stock are
dependent on distributions made to it by its subsidiaries. Ameren's principal
subsidiaries are listed below. See Note 1 - Summary of Significant Accounting
Policies to our financial statements under Part II, Item 8 of this report for a
more detailed description of the Ameren Companies.
o UE, also known as Union Electric Company, operates a rate-regulated
electric generation, transmission and distribution business, and a
rate-regulated natural gas distribution business in Missouri and Illinois.
o CIPS, also known as Central Illinois Public Service Company, operates a
rate-regulated electric and natural gas transmission and distribution
business in Illinois.
o Genco, also known as Ameren Energy Generating Company, operates a non
rate-regulated electric generation business.
o CILCO, also known as Central Illinois Light Company, is a subsidiary of
CILCORP (a holding company) and operates a rate-regulated electric
transmission and distribution business, a primarily non rate-regulated
electric generation business and a rate-regulated natural gas distribution
business in Illinois.
At December 31, 2003, Ameren employed 7,650 employees, UE employed 3,996
employees, CIPS employed 764 employees, Genco employed 701 employees and CILCORP
employed 862 employees, of which 855 employees are employed by CILCO. During the
second and third quarters of 2003, we entered into new four-year labor
agreements with the IBEW and the IUOE representing eleven bargaining units
covering approximately 70% of Ameren's, UE's, CIPS' and Genco's entire
workforces. The new agreements include no wage increase for year one of the
agreements, 3.5% increases for both years two and three, and an increase of
3.25% for year four. In addition, the agreements include a pension supplement,
more flexible work rules and a change to employee medical benefits resulting in
employees paying a greater portion of future benefit cost increases. CILCO has a
labor agreement with the IBEW which will expire on July 1, 2004. Employees
covered by the agreement represent approximately 4% of Ameren's and CILCO's
entire workforce.
For additional information regarding our business operations, see
Management's Discussion and Analysis of Financial Condition and Results of
Operations under Part II, Item 7 of this report and Note 1- Summary of
Significant Accounting Policies to our financial statements under Part II, Item
8 of this report.
CAPITAL PROGRAM AND FINANCING
For information on our capital program and financing needs, see Liquidity
and Capital Resources in Management's Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7 of this report and
Note 5 - Short-term Borrowings and Liquidity, Note 6 - Long-term Debt and Equity
Financings, Note 10 - Stockholder Rights Plan and Preferred Stock and Note 15 -
Commitments and Contingencies to our financial statements under Part II, Item 8
of this report.
9
RATES AND REGULATION
Rates
Rates that UE, CIPS and CILCO are allowed to charge for their services are
the single most important item influencing their and Ameren's consolidated
financial position, results of operations and liquidity. The rates charged to
UE, CIPS and CILCO customers are determined by governmental organizations.
Decisions by these organizations are influenced by many factors, including the
cost of providing service, the quality of service, regulatory staff knowledge
and experience, economic conditions and social and political views. Decisions
made by these organizations regarding rates could have a material impact on the
financial position, results of operations and liquidity of UE, CIPS, CILCO and
Ameren on a consolidated basis.
UE, CIPS and CILCO are subject to regulation by the ICC, and UE is also
subject to regulation by the MoPSC, as to rates, service, issuance of equity
securities, issuance of debt having a maturity of more than twelve months,
mergers, affiliate transactions, and various other matters. Genco is not subject
to regulation by the ICC or the MoPSC. See Note 3 - Rate and Regulatory Matters
to our financial statements under Part II, Item 8 of this report for information
regarding UE's proposed discontinuance of its utility operations subject to ICC
jurisdiction by transferring its Illinois-based electric and natural gas
transmission and distribution business to CIPS.
UE, CIPS, CILCO and Genco are also subject to regulation by the FERC as to
rates and charges in connection with the wholesale sale of energy and
transmission in interstate commerce, mergers, affiliate transactions, and
certain other matters. Issuance of short-term and long-term debt by Genco is
subject to approval by the FERC.
The following table presents the approximate percentage of electric
operating revenues subject to regulation by the MoPSC, the ICC and the FERC for
each of the Ameren Companies for the year ended December 31, 2003:
- -----------------------------------------------------------------------------------------------------------------
MoPSC ICC FERC
- -----------------------------------------------------------------------------------------------------------------
Ameren(a)............................................................. 51% 33% 16%
UE.................................................................... 80 6 14
CIPS.................................................................. - 90 10
Genco................................................................. - - 100
CILCORP............................................................... - 95 5
CILCO................................................................. - 95 5
- -----------------------------------------------------------------------------------------------------------------
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date
of January 31, 2003; includes amounts for non-registrant Ameren
subsidiaries as well as intercompany eliminations.
The following table presents the approximate percentage of gas operating
revenues subject to regulation by the MoPSC and the ICC for each of the Ameren
Companies for the year ended December 31, 2003:
- -----------------------------------------------------------------------------------------------------------------
MoPSC ICC
- -----------------------------------------------------------------------------------------------------------------
Ameren(a)..................................................................... 19% 81%
UE............................................................................ 87 13
CIPS.......................................................................... - 100
CILCORP....................................................................... - 100
CILCO......................................................................... - 100
- -----------------------------------------------------------------------------------------------------------------
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date
of January 31, 2003; includes amounts for non-registrant Ameren
subsidiaries as well as intercompany eliminations.
UE's, CIPS' and CILCO's electric and gas rates may be adjusted based on
certain criteria. PGA clauses allow for prudently-incurred natural gas purchase
costs to be passed directly to the consumer in Missouri and Illinois. There is
no similar provision for regulated electric operations which would allow fuel or
purchased power costs to be passed directly to the consumer. Environmental
adjustment rate riders authorized by the ICC permit the recovery of
prudently-incurred MGP remediation and litigation costs from UE's, CIPS' and
CILCO's Illinois electric and natural gas utility customers. There are also gas
pipeline replacement cost clauses permitted by the MoPSC that allow the recovery
from gas utility customers of infrastructure replacement costs. However, UE
agreed to not seek recovery under such a clause before January 1, 2006 in
conjunction with its 2003 Missouri gas rate case settlement. For additional
information see
10
Quantitative and Qualitative Disclosures About Market Risk under Part II, Item
7A of this report and Note 3 - Rate and Regulatory Matters and Note 15 -
Commitments and Contingencies to our financial statements under Part II, Item 8
of this report.
For information on rate matters in these jurisdictions, including UE's 2002
Missouri electric rate case, see Results of Operations in Management's
Discussion and Analysis of Financial Condition and Results of Operations under
Part II, Item 7 of this report and Note 3 - Rate and Regulatory Matters to our
financial statements under Part II, Item 8 of this report.
General Regulatory Matters
As a holding company registered with the SEC under the PUHCA, Ameren is
subject to the regulatory provisions of the PUHCA, including provisions relating
to the issuance of securities, sales and acquisitions of securities and utility
assets, affiliate transactions, financial reporting requirements, the services
performed by Ameren Services and AFS, and the activities of certain other
subsidiaries. Issuance of common stock and short-term and long-term debt and
other securities by Ameren and CILCORP and issuance of debt having a maturity of
twelve months or less by UE, CIPS and CILCO are subject to approval by the SEC
under the PUHCA.
Genco is certified by the FERC as an "exempt wholesale generator" under the
Energy Policy Act of 1992 and as a result is not a "public utility company"
under the PUHCA. As an exempt wholesale generator, Genco is exempt from most of
the provisions of the PUHCA that otherwise would apply to it as a subsidiary of
a registered holding company. Issuance of securities by Genco is not subject to
approval by the SEC under the PUHCA. The SEC may impose limitations on Ameren in
connection with its financing for the purpose of investing in exempt wholesale
generators and foreign utility companies if Ameren's aggregate investment in
those activities exceeds 50% of its consolidated retained earnings. At December
31, 2003, Ameren's aggregate investment in exempt wholesale generators was 23%
of its consolidated retained earnings. Ameren has no investment in foreign
utility companies.
In many states, including Illinois, companies that sell electricity
directly to retail customers pursuant to state statutes and regulations must be
registered or licensed. Marketing Company has obtained "alternative retail
electricity supplier" status in Illinois and plans to seek comparable status in
other states where retail competition is developing. In December 2003, the IBEW
filed a complaint before the ICC challenging Marketing Company's certification
status, based on its interpretation of the reciprocity clause requirements.
Marketing Company believes the complaint should be denied, but cannot predict
how or when the complaint will be resolved. CILCO is an Illinois electric
utility, and as such, is permitted to provide power and energy on a competitive
basis to retail customers located outside its service territory. CILCO was
required to seek Integrated Distribution Company status in the first quarter of
2004 whereby, upon approval, it would cease selling power and energy on a retail
basis as prescribed by the Integrated Distribution Company rules. However, as a
result of the IBEW complaint, CILCO has filed a notice with the ICC to extend
the deadline for CILCO becoming an Integrated Distribution Company. This
extension would ensure that either Marketing Company or CILCO would be able to
sell on a competitive basis to retail customers in Illinois given the
uncertainty presented by the IBEW complaint. We cannot predict how or when the
ICC will rule on CILCO's motion.
Operation of UE's Callaway Nuclear Plant is subject to regulation by the
NRC. Its Facility Operating License expires on October 18, 2024. UE's Osage
hydroelectric plant and UE's Taum Sauk pumped-storage hydro plant, as licensed
projects under the Federal Power Act, are subject to FERC regulations affecting,
among other things, the general operation and maintenance of the projects. The
license for the Osage Plant expires on February 28, 2006, and the license for
the Taum Sauk Plant expires on June 30, 2010. In February 2004, UE filed an
application with the FERC to renew the license for its Osage hydroelectric plant
for an additional 50 year term. UE's Keokuk Plant and dam located in the
Mississippi River between Hamilton, Illinois and Keokuk, Iowa, are operated
under authority, unlimited in time, granted by an Act of Congress in 1905.
For information on regulatory matters in these jurisdictions, including the
current status of electric transmission matters pending before the FERC, see
Regulatory Matters in Management's Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7 of this report and
Note 3 - Rate and Regulatory Matters to our financial statements under Part II,
Item 8 of this report.
11
Environmental Matters
Certain of our operations are subject to federal, state and local
environmental regulations relating to the safety and health of personnel, the
public and the environment, including the identification, generation, storage,
handling, transportation, disposal, record-keeping, labeling, reporting of and
emergency response in connection with hazardous and toxic materials, safety and
health standards, and environmental protection requirements, including standards
and limitations relating to the discharge of air and water pollutants. Failure
to comply with those statutes or regulations could have material adverse effects
on us, including the imposition of criminal or civil liability by regulatory
agencies or civil fines and liability to private parties, and the required
expenditure of funds to bring us into compliance. We believe we are in material
compliance with existing regulations.
For additional discussion of environmental matters, including NOx credit
requirements, see Liquidity and Capital Resources in Management's Discussion and
Analysis of Financial Condition and Results of Operations under Part II, Item 7
of this report and Note 15 - Commitments and Contingencies to our financial
statements under Part II, Item 8 of this report.
SUPPLY FOR ELECTRIC POWER
During 2003, the Ameren Companies peak demand from retail and wholesale
customers was 12,860 megawatts and the peak capability to deliver power from
owned generation and power supply agreements was 15,090 megawatts. Forecasted
peak demand from retail and wholesale customers for 2004 is 13,198 megawatts
with a 15% reserve margin. Ameren-owned generation and purchased power are used
to meet the energy needs of our customers. Factors that could cause us to
purchase power include, among other things, generating plant outages, extreme
weather conditions and the availability of power for a lower cost than we could
generate it.
UE, Genco and CILCO utilize coal, nuclear, natural gas, hydro and oil to
produce electric power for sale. On October 3, 2003, CILCO transferred
substantially all its generating property and plant to AERG. See additional
information regarding this transfer in Note 1 - Summary of Significant
Accounting Policies to our financial statements under Part II, Item 8 of this
report. The following table presents the fuel supply for electric generation for
the years ended December 31, 2003, 2002 and 2001:
===================================================================================================================
Natural
Fuel Supply Coal Nuclear Gas Hydro Oil
-------------------------------------------------------------------------------------------------------------------
Ameren:(a)
2003................................... 85% 13% (b) 1% 1%
2002................................... 82 13 2% 2 1
2001................................... 77 19 2 1 1
====================================================================================================================
UE:
2003................................... 77% 21% (b) 2% (b)
2002................................... 77 20 (b) - 3%
2001................................... 75 23 (b) 2 (b)
====================================================================================================================
Genco:
2003................................... 95% - 2% - 3%
2002................................... 88 - 8 - 4
2001................................... 87 - 9 - 4
====================================================================================================================
CILCORP:(c)
2003................................... 100% - (b) - (b)
2002................................... 100 - (b) - (b)
2001................................... 100 - (b) - (b)
====================================================================================================================
CILCO:
2003................................... 100% - (b) - (b)
2002................................... 100 - (b) - (b)
2001................................... 100 - (b) - (b)
====================================================================================================================
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date
of January 31, 2003; includes amounts for non-registrant Ameren
subsidiaries as well as intercompany eliminations.
(b) Less than 1% of total fuel supply.
(c) 2002 and 2001 amounts represent predecessor information. CILCORP
consolidates CILCO and therefore includes CILCO amounts in its
balances.
12
The following table presents the cost of fuels for electric generation for
the years ended December 31, 2003, 2002, and 2001:
====================================================================================================================
Cost of Fuels
(Dollars per million Btu) 2003 2002 2001
- --------------------------------------------------------------------------------------------------------------------
Ameren:(a)
Coal..................................................... $ 1.049 $ .999 $ 1.025
Nuclear.................................................. .410 .381 .372
Natural Gas(b)........................................... 8.665 3.869 4.332
- --------------------------------------------------------------------------------------------------------------------
Average-all fuels(c)..................................... $ .999 $ .974 $ .979
====================================================================================================================
UE:
Coal..................................................... $ .913 $ .914 $ .982
Nuclear.................................................. .410 .381 .372
Natural Gas(b)........................................... 9.328 3.407 4.025
- --------------------------------------------------------------------------------------------------------------------
Average-all fuels(c)..................................... $ .822 $ .813 $ .867
====================================================================================================================
Genco:
Coal..................................................... $ 1.220 $ 1.255 $ 1.218
Natural Gas(b)........................................... 8.759 3.962 4.397
- --------------------------------------------------------------------------------------------------------------------
Average-all fuels(c)..................................... $ 1.368 $ 1.452 $ 1.421
====================================================================================================================
CILCORP:(d)
Coal..................................................... $ 1.516 $ 1.610 $ 1.873
Natural Gas(b)........................................... 6.171 3.790 5.436
- --------------------------------------------------------------------------------------------------------------------
Average-all fuels(c)..................................... $ 1.543 $ 1.627 $ 1.890
====================================================================================================================
CILCO:
Coal..................................................... $ 1.664 $ 1.610 $ 1.873
Natural Gas(b)........................................... 6.171 3.790 5.436
- --------------------------------------------------------------------------------------------------------------------
Average-all fuels(c)..................................... $ 1.690 $ 1.627 $ 1.890
====================================================================================================================
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date
of January 31, 2003.
(b) The fuel cost for natural gas represents the actual cost of natural
gas and variable costs for transportation, storage, balancing and fuel
losses for delivery to the plant. In addition, the fixed costs for
firm transportation and firm storage capacity are included to
calculate a "fully-loaded" fuel cost for the generating facilities.
(c) Represents all fuels utilized in our electric generating facilities,
to the extent applicable, including coal, nuclear, natural gas, oil,
propane, tire chips and handling.
(d) 2002 and 2001 amounts represent predecessor information. CILCORP
consolidates CILCO and therefore includes CILCO amounts in its
balances.
Coal
UE, Genco and CILCO have long-term agreements in place for the purchase of
coal to supply electric generating facilities. These agreements have terms
through 2010. Coal supply agreements typically have an initial term of five
years, with approximately 20% of the contracts expiring annually. As of December
31, 2003, nearly 100% of UE's, Genco's and CILCO's expected 2004 coal usage was
under contract, and approximately 47% of the expected coal usage for 2005 to
2008 was under contract. Ameren burned 31 million tons of coal in 2003.
UE, Genco and CILCO have a policy of maintaining coal inventory consistent
with their historical usage. Levels may be adjusted based on uncertainties of
supply due to potential work stoppages, delays in coal deliveries, equipment
breakdowns and other factors. The following table presents the number of days
supply of coal in inventory as of December 31, 2003 and 2002:
===============================================================================
2003 2002
- -------------------------------------------------------------------------------
Ameren(a)....................................... 56 59
UE.............................................. 59 63
Genco........................................... 55 46
CILCORP(b)...................................... 38 49
CILCO........................................... 38 49
===============================================================================
(a) Excludes amounts for CILCORP and CILCO prior to the acquisition date
of January 31, 2003; includes amounts for non-registrant Ameren
subsidiaries as well as intercompany eliminations.
(b) 2002 amounts represent predecessor information. CILCORP consolidates
CILCO and therefore includes CILCO amounts in its balances.
13
Nuclear
UE has agreements and/or inventories to fulfill its Callaway Nuclear Plant
needs for uranium, conversion, enrichment and fabrication services through 2006.
UE expects to enter into additional contracts from time to time in order to
supply nuclear fuel during the expected remainder of the life of the plant, at
prices which cannot now be accurately predicted. The Callaway Nuclear Plant
normally requires refueling at 18-month intervals, and the next refueling is
scheduled for the spring of 2004. The Callaway Nuclear Plant is expected to be
out of service for approximately 40 to 45 days during this refueling. See Note
16 - Callaway Nuclear Plant to our financial statements under Part II, Item 8 of
this report for additional information.
Natural Gas Supply for Power Generation
Ameren owns 2,509 megawatts of natural gas-fired generating capacity. The
gas-fired capacity is primarily CTs, and some have the capability to use natural
gas or oil. See Item 2. Properties below for additional information. Our natural
gas procurement strategy is designed to ensure reliable and immediate delivery
of natural gas to our generating units by optimizing transportation and storage
options, minimizing cost and price risk by structuring various supply and price
hedging agreements to maintain access to multiple gas pools, supply basins and
storage, and reducing the impact of price volatility. For 2004, 47% of the
estimated required natural gas supply is under contract and 38% of the required
gas supply is hedged for price risk.
Oil
The actual and prospective use of oil is minimal, and we have not
experienced and do not expect to experience difficulty in obtaining adequate
supplies.
Purchased Power
We believe we can obtain enough purchased power to meet future needs.
However, during periods of high demand, the price and availability of these
purchases may be significantly affected. The Ameren transmission system has a
minimum of 24 direct connections to other control areas allowing access to
numerous sources of supply. See Item 2. Properties under Part I of this report
for additional information. See also Note 1 - Summary of Significant Accounting
Policies to our financial statements under Part II, Item 8 of this report for a
summary of purchased power costs for the three years ended December 31, 2003.
NATURAL GAS SUPPLY FOR DISTRIBUTION
UE, CIPS and CILCO are responsible for the purchase and delivery of natural
gas to their gas utility customers. UE, CIPS and CILCO develop and manage a
portfolio of gas supply resources including firm gas supply under term
agreements with producers, interstate and intrastate firm transportation
capacity, firm storage capacity leased from interstate pipelines, and on-system
storage facilities to maintain gas deliveries to our customers throughout the
year and especially during periods of peak demand. UE, CIPS and CILCO primarily
utilize the Panhandle Eastern Pipe Line Company, Trunkline Gas Company and
Natural Gas Pipeline Company of America interstate pipeline systems for
transportation to our systems. Financial instruments, including the NYMEX
futures market and OTC financial markets in addition to physical transactions
are used to hedge the price paid for natural gas. Prudently incurred natural gas
purchase costs are passed to UE, CIPS and CILCO gas customers in Illinois and
Missouri dollar-for-dollar under PGA clauses, subject to review by the ICC and
MoPSC.
For additional information on our fuel supply, see Results of Operations,
Liquidity and Capital Resources and Effects of Inflation and Changing Prices in
Management's Discussion and Analysis of Financial Condition and Results of
Operations under Part II, Item 7 of this report, Quantitative and Qualitative
Disclosures About Market Risk under Part II, Item 7A of this report, and Note 1
- - Summary of Significant Accounting Policies, Note 9 - Derivative Financial
Instruments, Note 15 - Commitments and Contingencies and Note 16 - Callaway
Nuclear Plant to our financial statements under Part II, Item 8 of this report.
14
INDUSTRY ISSUES
We are facing issues common to the electric and gas utility industries.
These issues include:
o the potential for more intense competition in generation and supply;
o the potential for changes in the structure of regulation;
o changes in the structure of the industry as a result of changes in federal
and state laws, including the formation of non rate-regulated generating
entities and regional transmission organizations;
o weak power prices due to available capacity exceeding demand;
o numerous troubled companies within the energy sector and their impact on
energy marketing and access to the capital markets;
o on-going consideration of additional changes of the industry by federal and
state authorities;
o continually developing environmental laws, regulations and issues,
including proposed new air quality standards;
o public concern about the siting of new facilities;
o proposals for programs to encourage energy efficiency;
o public concerns about nuclear decommissioning and the disposal of nuclear
wastes; and
o global climate issues.
We are monitoring these issues and are unable to predict at this time what
impact, if any, these issues will have on our results of operations, financial
condition or liquidity. For additional information, see Outlook and Regulatory
Matters in Management's Discussion and Analysis of Financial Condition and
Results of Operations under Part II, Item 7 of this report and Note 3 - Rate and
Regulatory Matters and Note 15 - Commitments and Contingencies to our financial
statements under Part II, Item 8 of this report.
RISK FACTORS
Ameren may not be able to complete its acquisition of Illinois Power. If
Ameren does not complete the acquisition, dilution to its earnings per share
will result unless Ameren is able to otherwise use the proceeds from the common
stock it issued in February 2004 so as to avoid or mitigate such dilution.
On February 2, 2004, Ameren entered into an agreement with Dynegy to
purchase the stock of Illinois Power and Dynegy's 20% ownership interest in EEI.
The total transaction value is approximately $2.3 billion, including the
assumption of approximately $1.8 billion of Illinois Power debt and preferred
stock. Ameren's financing plan for this transaction includes the issuance of new
Ameren common stock, which in total, is expected to equal at least 50% of the
transaction value. Ameren currently expects to issue common stock to finance the
cash portion of the purchase price, to reduce Illinois Power debt assumed as
part of this transaction and pay any related premiums and possibly to reduce
present or future indebtedness and/or repurchase securities of Ameren or its
subsidiaries. Ameren issued and sold 19.1 million shares of common stock on
February 6, 2004 for this purpose. The acquisition is subject to various
regulatory approvals, including the ICC, the SEC, the FERC, the Federal
Communications Commission, the expiration of the waiting period under the
Hart-Scott-Rodino Act and other customary closing conditions. Although Ameren
expects to complete the transaction by the end of 2004, it cannot be certain
that all of the required approvals will be obtained, or the other closing
conditions will be satisfied, within that time frame, if at all, or without
terms and conditions that may have a material adverse effect on our operations.
Ameren is also relying on the ability of Dynegy to close the sale of Illinois
Power when the required approvals are received. If Ameren is unable to complete
the acquisition, the issuance of the common stock on February 6, 2004 and any
other common stock issued with respect to the acquisition prior to its closing
will result in dilution to Ameren's earnings per share unless it is able to
otherwise use the proceeds from the common stock it issued in February 2004 in a
manner that will avoid or mitigate such dilution.
If Ameren is able to complete its acquisition of Illinois Power, Ameren may
not be able to successfully integrate it into its other businesses or achieve
the benefits it anticipates.
If Ameren completes the acquisition of Illinois Power, it cannot assure you
that it will be able to successfully integrate Illinois Power with its other
businesses. The integration of Illinois Power with its other businesses will
present significant challenges and, as a result, Ameren may not be able to
operate the combined company as effectively as
15
expected. Ameren may also fail to achieve the anticipated benefits of the
acquisition as quickly or as cost effectively as anticipated or may not be able
to achieve those benefits at all. While Ameren expects that this acquisition
will be accretive to earnings per share in the first full year of operation
after the transaction is completed, this expectation is based on important
assumptions, including assumptions related to interest rates and market prices
for power, which may ultimately be incorrect. As a result, if Ameren is unable
to integrate its businesses effectively or achieve the benefits anticipated, our
financial position, results of operations and liquidity may be materially
adversely affected.
The electric and gas rates that certain of the Ameren Companies are allowed
to charge in Missouri and Illinois are largely set through 2006. This "rate
freeze," along with other actions of regulators, can significantly affect our
earnings, liquidity and business activities and are largely outside our control.
The rates that certain of the Ameren Companies are allowed to charge for
their services are the single most important item influencing the financial
position, results of operations and liquidity of the Ameren Companies. We are
highly regulated and the regulation of the rates that we charge our customers is
determined, in large part, outside of our control by governmental organizations,
including the MoPSC, the ICC and the FERC. Ameren, UE, CIPS, Genco and CILCORP
are also subject to regulation by the SEC under the PUHCA. Decisions made by
these regulators could have a material impact on our financial position, results
of operations and liquidity.
As a part of the settlement of UE's Missouri electric rate case in 2002, UE
is subject to a rate moratorium providing for no changes in its electric rates
in Missouri before July 1, 2006, subject to limited statutory and other
exceptions. A rate reduction of $30 million will go into effect on April 1,
2004, which is the last portion of the $110 million rate reduction included in
the stipulation entered into as part of the settlement of the Missouri electric
rate case. In addition, as a provision of the Illinois legislation related to
the restructuring of the Illinois electric industry, a rate freeze is in effect
in Illinois through January 1, 2007. This Illinois legislation also contains a
provision requiring that earnings from the Illinois jurisdiction in excess of
certain levels be shared equally with UE's, CIPS' and CILCO's Illinois customers
through 2006. This Illinois legislation is also applicable to Illinois Power.
Furthermore, as part of the settlement of UE's Missouri gas rate case, which was
approved by the MoPSC on January 13, 2004, UE agreed to a rate moratorium
providing for no changes in its gas delivery rates prior to July 1, 2006,
subject to certain exceptions (the increased rates approved as part of the
settlement became effective on February 15, 2004).
As a part of the settlement of UE's Missouri electric rate case in 2002, UE
also undertook to use commercially reasonable efforts to make critical energy
infrastructure investments of $2.25 billion to $2.75 billion from January 1,
2002 through June 30, 2006, including, among other things, the addition of more
than 700 megawatts of new generation capacity (240 megawatts of which was added
in 2002) and the replacement of steam generators at UE's Callaway Nuclear Plant.
The amount of energy infrastructure investment through June 2006 described in
the settlement is consistent with UE's previously disclosed estimate of
construction expenditures UE expects to make over the same time period. However,
UE's agreement to a rate moratorium will result in these capital expenditures
not becoming recoverable in rates, or earning a return, before July 1, 2006.
Therefore, UE's undertakings with respect to making energy infrastructure
investments and funding new programs, coupled with the rate reductions and rate
moratorium described above, could result in increased financing requirements for
UE and thus have a material impact on our liquidity.
The Ameren Companies do not have the benefit of a fuel adjustment clause in
either Missouri or Illinois for their electric operations that would allow them
to recover increased fuel and power costs from customers. Therefore, to the
extent that we have not hedged our fuel and power costs, we are exposed to
changes in fuel and power prices to the extent fuel for our electric generating
facilities and power must be purchased on the open market in order for us to
serve our customers.
Steps taken and being considered at the federal and state levels continue
to change the structure of the electric industry and utility regulation. At the
federal level, the FERC has been mandating changes in the regulatory framework
in which transmission-owning public utilities, such as UE, CIPS and CILCO
operate. In Missouri, where a majority of our retail electric revenues are
derived, restructuring bills have been introduced in the past, but no
legislation has been passed. The Illinois Customer Choice Law provides for
electric utility restructuring and retail direct access. Retail direct access,
which allows customers to choose their electric generation supplier, was first
offered to Illinois residential customers on May 1, 2002. Although retail direct
access in Illinois has not had a negative effect on our revenues or liquidity,
we expect competitive forces in the electric supply segment of our business to
continue to increase.
16
The potential negative consequences associated with further electric
industry restructuring in our service territories, if it occurs, could be
significant and could include the impairment and writedown of certain assets,
including generation related plant and net regulatory assets, lower revenues,
reduced profit margins and increased costs of capital and operations expenses.
Increased federal and state environmental regulation could require UE,
Genco and CILCO to incur large capital expenditures and increase operating
costs.
Approximately 65% of Ameren's generating capacity is coal-fired. The
balance is nuclear, gas-fired, hydro and oil-fired. The EPA has recently issued
proposed regulations with respect to SO2, NOx and mercury emissions from
coal-fired power plants. These new rules, if adopted, would require significant
additional reductions in these emissions from our power plants in phases,
beginning in 2010. The rules are currently under a public review and comment
period, and may change before being issued as final late in 2004 or early 2005.
Preliminary estimates of capital costs based on current technology on the Ameren
systems to comply with the SO2 and NOx rules, as proposed, range from $400
million to $600 million by 2010, with an additional $500 million to $800 million
by 2015. The proposed mercury regulations contain a number of options and the
final control requirements are highly uncertain. Ameren anticipates additional
capital costs to comply with the mercury rules could be up to $100 million by
2010. Depending upon the final mercury rules, similar additional costs could be
incurred between 2010 and 2018.
In addition, Illinois has developed a NOx control regulation for utility
generating plant boilers consistent with an EPA program aimed at reducing ozone
levels in the eastern United States. In February 2002, the EPA proposed similar
rules for Missouri. Ameren currently estimates that the remaining capital
expenditures could range from $210 million to $250 million between 2004 and 2008
in order to comply with the final NOx regulations in Missouri and Illinois. This
estimate includes the assumption that these rules will require the installation
of selective catalytic reduction technology on some units, as well as additional
controls.
We are unable to predict the ultimate effect of any new environmental
regulations, guidelines, enforcement initiatives or legislation on our financial
position, results of operations or liquidity. Any of these factors would add
significant pollution control costs to UE's, Genco's and CILCO's generating
assets and therefore, could also increase financing requirements for some of the
Ameren Companies. While costs incurred by UE would be eligible for recovery in
rates, subject to MoPSC or ICC approval, as applicable, there is no similar
mechanism for recovery of costs by Genco or CILCO in Illinois.
UE's and CIPS' required participation in a RTO could increase costs, reduce
revenues and reduce UE's and CIPS' control over their transmission assets.
In December 1999, the FERC issued Order 2000 requiring all utilities
subject to FERC jurisdiction to state their intentions for joining a RTO. Since
April 2002, the GridAmerica Companies have participated in a number of filings
at the FERC in an effort to form GridAmerica LLC, or GridAmerica, as an ITC. On
December 19, 2002, the FERC issued an order conditionally approving the
formation and operation of GridAmerica as an ITC within the Midwest ISO subject
to further compliance filings, which were made by the GridAmerica Companies in
early 2003. CILCO is already a member of the Midwest ISO and has transferred
functional control of its transmission system to the Midwest ISO. Transmission
service on the CILCO transmission system is provided pursuant to the terms and
conditions of the Midwest ISO OATT on file with the FERC.
On April 30, 2003, the FERC issued an order authorizing the GridAmerica
Companies' request to transfer functional control of their transmission assets
to GridAmerica. The FERC also accepted the proposed rate amendments to the
Midwest ISO OATT, filed in early 2003 by Midwest ISO and the GridAmerica
Companies, effective upon the commencement of service over the GridAmerica
transmission facilities under the Midwest ISO OATT, suspended the proposed rates
for a nominal period, subject to refund, and established hearing and settlement
judge procedures to determine the justness and reasonableness of the proposed
rate amendments to the Midwest ISO OATT. In August 2003, the GridAmerica
Companies filed acknowledgements with the FERC to permit GridAmerica to commence
operations on October 1, 2003, on a phased basis, by assuming, with the Midwest
ISO, functional control of the transmission systems of American Transmission
Systems, Incorporated, a subsidiary of FirstEnergy Corp., and Northern Indiana
Public Service Company, a subsidiary of NiSource Inc. Pursuant to this
authorization, GridAmerica began operating on October 1, 2003.
17
Also beginning on October 1, 2003, the proposed rates filed by Midwest ISO
and the GridAmerica Companies became effective, subject to refund for
FirstEnergy Corp. and NiSource Inc. Since UE and CIPS have not transferred
functional control of their transmission assets to Midwest ISO, the proposed
rates are not effective for UE or CIPS. On December 18, 2003, the GridAmerica
Companies, the Midwest ISO and the Midwest ISO transmission owners filed a
Stipulation and Agreement with the FERC in an effort to settle the disputed rate
issues for transmission service over the transmission assets of the GridAmerica
Companies. On March 3, 2004, the FERC approved the Stipulation and Agreement.
UE also requires approval from the MoPSC to join the Midwest ISO. On
February 26, 2004, the MoPSC issued an order conditionally approving a
Stipulation and Agreement that was filed on February 6, 2004. The Order
authorizes UE's participation in the Midwest ISO through Grid America for a five
year period, but is conditioned on the FERC approving a Service Agreement that
outlines the terms and conditions under which the Midwest ISO wil provide
transmission service to UE's bundled retail load. FERC approval of this Service
Agreement is pending.
Until the tariffs and other material terms of UE's and CIPS' participation
in GridAmerica and GridAmerica's participation in the Midwest ISO are finalized
and approved by the FERC and other regulatory authorities having jurisdiction,
we are unable to predict the ultimate impact that ongoing RTO developments will
have on our financial position, results of operations or liquidity. UE and CIPS
could incur increased transmission-related costs and reduced transmission
service revenues, and may be required to expand their transmission system
according to decisions made by a RTO rather than our internal planning process
once UE and CIPS begin participating in the Midwest ISO through GridAmerica. UE
and CIPS expect to begin participating in the Midwest ISO in 2004.
The inability of UE and CIPS to recover "through and out" transmission
revenues could result in a material net revenue reduction.
On November 17, 2003, the FERC issued an order upholding an earlier order
issued in July 2003 that will reduce UE's and CIPS', as well as other
transmission-owning utilities', "through and out" transmission revenues
effective April 1, 2004 (the April 1 effective date was changed to May 1, 2004,
by subsequent order issued by the FERC). The revenues subject to elimination by
this order are those revenues from transmission reservations that travel through
or out of UE's and CIPS' transmission system and are also used to provide
electricity to load within the Midwest ISO or PJM Interconnection LLC systems.
The magnitude of the potential net revenue reduction resulting from this order
could be up to $20 million to $25 million annually if UE and CIPS are not in a
RTO. While it is anticipated that UE's and CIPS' transmission revenues could be
reduced by these orders, transmission expenses for Genco could be reduced.
Moreover, the FERC's final order explicitly permits companies to collect the
lost "through and out" revenues through other transitional rate mechanisms.
Until it is determined when, or if, UE and CIPS will join a RTO, or the
magnitude of lost "through and out" transmission revenue recovery UE and CIPS
will receive through other rate mechanisms, UE and CIPS are unable to predict
the ultimate impact of these orders.
The substance and implementation of standard market design rules by the
FERC is uncertain and may adversely affect the way in which UE, CIPS and CILCO
operate their transmission assets.
On July 31, 2002, the FERC issued its standard market design NOPR. The NOPR
proposes a number of changes to the way the current wholesale transmission
service and energy markets are operated. Specifically, the NOPR proposes that
all jurisdictional transmission facilities be placed under the control of an
independent transmission provider (similar to a 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. In our initial comments on the NOPR,
which were filed at the FERC on November 15, 2002, we expressed 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
filed additional comments on the remaining sections of the NOPR during the first
quarter of 2003.
In April 2003, the FERC issued a "white paper" reflecting comments received
in response to the NOPR. More specifically, the white paper indicated that the
FERC will not assert jurisdiction over the transmission rate component of
bundled retail service and will insure that existing bundled retail customers
retain their existing transmission rights and retain rights for future load
growth in its final rule. Moreover, the white paper acknowledged that the final
rule will provide the states with input on resource adequacy requirements,
allocation of firm transmission rights, and transmission planning. The FERC also
requested input on the flexibility and timing of the final rule's
implementation.
18
Although issuance of the final rule is uncertain and its implementation
schedule is still unknown, the Midwest ISO was in the process of implementing a
separate market design similar to the proposed market design in the NOPR. In
July 2003, the Midwest ISO filed with the FERC a revised OATT codifying the
terms and conditions under which it will implement the new market design.
Thereafter, on October 17, 2003, the Midwest ISO filed a motion to withdraw its
revised OATT. On October 29, 2003, the FERC issued a series of orders granting
the motion for withdrawal of the revised OATT and providing guidance to be
followed by the Midwest ISO in developing a new energy market design in the
future. Until the FERC issues a final rule and the Midwest ISO finalizes its new
market design, we are unable to predict the ultimate impact of the NOPR or the
Midwest ISO new market design on our future financial position, results of
operations or liquidity.
Increasing costs associated with our defined benefit retirement plans,
healthcare plans and other employee related benefits may adversely affect our
results of operations, liquidity and financial position.
The Ameren Companies made cash contributions totaling $25 million and $31
million to defined benefit retirement plans during 2003 and 2002, respectively.
In addition, a minimum pension liability was recorded at December 31, 2002,
which resulted in after-tax charge to OCI and a reduction in stockholders'
equity for Ameren of $102 million. At December 31, 2003, the minimum pension
liability was reduced, resulting in OCI of $46 million and an increase in
stockholders' equity. The Ameren Companies expect to be required under the ERISA
to fund an average of approximately $115 million annually from 2005 through
2008, in order to maintain minimum funding levels for our pension plans,
assuming the passage of a law which would be retroactive to January 1, 2004 to
extend the temporary interest rate relief used to calculate pension liabilities
in 2002 and 2003, that expired on December 31, 2003. These amounts are estimates
and may change based on actual stock market performance, changes in interest
rates, and any pertinent changes in government regulations, each of which could
also result in a requirement to record an additional minimum pension liability.
Furthermore, if Ameren completes its acquisition of Illinois Power, we could
incur material funding requirements with respect to Illinois Power's existing
defined benefit retirement plans.
In addition to the costs of our retirement plans, the costs to us of
providing healthcare benefits to our employees and retirees have increased
substantially in recent years. We believe that our employee benefit costs,
including costs related to healthcare plans for our employees and former
employees, will continue to rise. The increasing costs and funding requirements
associated with our defined benefit retirement plans, healthcare plans and other
employee benefits may adversely affect our results of operations, liquidity or
financial position.
UE's, Genco's and CIPS' electric generating facilities are subject to
operational risks that could result in unscheduled plant outages, unanticipated
operation and maintenance expenses and increased power purchase costs.
UE, CILCO, Genco, AERG, Medina Valley, and EEI own and operate coal,
nuclear, gas-fired, hydro and oil-fired generating facilities constituting
approximately 14,600 megawatts (net) of installed capability. Operation of
electric generating facilities involves certain risks which can adversely affect
energy output and efficiency levels. Included among these risks are:
o increased prices for fuel and fuel transportation as existing contracts
expire,
o facility shutdowns due to a breakdown or failure of equipment or processes
or interruptions in fuel supply,
o disruptions in the delivery of fuel and lack of adequate inventories,
o labor disputes,
o inability to comply with regulatory or permit requirements,
o disruptions in the delivery of electricity,
o increased capital expenditures requirements, including those due to
environmental regulation,
o operator error, and
o unusual or adverse weather conditions, including catastrophic events such
as fires, explosions, floods or other similar occurrences affecting
electric generating facilities.
19
A substantial portion of Genco's and CILCO's generating capacity is
committed under affiliate contracts which expire over the next several years.
Genco and CILCO have several electric power supply agreements under which
Genco and CILCO directly or indirectly supply the full requirements of UE, CIPS
and CILCO, including the following:
o Under two electric power supply agreements, Genco is obligated to supply to
Marketing Company, and Marketing Company, in turn, is obligated to supply
to CIPS, all of the energy and capacity needed by CIPS to offer service for
resale to its native load customers and to fulfill CIPS' other obligations
under all applicable federal and state tariffs or contracts. Any power not
used by CIPS is sold by Marketing Company under various long-term wholesale
and retail contracts. The agreement between CIPS and Marketing Company
expires on December 31, 2004. The agreement between Genco and Marketing
Company can be terminated by either party upon at least one year's notice,
but may not be terminated prior to December 31, 2004.
o AERG has an electric power supply agreement with CILCO to supply it
sufficient power to meet its native load requirements. This agreement
expires on December 31, 2004.
The affected Ameren Companies currently plan to pursue renewals or
extensions of these full requirements agreements as they expire. Such renewals
or extensions will depend on compliance with federal and state regulatory
requirements in effect at the time. Extensions through December 31, 2006 of the
agreements to which CIPS and CILCO are a party have been required by the ICC in
its order approving our acquisition of CILCORP and CILCO; however, approval by
the FERC is also required.
Midwest power markets have experienced high levels of new capacity
development over the last several years, which, in part, have contributed to
soft long-term power prices in this region. Owners of generating capacity in the
Midwest are actively seeking markets for their energy and capacity and have
asked our regulators to closely scrutinize power supply arrangements among our
subsidiaries when we have sought approval to enter into them. Even though the
ICC has required those extensions, it cannot be predicted whether obtaining
extensions of these agreements, described above, when they expire will be
successful. To the extent Genco or CILCO cannot secure extensions or other
long-term replacement power sale contracts for the energy and capacity currently
committed under these agreements, our generating subsidiaries and Marketing
Company will face competition from other power suppliers in the Midwest and will
be exposed to price risk.
Genco participates with UE in an agreement to jointly dispatch its
generating facilities with those of UE, which thereby produces benefits and
efficiencies for both generating parties. Pending or future federal and state
regulatory proceedings and policies may evolve in ways that could impact Genco's
ability to continue to participate in these affiliate transactions on current
terms.
Genco's and CILCO's electric generating facilities must compete for the
sale of energy and capacity, which exposes them to price risk.
As owners of non rate-regulated electric generating facilities, Genco
(4,800 megawatts) and CILCO (1,100 megawatts) will not have any recovery of
their costs or any specified rate of return set by a regulatory body. Of these
non rate-regulated electric generating facilities, approximately 3,500 megawatts
are currently under full requirements contracts with our affiliates, including
the contracts referred to in the immediately preceding risk factor. The
remainder of the generating capacity must compete for the sale of energy and
capacity. UE is currently seeking regulatory approval of the transfer by Genco
to it of approximately 550 megawatts of CTs at Pinckneyville and Kinmundy,
Illinois, which transfer is expected to occur in 2004, with the result that
those CTs will no longer be non rate-regulated.
To the extent electric capacity generated by these facilities is not under
contract to be sold, either now or in the future, the revenues and results of
operations of these non rate-regulated subsidiaries will generally depend on the
prices that they can obtain for energy and capacity in Illinois and adjacent
markets. Among the factors that could influence such prices (all of which are
beyond our control to a significant degree) are:
o the current and future market prices for natural gas, fuel oil and coal,
o current and forward prices for the sale of electricity,
o the extent of additional supplies of electric energy from current
competitors or new market entrants,
20
o the pace of deregulation in our market area and the slowing expansion of
deregulated markets,
o the regulatory and pricing structures developed for Midwest energy markets
as they continue to evolve and the pace of development of regional markets
for energy and capacity outside of bilateral contracts,
o future pricing for, and availability of, transmission services on
transmission systems, the effect of RTOs, development and export energy
transmission constraints, which could limit the ability to sell energy in
markets adjacent to Illinois,
o the rate of growth in electricity usage as a result of population changes,
regional economic conditions and the implementation of conservation
programs, and
o climate conditions prevailing in the Midwest market from time to time.
UE's ownership and operation of a nuclear generating facility creates
business, financial and waste disposal risks.
UE owns the Callaway Nuclear Plant, which represents approximately 14% of
UE's generation capability. Therefore, UE is subject to the risks of nuclear
generation, which include the following:
o the potential harmful effects on the environment and human health resulting
from the operation of nuclear facilities and the storage, handling and
disposal of radioactive materials,
o limitations on the amounts and types of insurance commercially available to
cover losses that might arise in connection with UE's nuclear operations or
those of others in the United States,
o uncertainties with respect to contingencies and assessment amounts if
insurance coverage is inadequate,
o increased public and governmental concerns over the adequacy of security at
nuclear power plants, and
o uncertainties with respect to the technological and financial aspects of
decommissioning nuclear plants at the end of their licensed lives (UE's
facility operating license for the Callaway Nuclear Plant expires in 2024).
The NRC has broad authority under federal law to impose licensing and
safety related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines or
shut down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could necessitate substantial capital expenditures at nuclear plants
such as UE's. In addition, although UE has no reason to anticipate a serious
nuclear incident at its plant, if an incident did occur, it could harm UE's
results of operations or financial position. A major incident at a nuclear
facility anywhere in the world could cause the NRC to limit or prohibit the
operation or licensing of any domestic nuclear unit.
Our energy risk management strategies may not be effective in managing fuel
and electricity pricing risks, which could result in unanticipated liabilities
to us or increased volatility of our earnings.
We are exposed to changes in market prices for natural gas, fuel,
electricity and emission credits. Prices for natural gas, fuel, electricity and
emission credits may fluctuate substantially over relatively short periods of
time and expose us to commodity price risk. We utilize derivatives such as
forward contracts, futures contracts, options and swaps to manage these risks.
We attempt to manage our exposure from these activities through enforcement of
established risk limits and risk management procedures. We cannot assure you
that these strategies will be successful in managing our pricing risk, or that
they will not result in net liabilities to us as a result of future volatility
in these markets.
In addition, although we routinely enter into contracts to offset our
positions (i.e., to hedge our exposure to the risks of demand, market effects of
weather and changes in commodity prices), we do not always hedge the entire
exposure of our operations from commodity price volatility. Furthermore, our
ability to hedge our exposure to commodity price volatility depends on liquid
commodity markets. As a result, to the extent the commodity markets are
illiquid, we may not be able to execute our risk management strategies, which
could result in greater open positions than we would prefer at a given time. To
the extent that open positions exist, fluctuating commodity prices can improve
or diminish our financial results and financial position.
Our businesses are dependent on our ability to successfully access the
capital markets. We may not have access to sufficient capital in the amounts and
at the times needed.
We rely on access to short-term and long-term capital markets as a
significant source of liquidity and funding for capital requirements not
satisfied by our operating cash flows. The inability to raise capital on
favorable terms,
21
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.
OPERATING STATISTICS
The following tables present key electric and natural gas operating
statistics for Ameren for the last five years. CILCORP and CILCO are included
only for the period after January 31, 2003.
===================================================================================================================
Electric Operating Statistics
Year Ended December 31, 2003 2002 2001 2000 1999
-------------------------------------------------------------------------------------------------------------------
Electric operating revenues (millions)
Residential............................. $ 1,247 $ 1,202 $ 1,133 $ 1,142 $ 1,097
Commercial.............................. 1,115 1,024 1,020 997 956
Industrial.............................. 733 511 541 505 505
Wholesale............................... 295 291 236 208 108
Other................................... 25 23 23 24 24
-------------------------------------------------------------------------------------------------------------------
Native................................ 3,415 3,051 2,953 2,876 2,690
Interchange............................. 295 200 309 477 399
EEI..................................... 134 185 110 164 177
Miscellaneous........................... 93 84 125 74 72
Credit to (from) customers.............. - - 10 (65) (38)
-------------------------------------------------------------------------------------------------------------------
Total electric operating revenues........... $ 3,937 $ 3,520 $ 3,507 $ 3,526 $ 3,300
-------------------------------------------------------------------------------------------------------------------
Kilowatthour sales (millions)
Residential............................. 17,673 16,704 15,678 15,683 14,863
Commercial.............................. 18,821 17,224 16,873 16,644 15,418
Industrial.............................. 17,685 12,442 13,175 11,914 11,549
Wholesale............................... 8,770 8,936 6,992 6,244 3,002
Other................................... 309 280 284 307 303
-------------------------------------------------------------------------------------------------------------------
Native................................ 63,258 55,586 53,002 50,792 45,135
Interchange............................. 9,268 8,165 10,130 14,679 12,371
EEI..................................... 5,255 6,588 5,824 6,914 9,270
-------------------------------------------------------------------------------------------------------------------
Total kilowatthour sales.................... 77,781 70,339 68,956 72,385 66,776
-------------------------------------------------------------------------------------------------------------------
Electric customers (end of year in thousands)
Residential............................. 1,517 1,319 1,312 1,307 1,298
Commercial.............................. 215 194 192 191 187
Industrial.............................. 7 6 6 6 6
Wholesale and other..................... 5 4 4 4 4
-------------------------------------------------------------------------------------------------------------------
Total electric customers.................... 1,744 1,523 1,514 1,508 1,495
-------------------------------------------------------------------------------------------------------------------
Residential customer data (average)
Kilowatthours used per customer......... 11,648 11,680 11,956 12,579 11,827
Annual electric bill per customer....... $ 821.84 $ 848.06 $ 869.25 $ 895.20 $ 859.53
Revenue per kilowatthour (cents)........ 7.06 7.26 7.27 7.12 7.27
Capability at time of peak, including net
purchases and sales (megawatts)
UE...................................... 9,022 9,765 9,747 9,359 9,141
Genco/CIPS(a)........................... 4,429 4,223 3,549 3,560 2,556
CILCO................................... 1,355 - - - -
Generating capability at time of peak
(megawatts)
UE...................................... 8,298 8,647 8,618 8,320 8,352
Genco/CIPS(a)........................... 4,452 4,327 3,945 3,443 3,027
CILCO................................... 1,230 - - - -
Coal burned (millions of tons).............. 31.0 27.1 24.5 25.3 23.6
Price per ton of coal (average)............. $ 19.36 $ 18.06 $ 18.88 $ 18.94 $ 20.34
-------------------------------------------------------------------------------------------------------------------
22
-------------------------------------------------------------------------------------------------------------------
Electric Operating Statistics
Year Ended December 31, 2003 2002 2001 2000 1999
-------------------------------------------------------------------------------------------------------------------
Source of energy supply
Fossil.................................. 77.5% 74.3% 72.3% 83.2% 85.4%
Nuclear................................. 11.9 12.4 11.6 18.8 17.9
Hydro................................... 0.9 1.7 1.4 1.6 3.1
Purchased and interchanged, net......... 9.7 11.6 14.7 (3.6) (6.4)
-------------------------------------------------------------------------------------------------------------------
100.0% 100.0% 100.0% 100.0% 100.0%
===================================================================================================================
(a) Genco commenced operations on May 1, 2000, when CIPS transferred its
five coal-fired power plants to Genco at historical net book value.
===================================================================================================================
Gas Operating Statistics
Year Ended December 31, 2003 2002 2001 2000 1999
-------------------------------------------------------------------------------------------------------------------
Natural gas operating revenues (millions)
Residential....................................... $ 343 $ 192 $ 187 $ 204 $ 146
Commercial........................................ 142 75 83 69 52
Industrial........................................ 123 37 40 17 18
Off-system sales.................................. 6 4 6 18 4
Other............................................. 34 7 26 16 8
-------------------------------------------------------------------------------------------------------------------
Total natural gas operating revenues.................. $ 648 $ 315 $ 342 $ 324 $ 228
-------------------------------------------------------------------------------------------------------------------
MMBtu sales (thousands of MMBtus)
Residential....................................... 35 21 19 25 21
Commercial........................................ 16 9 9 9 8
Industrial........................................ 20 8 7 3 4
Off-system sales.................................. 1 1 1 4 1
-------------------------------------------------------------------------------------------------------------------
Total MMBtu sales (thousands of MMBtus)............... 72 39 36 41 34
-------------------------------------------------------------------------------------------------------------------
Natural gas customers (end of year in thousands)
Residential....................................... 466 270 269 270 267
Commercial and industrial......................... 49 30 30 31 30
-------------------------------------------------------------------------------------------------------------------
Total natural gas customers........................... 515 300 299 301 297
-------------------------------------------------------------------------------------------------------------------
Peak day throughput (thousands of MMBtus)
UE................................................ 188 159 160 179 184
CIPS.............................................. 282 232 221 249 285
CILCO(a).......................................... 301 - - - -
-------------------------------------------------------------------------------------------------------------------
Total peak day throughput............................. 771 391 381 428 469
===================================================================================================================
(a) Represents peak day throughput since the acquisition date of January
31, 2003. CILCO's peak day throughput in January 2003 was 404.
AVAILABLE INFORMATION
The Ameren Companies make available free of charge through Ameren's
Internet website (http://www.ameren.com) their annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments
to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Exchange Act as soon as reasonably practicable after such reports are
electronically filed with, or furnished to, the SEC. Prior to the quarterly
report on Form 10-Q for the period ended September 30, 2003, separate filings
were made by each Registrant, except CILCORP and CILCO, which made a combined
filing. Ameren and its subsidiaries changed to a combined filing in order to
improve disclosure and to simplify administrative processes.
The Ameren Companies also make available free of charge through Ameren's
Internet website (http://www.ameren.com) the charters of the Board of Directors
Audit Committee, Human Resources Committee and Nominating and Corporate
Governance Committee and the corporate governance guidelines, shareholder
communications policy and director nomination policy which apply to the Ameren
Companies. These documents are also available in print upon written request to
Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri
63166-6149.
23
ITEM 2. PROPERTIES.
For information on our principal properties, planned additions or
replacements and transfers, see the generating facilities table below and
Liquidity and Capital Resources and Regulatory Matters in Management's
Discussion and Analysis of Financial Condition and Results of Operations under
Part II, Item 7 of this report and Note 3 - Rate and Regulatory Matters, Note 6
- - Long-term Debt and Equity Financings and Note 15 - Commitments and
Contingencies to our financial statements under Part II, Item 8 of this report.
UE, CIPS and CILCO are members of MAIN, which is one of the ten regional
electric reliability councils organized for coordinating the planning and
operation of the nation's bulk power supply. MAIN operates in Illinois and
portions of Michigan, Wisconsin, Iowa, Minnesota and Missouri. UE, CIPS and
CILCO provided formal written notice to the MAIN Board of Directors on June 23,
2003 of their intent to withdraw from MAIN effective January 1, 2005. These
Ameren companies intend to join another Regional Reliability Organization prior
to their withdrawal from MAIN becoming effective. Until their withdrawal is
effective, they will continue to honor all of their obligations as members of
MAIN. If these Ameren companies do not join another Regional Reliability
Organization, they may withdraw their notice of intent to withdraw from MAIN.
The bulk power system of UE, CIPS and Genco is operated as an Ameren-wide
control area and transmission system under the FERC-approved amended joint
dispatch agreement. The amended joint dispatch agreement provides a basis upon
which UE and Genco can participate in the coordinated operation of CIPS' and
UE's transmission facilities with UE's and Genco's generating facilities in
order to achieve economies consistent with the provision of reliable electric
service and an equitable sharing of the benefits and costs of that coordinated
operation. In 2003, we had a minimum of 24 direct connections with other control
areas and the exchange of electric energy, directly and through the facilities
of others. CILCO continues to operate as a separate control area. As such, its
generating plants and those of its subsidiary, AERG, have not been jointly
dispatched with the generating plants owned by UE and Genco. CILCO is a
transmission owning member of the Midwest ISO and has transferred functional
control of its system to the Midwest ISO. Transmission service on the CILCO
transmission system is provided pursuant to the terms of the Midwest ISO OATT on
file with the FERC. For information on CIPS' and UE's participation in the
Midwest ISO, see Note 3 - Rate and Regulatory Matters to our financial
statements under Part II, Item 8 of this report.
The following table presents information with respect to our electric
generating facilities and capability at the time of our expected 2004 peak
summer electrical demand:
======================================================================================================================
Primary Name Net Kilowatt Net Heat
Fuel Source of Plant Location Capability(a) Rate(b)
- ----------------------------------------------------------------------------------------------------------------------
UE:
Coal...................... Labadie Franklin County, MO 2,421,000 9,987
Rush Island Jefferson County, MO 1,194,000 10,325
Sioux St. Charles County, MO 978,000 9,725
Meramec St. Louis County, MO 821,000 11,114
- ----------------------------------------------------------------------------------------------------------------------
Total coal................ 5,414,000
- ----------------------------------------------------------------------------------------------------------------------
Nuclear................... Callaway Callaway County, MO 1,137,000 10,461
- ----------------------------------------------------------------------------------------------------------------------
Hydro..................... Osage Lakeside, MO 226,000 n/a
Keokuk Keokuk, IA 134,000 n/a
- ----------------------------------------------------------------------------------------------------------------------
Total hydro............... 360,000
- ----------------------------------------------------------------------------------------------------------------------
Pumped-storage............ Taum Sauk Reynolds County, MO 440,000 n/a
Oil (CTs)................. Fairgrounds Jefferson City, MO 55,000 11,100
Meramec St. Louis County, MO 55,000 11,100
Mexico Mexico, MO 55,000 11,100
Moberly Moberly, MO 55,000 11,100
Moreau Jefferson City, MO 55,000 11,100
Howard Bend St. Louis County, MO 43,000 11,899
Venice Venice, IL 25,000 14,380
- ----------------------------------------------------------------------------------------------------------------------
Total oil................. 343,000
- ----------------------------------------------------------------------------------------------------------------------
24
- ----------------------------------------------------------------------------------------------------------------------
Primary Name Net Kilowatt Net Heat
Fuel Source of Plant Location Capability(a) Rate(b)
- ----------------------------------------------------------------------------------------------------------------------
Natural gas (CTs)......... Peno Creek(c) Bowling Green, MO 188,000 9,379
Meramec St. Louis County, MO 53,000 12,031
Venice(d) Venice, IL 48,000 10,765
Viaduct Cape Girardeau, MO 25,000 15,137
Kirksville Kirksville, MO 13,000 18,811
- ----------------------------------------------------------------------------------------------------------------------
Total natural gas......... 327,000
- ----------------------------------------------------------------------------------------------------------------------
Total..................... 8,021,000(e)
======================================================================================================================
EEI:
Joppa Generating
Coal...................... Station Joppa, IL 600,000 10,490
Natural gas (CTs)......... Joppa Joppa, IL 44,000 12,200
- ----------------------------------------------------------------------------------------------------------------------
Total..................... 644,000(f)
======================================================================================================================
Genco:
Coal...................... Newton Newton, IL 1,126,000 10,310
Coffeen Coffeen, IL 900,000 10,250
Meredosia Meredosia, IL 327,000 12,070
Hutsonville Hutsonville, IL 153,000 10,179
- ----------------------------------------------------------------------------------------------------------------------
Total coal................