Leading the
Way to a
Secure Energy
Future
2009 Annual Report
Ready for
tomorrow
In a challenging environment, we have repositioned our company
with a bold, new vision: Ameren is committed to leading the way to
a secure energy future.
• We are dedicated to finding sustainable solutions that meet the
energy needs of our customers.
• We are working to earn an even deeper level of trust from our customers.
• We are actively engaging in dialogue on energy issues.
• We are building a diverse energy portfolio that includes renewables.
• We are working hard to protect the environment we all share.
• We are embracing challenges and turning them into opportunities.
Energy Solutions
Page 2
Community Partnership
Page 4
Operational Excellence
Page 6
Building Value for Our Investors
Page 9
48.4%
Debt
50.3%
Equity
Financial Highlights
Page 14
Energy
Solutions
Providing customers with secure,
clean and reliable energy solutions
Our customers are our future — their satisfaction is key to a
cycle that is the lifeblood of our business. Making investments
in our infrastructure helps us improve service, which, in turn,
leads to higher customer satisfaction. High levels of quality
service and satisfaction can lead to a more constructive
regulatory environment and appropriate returns on our invest-
ments. Fair returns are necessary to cost-effectively fund
future infrastructure investments, continuing the benefit for
our customers and our investors. At left and below are photos
reflecting recent transmission system projects, including
switches that are part of our investment in smart grid diagnostic
technologies. Company employees are shown strengthening
our electric delivery systems against storms and replacing
couplings on tens of thousands of feet of natural gas system
steel piping. These pages also reflect award-winning energy
efficiency programs that encourage customers to use energy
more wisely. Our customers are noticing these initiatives;
surveys show much-improved satisfaction ratings.
2 | 3
Community
Partnership
Working with our communities
to make them better places to live
Our relationship with our communities is nurtured over decades
through corporate contributions, employee volunteerism and
a range of programs like the one shown above — a company-
sponsored performance by The National Theatre for Children
(NTC). NTC educates children about energy conservation
and renewable energy. Also shown are photos of Skilled Craft
Program ambassadors who go into local schools to mentor
and help educate students. Community partnerships have been
strengthened over the past several years by purchases from
diverse suppliers, as reflected here by our growing relationship
with Centrex Electrical Supply Corporation — an electrical
equipment supplier. Ameren has more than doubled the amount
spent with these suppliers in the past three years. Also helping
the economies of our communities are our strong economic
development programs, like those that brought system upgrades
to support Continental Tire Company’s $160 million investment
in improvements to its Mt. Vernon, IL, facility. Continental Tire
representatives, shown here, recently announced an additional
$60 million investment for new machinery.
4 | 5
Operational
Excellence
Operating our business in a safe,
reliable, efficient and environmentally
responsible manner
Keeping our power plants available to supply generation is a core
Ameren competency. So is environmental stewardship. The Duck
Creek Plant, shown below, epitomizes this with its highly successful
2009 installation of a scrubber, which helps us greatly reduce
emissions. The Coffeen Plant followed Duck Creek with its scrubber
installations. Our Callaway Nuclear Plant, shown top left, generated
the most electricity in a single calendar year (2009) since it began
operating in 1984. In late 2009, we announced an initiative to
install equipment to evaluate the latest in solar technologies, and
AmerenUE began receiving energy purchased from a Midwestern
wind farm. Another reflection of our commitment to low-cost,
clean energy is the rebuild of our 440-megawatt Taum Sauk
pumped-storage hydroelectric plant, expected to return to service
in 2010. This facility can store energy produced by renewable
sources during non-peak periods for use during peak periods.
6 | 7
Building Value
for Our Investors
My fellow shareholders,
The dedication of Ameren’s many employees and the loyalty of
the investors who have stayed with us during a difficult time for the
economy and our industry have inspired all of us here at Ameren.
I thank you. In this, my first year as CEO, I have worked with a team
of talented executives to take important steps to respond to the
economic challenges of today and to capitalize on the opportunities
of tomorrow. As a result, we believe we are well-positioned to
create long-term value for you, our owners.
Ameren’s Executive Leadership Team: (from left) Scott A. Cisel, Chairman, President and Chief Executive Officer,
AmerenCILCO, AmerenCIPS and AmerenIP; Daniel F. Cole, Chairman, President and Chief Executive Officer, Ameren Services;
Andrew M. Serri, President and Chief Executive Officer, Ameren Energy Marketing; Adam C. Heflin, Senior Vice President and
Chief Nuclear Officer, AmerenUE; Karen C. Foss, Senior Vice President, Communications and Brand Management, Ameren
Services; Martin J. Lyons, Jr., Senior Vice President and Chief Financial Officer, Ameren Corporation; Charles D. Naslund,
Chairman, President and Chief Executive Officer, Ameren Energy Resources and Chairman and President, Ameren Energy
Generating Company; Michael L. Moehn, Senior Vice President, Corporate Planning and Business Risk Management, Ameren
Services; Steven R. Sullivan, Senior Vice President, General Counsel and Secretary, Ameren Corporation; Warner L. Baxter,
Chairman, President and Chief Executive Officer, AmerenUE; Richard J. Mark, Senior Vice President, Customer Operations,
AmerenUE; and Thomas R. Voss, President and Chief Executive Officer, Ameren Corporation.
8 | 9
Strengthening Our Foundation
During 2009, we continued to proactively
address the effects of the global economic
and financial crisis—building on efforts
begun in 2008. We moved quickly and
aggressively to maintain and enhance our
financial strength and liquidity position
by issuing new long-term debt and equity,
extending our credit facilities, cutting
planned spending, eliminating approximately
300 positions, freezing management salaries,
and taking the difficult step of reducing
the dividend. That reduction, while essential,
was not a step we took lightly. These
actions enhanced our credit profile and
established a solid foundation to execute
our future strategies.
The worldwide economic and financial
crisis has affected businesses around the
globe, and we are not immune. We are
experiencing lower revenues due to a drop
in demand for electricity, particularly among
industrial customers, and to lower wholesale
electricity prices. In addition, the infrastructure
investments we have made to meet our cus-
tomers’ expectations and higher financing costs
have resulted in earned returns in our regulated
businesses that are well below levels authorized
by our regulators.
All these factors had an impact on our share
price, but we are taking necessary and
prudent steps to build a stronger company.
The Ameren team is dedicated to generating
long-term earnings growth and value for
our shareholders.
As part of that commitment, this past
summer our utilities in Illinois and Missouri
filed for higher rates. These requests were
driven by significant investments in service
quality and reliability, by higher financing costs
and by our continued pursuit of fair returns
on our regulated investments. In Missouri,
higher net fuel costs accounted for more
than half of the requested revenue increase.
Rulings on these requests are expected in
the second quarter of 2010.
Upon assuming the position of chief execu-
tive officer in May 2009, I immediately began
a strategic planning initiative to define a bold,
From exploring solar power
technologies to supporting
economic development programs
and building strong reliability,
Ameren employees are engaged
in the communities they serve.
Far left is lineman Rob Nguyen—
a Vietnamese refugee who
became a U.S. citizen and an
AmerenUE employee. At right is
Ameren Business Development
Executive, Glenn W. Smallwood, Jr.
(left) shown here with Continental
Tire Company Plant Manager,
Hank Eisenga. Smallwood helped
facilitate the expansion of Conti-
nental Tire’s Mt. Vernon, IL, plant.
new vision for Ameren —Leading the Way to
a Secure Energy Future. That vision is sup-
ported by defined business strategies that
anticipate the changing energy needs of our
customers and the changing environment
in which we operate.
Focusing on Our Vision
With a solid financial foundation in place,
your company is now focused on realizing
its new vision— beginning with an even
stronger focus on the customer.
Essential to our success is a commitment
to providing our customers with secure,
clean and reliable energy solutions. We are
working to achieve top quartile customer
satisfaction ratings. To help customers man-
age the impact of rate increases and, at the
same time, to protect the environment, we
are promoting more efficient use of energy.
We offer programs ranging from financial
assistance for home and business improve-
ments to energy audits and appliance
rebates. In Illinois, we are able to recover
the costs of these programs on a timely
We are taking necessary
and prudent steps to build
a stronger company.
basis, while homeowners and businesses
realize energy savings. In Missouri, a new
law was passed that could allow shareholders
to benefit from our investments in energy
efficiency programs.
In addition, we are deploying smart technolo-
gies across our electrical system to provide
greater reliability and safety, increase oper-
ating efficiency and offer timely information
about energy usage to our customers— again,
to help them better manage their costs.
In both Illinois and Missouri, we are pursuing
renewable generation projects. In Illinois,
we purchased more than 700,000 renewable
energy credits. In Missouri, we are designing
and building a new facility that will tap landfill
10 | 11
gas to generate enough electricity to power
10,000 households. Located in the St. Louis
area, the facility will be one of the nation’s
largest methane recovery projects. We have
also purchased 100 megawatts of wind
power. In addition, we are installing solar
energy systems at our St. Louis headquarters
campus and at a location in Illinois.
Clearly our ability to continue to invest
in these initiatives relies upon rate case
outcomes that provide necessary cash
flows on a timely basis.
Our higher customer satisfaction ratings are
evidence that our ongoing investment in
energy efficiency programs, renewable power,
delivery system reliability and responsive
service is paying off. We believe strong
customer satisfaction can contribute to a
more positive environment that could lead
to constructive regulatory decisions and an
ability to earn returns that are closer to levels
authorized by our regulators.
Your company is strategi-
cally poised to benefit from
an economic recovery,
improved regulatory
returns and significant
investment opportunities.
for our generating units, where we installed
environmental controls to vastly reduce
emissions from our power plants.
Building Value for Shareholders
Our new vision and supporting initiatives are
intended to build value for you, our owners.
We are committed to making disciplined invest-
ments and enhancing the regulatory and
market framework to support our long-term
earnings growth.
On the merchant generation side of our
business, the year also marked milestones
While we remain committed to growing earnings
in our utility operations, current returns on our
Ameren’s community relations
coordinators like Stacey Young
(at right) reach out to customers
through speaking engagements
and workshops on topics ranging
from the Ameren Illinois Utilities’
energy efficiency programs to
safety. Also supporting our safety
messages is Ameren’s Safety
Spokesbug, Louie the Lighting
Bug (far left), who reached almost
34,000 children in 2009.
regulated investments are unacceptably low.
Our rate cases in both states are designed to
improve those returns. We know this is a tough
time to raise utility rates, but even if we are
granted the full amounts we have requested,
customer rates would still remain below the
national average.
In our merchant generation business, our plants
are highly competitive and well-positioned in their
market. As the economy recovers, we believe
demand for power will rise, lifting power prices
and sustaining the profitability of this business.
In the meantime, we are focused on maintaining
a low-cost structure and reducing the volatility
of merchant generation segment earnings.
I personally thank you for your continued invest-
ment and trust in Ameren. Your company is
strategically poised to benefit from an economic
recovery, improved regulatory returns and
significant investment opportunities. All of us
here at Ameren are committed to Leading the
Way to a Secure Energy Future and delivering
solid value to you, our owners.
I also thank our employees for their dedication
to our vision and strategies and for incorporating
our values in everything they do.
I invite you to attend this year’s annual share-
holders meeting on April 27 at Powell Symphony
Hall in St. Louis.
Finally, our deep gratitude goes to Executive
Chairman Gary Rainwater who retires in 2010
after more than 30 years of service to our
company. Gary was the driving force behind
the creation of Ameren— a company that
now serves 2.4 million electric and nearly
one million natural gas customers— more than
double the customer base of a decade ago.
His vision and leadership will be missed. His
decades of service are appreciated.
Thomas R. Voss
President and Chief Executive Officer
Ameren Corporation
12 | 13
Financial Highlights
AMEREN CONSOLIDATED
(In millions, except per share amounts and as noted)
2009
2008
2007
Year Ended December 31,
RESULTS OF OPERATIONS
Operating revenues
Operating expenses
Operating income
Net income attributable to Ameren Corporation
COMMON STOCK DATA
Earnings per basic and diluted share
Dividends per common share
Dividend yield (year-end)
Market price per common share (year-end closing)
Shares outstanding (weighted average)
Total market value of common shares (year-end)
Book value per common share
BALANCE SHEET DATA
Property and plant, net
Total assets
Long-term debt obligations, excluding current maturities
Capitalization ratios
Common equity
Preferred stock, not subject to mandatory redemption
Debt and preferred stock subject to mandatory redemption, net of cash
OPERATING DATA
Total electric sales (kilowatthours)
Native natural gas sales (decatherms in thousands)
Total generation output (kilowatthours)
Electric customers
Natural gas customers
$7,090
$5,674
$1,416
$612
$7,839
$6,477
$1,362
$605
$2.78
$1.54
5.5%
$27.95
220.4
$6,635
$33.08
$17,610
$23,790
$7,113
50.3%
1.3%
48.4%
104,062
107,647
76,239
2.4
0.9
$2.88
$2.54
7.6%
$33.26
210.1
$7,062
$32.80
$16,567
$22,671
$6,554
45.9%
1.3%
52.8%
107,754
119,712
80,859
2.4
0.9
$7,562
$6,203
$1,359
$618
$2.98
$2.54
4.7%
$54.21
207.4
$11,294
$32.41
$15,069
$20,752
$5,689
48.2%
1.4%
50.4%
107,486
107,871
81,367
2.4
1.0
Electrical Generating Capacity
(Expected for 2010 summer peak)
6,400
megawatts generating
capacity in Illinois
3,300,000
electric and natural
gas customers
Peoria
Springfield
Decatur
10,400
megawatts generating
capacity in Missouri
St. Louis
Company Headquarters
Subsidiary Headquarters
Electric Service Territory
Electric and Natural Gas
Service Territory
Ameren companies serve approximately
2.4 million electric and nearly one million natural
gas customers over 64,000 square miles in
Illinois and Missouri. The company’s service
territory includes a diverse base of residential,
commercial and large industrial customers in
both urban and rural areas. In Missouri, we
operate primarily as a traditional, rate-regulated
utility with approximately 10,400 megawatts
of generating capacity. Our Illinois operations
include rate-regulated electric and natural gas
transmission and distribution businesses, as
well as a merchant generation business with
a capacity of approximately 6,400 megawatts
of generation. Ameren’s Missouri company,
AmerenUE, is the largest electric utility in the
state, while the Illinois operations make
Ameren’s utility operations the second largest
electric distributor and one of the largest
natural gas distributors in that state.
Residential Rates
(Cents per kilowatthour at June 2009)
Capitalization
(December 31, 2009)
U.S. Average
Ameren - Illinois
AmerenUE
11.76¢
10.05 ¢
6.76 ¢
1.3%
Preferred
Stock
Commercial Rates
(Cents per kilowatthour at June 2009)
48.4%
Debt
50.3%
Equity
U.S. Average
Ameren - Illinois
AmerenUE
10.25 ¢
9.53 ¢
5.47 ¢
Source: Summer 2009 EEI Typical Bills and Average Rates Report
14 | 15
Ameren Corporation and Subsidiaries Officers and Directors
ExECUTIVE LEADERSHIP TEAM
Gary L. Rainwater
Executive Chairman
Thomas R. Voss
President and
Chief Executive Officer
Warner L. Baxter*
Chairman, President and
Chief Executive Officer,
AmerenUE
Scott A. Cisel*
Chairman, President and Chief
Executive Officer, AmerenCILCO,
AmerenCIPS and AmerenIP
OTHER OFFICERS
Lynn M. Barnes*
Vice President, Business Planning
and Controller, AmerenUE
Jerre E. Birdsong
Vice President and Treasurer
Mark C. Birk*
Vice President,
Power Operations, AmerenUE
Maureen A. Borkowski*
Vice President, Transmission,
Ameren Services
S. Mark Brawley*
Vice President, Internal Audit,
Ameren Services
Kevin DeGraw*
Vice President, Corporate
Project Risk Management,
Ameren Services
Fadi Diya*
Vice President,
Nuclear Operations, AmerenUE
Scott A. Glaeser*
Vice President, Technical
Services, AmerenCILCO,
AmerenCIPS and AmerenIP
BOARD OF DIRECTORS
Stephen F. Brauer 1, 2
Chairman and Chief
Executive Officer, Hunter
Engineering Company
Susan S. Elliott 2, 6
Chairman and Chief Executive
Officer, Systems Service
Enterprises, Inc.
Ellen M. Fitzsimmons 2, 4
Senior Vice President of Law
and Public Affairs, General
Counsel and Corporate
Secretary, CSX Corporation
Daniel F. Cole*
Chairman, President and
Chief Executive Officer,
Ameren Services
Charles D. Naslund*
Chairman, President and Chief
Executive Officer, Ameren Energy
Resources; Chairman and
President, Ameren Energy
Generating Company
Karen C. Foss*
Senior Vice President,
Communications and
Brand Management,
Ameren Services
Mary P. Heger*
Vice President, Information
Technology and Ameren Services
Center, Ameren Services
Christopher A. Iselin*
Vice President, Generation
Technical Services,
Ameren Energy Resources
Stephen M. Kidwell*
Vice President,
Regulatory Affairs, AmerenUE
Mark C. Lindgren*
Vice President, Human
Resources, Ameren Services
Michael L. Menne*
Vice President,
Environmental Safety and Health,
Ameren Services
Donald M. Mosier*
Vice President,
Ameren Energy Marketing
Michael G. Mueller*
President, Ameren Energy
Fuels and Services
Adam C. Heflin*
Senior Vice President and
Chief Nuclear Officer,
AmerenUE
Martin J. Lyons, Jr.
Senior Vice President
and Chief Financial Officer
Richard J. Mark*
Senior Vice President,
Customer Operations,
AmerenUE
Michael L. Moehn*
Senior Vice President, Corporate
Planning and Business Risk
Management, Ameren Services
Andrew M. Serri*
President and Chief Executive
Officer, Ameren Energy Marketing
Steven R. Sullivan
Senior Vice President, General
Counsel and Secretary
Robert K. Neff*
Vice President, Coal Supply
and Transportation,
Ameren Energy Fuels and
Services
Craig D. Nelson*
Senior Vice President, Regulatory
Affairs and Financial Services,
AmerenCILCO, AmerenCIPS
and AmerenIP
Gregory L. Nelson*
Vice President and Tax Counsel,
Ameren Services
Stan E. Ogden*
Vice President, Customer
Service and Public Relations,
AmerenCILCO, AmerenCIPS
and AmerenIP
Ronald D. Pate*
Vice President, Regional
Operations, AmerenCILCO,
AmerenCIPS and AmerenIP
Joseph M. Power*
Vice President, Federal
Legislative and Regulatory
Affairs, Ameren Services
Cleveland O. Reasoner*
Vice President, Engineering,
Callaway Nuclear Plant,
AmerenUE
David J. Schepers*
Vice President, Energy
Delivery Technical Services,
AmerenUE
Shawn E. Schukar*
Vice President, Strategic
Initiatives, Ameren Services
James A. Sobule*
Vice President and
Deputy General Counsel,
Ameren Services
Bruce A. Steinke
Vice President and Controller
David N. Wakeman*
Vice President, Energy Delivery-
Distribution Services, AmerenUE
Dennis W. Weisenborn*
Vice President, Supply Services,
Ameren Services
D. Scott Wiseman*
Vice President, Regulatory Affairs,
AmerenCILCO, AmerenCIPS
and AmerenIP
Dr. Gayle P. W. Jackson 5, 6
President, Energy Global, Inc.
Harvey Saligman 3, 4
Partner, Cynwyd Investments
1 Member of Finance Committee
2 Member of Audit and Risk Committee
James C. Johnson 3, 4
Retired Vice President and
Assistant General Counsel,
Commercial Airplanes,
The Boeing Company
Charles W. Mueller 1, 5, 6
Retired Chairman and
Chief Executive Officer,
Ameren Corporation
Douglas R. Oberhelman 2, 4
Vice Chairman and CEO-Elect,
Caterpillar Inc.
3 Member of Human Resources
Committee
4 Member of Nominating and Corporate
Governance Committee
5 Member of Public Policy Committee
6 Member of Nuclear Oversight
Committee
7 Lead Director
Patrick T. Stokes 3, 4, 7
Former Chairman, Anheuser-
Busch Companies, Inc.
Thomas R. Voss
President and Chief Executive
Officer, Ameren Corporation
Stephen R. Wilson 2, 6
President and Chief
Executive Officer,
CF Industries Holdings, Inc.
Jack D. Woodard 5, 6
Retired Executive Vice
President and Chief Nuclear
Officer, Southern Nuclear
Operating Company, Inc.
Walter J. Galvin 1, 3
Vice Chairman,
Emerson Electric Co.
Gary L. Rainwater
Executive Chairman,
Ameren Corporation
* Officer of an Ameren Corporation subsidiary only
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(X) Annual report pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
for the fiscal year ended December 31, 2009
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;
State of Incorporation;
Address and Telephone Number
Ameren Corporation
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
Union Electric Company
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
Central Illinois Public Service Company
(Illinois Corporation)
607 East Adams Street
Springfield, Illinois 62739
(888) 789-2477
Ameren Energy Generating Company
(Illinois Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
Central Illinois Light Company
(Illinois Corporation)
300 Liberty Street
Peoria, Illinois 61602
(309) 677-5271
Illinois Power Company
(Illinois Corporation)
370 South Main Street
Decatur, Illinois 62523
(217) 424-6600
Commission
File Number
1-14756
1-2967
1-3672
333-56594
1-2732
1-3004
IRS Employer
Identification No.
43-1723446
43-0559760
37-0211380
37-1395586
37-0211050
37-0344645
Securities Registered Pursuant to Section 12(b) of the Securities Exchange Act of 1934:
The following securities are registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and are listed
on the New York Stock Exchange:
Registrant
Title of each class
Ameren Corporation
Common Stock, $0.01 par value per share
Securities Registered Pursuant to Section 12(g) of the Securities Exchange Act of 1934:
Registrant
Title of each class
Union Electric Company
Central Illinois Public Service Company
Central Illinois Light Company
Preferred Stock, cumulative, no par value,
stated value $100 per share:
$4.56 Series
$4.00 Series
$4.50 Series
$3.50 Series
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
Preferred Stock, cumulative, $100 par value per share:
4.50% Series
Ameren Energy Generating Company and Illinois Power Company do not have securities registered under either
Section 12(b) or 12(g) of the Securities Exchange Act of 1934.
Indicate by checkmark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
of 1933.
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
Central Illinois Light Company
Illinois Power Company
Yes
(X)
(X)
Yes
Yes ( )
Yes ( )
Yes ( )
Yes ( )
No
No
No
No
No
No
( )
( )
(X)
(X)
(X)
(X)
Indicate by checkmark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Securities Exchange Act of 1934.
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
Central Illinois Light Company
Illinois Power Company
Yes ( )
Yes ( )
Yes ( )
Yes ( )
Yes ( )
Yes ( )
No
No
No
No
No
No
(X)
(X)
(X)
(X)
(X)
(X)
Indicate by checkmark 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.
(X)
(X)
(X)
(X)
(X)
(X)
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
Central Illinois Light Company
Illinois Power Company
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
No
No
No
( )
( )
( )
( )
( )
( )
Indicate by checkmark 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
Central Illinois Light Company
Illinois Power Company
Indicate by checkmark whether each registrant has submitted electronically and posted on its corporate Web site, if
any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the
preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
( )
(X)
(X)
(X)
(X)
(X)
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
Central Illinois Light Company
Illinois Power Company
Indicate by checkmark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer
Yes
(X)
Yes ( )
Yes ( )
Yes ( )
Yes ( )
Yes ( )
No ( )
No ( )
No ( )
No ( )
No ( )
No ( )
or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting
company” in Rule 12b-2 of the Securities Exchange Act of 1934.
Smaller
Reporting
Company
( )
Ameren Corporation
( )
Union Electric Company
( )
Central Illinois Public Service Company
( )
Ameren Energy Generating Company
( )
Central Illinois Light Company
Illinois Power Company
( )
Indicate by checkmark whether each registrant is a shell company (as defined in Rule 12b-2 of the Securities
Large
Accelerated
Filer
(X)
( )
( )
( )
( )
( )
Non-
accelerated
Filer
( )
(X)
(X)
(X)
(X)
(X)
Accelerated
Filer
( )
( )
( )
( )
( )
( )
Exchange Act of 1934).
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
Central Illinois Light Company
Illinois Power Company
As of June 30, 2009, Ameren Corporation had 214,228,275 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 nonaffiliates was $5,332,141,765. The shares of common stock of the other
registrants were held by affiliates as of June 30, 2009.
Yes ( )
Yes ( )
Yes ( )
Yes ( )
Yes ( )
Yes ( )
No
No
No
No
No
No
(X)
(X)
(X)
(X)
(X)
(X)
The number of shares outstanding of each registrant’s classes of common stock as of January 29, 2010, was as follows:
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
Central Illinois Light Company
Illinois Power Company
Common stock, $0.01 par value per share: 237,503,643
Common stock, $5 par value per share, held by Ameren
Corporation (parent company of the registrant): 102,123,834
Common stock, no par value, held by Ameren Corporation (parent
company of the registrant): 25,452,373
Common stock, no par value, held by Ameren Energy Resources
Company, LLC (parent company of the registrant and subsidiary of
Ameren Corporation): 2,000
Common stock, no par value, held by CILCORP Inc. (parent
company of the registrant and subsidiary of Ameren Corporation):
13,563,871
Common stock, no par value, held by Ameren Corporation (parent
company of the registrant): 23,000,000
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement of Ameren Corporation and portions of the definitive information statements
of Union Electric Company, Central Illinois Public Service Company, and Central Illinois Light Company for the 2010
annual meetings of shareholders are incorporated by reference into Part III of this Form 10-K.
OMISSION OF CERTAIN INFORMATION
Ameren Energy Generating Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-
K and is 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, Central Illinois Light Company, and Illinois Power 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.
TABLE OF CONTENTS
Page
GLOSSARY OF TERMS AND ABBREVIATIONS ....................................................................................................................
Forward-looking Statements .....................................................................................................................................................
1
3
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Business ............................................................................................................................................................
4
General .....................................................................................................................................................
4
Business Segments ..................................................................................................................................
5
Rates and Regulation................................................................................................................................
5
Supply for Electric Power ..........................................................................................................................
7
9
Fuel for Power Generation ........................................................................................................................
Natural Gas Supply for Distribution ........................................................................................................... 11
Industry Issues .......................................................................................................................................... 12
Operating Statistics ................................................................................................................................... 13
Available Information................................................................................................................................. 15
Risk Factors ....................................................................................................................................................... 15
Unresolved Staff Comments .............................................................................................................................. 21
Properties ........................................................................................................................................................... 21
Legal Proceedings ............................................................................................................................................. 23
Submission of Matters to a Vote of Security Holders ......................................................................................... 24
Executive Officers of the Registrants (Item 401(b) of Regulation S-K) .................................................................................. 24
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities ...............................................................................................................................................................
Selected Financial Data .........................................................................................................................................
Management’s Discussion and Analysis of Financial Condition and Results of Operations ..................................
Overview .......................................................................................................................................................
Results of Operations....................................................................................................................................
Liquidity and Capital Resources....................................................................................................................
Outlook ..........................................................................................................................................................
Regulatory Matters ........................................................................................................................................
Accounting Matters .......................................................................................................................................
Effects of Inflation and Changing Prices .......................................................................................................
Quantitative and Qualitative Disclosures About Market Risk .................................................................................
Financial Statements and Supplementary Data .....................................................................................................
Selected Quarterly Information ....................................................................................................................
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ................................
26
28
29
29
31
49
64
70
70
72
72
78
177
178
Item 9.
Item 9A and
Item 9A(T). Controls and Procedures .......................................................................................................................................
Item 9B.
Other Information ...................................................................................................................................................
178
178
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Directors, Executive Officers and Corporate Governance .................................................................................. 179
179
Executive Compensation ......................................................................................................................................
180
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters ..............
180
Certain Relationships and Related Transactions and Director Independence ......................................................
180
Principal Accountant Fees and Services ...............................................................................................................
PART IV
Item 15.
Exhibits and Financial Statement Schedules ........................................................................................................
SIGNATURES .............................................................................................................................................................................
EXHIBIT INDEX ...........................................................................................................................................................................
181
185
191
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
on pages 3 and 4 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.
GLOSSARY OF TERMS AND ABBREVIATIONS
We use the words “our,” “we” or “us” with respect to certain information that relates to all Ameren Companies, as defined
below. When appropriate, subsidiaries of Ameren are named specifically as we discuss their various business activities.
2007 Illinois Electric Settlement Agreement – A
comprehensive settlement of issues in Illinois arising out of
the end of ten years of frozen electric rates, effective
January 2, 2007. The settlement, which became effective on
August 28, 2007, was designed to avoid new rate rollback
and freeze legislation and legislation that would impose a tax
on electric generation in Illinois. The settlement addressed
the issue of power procurement, and it included a
comprehensive rate relief and customer assistance program.
AERG – AmerenEnergy Resources Generating Company, a
CILCO subsidiary that operates a merchant electric
generation business in Illinois.
AFS – Ameren Energy Fuels and Services Company, a
Resources Company subsidiary that procures fuel and
natural gas and manages the related risks for the Ameren
Companies.
AITC – Ameren Illinois Transmission Company, an Ameren
Corporation subsidiary that is engaged in the construction
and operation of transmission assets in Illinois and is
regulated by the ICC.
Ameren – Ameren Corporation and its subsidiaries on a
consolidated basis. In references to financing activities,
acquisition activities, or liquidity arrangements, Ameren is
defined as Ameren Corporation, the parent.
Ameren Companies – The individual registrants within the
Ameren consolidated group.
Ameren Illinois Utilities – CIPS, IP, and the rate-regulated
electric and natural gas utility operations of CILCO.
Ameren Services – Ameren Services Company, an Ameren
Corporation subsidiary that provides support services to
Ameren and its subsidiaries.
AMIL – The balancing authority area operated by Ameren,
which includes the load of the Ameren Illinois Utilities and the
generating assets of Genco and AERG.
AMMO – The balancing authority area operated by Ameren,
which includes the load and generating assets of UE.
AMT – Alternative minimum tax.
ARO – Asset retirement obligations.
Baseload – The minimum amount of electric power delivered
or required over a given period of time at a steady rate.
Btu – British thermal unit, a standard unit for measuring the
quantity of heat energy required to raise the temperature of
one pound of water by one degree Fahrenheit.
Capacity factor – A percentage measure that indicates how
much of an electric power generating unit’s capacity was
used during a specific period.
CILCO – Central Illinois Light Company, a CILCORP
subsidiary that operates a rate-regulated electric
transmission and distribution business, a merchant electric
generation business through AERG, and a rate-regulated
natural gas transmission and distribution business, all in
Illinois, as AmerenCILCO. CILCO owns all of the common
stock of AERG.
CILCORP – CILCORP Inc., an Ameren Corporation
subsidiary that operates as a holding company for CILCO
and its merchant generation subsidiary. CILCORP ceased
filing periodic and current reports with the SEC under the
Exchange Act as a result of the covenant defeasance of its
remaining outstanding senior bonds.
CIPS – Central Illinois Public Service Company, an Ameren
Corporation subsidiary that operates a rate-regulated electric
and natural gas transmission and distribution business in
Illinois as AmerenCIPS.
CIPSCO – CIPSCO Inc., the former parent of CIPS.
CO 2 – Carbon dioxide.
COLA – Combined nuclear plant construction and operating
license application.
Cooling degree-days – The summation of positive
differences between the mean daily temperature and a 65-
degree Fahrenheit base. This statistic is useful for estimating
electricity demand by residential and commercial customers
for summer cooling.
CT – Combustion turbine electric generation equipment used
primarily for peaking capacity.
Development Company – Ameren Energy Development
Company, which was an Ameren Energy Resources
Company subsidiary and parent of Genco, Marketing
Company, AFS, and Medina Valley. It was eliminated in an
internal reorganization in February 2008.
DOE – Department of Energy, a U.S. government agency.
DRPlus – Ameren Corporation’s dividend reinvestment and
direct stock purchase plan.
Dth (dekatherm) – One million Btus of natural gas.
EEI – Electric Energy, Inc., an 80%-owned Ameren
Corporation subsidiary that operates merchant electric
generation facilities and FERC-regulated transmission
facilities in Illinois. Prior to February 29, 2008, EEI was 40%
owned by UE and 40% owned by Development Company.
On February 29, 2008, UE’s 40% ownership interest and
Development Company’s 40% ownership interest were
transferred to Resources Company. The remaining 20% is
owned by Kentucky Utilities Company, a nonaffiliated entity.
Effective January 1, 2010, in an internal reorganization,
Resources Company contributed its 80% ownership interest
in EEI to its subsidiary, Genco.
EPA – Environmental Protection Agency, a U.S. government
agency.
Equivalent availability factor – A measure that indicates
the percentage of time an electric power generating unit was
available for service during a period.
ERISA – Employee Retirement Income Security Act of 1974,
as amended.
Exchange Act – Securities Exchange Act of 1934, as
amended.
FAC – A fuel and purchased power cost recovery mechanism
that allows UE to recover, through customer rates, 95% of
changes in fuel (coal, coal transportation, natural gas for
generation, and nuclear) and purchased
1
power costs, net of off-system revenues, including MISO
costs and revenues, greater or less than the amount set in
base rates, without a traditional rate proceeding.
FASB – Financial Accounting Standards Board, a rulemaking
organization that establishes financial accounting and
reporting standards in the United States.
FERC – The Federal Energy Regulatory Commission, a U.S.
government agency.
Fitch – Fitch Ratings, a credit rating agency.
FTRs – Financial transmission rights, financial instruments
that entitle the holder to pay or receive compensation for
certain congestion-related transmission charges between two
designated points.
Fuelco – Fuelco LLC, a limited-liability company that
provides nuclear fuel management and services to its
members. The members are UE, Luminant, and Pacific Gas
and Electric Company.
GAAP – Generally accepted accounting principles in the
United States of America.
Genco – Ameren Energy Generating Company, a Resources
Company subsidiary that operates a merchant electric
generation business in Illinois and Missouri.
Gigawatthour – One thousand megawatthours.
Heating degree-days – The summation of negative
differences between the mean daily temperature and a 65-
degree 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, a
labor union.
ICC – Illinois Commerce Commission, a state agency that
regulates Illinois utility businesses, including the rate-
regulated operations of CIPS, CILCO and IP.
Illinois Customer Choice Law – Illinois Electric Service
Customer Choice and Rate Relief Law of 1997, which
provided for electric utility restructuring and was designed to
introduce competition into the retail supply of electric energy
in Illinois.
Illinois EPA – Illinois Environmental Protection Agency, a
state government agency.
Illinois Regulated – A financial reporting segment consisting
of the regulated electric and natural gas transmission and
distribution businesses of CIPS, CILCO, IP and AITC.
IP – Illinois Power Company, an Ameren Corporation
subsidiary. IP operates a rate-regulated electric and natural
gas transmission and distribution business in Illinois as
AmerenIP.
IP LLC – Illinois Power Securitization Limited Liability
Company, which was a special-purpose Delaware limited-
liability company. It was dissolved in February 2009 because
the remaining TFNs, with respect to which this entity was
created, were redeemed by IP in September 2008.
IP SPT – Illinois Power Special Purpose Trust, which was
created as a subsidiary of IP LLC to issue TFNs as allowed
under the Illinois Customer Choice Law. It was dissolved in
February 2009 because the remaining TFNs were redeemed
by IP in September 2008.
IPA – Illinois Power Agency, a state government agency that
has broad authority to assist in the procurement of electric
power for residential and nonresidential customers.
ISRS – Infrastructure system replacement surcharge. A cost
recovery mechanism in Missouri that allows UE to recover
gas infrastructure replacement costs from utility customers
without a traditional rate case.
IUOE – International Union of Operating Engineers, a labor
union.
Kilowatthour – A measure of electricity consumption
equivalent to the use of 1,000 watts of power over a period of
one hour.
MACT – Maximum Achievable Control Technology.
Marketing Company – Ameren Energy Marketing Company,
a Resources Company subsidiary that markets power for
Genco, AERG, EEI and Medina Valley.
Medina Valley – AmerenEnergy Medina Valley Cogen LLC,
a Resources Company subsidiary, which owns a 40-
megawatt gas-fired electric generation plant.
Megawatthour – One thousand kilowatthours.
Merchant Generation – A financial reporting segment
consisting primarily of the operations or activities of Genco,
the CILCORP parent company, AERG, EEI, Medina Valley,
and Marketing Company.
MGP – Manufactured gas plant.
MISO – Midwest Independent Transmission System
Operator, Inc., an RTO.
MISO Energy and Operating Reserves Market – A market
that uses market-based pricing, incorporating transmission
congestion and line losses, to compensate market
participants for power and ancillary services.
Missouri Environmental Authority – Environmental
Improvement and Energy Resources Authority of the state of
Missouri, a governmental body authorized to finance
environmental projects by issuing tax-exempt bonds and
notes.
Missouri Regulated – A financial reporting segment
consisting of UE’s rate-regulated businesses.
Mmbtu – One million Btus.
Money pool – Borrowing agreements among Ameren and its
subsidiaries to coordinate and provide for certain short-term
cash and working capital requirements. Separate money
pools maintained for rate-regulated and non-rate-regulated
business are referred to as the utility money pool and the
non-state-regulated subsidiary money pool, respectively.
Moody’s – Moody’s Investors Service Inc., a credit rating
agency.
MoPSC – Missouri Public Service Commission, a state
agency that regulates Missouri utility businesses, including
the rate-regulated operations of UE.
MPS – Multi-Pollutant Standard, an agreement, as amended,
reached in 2006 among Genco, CILCO (AERG), EEI and the
Illinois EPA, which was codified in Illinois environmental
regulations.
MTM – Mark-to-market.
MW – Megawatt.
Native load – Wholesale customers and end-use retail
customers, whom we are obligated to serve by statute,
franchise, contract, or other regulatory requirement.
2
NCF&O – National Congress of Firemen and Oilers, a labor
union.
NO x – Nitrogen oxide.
Noranda – Noranda Aluminum, Inc.
NPNS – Normal purchases and normal sales.
NRC – Nuclear Regulatory Commission, a U.S. government
agency.
NSR – New Source Review provisions of the Clean Air Act.
NYMEX – New York Mercantile Exchange.
NYSE – New York Stock Exchange, Inc.
OATT – Open Access Transmission Tariff.
OCI – Other comprehensive income (loss) as defined by
GAAP.
Off-system revenues – Revenues from other than native
load sales.
OTC – Over-the-counter.
PGA – Purchased Gas Adjustment tariffs, which allow the
passing through of the actual cost of natural gas to utility
customers.
PJM – PJM Interconnection LLC.
PUHCA 2005 – The Public Utility Holding Company Act of
2005, enacted as part of the Energy Policy Act of 2005,
effective February 8, 2006.
Regulatory lag – Adjustments to retail electric and natural
gas rates are based on historic cost and revenue levels. Rate
increase requests can take up to 11 months to be acted upon
by the MoPSC and the ICC. As a result, revenue increases
authorized by regulators will lag behind changing costs and
revenue.
Resources Company – Ameren Energy Resources
Company, LLC, an Ameren Corporation subsidiary that
consists of non-rate-regulated operations, including Genco,
Marketing Company, EEI, AFS, and Medina Valley. It is the
successor to Ameren Energy Resources Company, which
was eliminated in an internal reorganization in February
2008.
RFP – Request for proposal.
RTO – Regional Transmission Organization.
S&P – Standard & Poor’s Ratings Services, a credit rating
agency that is a division of The McGraw-Hill Companies, Inc.
SEC – Securities and Exchange Commission, a U.S.
government agency.
SERC – SERC Reliability Corporation, one of the regional
electric reliability councils organized for coordinating the
planning and operation of the nation’s bulk power supply.
SO 2 – Sulfur dioxide.
TFN – Transitional Funding Trust Notes issued by IP SPT as
allowed under the Illinois Customer Choice Law. IP
designated a portion of cash received from customer billings
to pay the TFNs. The designated funds received by IP were
remitted to IP SPT. The designated funds were restricted for
the sole purpose of making payments of principal and interest
on, and paying other fees and expenses related to, the TFNs.
After the implementation of authoritative accounting guidance
on the consolidation of variable-interest entities, IP did not
consolidate IP SPT. In September 2008, IP redeemed the
remaining TFNs.
TVA – Tennessee Valley Authority, a public power authority.
3
UE – Union Electric Company, an Ameren Corporation
subsidiary that operates a rate-regulated electric generation,
transmission and distribution business, and a rate-regulated
natural gas transmission and distribution business in Missouri
as AmerenUE.
VIE – Variable-interest entity.
FORWARD-LOOKING STATEMENTS
Statements in this report not based on historical facts are
considered “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 under Risk
Factors and elsewhere in this report and in our other filings
with the SEC, could cause actual results to differ materially
from management expectations suggested in such forward-
looking statements:
regulatory or legislative actions, including changes in
regulatory policies and ratemaking determinations, such
as the outcome of pending UE, CIPS, CILCO and IP rate
proceedings, and future rate proceedings or legislative
actions that seek to limit or reverse rate increases;
the effects of, or changes to, the Illinois power
procurement process;
changes in laws and other governmental actions,
including monetary and fiscal policies;
changes in laws or regulations that adversely affect the
ability of electric distribution companies and other
purchasers of wholesale electricity to pay their suppliers,
including UE and Marketing Company;
the effects of increased competition in the future due to,
among other things, deregulation of certain aspects of our
business at both the state and federal levels, and the
implementation of deregulation, such as occurred when
the electric rate freeze and power supply contracts
expired in Illinois at the end of 2006;
the effects on demand for our services resulting from
technological advances, including advances in energy
efficiency and distributed generation sources, which
generate electricity at the site of consumption;
increasing capital expenditure and operating expense
requirements and our ability to recover these costs in a
timely fashion in light of regulatory lag;
the effects of participation in the MISO;
the cost and availability of fuel such as coal, natural gas,
and enriched uranium used to produce electricity; the cost
and availability of purchased power and natural
gas for distribution; and the level and volatility of future
market prices for such commodities, including the ability
to recover the costs for such commodities;
the effectiveness of our risk management strategies and
the use of financial and derivative instruments;
prices for power in the Midwest, including forward prices;
business and economic conditions, including their impact
on interest rates, bad debt expense, and demand for our
products;
disruptions of the capital markets or other events that
make the Ameren Companies’ access to necessary
capital, including short-term credit and liquidity,
impossible, more difficult, or more costly;
our assessment of our liquidity;
the impact of the adoption of new accounting guidance
and the application of appropriate technical accounting
rules and guidance;
actions of credit rating agencies and the effects of such
actions;
the impact of weather conditions and other natural
phenomena on us and our customers;
the impact of system outages;
generation plant construction, installation and
performance;
the recovery of costs associated with UE’s Taum Sauk
pumped-storage hydroelectric plant incident and
investment in a COLA for a second unit at its Callaway
nuclear plant;
impairments of long-lived assets or goodwill;
operation of UE’s nuclear power facility, including planned
and unplanned outages, and decommissioning costs;
the effects of strategic initiatives, including mergers,
acquisitions and divestitures;
the impact of current environmental regulations on utilities
and power generating companies and the expectation
that more stringent requirements, including those related
to greenhouse gases and energy efficiency, will be
enacted over time, which could limit, or terminate, the
operation of certain of our generating units, increase our
costs, reduce our customers’ demand for electricity or
natural gas, or otherwise have a negative financial effect;
labor disputes, work force reductions, future wage and
employee benefits costs, including changes in discount
rates and returns on benefit plan assets;
the inability of our counterparties and affiliates to meet
their obligations with respect to contracts, credit facilities
and financial instruments;
the cost and availability of transmission capacity for the
energy generated by the Ameren Companies’ facilities or
required to satisfy energy sales made by the Ameren
Companies;
legal and administrative proceedings; and
acts of sabotage, war, terrorism, or intentionally disruptive
acts.
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 update or revise publicly any forward-looking
statements to reflect new information or future events.
PART I
ITEM 1. BUSINESS.
GENERAL
Ameren, headquartered in St. Louis, Missouri, is a public
utility holding company under PUHCA 2005 administered by
FERC. Ameren was formed in 1997 by the merger of UE and
CIPSCO. Ameren acquired CILCORP in 2003 and IP in
2004. Ameren’s primary assets are the common stock of its
subsidiaries, including UE, CIPS, Genco, CILCO and IP.
Ameren’s subsidiaries are separate, independent legal
entities with separate businesses, assets, and liabilities.
These subsidiaries operate, as the case may be, rate-
regulated electric generation, transmission, and distribution
businesses, rate-regulated natural gas transmission and
distribution businesses, and merchant generation businesses
in Missouri and Illinois. Dividends on Ameren’s common
stock and the payment of other expenses by Ameren depend
on distributions made to it by its subsidiaries.
As part of an internal reorganization, Resources
Company transferred its 80% ownership interest in EEI to
Genco, through a capital contribution, on January 1, 2010.
The following table presents our total employees at
December 31, 2009:
Ameren(a) .....................................................................................................................................................................................
9,780
UE ...............................................................................................................................................................................................
4,425
CIPS .............................................................................................................................................................................................
657
Genco ...........................................................................................................................................................................................
553
CILCO ..........................................................................................................................................................................................
1,183
IP ............................................................................................ 1,132
(a) Total for Ameren includes Ameren registrant and nonregistrant
subsidiaries.
As of January 1, 2010, the IBEW, the IUOE, the NCF&O
and the Laborers and Gas Fitters labor unions collectively
represented about 59% of Ameren’s total employees. They
represented 64% of the employees at UE, 83% at CIPS, 72%
at Genco, 38% at CILCO, and 90% at IP. All collective
bargaining agreements that expired in 2009 have been
renegotiated and ratified. Most of the collective bargaining
agreements have three- to five-year terms, and expire
between 2011 and 2013.
4
In 2009, Ameren initiated a voluntary separation program
that provided eligible management employees the
opportunity to voluntarily terminate their employment and
receive benefits consistent with Ameren’s standard
management severance program. This program was offered
to eligible management employees at Ameren’s subsidiaries,
including UE, CIPS, Genco, CILCO and IP. Additionally,
Ameren initiated an involuntary separation program to reduce
additional management positions under terms and benefits
consistent with Ameren’s standard management severance
program. In the third quarter of 2009, Genco announced
operational changes and staff reductions at three of its
generating facilities. The affected three plants were the
Meredosia, Grand Tower, and Hutsonville plants. In addition,
Genco retired two of the four units at its Meredosia plant. The
Grand Tower plant will be operated seasonally from May
through September; a very limited staff will maintain the plant
during the other months. The number of positions eliminated
as a result of these separation programs and operational
changes was approximately 300.
For additional information about the development of our
businesses, our business operations, and factors affecting
our operations and financial position, 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 under Part II,
Item 8, of this report.
BUSINESS SEGMENTS
Ameren has three reportable segments: Missouri
Regulated, Illinois Regulated, and Merchant Generation.
CILCO has two reportable segments: Illinois Regulated and
Merchant Generation. See Note 18 – Segment Information
under Part II, Item 8, of this report for additional information
on reporting segments.
RATES AND REGULATION
Rates
The rates that UE, CIPS, CILCO and IP are allowed to
charge for their utility services significantly influence the
results of operations, financial position, and liquidity of these
companies and Ameren. The electric and natural gas utility
industry is highly regulated. The utility rates charged to UE,
CIPS, CILCO and IP customers are determined, in large part,
by governmental entities, including the MoPSC, the ICC, and
FERC. Decisions by these entities are influenced by many
factors, including the cost of providing service, the prudency
of expenditures, the quality of service, regulatory staff
knowledge and experience, economic conditions, public
policy, and social and political views, and are largely outside
of our control. Decisions made by these governmental
entities regarding rates, as well as the regulatory lag involved
in filing and getting new rates approved, could have a
material impact on the results of operations, financial
position, and liquidity of Ameren, UE, CIPS, CILCO and IP.
The ICC regulates rates and other matters for CIPS,
CILCO and IP. The MoPSC regulates rates and other matters
for UE. The FERC regulates UE, CIPS, Genco, CILCO and
IP as to their ability to charge market-based rates for the sale
and transmission of energy in interstate commerce and
various other matters discussed below under General
Regulatory Matters.
About 38% of Ameren’s electric and 14% of its gas
operating revenues were subject to regulation by the MoPSC
in the year ended December 31, 2009. About 39% of
Ameren’s electric and 86% of its gas operating revenues
were subject to regulation by the ICC in the year ended
December 31, 2009. Wholesale revenues for UE, Genco and
AERG are subject to FERC regulation, but not subject to
direct MoPSC or ICC regulation.
Missouri Regulated
Electric
About 83% of UE’s electric operating revenues were
subject to regulation by the MoPSC in the year ended
December 31, 2009. Effective March 1, 2009, as a result of a
MoPSC electric rate order issued in January 2009, UE’s retail
electric rates include a FAC for billing adjustments for
changes in prudently incurred fuel and purchased power
costs.
FERC regulates the rates charged and the terms and
conditions for electric transmission services. Each RTO
separately files regional transmission tariff rates for approval
by FERC. All members within that RTO are then subjected to
those rates. As a member of MISO, UE’s transmission rate is
calculated in accordance with MISO’s rate formula. The
transmission rate is updated in June of each year based on
FERC filings. This rate is charged directly to wholesale
customers. This rate is not directly charged to Missouri retail
customers because the MoPSC includes transmission-
related costs in setting bundled retail rates in Missouri.
Natural Gas
All of UE’s natural gas operating revenues were subject
to regulation by the MoPSC in the year ended December 31,
2009.
If certain criteria are met, UE’s natural gas rates may be
adjusted without a traditional rate proceeding. PGA clauses
permit prudently incurred natural gas costs to be passed
directly to the consumer. The ISRS also permits prudently
incurred natural gas infrastructure replacement costs to be
passed directly to the consumer.
As part of a 2007 stipulation and agreement approved by
the MoPSC that authorized an increase in annual natural gas
delivery revenues of $6 million effective April 1, 2007, UE
agreed not to file a natural gas delivery rate case before
March 15, 2010. This agreement did not prevent UE from
filing to recover gas infrastructure replacement costs through
an ISRS during this three-year rate moratorium. Since April 1,
2007, the MoPSC has approved three separate requests
from UE for an ISRS to recover annual revenues of $3
million, in the aggregate. These surcharges remain in place
until new rates go into effect.
5
For additional information on Missouri rate matters,
including UE’s pending electric rate case and UE’s 2009
electric rate order, see Results of Operations and Outlook in
Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7,
Quantitative and Qualitative Disclosures About Market Risk
under Part II, Item 7A, and Note 2 – Rate and Regulatory
Matters, and Note 15 – Commitments and Contingencies
under Part II, Item 8, of this report.
Illinois Regulated
The following table presents the approximate percentage
of electric and natural gas operating revenues subject to
regulation by the ICC for each of the Illinois Regulated
companies for the year ended December 31, 2009:
Electric
100%
CIPS ................................................................
41
CILCO(a) ..........................................................
100
IP ..................................................................
(a) AERG’s revenues are not subject to ICC regulation.
Natural Gas
100%
100
100
Under the Illinois Customer Choice Law, all electric
customers in Illinois may choose their own electric energy
provider. However, the Ameren Illinois Utilities are required to
serve as the provider of last resort (POLR) for electric
customers within their territory who have not chosen an
alternative retail electric supplier. The Ameren Illinois Utilities’
obligation to provide full requirements electric service,
including power supply, as a POLR varies by customer size.
The Ameren Illinois Utilities are not required to offer fixed
priced electric service to many of their largest customers with
electric demands of 400 kilowatts or greater, as this group of
customers has been declared competitive. The power
procurement costs incurred by the Ameren Illinois Utilities are
passed directly to their customers through a cost recovery
mechanism.
Environmental adjustment rate riders authorized by the
ICC permit the recovery of prudently incurred MGP
remediation and litigation costs from CIPS’, CILCO’s and IP’s
Illinois electric and natural gas utility customers. In addition,
IP has a tariff rider to recover the costs of asbestos-related
litigation claims, subject to the following terms: 90% of cash
expenditures in excess of the amount included in base
electric rates is recoverable by IP from a trust fund
established by IP. At December 31, 2009, the trust fund
balance was $23 million, including accumulated interest. If
cash expenditures are less than the amount in base rates, IP
will contribute 90% of the difference to the fund. Once the
trust fund is depleted, 90% of allowed cash expenditures in
excess of base rates will be recoverable through charges
assessed to customers under the tariff rider.
In 2009, a new law became effective in Illinois that allows
electric and natural gas utilities to recover through a rate
adjustment the difference between their actual bad debt
expense and the bad debt expense included in their base
rates. In February 2010, the ICC approved the Ameren
Illinois Utilities’ electric and natural gas rate adjustment tariffs
to recover bad debt expense not recovered in base rates.
If certain criteria are met, CIPS’, CILCO’s and IP’s
natural gas rates may be adjusted without a traditional rate
proceeding. PGA clauses permit prudently incurred natural
gas costs to be passed directly to the consumer.
FERC regulates the rates charged and the terms and
conditions for electric transmission services. Each RTO
separately files regional transmission tariff rates for approval
by FERC. All members within that RTO are then subjected to
those rates. As members of MISO, the Ameren Illinois
Utilities’ transmission rate is calculated in accordance with
MISO’s rate formula. The transmission rate is updated in
June of each year based on FERC filings. This rate is
charged directly to wholesale customers and alternative retail
electric suppliers. For retail customers who have not chosen
an alternative retail electric supplier, the transmission rate is
collected through a rider mechanism.
For additional information on Illinois rate matters,
including the currently pending electric and natural gas rate
cases, see Results of Operations and Outlook in
Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7,
Quantitative and Qualitative Disclosures About Market Risk
under Part II, Item 7A, and Note 2 – Rate and Regulatory
Matters, and Note 15 – Commitments and Contingencies
under Part II, Item 8, of this report.
Merchant Generation
Merchant Generation revenues are determined by
market conditions and contractual arrangements. We expect
the Merchant Generation fleet of assets to have 6,370
megawatts of capacity available for the 2010 peak summer
electrical demand. As discussed below, Genco, AERG and
EEI sell all of their power and capacity to Marketing Company
through power supply agreements. Marketing Company
attempts to optimize the value of those assets and mitigate
risks through a variety of hedging techniques, including
wholesale sales of capacity and energy, retail sales in the
non-rate-regulated Illinois market, spot market sales primarily
in MISO and PJM, and financial transactions. Marketing
Company enters into long-term and short-term contracts.
Marketing Company’s counterparties include cooperatives,
municipalities, commercial and industrial customers, power
marketers, MISO, and investor-owned utilities such as the
Ameren Illinois Utilities. For additional information on
Marketing Company’s hedging activities and Marketing
Company’s sales to the Ameren Illinois Utilities, see Outlook
in Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7 and
Note 7 – Derivative Financial Instruments and Note 14 –
Related Party Transactions under Part II, Item 8, of this
report.
General Regulatory Matters
UE, CIPS, CILCO and IP must receive FERC approval to
issue short-term debt securities and to conduct certain
acquisitions, mergers and consolidations involving electric
utility holding companies having a value in excess of
$10 million. In addition, these Ameren utilities must receive
authorization from the applicable state public utility regulatory
6
agency to issue stock and long-term debt securities (with
maturities of more than 12 months) and to conduct mergers,
affiliate transactions, and various other activities. Genco,
AERG and EEI are subject to FERC’s jurisdiction when they
issue any securities.
Under PUHCA 2005, FERC and any state public utility
regulatory agencies may access books and records of
Ameren and its subsidiaries that are determined to be
relevant to costs incurred by Ameren’s rate-regulated
subsidiaries with respect to jurisdictional rates. PUHCA 2005
also permits Ameren, the ICC, or the MoPSC to request that
FERC review cost allocations by Ameren Services to other
Ameren companies.
Operation of UE’s Callaway nuclear plant is subject to
regulation by the NRC. Its facility operating license expires on
June 11, 2024. UE intends to submit a license extension
application with the NRC to extend the plant’s operating
license to 2044. UE’s Osage hydroelectric plant and UE’s
Taum Sauk pumped-storage hydroelectric 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
UE’s Osage hydroelectric plant expires on March 30, 2047,
and the license for UE’s Taum Sauk plant expires on
June 30, 2010. In June 2008, UE filed an application with
FERC to relicense its Taum Sauk plant for another 40 years.
Approval and relicensure are expected in 2012. Operations
are permitted to continue under the current license while the
application for relicensing is pending. The Taum Sauk plant is
currently out of service. It is being rebuilt due to a major
breach of the upper reservoir in December 2005. UE expects
the Taum Sauk plant to become operational in the second
quarter of 2010. UE’s Keokuk plant and its dam, in the
Mississippi River between Hamilton, Illinois, and Keokuk,
Iowa, are operated under authority granted by an Act of
Congress in 1905.
For additional information on regulatory matters, see
Note 2 – Rate and Regulatory Matters and Note 15 –
Commitments and Contingencies under Part II, Item 8, of this
report, which include a discussion about the December 2005
breach of the upper reservoir at UE’s Taum Sauk pumped-
storage hydroelectric plant.
Environmental Matters
Certain of our operations are subject to federal, state,
and local environmental statutes or regulations relating to the
safety and health of personnel, the public, and the
environment. These environmental statutes and regulations
include requirements for identification, generation, storage,
handling, transportation, disposal, recordkeeping, labeling,
reporting, 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 and the management of waste and
byproduct materials. Failure to comply with those statutes or
regulations could have material adverse effects on us. We
could be subject to criminal or civil penalties by regulatory
agencies. We could be ordered to make payment to private
parties by the courts. Except as indicated in this report, we
believe that we are in material compliance with existing
statutes and regulations.
For additional discussion of environmental matters,
including NOx , SO2 , and mercury emission reduction
requirements, global climate change, remediation efforts and
UE’s receipt in January 2010 of a Notice of Violation from the
EPA alleging violations of the Clean Air Act’s NSR and New
Source Performance Standards (NSPS) provisions, see
Liquidity and Capital Resources in Management’s Discussion
and Analysis of Financial Condition and Results of
Operations under Part II, Item 7, and Note 15 –
Commitments and Contingencies under Part II, Item 8, of this
report.
SUPPLY FOR ELECTRIC POWER
Ameren owns an integrated transmission system that
comprises the transmission assets of UE, CIPS, CILCO, IP
and AITC. Ameren also operates two balancing authority
areas, AMMO (which includes UE) and AMIL (which includes
CIPS, CILCO, IP, AITC, Genco and AERG). During 2009, the
peak demand in AMMO was 8,081 MW and in AMIL was
8,607 MW. The Ameren transmission system directly
connects with 15 other balancing authority areas for the
exchange of electric energy.
UE, CIPS, CILCO and IP are transmission-owning
members of MISO. Transmission service on the UE, CIPS,
CILCO and IP transmission systems is provided pursuant to
the terms of the MISO OATT on file with FERC. EEI operates
its own balancing authority area and its own transmission
facilities in southern Illinois. The EEI transmission system is
directly connected to MISO and TVA. EEI’s generating units
are dispatched separately from those of UE, Genco and
AERG.
The Ameren Companies and EEI are members of SERC.
SERC is responsible for the bulk electric power supply
system in much of the southeastern United States, including
all or portions of Missouri, Illinois, Arkansas, Kentucky,
Tennessee, North Carolina, South Carolina, Georgia,
Mississippi, Alabama, Louisiana, Virginia, Florida, Oklahoma,
Iowa, and Texas.
See Note 2 – Rate and Regulatory Matters under Part II,
Item 8, of this report for additional information.
Missouri Regulated
UE’s electric supply is obtained primarily from its own
generation. Factors that could cause UE to purchase power
include, among other things, absence of sufficient owned
generation, plant outages, the fulfillment of renewable energy
requirements, the failure of suppliers to meet their power
supply obligations, extreme weather conditions, and the
availability of power at a cost lower than the cost of
generating it.
UE continues to evaluate its longer-term needs for new
baseload and peaking electric generation capacity. UE’s
7
integrated resource plan filed with the MoPSC in February
2008 included the expectation that new baseload
generation capacity would be required in the 2018 to 2020
time frame. Due to the significant time required to plan,
acquire permits for, and build a baseload power plant, UE
is actively studying future plant alternatives, including
energy efficiency programs that could help defer new plant
construction. UE’s 2008 integrated resource plan included
proposals to pursue energy efficiency programs, expand
the role of renewable energy sources in UE’s overall
generation mix, increase operational efficiency at existing
power plants, and possibly retire some generating units
that are older and less efficient. UE will file a new
integrated resource plan with the MoPSC in 2011.
See also Outlook in Management’s Discussion and
Analysis of Financial Condition and Results of Operations
under Part II, Item 7 and Note 2 – Rate and Regulatory
Matters and Note 15 – Commitments and Contingencies
under Part II, Item 8, of this report.
Illinois Regulated
As of January 1, 2007, CIPS, CILCO and IP were
required to obtain from market sources all electric supply
requirements for customers, except those declared
competitive, who did not purchase electric supply from
third-party suppliers. The power procurement costs
incurred by CIPS, CILCO and IP are passed directly to
their customers through a cost recovery mechanism.
In September 2006, a reverse power procurement
auction was held, as a result of which CIPS, CILCO and
IP entered into power supply contracts with the winning
bidders, including Marketing Company. Under these
contracts, the electric suppliers are responsible for
providing to CIPS, CILCO and IP energy, capacity, certain
transmission, volumetric risk management, and other
services necessary for the Ameren Illinois Utilities to serve
the electric load needs of fixed-price residential and small
commercial customers (with less than one MW of
demand) at an all-inclusive fixed price. These contracts
commenced on January 1, 2007, with one-third of the
supply contracts expiring in May 2008, 2009 and 2010.
As part of the 2007 Illinois Electric Settlement
Agreement, the reverse power procurement auction
process was discontinued and a new competitive power
procurement process led by the IPA beginning in 2009
was established. In January 2009, the ICC approved the
electric power procurement plan filed by the IPA for both
the Ameren Illinois Utilities and Commonwealth Edison
Company. The plan outlined the wholesale products that
the IPA procured on behalf of the Ameren Illinois Utilities
for the period June 1, 2009, through May 31, 2014. The
IPA procured capacity, energy swaps, and renewable
energy credits through an RFP process on behalf of the
Ameren Illinois Utilities in the second quarter of 2009. In
August 2009, the IPA submitted its plan to the ICC for
procurement of electric power for the Ameren Illinois
Utilities and Commonwealth Edison Company for the
period June 1, 2010, through May 31, 2015. The plan was
modified and approved by the ICC in December 2009. The
IPA will procure energy swaps, capacity and renewable
energy credits, and long-term renewable supply.
A portion of the electric power supply required for the
Ameren Illinois Utilities to satisfy their distribution
customers’ requirements is purchased from Marketing
Company on behalf of Genco, AERG and EEI. Also as
part of the 2007 Illinois Electric Settlement Agreement, the
Ameren Illinois Utilities entered into financial contracts
with Marketing Company (for the benefit of Genco and
AERG) to lock in energy prices for 400 to 1,000
megawatts annually of their round-the-clock power
requirements during the period June 1, 2008, through
December 31, 2012, at relevant market prices at that time.
These financial contracts do not include capacity, are not
load-following products, and do not involve the physical
delivery of energy.
See Note 2 – Rate and Regulatory Matters, Note 14 –
Related Party Transactions and Note 15 – Commitments
and Contingencies under Part II, Item 8, of this report for
additional information on power procurement in Illinois.
Merchant Generation
Genco and AERG have entered into power supply
agreements with Marketing Company whereby Genco and
AERG sell and Marketing Company purchases all the
capacity available from Genco’s and AERG’s generation
fleets and the associated energy. These power supply
agreements continue through December 31, 2022, and
from year to year thereafter unless either party elects to
terminate the agreement by providing the other party with
no less than six months advance written notice. EEI and
Marketing Company have entered into a power supply
agreement for EEI to sell all of its capacity and energy to
Marketing Company. This agreement expires on
December 31, 2015. All of Genco’s, AERG’s and EEI’s
generating facilities compete for the sale of energy and
capacity in the competitive energy markets through
Marketing Company. See Note 14 – Related Party
Transactions under Part II, Item 8, of this report for
additional information.
Factors that could cause Marketing Company to
purchase power for the Merchant Generation business
segment include, among other things, absence of
sufficient owned generation, plant outages, the fulfillment
of renewable energy requirements, the failure of suppliers
to meet their power supply obligations, extreme weather
conditions, and the availability of power at a cost lower
than the cost of generating it.
8
FUEL FOR POWER GENERATION
The following table presents the source of electric generation by fuel type, excluding purchased power, for the years
ended December 31, 2009, 2008 and 2007:
Nuclear
Natural Gas
Hydroelectric
Ameren:(a)
2009 .................................................................................................................
2008 .................................................................................................................
2007 .................................................................................................................
2009 .................................................................................................................
2008 .................................................................................................................
2007 .................................................................................................................
Missouri Regulated:
UE:
Merchant Generation:
Genco:
2009 .................................................................................................................
2008 .................................................................................................................
2007 .................................................................................................................
2009 ................................................................................................................. 100 %
99
2008 .................................................................................................................
99
2007 .................................................................................................................
CILCO (AERG):
EEI:
2009 ................................................................................................................. 100 %
2008 ................................................................................................................. 100
2007 ................................................................................................................. 100
Total Merchant Generation:
2009 .................................................................................................................
2008 .................................................................................................................
2007 .................................................................................................................
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
99 %
99
98
-%
-
-
(a)
(b) Less than 1% of total fuel supply.
Coal
83 %
85
84
75 %
77
76
99 %
99
96
13%
12
12
21%
19
19
-%
-
-
-%
-
-
-%
-
-
1%
1
2
(b)%
1
2
1%
1
4
(b)%
1
1
-%
-
-
1%
1
2
3%
2
2
4%
3
3
-%
-
-
-%
-
-
-%
-
-
-%
-
-
Oil
(b)%
(b)
(b)
-%
(b)
(b)
(b)%
(b)
(b)
-%
-
(b)
-%
-
-
(b)%
(b)
(b)
9
The following table presents the cost of fuels for electric generation for the years ended December 31, 2009, 2008
and 2007:
Cost of Fuels (Dollars per million Btus)
2009
2008
2007
$
$
$
$
$
1.399
0.490
7.939
1.462
1.654
0.620
8.685
1.591
1.572 (b)
0.493
10.503
1.573 (b)
Ameren:
Coal(a) .................................................................................................................................................... $
Nuclear ...................................................................................................................................................
Natural gas(c) ..........................................................................................................................................
Weighted average – all fuels(d) ................................................................................................................ $
Missouri Regulated:
UE:
Coal(a) .................................................................................................................................................... $
Nuclear ...................................................................................................................................................
Natural gas(c) ..........................................................................................................................................
Weighted average – all fuels(d) ................................................................................................................ $
Merchant Generation:
Genco:
Coal(a) .................................................................................................................................................... $
Natural gas(c) ..........................................................................................................................................
Weighted average – all fuels(d) ................................................................................................................ $
CILCO (AERG):
Coal(a) .................................................................................................................................................... $
Weighted average – all fuels(d) ................................................................................................................ $
EEI:
Coal(a) .................................................................................................................................................... $
Total Merchant Generation:
Coal(a) .................................................................................................................................................... $
Natural gas(c) ..........................................................................................................................................
Weighted average – all fuels(d) ................................................................................................................ $
$
(a) The fuel cost for coal represents the cost of coal, costs for transportation, which includes diesel fuel adders, and cost of emission allowances.
(b) Excludes impact of the Genco coal supply contract settlement under which Genco received a lump-sum payment of $60 million in July 2008 from a coal mine
1.426
0.493
10.264
1.340
1.534
0.620
8.544
1.386
1.746 (b)
10.764
1.919 (b)
1.958 (b)
15.857
2.121 (b)
1.877
13.159
2.001
1.813
8.796
1.934
(c) The fuel cost for natural gas represents the cost of natural gas and firm and variable costs for transportation, storage, balancing, and fuel losses for delivery
owner. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
to the plant. In addition, the fixed costs for firm transportation and firm storage capacity are included in the calculation of fuel cost for the generating facilities.
paint products, and handling. Oil, paint, propane, and tire chips are not individually listed in this table because their use is minimal.
(d) Represents all costs for fuels used in our electric generating facilities, to the extent applicable, including coal, nuclear, natural gas, oil, propane, tire chips,
1.284
0.490
7.580
1.271
1.643
1.673
1.598
1.721
1.545
8.390
1.759
1.717
8.440
1.939
1.309
1.450
1.855
1.438
1.329
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Coal
UE, Genco, AERG and EEI have agreements in place
to purchase a portion of their coal needs and to transport it
to electric generating facilities through 2019. UE, Genco,
AERG and EEI expect to enter into additional contracts to
purchase coal from time to time. Coal supply agreements
typically have an initial term of five years, with about 20%
of the contracts expiring annually. Ameren burned
37.6 million tons (UE – 21.3 million, Genco – 7.9 million,
AERG – 4.0 million, EEI – 4.4 million) of coal in 2009. See
Part II, Item 7A – Quantitative and Qualitative Disclosures
About Market Risk of this report for additional information
about coal supply contracts.
About 96% of Ameren’s coal (UE – 96%, Genco –
99%, AERG – 89%, EEI – 100%) is purchased from the
Powder River Basin in Wyoming. The remaining coal is
typically purchased from the Illinois Basin. UE, Genco,
AERG and EEI have a policy to maintain coal inventory
consistent with their projected usage. Inventory may be
adjusted because of uncertainties of supply due to
potential work stoppages, delays in coal deliveries,
equipment breakdowns, and other factors. In the past,
deliveries from the Powder River Basin have occasionally
been restricted because of rail maintenance, weather, and
derailments. As of December 31, 2009, coal inventories
for UE, Genco, AERG and EEI were at targeted levels.
Disruptions in coal deliveries could cause UE, Genco,
AERG and EEI to pursue a strategy that could include
reducing sales of power during low-margin periods, buying
higher-cost fuels to generate required electricity, and
purchasing power from other sources.
Nuclear
Developing nuclear fuel generally involves the mining
and milling of uranium ore to produce uranium
concentrates, the conversion of uranium concentrates to
uranium hexafluoride gas, the enrichment of that gas, and
the fabrication of the enriched uranium hexafluoride gas
into usable fuel assemblies. UE has entered into uranium,
uranium conversion, enrichment, and fabrication contracts
to procure the fuel supply for its Callaway nuclear plant.
10
Fuel assemblies for the 2010 spring refueling at UE’s
Callaway nuclear plant have been manufactured and
delivered to the plant. UE also has agreements or inventories
to price-hedge approximately 89% of Callaway’s 2011 and
79% of Callaway’s 2013 refueling requirements. UE has
uranium (concentrate and hexafluoride) inventories and
supply contracts sufficient to meet all of its uranium and
conversion requirements at least through 2014. UE has
enriched uranium inventories and enrichment supply
contracts sufficient to satisfy enrichment requirements
through 2012. Fuel fabrication services are under contract
through 2010. UE expects to enter into additional contracts to
purchase nuclear fuel. As a member of Fuelco, UE can join
with other member companies to increase its purchasing
power and opportunities for volume discounts. The Callaway
nuclear plant normally requires refueling at 18-month
intervals. The last refueling was completed in November
2008. The nuclear fuel markets are competitive, and prices
can be volatile; however, we do not anticipate any significant
problems in meeting our future supply requirements.
Natural Gas Supply
To maintain gas deliveries to gas-fired generating units
throughout the year, especially during the summer peak
demand, Ameren’s portfolio of natural gas supply resources
includes firm transportation capacity and firm no-notice
storage capacity leased from interstate pipelines. UE, Genco
and EEI primarily use the interstate pipeline systems of
Panhandle Eastern Pipe Line Company, Trunkline Gas
Company, Natural Gas Pipeline Company of America, and
Mississippi River Transmission Corporation to transport
natural gas to generating units. In addition to physical
transactions, Ameren uses financial instruments, including
some in the NYMEX futures market and some in the OTC
financial markets, to hedge the price paid for natural gas.
UE, Genco and EEI’s natural gas procurement strategy
is designed to ensure reliable and immediate delivery of
natural gas to their generating units. UE, Genco and EEI do
this in two ways. They optimize transportation and storage
options and minimize cost and price risk through various
supply and price-hedging agreements that allow them to
maintain access to multiple gas pools, supply basins, and
storage. As of December 31, 2009, UE had price-hedged
about 89% and Genco had price-hedged 100% of their
expected natural gas supply requirements for generation in
2010. As of December 31, 2009, EEI did not have any of its
required gas supply for generation hedged for price risk.
Renewable Energy
Illinois and Missouri have enacted laws requiring electric
utilities to include renewable energy resources in their
portfolios. Illinois requires renewable energy resources to
equal or exceed 2% of the total electricity that each electric
utility supplies to its eligible retail customers as of June 1,
2008, increasing to 10% by June 1, 2015, and to 25% by
June 1, 2025. The Ameren Illinois Utilities have procured
renewable energy credits under the ICC-approved RFP to
meet this requirement through May 2010. See Note 2 – Rate
and Regulatory Matters under Part II, Item 8, for additional
information about the Illinois power procurement process. In
Missouri, utilities will be required to purchase or generate
electricity from renewable energy sources equaling at least
2% of native load sales by 2011, with that percentage
increasing in subsequent years to at least 15% by 2021,
subject to a 1% limit on customer rate impacts. At least 2% of
each renewable energy portfolio requirement must be derived
from solar energy. UE expects to satisfy the 2011
requirement with existing renewable generation in its current
fleet along with a 15-year, 102-MW power purchase
agreement with a wind farm operator in Iowa that began
generation in 2009 and the 15-MW landfill gas project
discussed below.
In September 2009, UE announced an agreement with a
landfill owner to install CTs at a landfill site in St. Louis
County, Missouri, which would generate approximately 15-
MW of electricity by burning methane gas collected from the
landfill. Construction of the CTs is expected to begin in 2010,
and the CTs are expected to begin generating power in 2011.
UE signed a 20-year supply agreement with the landfill owner
to purchase methane gas.
Energy Efficiency
Ameren’s regulated utilities have implemented energy
efficiency programs to educate and help their customers
become more efficient users of energy. A new law in Missouri
allows electric utilities to recover costs related to MoPSC-
approved energy efficiency programs. The new law could,
among other things, allow UE to earn a return on its energy
efficiency programs equivalent to the return UE could earn
with supply-side capital investments, such as new power
plants. UE introduced multiple energy efficiency programs in
2009. The goal of these recently announced and future UE
energy efficiency programs is to reduce usage by 540-MW by
2025. UE has set up a website at www.uefficiency.com in
order to provide more information to its customers regarding
energy efficiency.
The Ameren Illinois Utilities are participating in the Illinois
Clean Energy Community Foundation, a program that
supports energy efficiency, promotes renewable energy, and
provides educational opportunities. In June 2008, the ICC
issued an order approving the Ameren Illinois Utilities’ electric
energy efficiency plan as well as a cost recovery mechanism
by which the program costs will be recovered from electric
customers. In October 2008, the ICC issued an order
approving the Ameren Illinois Utilities’ natural gas energy
efficiency plan as well as a cost recovery mechanism by
which the program costs will be recovered from natural gas
customers. The Ameren Illinois Utilities have set up a website
at www.actonenergy.com in order to provide more
information to their customers regarding energy efficiency.
NATURAL GAS SUPPLY FOR DISTRIBUTION
UE, CIPS, CILCO and IP are responsible for the
purchase and delivery of natural gas to their gas utility
customers. UE, CIPS, CILCO and IP develop and manage a
portfolio of gas supply resources. These include firm gas
supply under term
11
pressure on customer growth and usage in light of
current economic conditions;
the potential for reregulation in some states, including
Illinois, which could cause electric distribution
companies to build or acquire generation facilities and
to purchase less power from electric generating
companies such as Genco, AERG and EEI;
changes in the structure of the industry as a result of
changes in federal and state laws, including the
formation of merchant generating and independent
transmission entities and RTOs;
increases or decreases in power prices due to the
balance of supply and demand;
the availability of fuel and increases or decreases in
fuel prices;
the availability of qualified labor and material, and
rising costs;
regulatory lag;
negative free cash flows due to rising investments and
the regulatory framework;
continually developing and complex environmental
laws, regulations and issues, including air-quality
standards, mercury regulations, and increasingly likely
greenhouse gas limitations and ash management
requirements;
public concern about the siting of new facilities;
aging infrastructure and the need to construct new
power generation, transmission and distribution
facilities;
proposals for programs to encourage or mandate
energy efficiency and renewable sources of power;
public concerns about nuclear plant operation and
decommissioning and the disposal of nuclear waste;
and
consolidation of electric and natural gas companies.
We are monitoring these issues. Except as otherwise
noted in this report, we are unable to predict what impact,
if any, these issues will have on our results of operations,
financial position, or liquidity. For additional information,
see Risk Factors under Part I, Item 1A, and Outlook and
Regulatory Matters in Management’s Discussion and
Analysis of Financial Condition and Results of Operations
under Part II, Item 7, and Note 2 – Rate and Regulatory
Matters, and Note 15 – Commitments and Contingencies
under Part II, Item 8, of this report.
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 customers throughout the year
and especially during peak demand. UE, CIPS, CILCO
and IP primarily use the Panhandle Eastern Pipe Line
Company, the Trunkline Gas Company, the Natural Gas
Pipeline Company of America, the Mississippi River
Transmission Corporation, and the Texas Eastern
Transmission Corporation interstate pipeline systems to
transport natural gas to their systems. In addition to
physical transactions, financial instruments, including
those entered into in the NYMEX futures market and in the
OTC financial markets, are used to hedge the price paid
for natural gas. See Part II, Item 7A – Quantitative and
Qualitative Disclosures About Market Risk of this report for
additional information about natural gas supply contracts.
Prudently incurred natural gas purchase costs are passed
on to customers of UE, CIPS, CILCO and IP in Illinois and
Missouri under PGA clauses, subject to prudency review
by the ICC and the MoPSC.
For additional information on our fuel and purchased
power 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. Also see Quantitative and
Qualitative Disclosures About Market Risk under Part II,
Item 7A, of this report, Note 1 – Summary of Significant
Accounting Policies, Note 7 – Derivative Financial
Instruments, Note 14 – Related Party Transactions, Note
15 – Commitments and Contingencies, and Note 16 –
Callaway Nuclear Plant under Part II, Item 8.
INDUSTRY ISSUES
We are facing issues common to the electric and
natural gas utility industry and the merchant electric
generation industry. These issues include:
political and regulatory resistance to higher rates,
especially in a recessionary economic environment;
the potential for changes in laws, regulation, and
policies at the state and federal level, including those
resulting from election cycles;
access to, and uncertainty in, the capital and credit
markets;
the potential for more intense competition in
generation, supply and distribution, including new
technologies;
12
OPERATING STATISTICS
The following tables present key electric and natural gas operating statistics for Ameren for the past three years:
2007
Electric Operating Statistics – Year Ended December 31,
2009
2008
Electric Sales – kilowatthours (in millions):
Missouri Regulated:
Residential ......................................................................................................................................
Commercial .....................................................................................................................................
Industrial .........................................................................................................................................
Other ...............................................................................................................................................
Native load subtotal ....................................................................................................................
Off-system sales .............................................................................................................................
Subtotal ......................................................................................................................................
Illinois Regulated:
Residential
Commercial
Industrial
Power supply and delivery service ..............................................................................................
Power supply and delivery service ..............................................................................................
Delivery service only ...................................................................................................................
Power supply and delivery service ..............................................................................................
Delivery service only ...................................................................................................................
Other...............................................................................................................................................
Native load subtotal ....................................................................................................................
Merchant Generation:
Nonaffiliate energy sales .................................................................................................................
Affiliate native energy sales .............................................................................................................
Subtotal ......................................................................................................................................
Eliminate affiliate sales...........................................................................................................................
Eliminate Illinois Regulated/Merchant Generation common customers ...................................................
Ameren total ...............................................................................................................................
Electric Operating Revenues (in millions):
Missouri Regulated:
Residential ...................................................................................................................................... $
Commercial .....................................................................................................................................
Industrial .........................................................................................................................................
Other...............................................................................................................................................
Native load subtotal ....................................................................................................................
Off-system sales .............................................................................................................................
Subtotal ...................................................................................................................................... $
Illinois Regulated:
Residential
Commercial
Industrial
Power supply and delivery service .............................................................................................. $
Power supply and delivery service ..............................................................................................
Delivery service only ...................................................................................................................
Power supply and delivery service ..............................................................................................
Delivery service only ...................................................................................................................
Other...............................................................................................................................................
Native load subtotal .................................................................................................................... $
Merchant Generation:
Nonaffiliate energy sales ................................................................................................................. $
Affiliate native energy sales .............................................................................................................
Other...............................................................................................................................................
Subtotal ...................................................................................................................................... $
Eliminate affiliate revenues ....................................................................................................................
Ameren total ............................................................................................................................... $
13,413
14,510
7,037
1,655
36,615
12,447
49,062
11,089
5,235
6,797
514
10,712
546
34,893
25,673
3,529
29,202
(3,529 )
(5,566 )
104,062
982
881
314
122
2,299
401
2,700
1,094
521
103
22
36
157
1,933
1,340
385
(15 )
1,710
(434 )
5,909
13,904
14,690
9,256
785
38,635
10,457
49,092
11,667
6,095
6,147
1,442
11,300
555
37,206
26,395
6,055
32,450
(6,055)
(4,939)
107,754
948
838
372
108
2,266
490
2,756
1,112
616
77
102
30
285
2,222
1,389
441
106
1,936
(547)
6,367
$
$
$
$
$
$
$
14,258
14,766
9,675
759
39,458
10,984
50,442
11,857
7,232
5,178
1,606
11,199
576
37,648
25,196
7,296
32,492
(7,296)
(5,800)
107,486
980
839
390
93
2,302
484
2,786
1,055
666
54
105
24
372
2,276
1,310
461
41
1,812
(591)
6,283
$
$
$
$
$
$
$
13
Electric Operating Statistics – Year Ended December 31,
Electric Generation – megawatthours (in millions):
Missouri Regulated ...........................................................................................................................
Merchant Generation:
Genco.........................................................................................................................................
AERG .........................................................................................................................................
EEI .............................................................................................................................................
Medina Valley .............................................................................................................................
Subtotal ................................................................................................................................
Ameren total..........................................................................................................................
Price per ton of delivered coal (average) ................................................................................................
Source of energy supply:
Coal .................................................................................................................................................
Gas ..................................................................................................................................................
Nuclear ............................................................................................................................................
Hydroelectric ....................................................................................................................................
Purchased and interchanged, net .....................................................................................................
Gas Operating Statistics – Year Ended December 31,
Gas Sales (millions of Dth)
Missouri Regulated:
Illinois Regulated:
Residential ........................................................................................................................................
Commercial .......................................................................................................................................
Industrial ...........................................................................................................................................
Subtotal .......................................................................................................................................
Residential ........................................................................................................................................
Commercial .......................................................................................................................................
Industrial ...........................................................................................................................................
Subtotal .......................................................................................................................................
Industrial ...........................................................................................................................................
Subtotal .......................................................................................................................................
Eliminate affiliate sales............................................................................................................................
Ameren total ................................................................................................................................
Other:
Natural Gas Operating Revenues (in millions)
Missouri Regulated:
Illinois Regulated:
Residential ........................................................................................................................................
Commercial .......................................................................................................................................
Industrial ...........................................................................................................................................
Other .................................................................................................................................................
Subtotal .......................................................................................................................................
Residential ........................................................................................................................................
Commercial .......................................................................................................................................
Industrial ...........................................................................................................................................
Other .................................................................................................................................................
Subtotal .......................................................................................................................................
Industrial ...........................................................................................................................................
Subtotal .......................................................................................................................................
Eliminate affiliate revenues .....................................................................................................................
Ameren total ................................................................................................................................
Peak day throughput (thousands of Dth):
UE
CIPS .................................................................................................................................................
CILCO ...............................................................................................................................................
IP
Total peak day throughput.......................................................................................................................
Other:
2009
2008
2007
$
48.7
13.4
6.8
7.1
0.2
27.5
76.2
29.85
67.0 %
0.6
10.8
2.0
19.6
100.0 %
49.3
16.6
6.7
8.0
0.2
31.5
80.8
26.90(a)
70.1%
0.8
9.5
1.8
17.8
100.0%
$
50.3
17.4
5.3
8.1
0.2
31.0
81.3
25.20
68.7%
1.8
9.4
1.6
18.5
100.0%
$
2009
2008
2007
7
4
1
12
60
26
7
93
3
3
-
108
106
47
10
7
170
646
259
38
58
1,001
15
15
(5)
1,181
163
280
423
650
1,516
$
$
$
$
$
$
$
8
4
1
13
65
28
11
104
4
4
(1 )
120
121
54
12
14
201
819
338
119
(21 )
1,255
26
26
(10 )
1,472
158
266
399
615
1,438
$
$
$
$
$
$
$
7
4
1
12
59
25
10
94
2
2
-
108
108
47
12
7
174
687
272
103
39
1,101
16
16
(12)
1,279
155
250
401
574
1,380
$
$
$
$
$
$
$
(a)
Includes impact of the Genco coal settlement under which Genco received a lump-sum payment of $60 million in July 2008 from a coal mine owner. See
Note 1 – Summary of Significant Account Policies under Part II, Item 8, of this report.
14
AVAILABLE INFORMATION
The Ameren Companies make available free of charge
through Ameren’s Web site (www.ameren.com) their annual
reports 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 Sections 13(a) or 15(d)
of the Exchange Act as soon as reasonably possible after
such reports are electronically filed with, or furnished to, the
SEC. These documents are also available through an
Internet Web site maintained by the SEC (www.sec.gov).
Ameren also uses its Web site (www.ameren.com) as a
channel of distribution of material information relating to the
Ameren Companies. Financial and other material information
regarding the Ameren Companies is routinely posted and
accessible at Ameren’s Web site.
The Ameren Companies also make available free of
charge through Ameren’s Web site (www.ameren.com) the
charters of Ameren’s board of directors’ audit and risk
committee, human resources committee, nominating and
corporate governance committee, finance committee, nuclear
oversight committee, and public policy committee; the
corporate governance guidelines; a policy regarding
communications to the board of directors; a policy and
procedures with respect to related-person transactions; a
code of ethics for principal executive and senior financial
officers; a code of business conduct applicable to all
directors, officers and employees; and a director nomination
policy that applies to the Ameren Companies. The
information on Ameren’s Web site, or any other Web site
referenced in this report, is not incorporated by reference into
this report.
ITEM 1A. RISK FACTORS.
Investors should review carefully the following risk
factors and the other information contained in this report. The
risks that the Ameren Companies face are not limited to
those in this section. There may be additional risks and
uncertainties (either currently unknown or not currently
believed to be material) that could adversely affect the
financial position, results of operations, and liquidity of the
Ameren Companies. See Forward-looking Statements above
and Outlook in Management’s Discussion and Analysis of
Financial Condition and Results of Operations under Part II,
Item 7, of this report.
The electric and gas rates that UE, CIPS, CILCO and
IP are allowed to charge are determined through
regulatory proceedings and are subject to legislative
actions, which are largely outside of their control. Any
such events that prevent UE, CIPS, CILCO or IP from
recovering their respective costs or from earning
appropriate returns on their investments could have a
material adverse effect on future results of operations,
financial position, and liquidity.
The rates that UE, CIPS, CILCO and IP are allowed to
charge for their utility services significantly influence the
results of operations, financial position, and liquidity of these
companies and Ameren. The electric and natural gas utility
industry is highly regulated. The utility rates charged to UE,
CIPS, CILCO and IP customers are determined, in large part,
by governmental entities, including the MoPSC, the ICC, and
FERC. Decisions by these entities are influenced by many
factors, including the cost of providing service, the prudency
of expenditures, the quality of service, regulatory staff
knowledge and experience, economic conditions, public
policy, and social and political views, and are largely outside
of our control. Decisions made by these governmental
entities regarding rates, as well as the regulatory lag involved
in filing and getting new rates approved, could have a
material adverse effect on results of operations, financial
position, and liquidity.
UE, CIPS, CILCO and IP electric and gas utility rates are
typically established in regulatory proceedings that take up to
11 months to complete. Rates established in those
proceedings are primarily based on historical costs and
revenues, and they include an allowed return on investments
by the regulator.
Our company, and the industry as a whole, is going
through a period of rising costs and investments. The fact
that rates at UE, CIPS, CILCO and IP are primarily based on
historical costs and revenues means that these companies
may not be able to earn the allowed return established by
their regulators and could result in deferral or elimination of
planned capital investments. As a result, UE, CIPS, CILCO
and IP expect to file rate cases frequently. A period of
increasing rates for our customers, especially during weak
economic times, could result in additional regulatory and
legislative actions, as well as competitive and political
pressures, that could have a material adverse effect on our
results of operations, financial position, and liquidity.
We are subject to various environmental laws and
regulations that require significant capital expenditures
or could result in closure of facilities, could increase our
operating costs, and could adversely influence or limit
our results of operations, financial position, and liquidity
or expose us to environmental fines and liabilities.
We are subject to various environmental laws and
regulations enforced by federal, state and local authorities.
From the beginning phases of siting and development to the
ongoing operation of existing or new electric generating,
transmission and distribution facilities, natural gas storage
facilities, and natural gas transmission and distribution
facilities, our activities involve compliance with diverse laws
and regulations. These laws and regulations address noise,
emissions, impacts to air, land and water, protected and
cultural resources (such as wetlands, endangered species,
and archeological and historical resources), and chemical
and waste handling. Complex and lengthy processes are
required to obtain approvals, permits, or licenses for new,
existing or modified facilities. Additionally, the use and
handling of various chemicals or hazardous materials
(including wastes) requires release prevention plans and
emergency response procedures.
Compliance with environmental laws and regulations can
require significant capital expenditures and operating costs.
Periodically, environmental statutes and regulations are
amended and new statutes and regulations are adopted that
15
impose new or modified obligations on our facilities and
operations. Actions required to ensure that our facilities and
operations are in compliance with environmental laws and
regulations could be prohibitively expensive. As a result, we
could be required to close or alter the operation of our
facilities, which could have an adverse effect on our results of
operations, financial position, and liquidity.
Failure to comply with environmental laws and
regulations may also result in the imposition of fines,
penalties, and injunctive measures affecting operating
assets. We are also subject to liability under environmental
laws for remediating environmental contamination of property
now or formerly owned by us or by our predecessors, as well
as property contaminated by hazardous substances that we
generated. Such sites include MGP sites and third-party
sites, such as landfills. Additionally, private individuals may
seek to enforce environmental laws and regulations against
us and could allege injury from exposure to hazardous
materials.
Ameren also may be subject to risks in connection with
changing or conflicting interpretations of existing laws and
regulations. The EPA is engaged in an enforcement initiative
targeted at coal-fired power plants in the United States to
determine whether those power plants failed to comply with
the requirements of the NSR and New Source Performance
Standards (NSPS) provisions under the Clean Air Act when
the plants implemented modifications. Failure to comply with
the NSR and NSPS provisions under the Clean Air Act can
result in increased capital expenditures for the installation of
control technology, increased operations and maintenance
expenses, and fines or penalties. In January 2010, UE
received a Notice of Violation from the EPA alleging
violations of the Clean Air Act’s NSR and Title V programs.
An outcome in this matter, adverse to UE, could require
substantial capital expenditures and the payment of
substantial penalties, neither of which can be determined at
this time. Such expenditures could affect unit retirement and
replacement decisions and our results of operations, financial
position, and liquidity if such costs are not recovered through
regulated rates.
Ameren, UE, Genco, AERG and EEI have incurred and
expect to incur significant costs related to environmental
compliance and site remediation. New environmental
regulations, voluntary compliance guidelines, enforcement
initiatives, or legislation could result in a significant increase
in capital expenditures and operating costs, decreased
revenues, increased financing requirements, penalties, or
closure of facilities for UE, Genco, AERG and EEI. Although
costs incurred by UE would be eligible for recovery in rates
over time, subject to MoPSC approval in a rate proceeding,
there is no similar mechanism for recovery of costs for
Genco, AERG or EEI. We are unable to predict the ultimate
impact of these matters on our results of operations, financial
position and liquidity.
Future limits on greenhouse gas emissions would
likely require UE, Genco, CILCO (through AERG) and EEI
to incur significant increases in capital expenditures and
operating costs, which, if excessive, could result in the
closures of coal-fired generating plants, impairment of
assets, or otherwise materially adversely affect our
results of operations, financial position, and liquidity.
Initiatives to limit greenhouse gas emissions and to
address climate change are subject to active consideration in
the U.S. Congress. In June 2009, the U.S. House of
Representatives passed energy legislation entitled “The
American Clean Energy and Security Act of 2009” that, if
enacted, would establish an economy-wide cap-and-trade
program. The overarching goal of this proposed cap-and-
trade program is to reduce greenhouse gas emissions from
capped sources, including coal-fired electric generation units,
to 3% below 2005 levels by 2012, 17% below 2005 levels by
2020, 42% below 2005 levels by 2030, and 83% below 2005
levels by the year 2050. In September 2009, climate change
legislation entitled “The Clean Energy Jobs and American
Power Act” was introduced in the U.S. Senate that was
similar to that passed by the U.S. House of Representatives
in June 2009, although it proposes a slightly greater
reduction in greenhouse gas emissions in the year 2020 and
grants fewer emission allowances to the electricity sector.
Under both proposed pieces of legislation, large sources of
CO2 emissions will be required to obtain and retire an
allowance for each ton of CO2 emitted. The allowances may
be allocated to the sources without cost, sold to the sources
through auctions or other mechanisms, or traded among
parties. “The Clean Energy Jobs and American Power Act”
was voted out of committee in November 2009. In December
2009, Senators Kerry, Graham and Lieberman introduced a
framework for Senate legislation in 2010. The framework
lacks specifics, but it is consistent with the House-passed
legislation except that it emphasizes the need for greater
support for nuclear power and energy independence through
support for clean energy and drilling for oil and natural gas.
Senate leadership has stated that consideration of climate
legislation will be postponed until spring 2010. In addition, the
reduction of greenhouse gas emissions has been identified
as a high priority by President Obama’s administration.
Although we cannot predict the date of enactment or the
requirements of any future climate change legislation or
regulations, we believe it is possible that some form of
federal legislation or regulations to control emissions of
greenhouse gases will become law during the current
administration.
Potential impacts from climate change legislation could
vary, depending upon proposed CO2 emission limits, the
timing of implementation of those limits, the method of
distributing allowances, the degree to which offsets are
allowed and available, and provisions for cost containment
measures, such as a “safety valve” provision that provides a
maximum price for emission allowances. As a result of our
diverse fuel portfolio, our emissions of greenhouse gases
vary among our generating facilities, but coal-fired power
plants are significant sources of CO2 , a principal greenhouse
gas. Ameren’s analysis shows that if either “The American
Clean Energy and Security Act of 2009” or “The Clean
Energy Jobs and American Power Act” were enacted into law
in its current form, household costs and rates for electricity
could rise significantly. The burden could fall particularly hard
on electricity consumers and upon the economy in the
Midwest
16
because of the region’s reliance on electricity generated by
coal-fired power plants. Natural gas emits about half the
amount of CO 2 that coal emits when burned to produce
electricity. As a result, economy-wide shifts favoring natural
gas as a fuel source for electricity generation also could
affect the cost of heating for our utility customers and many
industrial processes. Ameren believes that wholesale natural
gas costs could rise significantly as well. Higher costs for
energy could contribute to reduced demand for electricity and
natural gas.
Additional requirements to control greenhouse gas
emissions and address global climate change may also arise
pursuant to the Midwest Greenhouse Gas Reduction Accord,
an agreement signed by the governors of Illinois, Iowa,
Kansas, Michigan, Wisconsin, and Minnesota to develop a
strategy to achieve energy security and to reduce
greenhouse gas emissions through a cap-and-trade
mechanism. The advisory group to the Midwest governors
provided draft final recommendations on the design of a
greenhouse gas reduction program in June 2009. The
recommendations have not been endorsed or approved by
the state governors. It is uncertain whether legislation to
implement the recommendations will be implemented or
passed by any of the states, including Illinois.
With regard to the control of greenhouse gas emissions
under federal regulation, in 2007, the U.S. Supreme Court
issued a decision finding that the EPA has the authority to
regulate CO2 and other greenhouse gases from automobiles
as “air pollutants” under the Clean Air Act. This decision
required the EPA to determine whether greenhouse gas
emissions may reasonably be anticipated to endanger public
health or welfare, or, in the alternative, to provide a
reasonable explanation as to why greenhouse gas emissions
should not be regulated. In December 2009, in response to
the decision of the U.S. Supreme Court, the EPA issued its
“endangerment finding” determining that greenhouse gas
emissions, including CO2 , endanger human health and
welfare and that emissions of greenhouse gases from motor
vehicles contribute to that endangerment. It is expected that
the EPA will issue a rule by the end of March 2010 to control
greenhouse gas emissions from light-duty vehicles such as
automobiles. Once this rule is effective, greenhouse gases
will, for the first time, be a regulated air pollutant under the
Clean Air Act. The EPA has taken the position that the
regulation of greenhouse gas emissions from new motor
vehicles under the Clean Air Act will trigger the applicability of
other Clean Air Act programs, such as the Title V Operating
Permit Program and the NSR program, which apply to
greenhouse gas emissions from stationary sources. This
would include fossil fuel-fired electricity generating plants.
Recognizing the difficulties presented by regulating at
once virtually all emitters of greenhouse gases, the EPA
announced in September 2009 a proposed rule, known as
the “tailoring rule,” that would establish new higher thresholds
for regulating greenhouse gas emissions from stationary
sources, such as power plants. The rule would require any
source that emits at least 25,000 tons per year of greenhouse
gases measured as CO2 equivalents (CO2 e) to obtain an
operating permit under Title V Operating Permit Program of
the Clean Air Act. Sources that already have an operating
permit would have greenhouse gas-specific provisions added
to their permits upon renewal. Currently, all Ameren power
plants have operating permits that, depending on the final
rule, may be modified when they are renewed to address
greenhouse gas emissions. The proposed tailoring rule also
would set a new applicability threshold for subjecting
stationary sources to the requirements of the NSR program
for greenhouse gas emissions and a new emissions
threshold for determining when modifications at such
stationary sources would require the source to obtain a
permit and to implement control technology to address
greenhouse gas emissions.
Future federal and state legislation or regulations that
mandate limits on the emission of greenhouse gases would
result in significant increases in capital expenditures and
operating costs, which, in turn, could lead to increased
liquidity needs and higher financing costs. Moreover, to the
extent we request recovery of these costs through rates, our
regulators might deny some or all of, or defer timely recovery
of, these costs. Excessive costs to comply with future
legislation or regulations might force UE, Genco, CILCO
(through AERG) and EEI as well as other similarly situated
electric power generators to close some coal-fired facilities
and could lead to possible impairment of assets and reduced
revenues. As a result, mandatory limits could have a material
adverse impact on Ameren’s, UE’s, Genco’s, CILCO’s
(through AERG) and EEI’s results of operations, financial
position, and liquidity.
The construction of, and capital improvements to,
UE’s, CIPS’, CILCO’s and IP’s electric and gas utility
infrastructure as well as to Genco’s, CILCO’s (through
AERG) and EEI’s merchant generation facilities involve
substantial risks. These risks include escalating costs,
unsatisfactory performance by the projects when
completed, the inability to complete projects as
scheduled, cost disallowances by regulators and the
inability to earn a reasonable rate of return on invested
capital at our rate-regulated utilities, any of which could
result in higher costs and the closure of facilities.
Over the next five years, the Ameren Companies will
incur significant capital expenditures to comply with
environmental regulations and to make investments in their
electric and gas utility infrastructure and their merchant
generation facilities. The Ameren Companies estimate that
they will incur up to $8.1 billion (UE – up to $4.2 billion;
CIPS – up to $555 million; Genco – up to $1.0 billion; CILCO
(Illinois Regulated) – up to $400 million; CILCO (AERG) – up
to $180 million; IP – up to $1.1 billion; EEI – up to
$460 million; Other – up to $220 million) of capital
expenditures during the period 2010 through 2014. These
expenses include construction expenditures, capitalized
interest or allowance for funds used during construction, and
compliance with environmental standards. Construction costs
as well as the cost of capital have escalated in recent years
and are expected to either stay at current levels or escalate
further.
17
Investments in Ameren’s regulated operations are
expected to be recoverable from ratepayers, but are subject
to prudency reviews and regulatory lag. The recoverability of
amounts expended in merchant generation operations will
depend on whether market prices for power adjust to reflect
increased costs for generators.
The ability of the Ameren Companies to complete
facilities under construction successfully, and to complete
future projects within established estimates, is contingent
upon many variables and subject to substantial risks. These
variables include, but are not limited to, project management
expertise and escalating costs for materials, labor, and
environmental compliance. Delays in obtaining permits,
shortages in materials and qualified labor, suppliers and
contractors who do not perform as required under their
contracts, changes in the scope and timing of projects, the
inability to raise capital on favorable terms, or other events
beyond our control may occur that may materially affect the
schedule, cost and performance of these projects. With
respect to capital spent for pollution control equipment, there
is a risk that electric generating plants will not be permitted to
continue to operate if pollution control equipment is not
installed by prescribed deadlines or does not perform as
expected. Should any such construction efforts be
unsuccessful, the Ameren Companies could be subject to
additional costs and to the loss of their investment in the
project or facility. The Ameren Companies may also be
required to purchase electricity for their customers until the
projects are completed. All of these risks may have a material
adverse effect on the Ameren Companies’ results of
operations, financial position, and liquidity.
Our counterparties may not meet their obligations to
us.
We are exposed to the risk that counterparties to various
arrangements who owe us money, energy, coal, or other
commodities or services will not be able to perform their
obligations or, with respect to our credit facilities, will fail to
honor their commitments. Should the counterparties to
commodity arrangements fail to perform, we might be forced
to replace or to sell the underlying commitment at then-
current market prices. Should the lenders under our credit
facilities fail to perform, the level of borrowing capacity under
those arrangements would decrease unless we were able to
find replacement lenders to assume the nonperforming
lender’s commitment. In such an event, we might incur
losses, or our results of operations, financial position, and
liquidity could otherwise be adversely affected.
Certain of the Ameren Companies have obligations to
other Ameren Companies or other Ameren subsidiaries as a
result of transactions involving energy, coal, other
commodities and services, and as a result of hedging
transactions. If one Ameren entity failed to perform under any
of these arrangements, other Ameren entities might incur
losses. Their results of operations, financial position, and
liquidity could be adversely affected, resulting in the
nondefaulting Ameren entity being unable to meet its
obligations, including to unrelated third parties.
Increasing costs associated with our defined benefit
and postretirement plans, health care plans, and other
employee-related benefits could materially adversely
affect our results of operations, financial position, and
liquidity.
We offer defined benefit and postretirement plans that
cover substantially all of our employees. Assumptions related
to future costs, returns on investments, interest rates, and
other actuarial matters have a significant impact on our
earnings and funding requirements. Ameren expects to fund
its pension plans at a level equal to the greater of the pension
expense or the legally required minimum contribution.
Considering Ameren’s assumptions at December 31, 2009,
its investment performance in 2009, and its pension funding
policy, Ameren expects to make annual contributions of
$75 million to $225 million in each of the next five years, with
aggregate estimated contributions of $740 million. We expect
UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future
funding requirements to be 66%, 6%, 9%, 9%, and 10%,
respectively. These amounts are estimates. They may
change with actual investment performance, changes in
interest rates, changes in our assumptions, any pertinent
changes in government regulations, and any voluntary
contributions.
In addition to the costs of our retirement plans, the costs
of providing health care benefits to our employees and
retirees have increased in recent years. We believe that our
employee benefit costs, including costs of health care plans
for our employees and former employees, will continue to
rise. The increasing costs and funding requirements
associated with our defined benefit retirement plans, health
care plans, and other employee benefits could increase our
financing needs and otherwise materially adversely affect our
results of operations, financial position, and liquidity.
Our electric generating, transmission and
distribution facilities are subject to operational risks that
could materially adversely affect our results of
operations, financial position, and liquidity.
The Ameren Companies’ financial performance depends
on the successful operation of electric generating,
transmission, and distribution facilities. Operation of electric
generating, transmission, and distribution facilities involves
many risks, including:
facility shutdowns due to operator error or a failure of
equipment or processes;
longer-than-anticipated maintenance outages;
disruptions in the delivery of fuel or lack of adequate
inventories;
lack of water for cooling plant operations;
labor disputes;
inability to comply with regulatory or permit requirements,
including those relating to environmental contamination;
disruptions in the delivery of electricity, including impacts
on us or our customers;
handling and storage of fossil-fuel combustion waste
products, such as coal ash;
unusual or adverse weather conditions, including severe
storms, droughts, and floods;
18
a workplace accident that might result in injury or loss of
life, extensive property damage, or environmental
damage;
information security risk, such as a breach of systems
where sensitive utility customer data and account
information are stored;
catastrophic events such as fires, explosions, pandemic
health events, or other similar occurrences; and
other unanticipated operations and maintenance
expenses and liabilities.
Our natural gas distribution and storage activities
involve numerous risks that may result in accidents and
other operating risks and costs that could materially
adversely affect our results of operations, financial
position, and liquidity.
Inherent in our natural gas distribution and storage
activities are a variety of hazards and operating risks, such
as leaks, accidental explosions and mechanical problems,
which could cause substantial financial losses. In addition,
these risks could result in serious injury to employees and
nonemployees, loss of human life, significant damage to
property, environmental pollution and impairment of our
operations, which in turn could lead to substantial losses to
us. In accordance with customary industry practice, we
maintain insurance against some, but not all, of these risks
and losses. The location of distribution lines and storage
facilities near populated areas, including residential areas,
commercial business centers, industrial sites, and other
public gathering places, could increase the level of damages
resulting from these risks. The occurrence of any of these
events not fully covered by insurance could materially
adversely affect our results of operations, financial position,
and liquidity.
Even though agreements have been reached with the
state of Missouri and the FERC, the breach of the upper
reservoir of UE’s Taum Sauk pumped-storage
hydroelectric facility could continue to have a material
adverse effect on Ameren’s and UE’s results of
operations, liquidity, and financial condition.
In December 2005, there was a breach of the upper
reservoir at UE’s Taum Sauk pumped-storage hydroelectric
facility. This resulted in significant flooding in the local area,
which damaged a state park. UE settled with FERC and the
state of Missouri all issues associated with the December
2005 Taum Sauk incident.
UE has property and liability insurance coverage for the
Taum Sauk incident, subject to certain limits and deductibles.
Insurance does not cover lost electric margins and penalties
paid to FERC. UE expects that the total cost for cleanup,
damage, and liabilities, excluding costs to rebuild the upper
reservoir, will be approximately $205 million.
UE received approval from FERC to rebuild the upper
reservoir at its Taum Sauk plant and is in the process of
testing the rebuilt facility. UE expects the Taum Sauk plant to
become operational in the second quarter of 2010. The
estimated cost to rebuild the upper reservoir is in the range of
$490 million.
Under UE’s insurance policies, all claims by or against
UE are subject to review by its insurance carriers. In July
2009, three insurance carriers filed a petition against Ameren
in the Circuit Court of St. Louis County, Missouri, seeking a
declaratory judgment that the property insurance policy does
not require these three insurers to indemnify Ameren for their
share of the entire cost of construction associated with the
facility rebuild design being utilized. The three insurers allege
that they, along with the other policy participants, presented a
rebuild design that was consistent with their insurance
coverage obligations and that the insurance policies do not
require these insurers to pay their share of the costs of
construction associated with the design being used. These
insurers have estimated a cost of approximately $214 million
for their rebuild design compared to the estimated
$490 million cost of the design approved by FERC and
implemented by Ameren. Ameren has filed an answer and
counterclaim in the Circuit Court of St. Louis County,
Missouri, against these insurers. The counterclaim asserts
that the three insurance carriers have breached their
obligations under the property insurance policies issued to
Ameren and UE. Ameren seeks payment of a sum to-be-
determined for all amounts covered by these policies incurred
in the facility rebuild, including power replacement costs,
interest, and attorneys’ fees. The insurers that are parties to
the litigation represent approximately 40%, on a weighted
average basis, of the property insurance policy coverage
between the disputed amounts of $214 million and $490
million.
Until Ameren’s remaining insurance claims and the
related litigation are resolved, among other things, we are
unable to determine the total impact the breach could have
on Ameren’s and UE’s results of operations, financial
position, and liquidity beyond those amounts already
recognized. Ameren and UE expect to recover, through
insurance, 80% to 90% of the total property insurance claim
for the Taum Sauk incident. Beyond insurance, the
recoverability of any Taum Sauk facility rebuild costs from
customers is subject to the terms and conditions set forth in
UE’s November 2007 State of Missouri settlement
agreement. In that settlement, UE agreed that it would not
attempt to recover from rate payers costs incurred in the
reconstruction expressly excluding, however, enhancements,
costs incurred due to circumstances or conditions that were
not at that time reasonably foreseeable and costs that would
have been incurred absent the Taum Sauk incident. Certain
costs associated with the Taum Sauk facility not recovered
from property insurers may be recoverable from UE’s electric
customers through rates established in rate cases filed
subsequent to the in-service date of the rebuilt facility. As of
December 31, 2009, UE had capitalized in property and plant
qualifying Taum Sauk-related costs of $99 million that UE
believes qualify for potential recovery in electric rates under
the terms of the November 2007 State of Missouri
Settlement. The inclusion of such costs in UE’s electric rates
is subject to review and approval by the MoPSC in a future
rate case. Any amounts not recovered through insurance, in
electric rates, or otherwise could result in charges to
earnings, which could be material.
19
Genco’s, AERG’s, and EEI’s electric generating
UE’s ownership and operation of a nuclear
facilities must compete for the sale of energy and
capacity, which exposes them to price risks.
generating facility creates business, financial, and waste
disposal risks.
All of Genco’s, AERG’s, and EEI’s generating facilities
compete for the sale of energy and capacity in the
competitive energy markets.
To the extent that electricity generated by these facilities
is not under a fixed-price contract to be sold, the revenues
and results of operations of these merchant subsidiaries
generally depend on the prices that can be obtained for
energy and capacity in Illinois and adjacent markets by
Marketing Company.
Market prices for energy and capacity may fluctuate
substantially, sometimes over relatively short periods of time,
and at other times experience sustained increases or
decreases. Demand for electricity and fuel can fluctuate
dramatically, creating periods of substantial under- or over-
supply. During periods of over-supply, prices might be
depressed. Also, at times legislators or regulators with
jurisdiction over wholesale and retail energy commodity and
transportation rates may impose price limitations, bidding
rules and other mechanisms to address volatility and other
issues in these markets.
For power products sold in advance, contract prices are
influenced both by market conditions as well as the contract
terms such as damage provisions, credit support
requirements and the number of available counterparties
interested in contracting for the desired forward period.
Depending on differences between market factors at the time
of contracting versus current conditions, Marketing
Company’s contract portfolio may have average contract
prices greater than or less than current market prices,
including at the expiration of the contracts, which could
significantly affect Ameren’s, Genco’s, AERG’s, and EEI’s
results of operations, financial condition and liquidity.
Among the factors that could influence such prices (all of
which are beyond our control to a significant degree) are:
current and future delivered market prices for natural
gas, fuel oil, and coal, and related transportation costs;
current and forward prices for the sale of electricity;
the extent of additional supplies of electric energy from
current competitors or new market entrants;
the regulatory and market structures developed for
evolving Midwest energy markets;
changes enacted by the Illinois legislature, the ICC, the
IPA, or other government agencies with respect to power
procurement procedures;
the potential for reregulation of generation in some
states;
future pricing for, and availability of, services on
transmission systems, and the effect of RTOs and export
energy transmission constraints, which could limit our
ability to sell energy in our markets;
the growth rate in electricity usage as a result of
population changes, regional economic conditions, and
the implementation of energy-efficiency programs;
climate conditions in the Midwest market and major
natural disasters; and
environmental laws and regulations.
UE’s ownership of the Callaway nuclear plant subjects it
to the risks of nuclear generation, which include the following:
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;
the lack of a permanent waste storage site;
limitations on the amounts and types of insurance
commercially available to cover losses that might arise in
connection with the Callaway nuclear plant or other U.S.
nuclear operations;
uncertainties with respect to contingencies and
assessment amounts if insurance coverage is
inadequate;
public and governmental concerns over the adequacy of
security at nuclear power plants;
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);
limited availability of fuel supply; and
costly and extended outages for scheduled or
unscheduled maintenance and refueling.
The NRC has broad authority under federal law to
impose licensing and safety requirements for nuclear
generation facilities. In the event of noncompliance, the NRC
has the authority to impose fines, shut down a unit, or both,
depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety
requirements promulgated from time to time by the NRC
could necessitate substantial capital expenditures at nuclear
plants such as UE’s. In addition, if a serious nuclear incident
were to occur, it could have a material but indeterminable
adverse effect on UE’s results of operations, financial
position, and liquidity. A major incident at a nuclear facility
anywhere in the world could cause the NRC to limit or
prohibit the operation or relicensing of any domestic nuclear
unit.
Our energy risk management strategies may not be
effective in managing fuel and electricity procurement
and pricing risks, which could result in unanticipated
liabilities or increased volatility in our earnings and cash
flows.
We are exposed to changes in market prices for natural
gas, fuel, electricity, emission allowances, and transmission
congestion. Prices for natural gas, fuel, electricity, and
emission allowances may fluctuate substantially over
relatively short periods of time, and at other times experience
sustained increases or decreases, and expose us to
commodity price risk. We use short-term and long-term
purchase and sales contracts in addition to derivatives such
as forward contracts, futures contracts, options, and swaps to
manage these risks. We attempt to manage our risk
associated with these activities through enforcement of
established risk limits and risk management procedures. We
cannot ensure that these strategies will be successful in
managing our pricing risk or that they will not result in net
liabilities because of future volatility in these markets.
20
Although we routinely enter into contracts to hedge our
exposure to the risks of demand and changes in commodity
prices, we do not 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. To the extent that commodity
markets are illiquid, we may not be able to execute our risk
management strategies, which could result in greater
unhedged positions than we would prefer at a given time. To
the extent that unhedged positions exist, fluctuating
commodity prices can adversely affect our results of
operations, financial position, and liquidity.
Our facilities are considered critical energy
infrastructure and may therefore be targets of acts of
terrorism.
Like other electric and natural gas utilities and other
merchant electric generators, our power generation plants,
fuel storage facilities, and transmission and distribution
facilities may be targets of terrorist activities that could result
in disruption of our ability to produce or distribute some
portion of our energy products. Any such disruption could
result in a significant decrease in revenues or significant
additional costs for repair, which could have a material
adverse effect on our results of operations, financial position,
and liquidity.
Our businesses are dependent on our ability to
access the capital markets successfully. We may not
have access to sufficient capital in the amounts and at
the times needed.
We use short-term and long-term debt as a significant
source of liquidity and funding for capital requirements not
satisfied by our operating cash flow, including requirements
related to future environmental compliance. As a result of
rising costs and increased capital and operations and
maintenance expenditures, coupled with near-term regulatory
lag, we expect to continue to rely on short-term and long-term
debt financing. Ameren intends to replace or extend its credit
facility agreements during 2010. The inability to raise debt or
equity capital on favorable terms, or at all, particularly during
times of uncertainty in the capital markets, could negatively
affect our ability to maintain and to expand our businesses.
Our current credit ratings cause us to believe that we will
continue to have access to the capital markets. However,
events beyond our control, such as the extreme volatility and
disruption in global debt or equity capital and credit markets
that occurred in 2008 and continued into 2009, may create
uncertainty that could increase our cost of capital or impair,
or eliminate, our ability to access the debt, equity or credit
markets, including the ability to draw on our bank credit
facilities. Any adverse change in the Ameren Companies’
credit ratings may reduce access to capital and trigger
additional collateral postings and prepayments. Such
changes may also increase the cost of borrowing and fuel,
ITEM 2. PROPERTIES.
power and gas supply, among other things, which could have
a material adverse effect on our results of operations,
financial position, and liquidity. Certain of the Ameren
Companies rely, in part, on Ameren for access to capital.
Circumstances that limit Ameren’s access to capital,
including those relating to its other subsidiaries, could impair
its ability to provide those Ameren Companies with needed
capital.
Ameren’s holding company structure could limit
its ability to pay common stock dividends and to
service its debt obligations.
Ameren is a holding company; therefore, its primary
assets are the common stock of its subsidiaries. As a
result, Ameren’s ability to pay dividends on its common
stock depends on the earnings of its subsidiaries and the
ability of its subsidiaries to pay dividends or otherwise
transfer funds to Ameren. Similarly, Ameren’s ability to
service its debt obligations is also dependent upon the
earnings of operating subsidiaries and the distribution of
those earnings and other payments, including payments of
principal and interest under intercompany indebtedness.
The payment of dividends to Ameren by its subsidiaries in
turn depends on their results of operations and cash flows
and other items affecting retained earnings. Ameren’s
subsidiaries are separate and distinct legal entities and
have no obligation, contingent or otherwise, to pay any
dividends or make any other distributions (except for
payments required pursuant to the terms of intercompany
borrowing arrangements) to Ameren. Certain of the
Ameren Companies’ financing agreements and articles of
incorporation, in addition to certain statutory and
regulatory requirements, may impose restrictions on the
ability of such Ameren Companies to transfer funds to
Ameren in the form of cash dividends, loans or advances.
Failure to retain and attract key officers and other
skilled professional and technical employees could
have an adverse effect on our operations.
Our businesses depend upon our ability to employ
and retain key officers and other skilled professional and
technical employees. A significant portion of our work
force is nearing retirement, including many employees
with specialized skills such as maintaining and servicing
our electric and natural gas infrastructure and operating
our generating units. Our inability to retain and recruit
qualified employees could adversely affect our results of
operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
For information on our principal properties, see the generating facilities table below. See also 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 for any planned additions, replacements or transfers. See also Note 5 – Long-term Debt and
Equity Financings, and Note 15 – Commitments and Contingencies under Part II, Item 8, of this report.
21
The following table shows what our electric generating facilities and capability are anticipated to be at the time of our
Location
Net Kilowatt Capability(a)
expected 2010 peak summer electrical demand:
Primary Fuel Source
Missouri Regulated (UE):
Coal .........................................................................................
Total coal .................................................................................
Nuclear ....................................................................................
Hydroelectric ............................................................................
Total hydroelectric ...................................................................
Pumped-storage ......................................................................
Oil (CTs) ..................................................................................
Total oil ....................................................................................
Natural gas (CTs) ....................................................................
Plant
Labadie
Rush Island
Sioux
Meramec
Callaway
Osage
Keokuk
Taum Sauk(b)
Meramec
Fairgrounds
Mexico
Moberly
Moreau
Howard Bend
Venice
Audrain(d)
Venice(e)
Goose Creek
Pinckneyville
Raccoon Creek
Kinmundy(e)
Peno Creek(d)(e)
Meramec(e)
Viaduct
Kirksville
Total natural gas ......................................................................
Total UE .............................................................................
Merchant Generation:
Genco:
Coal .........................................................................................
Total coal .................................................................................
Oil
Total oil ....................................................................................
Natural gas (CTs) ....................................................................
Total natural gas ......................................................................
Total Genco .......................................................................
CILCO (through AERG):
Coal .........................................................................................
Total coal .................................................................................
Total CILCO .......................................................................
Medina Valley:
Natural gas ..............................................................................
Total Merchant Generation .......................................................
Total Ameren .....................................................................
Newton
Joppa Generating Station (EEI)(f)
Coffeen
Meredosia
Hutsonville
Meredosia
Hutsonville (Diesel)
Grand Tower
Elgin
Gibson City(e)
Joppa 7B
Columbia(g)
Joppa (EEI)(f)
Franklin County, Mo.
Jefferson County, Mo.
St. Charles County, Mo.
St. Louis County, Mo.
Callaway County, Mo.
Lakeside, Mo.
Keokuk, Ia.
Reynolds County, Mo.
St. Louis County, Mo.
Jefferson City, Mo.
Mexico, Mo.
Moberly, Mo.
Jefferson City, Mo.
St. Louis County, Mo.
Venice, Ill.
Audrain County, Mo.
Venice, Ill.
Piatt County, Ill.
Pinckneyville, Ill.
Clay County, Ill.
Kinmundy, Ill.
Bowling Green, Mo.
St. Louis County, Mo.
Cape Girardeau, Mo.
Kirksville, Mo.
Newton, Ill.
Joppa, Ill.
Coffeen, Ill.
Meredosia, Ill.
Hutsonville, Ill.
Meredosia, Ill.
Hutsonville, Ill.
Grand Tower, Ill.
Elgin, Ill.
Gibson City, Ill.
Joppa, Ill.
Columbia, Mo.
Joppa, Ill.
2,407,000
1,204,000
986,000
839,000
5,436,000
1,190,000
234,000
137,000
371,000
440,000
59,000
55,000
55,000
55,000
55,000
43,000
(c)
322,000
608,000
491,000
438,000
316,000
304,000
208,000
188,000
53,000
26,000
13,000
2,645,000
10,404,000
1,194,000
1,002,000
904,000
203,000
151,000
3,454,000
166,000
3,000
169,000
511,000
460,000
228,000
165,000
140,000
74,000
1,578,000
5,201,000
715,000
410,000
1,125,000
1,125,000
44,000
6,370,000
16,774,000
E.D. Edwards
Duck Creek
Bartonville, Ill.
Canton, Ill.
Medina Valley
Mossville, Ill.
22
“Net Kilowatt Capability” is the generating capacity available for dispatch from the facility into the electric transmission grid.
(a)
(b) This facility is not currently operational because of a breach of its upper reservoir in December 2005. It is expected to become operational in the second
quarter of 2010 and therefore is expected to be available for the 2010 peak summer demand. For additional information on the Taum Sauk incident, see Note
15 – Commitments and Contingencies under Part II, Item 8, of this report.
(c) This facility will be out of service in 2010.
(d) There are economic development lease arrangements applicable to these CTs.
(e) These CTs have the capability to operate on either oil or natural gas (dual fuel).
(f) Ameren owns an 80% interest in EEI. This table reflects the full capability of EEI’s facilities. As part of an internal reorganization, Resources Company
transferred its 80% ownership interest in EEI to Genco, through a capital contribution, on January 1, 2010. See Part I, Item 1, Business and Note 1 –
Summary of Significant Accounting Policies under Part II, Item 8, of this report.
(g) Genco and the city of Columbia, Missouri currently are parties to a power purchase agreement pursuant to which Columbia is now purchasing up to 72
megawatts of capacity and energy generated by the facility. Genco has granted Columbia options to purchase an ownership interest in the facility, which
would result in a sale of up to 72 megawatts (about 50%) of the facility. Columbia can exercise one option for 36 megawatts at the end of 2010 for a
purchase price of $15.5 million, at the end of 2014 for a purchase price of $9.5 million, or at the end of 2020 for a purchase price of $4 million. The other
option can be exercised for another 36 megawatts at the end of 2013 for a purchase price of $15.5 million, at the end of 2017 for a purchase price of $9.5
million, or at the end of 2023 for a purchase price of $4 million. The purchase power agreement will terminate if Columbia exercises the purchase options. In
addition, in February 2010, the city of Columbia approved the purchase of approximately 36 megawatts, or 25%, of the facility, subject to regulatory
approvals. As part of this transaction, the structure of the first purchase option described above will be amended. Instead of the ability to exercise the option
to purchase 36 megawatts at the end of 2010 for a purchase price of $15.5 million, the option could be exercised at the end of 2011 for a purchase price of
$14.9 million. All other provisions of the options described above will remain the same.
The following table presents electric and natural gas
The United States, the state of Illinois, the state of
Iowa, or the city of Keokuk, Iowa, may own or may
have paramount rights with respect to certain lands
lying in the bed of the Mississippi River on which a
portion of UE’s Keokuk plant is located.
Substantially all of the properties and plant of UE,
CIPS, CILCO and IP are subject to the first liens of the
indentures securing their mortgage bonds.
UE has conveyed most of its Peno Creek CT facility to
the city of Bowling Green, Missouri, and leased the facility
back from the city through 2022. Under the terms of this
capital lease, UE is responsible for all operation and
maintenance for the facility. Ownership of the facility will
transfer to UE at the expiration of the lease, at which time
the property and plant will become subject to the lien of
any outstanding UE first mortgage bond indenture.
UE operates a CT facility located in Audrain County,
Missouri. UE has rights and obligations as lessee of the
CT facility under a long-term lease with Audrain County.
The lease term will expire on December 1, 2023. Under
the terms of this capital lease, UE is responsible for all
operation and maintenance for the facility. Ownership of
the facility will transfer to UE at the expiration of the lease,
at which time the property and plant will become subject to
the lien of any outstanding UE first mortgage bond
indenture.
ITEM 3. LEGAL PROCEEDINGS.
We are involved in legal and administrative
proceedings before various courts and agencies with
respect to matters that arise in the ordinary course of
business, some of which involve substantial amounts of
money. We believe that the final disposition of these
proceedings, except as otherwise disclosed in this report,
utility-related properties for UE, CIPS, CILCO and IP as of
December 31, 2009:
UE
Circuit miles of electric
Circuit miles of electric
transmission lines ........... 2,942
distribution lines ............. 33,012
CIPS
2,306
14,929
CILCO
331
8,926
IP
1,869
21,639
Circuit miles of electric
distribution lines
underground ...................
22%
12%
26%
13%
Miles of natural gas
transmission and
distribution mains ........... 3,259
1
-
Propane-air plants ...............
Underground gas storage
fields ..............................
5,359
1
3
3,915
-
2
8,818
-
7
Billion cubic feet of total
working capacity of
underground gas
storage fields ..................
-
2
8
15
Our other properties include office buildings,
warehouses, garages, and repair shops.
With only a few exceptions, we have fee title to all
principal plants and other units of property material to the
operation of our businesses, and to the real property on
which such facilities are located (subject to mortgage liens
securing our outstanding first mortgage bonds and credit
facility indebtedness and to certain permitted liens and
judgment liens). The exceptions are as follows:
A portion of UE’s Osage plant reservoir, certain
facilities at UE’s Sioux plant, most of UE’s Peno Creek
and Audrain CT facilities, Genco’s Columbia CT
facility, Medina Valley’s generating facility, certain
substations, and most transmission and distribution
lines and gas mains are situated on lands occupied
under leases, easements, franchises, licenses, or
permits.
The United States or the state of Missouri may own or
may have paramount rights to certain lands lying in the
bed of the Osage River or located between the inner
and outer harbor lines of the Mississippi River on
which certain of UE’s generating and other properties
are located.
23
will not have a material adverse effect on our results of
operations, financial position, or liquidity. Risk of loss is
mitigated, in some cases, by insurance or contractual or
statutory indemnification. We believe that we have
established appropriate reserves for potential losses.
In July 2009, Caterpillar Inc., in conjunction with other
industrial customers as a coalition, intervened in the 2009
rate cases filed by CILCO and IP with the ICC to modify its
electric and natural gas delivery service rates. Douglas R.
Oberhelman is an executive officer of Caterpillar Inc. and a
member of the board of directors of Ameren. Mr. Oberhelman
did not participate in Ameren Corporation’s board and
committee deliberations relating to these matters.
For additional information on legal and administrative
proceedings, see Rates and Regulation under Item 1,
Business, and Item 1A, Risk Factors, above. See also
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,
and Note 2 – Rate and Regulatory Matters, and Note 15 –
Commitments and Contingencies under Part II, Item 8, of this
report.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the fourth quarter of 2009 with respect to any of the
Ameren Companies.
EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):
The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of
December 31, 2009, all positions and offices held with the Ameren Companies, tenure as officer, and business background for
at least the last five years. Some executive officers hold multiple positions within the Ameren Companies; their titles are given in
the description of their business experience.
AMEREN CORPORATION:
Age at
12/31/09 Positions and Offices Held
63
Executive Chairman and Director
Name
Gary L. Rainwater
Rainwater joined UE in 1979 and has held various positions with UE and other Ameren subsidiaries during his employment. In
2004, Rainwater was elected to serve as chairman and chief executive officer of Ameren, UE, and Ameren Services in addition
to his position as president. At that time, he was elected chairman of CILCO in addition to his position as chief executive officer
and president of CILCO, which he assumed in 2003. In 2004, upon Ameren’s acquisition of IP, Rainwater was also elected
chairman, chief executive officer, and president of IP. He held the position of chairman of CIPS, CILCO and IP after relinquishing
his position as president in October 2004. In 2007, Rainwater relinquished his positions as chairman, president and chief
executive officer of UE and Ameren Services and as chairman and chief executive officer of CIPS, CILCO and IP. In 2009,
Rainwater was succeeded as president and chief executive officer of Ameren by Thomas R. Voss and will retire as executive
chairman and director in April 2010.
Thomas R. Voss
Voss joined UE in 1969. He was elected senior vice president of UE, CIPS, and Ameren Services in 1999, of Genco in 2001, of
CILCO in 2003, and of IP in 2004. In 2003, Voss was elected president of Genco; he relinquished his presidency of this
company in 2004. In 2006, he was elected executive vice president of UE, CIPS, CILCO and IP. In 2007, Voss was elected
chairman, president and chief executive officer of UE. He relinquished his positions at CIPS, CILCO and IP in 2007. In 2009,
Voss was elected president and chief executive officer of Ameren; at that time, he relinquished his other positions.
President and Chief Executive Officer, and Director
62
Martin J. Lyons, Jr.
Lyons joined Ameren, UE, CIPS, Genco, and Ameren Services in 2001 as controller. He was elected controller of CILCO in
2003. He was also elected vice president of Ameren, UE, CIPS, Genco, CILCO, and Ameren Services in 2003 and vice
president and controller of IP in 2004. In 2007, his position at UE was changed to vice president and principal accounting officer.
In 2008, Lyons was elected senior vice president and chief accounting officer of the Ameren Companies. In 2009, Lyons was
also elected chief financial officer of the Ameren Companies.
Senior Vice President and Chief Financial Officer
43
Steven R. Sullivan
Sullivan joined Ameren, UE, CIPS, and Ameren Services in 1998 as vice president, general counsel, and secretary. He added
those positions at Genco in 2000. In 2003, Sullivan was elected vice president, general counsel and secretary of CILCO. He was
elected to his present position at Ameren, UE, CIPS, Genco, CILCO, and Ameren Services in 2003, and at IP in 2004.
Senior Vice President, General Counsel and Secretary
49
Jerre E. Birdsong
Birdsong joined UE in 1977 and was elected treasurer of UE in 1993. He was elected treasurer of Ameren, CIPS, and Ameren
Services in 1997, and Genco in 2000. In addition to being treasurer, in 2001 he was elected vice president at Ameren and at the
subsidiaries listed above. Additionally, he was elected vice president and treasurer of CILCO in 2003, and of IP in 2004.
Vice President and Treasurer
55
24
SUBSIDIARIES:
Age at
12/31/09 Positions and Offices Held
Name
Warner L. Baxter
Baxter joined UE in 1995. He was elected senior vice president, finance, of Ameren, UE, CIPS, Ameren Services, and
Genco in 2001 and of CILCO in 2003. Baxter was elected to the position of executive vice president and chief financial
officer of Ameren, UE, CIPS, Genco, CILCO, and Ameren Services in 2003 and of IP in 2004. He was elected chairman,
chief executive officer, president, and chief financial officer of Ameren Services effective in 2007. In 2009, Baxter was
elected chairman, president and chief executive officer of UE; at that time, he relinquished his other positions.
Chairman, President and Chief Executive Officer (UE)
48
Scott A. Cisel
Chairman, President and Chief Executive Officer (CIPS, CILCO
and IP)
Cisel joined CILCO in 1975. He was named senior vice president and leader of CILCO’s Sales and Marketing Business
Unit in 2001. Cisel assumed the position of vice president and chief operating officer for CILCO in 2003, upon Ameren’s
acquisition of that company. In 2004, Cisel was elected vice president of UE and president and chief operating officer of
CIPS, CILCO and IP. In 2007, Cisel was elected chairman and chief executive officer of CIPS, CILCO and IP, in addition
to his position as president. He relinquished his position at UE in 2007.
56
Daniel F. Cole
Chairman, President and Chief Executive Officer (Ameren
Services)
Cole joined UE in 1976. He was elected senior vice president of UE and Ameren Services in 1999, and of CIPS in 2001.
He was elected president of Genco in 2001; he relinquished that position in 2003. He was elected senior vice president of
CILCO in 2003, and of IP in 2004. In 2009, Cole was elected chairman, president and chief executive officer of Ameren
Services.
56
Karen C. Foss
Foss joined UE in 2007 as vice president for public relations. She was elected senior vice president, communications and
brand management, of Ameren Services in 2009. Foss relinquished her position at UE in 2009. Prior to joining UE, Foss
was a news anchor at KSDK-TV in St. Louis, Missouri.
Senior Vice President (Ameren Services)
65
Adam C. Heflin
Heflin joined UE in 2005 as vice president of nuclear operations and was elected senior vice president and chief nuclear
officer of UE in 2008. Prior to joining UE, Heflin served as Unit 2 plant manager at Arkansas Nuclear One, owned by
Entergy Corporation. He joined Entergy Corporation’s nuclear operations in 1992.
Senior Vice President and Chief Nuclear Officer (UE)
45
Richard J. Mark
Mark joined Ameren Services in 2002 as vice president of customer service. In 2003, he was elected vice president of
governmental policy and consumer affairs at Ameren Services, with responsibility for government affairs, economic
development, and community relations for Ameren’s operating utility companies. He was elected senior vice president at
UE in 2005, with responsibility for Missouri energy delivery. In 2007, Mark relinquished his position at Ameren Services.
Senior Vice President (UE)
54
Michael L. Moehn
Moehn joined Ameren Services in 2000. He was named director of Ameren Services’ corporate modeling and transaction
support in 2001 and elected vice president of business services for Ameren Energy Resources Company in 2002. In
2004, Moehn was elected vice president of corporate planning for Ameren Services and relinquished his position at
Ameren Energy Resources Company. In 2008, he was elected senior vice president of Ameren Services.
Senior Vice President (Ameren Services)
40
Michael G. Mueller
Mueller joined UE in 1986. He was elected vice president of AFS in 2000 and president of AFS in 2004.
President (AFS)
46
Charles D. Naslund
57
Chairman, President and Chief Executive Officer (Resources
Company), and Chairman and President (Genco)
Naslund joined UE in 1974. He was elected vice president of power operations at UE in 1999, vice president of Ameren
Services in 2000, and vice president of nuclear operations at UE in 2004. He relinquished his position at Ameren Services
in 2001. Naslund was elected senior vice president and chief nuclear officer at UE in 2005. In 2008, he was elected
chairman, president and chief executive officer of Resources Company and chairman and president of Genco. Naslund
relinquished his position at UE in 2008.
President and Chief Executive Officer (Marketing Company)
Andrew M. Serri
Serri joined Marketing Company as vice president of sales and marketing in 2000. He was elected vice president of
marketing and trading of Ameren Services in 2004, before being elected president and chief executive officer of Marketing
Company that same year. He relinquished his position at Ameren Services in 2007.
48
25
Officers are generally elected or appointed annually by the respective board of directors of each company, following
the election of board members at the annual meetings of shareholders. No special arrangement or understanding exists
between any of the above-named executive officers and the Ameren Companies nor, to our knowledge, with any other
person or persons pursuant to which any executive officer was selected as an officer. There are no family relationships
among the officers. Except for Karen C. Foss and Adam C. Heflin, all of the above-named executive officers have been
employed by an Ameren company for more than five years in executive or management positions.
PART II
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES.
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled
69,881 on January 29, 2010. The following table presents the price ranges, closing prices, and dividends paid per Ameren
common share for each quarter during 2009 and 2008.
AEE 2009 Quarter Ended:
March 31 .........................................................................
June 30 ...........................................................................
September 30 .................................................................
December 31 ..................................................................
AEE 2008 Quarter Ended:
March 31 .........................................................................
June 30 ...........................................................................
September 30 .................................................................
December 31 ..................................................................
High
Low
Close
Dividends Paid
$
$
35.35
25.25
27.66
28.67
54.29
48.39
43.16
39.15
$
$
19.51
21.75
23.09
23.78
40.92
41.34
38.49
25.51
$
$
23.19
24.89
25.28
27.95
44.04
42.23
39.03
33.26
38 1 /2 ¢
38 1 /2
38 1 /2
38 1 /2
63 1/2 ¢
63 1/2
63 1/2
63 1/2
There is no trading market for the common stock of UE, CIPS, Genco, CILCO or IP. Ameren holds all outstanding
common stock of UE, CIPS and IP; Resources Company holds all outstanding common stock of Genco; and CILCORP
holds all outstanding common stock of CILCO.
The following table sets forth the quarterly common stock dividend payments made by Ameren and its subsidiaries
during 2009 and 2008:
(In millions)
2009
Quarter Ended
2008
Quarter Ended
Registrant
UE ..................................
CIPS ................................
Genco ..............................
CILCO .............................
IP ..................................
Nonregistrants .................
Ameren ............................
December 31
5
$
35
-
20
31
-
$ 91
September 30
71
$
12
-
-
-
-
$ 83
June 30
47
$
-
-
-
-
35
$ 82
March 31
52
$
-
-
-
-
30
$ 82
$
December 31
71
-
17
-
15
32
$ 135
$
September 30
88
-
-
-
15
30
$ 133
June 30
28
$
-
60
-
15
30
$ 133
March 31
77
$
-
24
-
15
17
$ 133
On February 12, 2010, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of
38.5 cents per share. The common share dividend is payable March 31, 2010, to stockholders of record on March 10,
2010.
For a discussion of restrictions on the Ameren Companies’ payment of dividends, 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.
26
Purchase of Equity Securities
The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of
Regulation S-K:
Period
October 1 – October 31, 2009 ........................
November 1 – November 30, 2009 .................
December 1 – December 31, 2009 .................
Total ..............................................................
(a) Total Number
of Shares (or Units)
Purchased(a)
-
2,368
5,928
8,296
(b) Average Price
Paid per Share
(or Unit)
-
$
25.77
27.95
$ 27.33
(c) Total Number of Shares
(or Units) Purchased as
Part of Publicly
Announced
Plans or Programs
-
-
-
-
(d) Maximum Number
(or Approximate Dollar Value)
of Shares (or Units) that May Yet
Be Purchased Under the
Plans or Programs
-
-
-
-
(a)
Included in December were 2,850 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus
Incentive Compensation Plan in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards. The remaining shares of Ameren
common stock were purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of
Ameren’s obligation to distribute shares of common stock for vested performance units. Ameren does not have any publicly announced equity securities
repurchase plans or programs.
None of the other registrants purchased equity securities reportable under Item 703 of Regulation S-K during the
period from October 1, 2009 to December 31, 2009.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five years ended December 31,
2009. The graph also shows the cumulative total returns of the S&P 500 Index and the Edison Electric Institute Index (EEI
Index), which comprises most investor-owned electric utilities in the United States. The comparison assumes that $100
was invested on December 31, 2004, in Ameren common stock and in each of the indices shown, and it assumes that all
of the dividends were reinvested.
December 31,
Ameren ...................................................................................
S&P 500 Index ........................................................................
EEI Index ................................................................................
2004
$ 100
100
100
2005
$ 107.26
104.91
116.05
2006
$ 118.11
121.48
140.14
2007
$ 125.12
128.14
163.35
$
2008
81.84
80.73
121.04
$
2009
73.08
102.09
134.01
Ameren management cautions that the stock price performance shown in the graph above should not be considered
indicative of potential future stock price performance.
27
UE:
ITEM 6. SELECTED FINANCIAL DATA.
For the years ended December 31,
(In millions, except per share amounts)
Ameren:
Operating revenues(a) .............................................................
Operating income(a) ................................................................
Net income attributable to Ameren Corporation(a) ....................
Common stock dividends........................................................
Earnings per share – basic and diluted(a) ................................
Common stock dividends per share ........................................
As of December 31:
Total assets ............................................................................
Long-term debt, excluding current maturities ..........................
Preferred stock subject to mandatory redemption ...................
Total Ameren Corporation stockholders’ equity .......................
CIPS:
Operating revenues ................................................................
Operating income ...................................................................
Net income available to common stockholder .........................
Dividends to parent ................................................................
As of December 31:
Total assets ............................................................................
Long-term debt, excluding current maturities ..........................
Total stockholders’ equity .......................................................
Operating revenues ................................................................
Operating income ...................................................................
Net income available to common stockholder .........................
Dividends to parent ................................................................
As of December 31:
Total assets ............................................................................
Long-term debt, excluding current maturities ..........................
Total stockholders’ equity .......................................................
Genco:
As of December 31:
Operating revenues ................................................................
Operating income ...................................................................
Net income .............................................................................
Dividends to parent ................................................................
Total assets ............................................................................
Long-term debt, excluding current maturities ..........................
Subordinated intercompany notes (current and long-term) .....
Total stockholder’s equity .......................................................
CILCO:
As of December 31:
Operating revenues ................................................................
Operating income ...................................................................
Net income available to common stockholder .........................
Dividends to parent ................................................................
Total assets ............................................................................
Long-term debt, excluding current maturities ..........................
Preferred stock subject to mandatory redemption ...................
Total stockholders’ equity .......................................................
As of December 31:
Operating revenues ................................................................
Operating income ...................................................................
Net income available to common stockholder .........................
Dividends to parent ................................................................
Total assets ............................................................................
Long-term debt, excluding current maturities ..........................
Long-term debt to IP SPT, excluding current maturities...........
Total stockholders’ equity .......................................................
IP:
2009
2008
2007
2006
2005
$
$
7,090
1,416
612
338
2.78
1.54
$
7,839
1,362
605
534
2.88
2.54
7,562
1,359
618
527
2.98
2.54
$
6,895
1,188
547
522
2.66
2.54
$
6,780
1,284
606 (b)
511
3.02 (b)
2.54
$ 23,790
7,113
-
7,853
$ 22,671
6,554
-
6,963
$ 20,752
5,689
16
6,752
$ 19,662
5,285
17
6,583
$ 18,171
5,354
19
6,364
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2,960
514
245
264
11,529
3,673
3,562
982
42
12
-
1,920
421
529
908
330
175
101
2,244
774
87
695
1,147
132
68
-
2,296
279
-
684
1,696
103
3
60
3,770
1,150
-
1,251
2,961
590
336
267
10,903
3,208
3,601
1,005
49
14
40
1,866
456
517
876
258
125
113
1,968
474
126
648
1,011
143
74
-
1,867
148
16
622
1,646
109
24
61
3,331
1,014
-
1,308
$
$
$
$
$
$
$
$
$
$
2,823
620
343
249
10,290
2,934
3,153
954
69
35
50
1,861
471
543
992
131
49
113
1,850
474
163
563
747
78
45
65
1,656
148
17
535
1,694
141
55
-
3,227
772
92
1,346
$
$
$
$
$
$
$
$
$
$
2,889
640
346
280
9,277
2,698
3,016
934
85
41
35
1,784
410
569
1,038
257
97 (b)
88
1,811
474
197
444
742
63
24 (b)
20
1,557
122
19
562
1,653
202
95
76
3,056
704
184
1,287
$
$
$
$
$
$
$
$
$
$
2,874
566
259
175
12,301
4,018
4,057
869
68
26
47
1,965
421
574
850
310
155
-
2,535
823
45
862
1,082
252
134
20
2,382
279
-
855
1,504
230
77
31
3,942
1,147
-
1,451
28
(a)
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Included income (loss) from cumulative effect of change in accounting principle of $(22) million ($(0.11) per share) for Ameren, $(16) million for Genco, and
$(2) million for CILCO.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
OVERVIEW
Ameren Executive Summary
Operations
At Ameren’s rate-regulated utilities, milder weather and
the economic slowdown led to a 3% decrease in
kilowatthour sales to residential and commercial customers
in 2009, compared with 2008. However, this sales decline
was smaller, an estimated 1%, on a weather-normalized
basis. The weak economy also led to a decline in
kilowatthour sales by Ameren’s rate-regulated utilities to
their industrial customers. These sales declined 11% in
2009, compared with 2008, excluding the impact of reduced
sales to Noranda’s smelter plant in New Madrid, Missouri.
Noranda’s plant sustained damage because of a power
interruption on non-Ameren-owned power lines during a
severe ice storm in January 2009. As a result, the smelter’s
load was sharply reduced but has been rising steadily as
repairs have been made to the smelter plant’s production
lines, with full production expected to be reached in the
second quarter of 2010. Electric sales to industrial
customers, including Noranda, declined 17% in 2009,
compared with 2008.
For several years, Ameren’s rate-regulated utility
businesses have been earning returns on investment that
are well below their authorized levels, in part, due to
regulatory lag. Ameren is focused on improving earnings to
levels that represent fair returns on its rate-regulated
investments. Ameren has rate cases pending in both its
Illinois and Missouri jurisdictions. Ameren is seeking
revenue levels that reflect the significant investments it has
made in electric and gas utility infrastructure to improve
reliability. Ameren is also seeking recovery of higher
financing costs and, in Missouri, rising net fuel costs. The
Ameren Illinois Utilities are currently requesting a $130
million aggregate annual increase in base electric and
natural gas delivery rates. The staff of the ICC currently
supports a $46 million annual revenue increase. The staff’s
lower revenue amount reflects its lower recommended
return on equity of 10.1% compared to the Ameren Illinois
Utilities’ request of 11.5%, on a rate base weighted basis,
and use of a lower pension and benefits expense level,
among other things. In February 2010, administrative law
judges issued a consolidated proposed order, which
included a recommended revenue increase for electric
delivery service for the Ameren Illinois Utilities of $66 million
in the aggregate (CIPS – $26 million increase, CILCO – $6
million increase, and IP - $34 million increase) and a
recommended revenue net decrease for natural gas
delivery service of $10 million in the aggregate (CIPS – $1
million increase, CILCO – $6 million decrease, and IP - $5
million decrease). The ICC is not bound by the proposed
order issued by the administrative law judges. New rates
should be effective by early May 2010.
UE filed a request with the MoPSC in July 2009 for an
annual electric service rate increase of $402 million. More
than half of the request was for anticipated higher net fuel
costs. These increased net fuel costs would have been
eligible for recovery through the FAC absent this filing. The
MoPSC staff, in its direct testimony in the rate case,
recommended an annual electric service rate increase of
$218 million to $251 million, with approximately $214 million
of this related to higher net fuel costs. The staff’s lower
revenue amount reflects its lower recommended return on
equity range of 9.0% to 9.7%, which was lower than UE’s
initial request of 11.5%. The staff’s revenue amount also
incorporated lower depreciation, plant maintenance and
financing cost levels, as well as other adjustments. The
staff testimony reflects continuation of the FAC and the
pension and postretirement benefit cost trackers and a
modified environmental cost recovery mechanism. Other
parties filed testimony in the rate case, including a group of
large industrial customers and the Office of Public Counsel.
The Missouri Office of Public Counsel recommended a
return on equity of 10.2%. The large industrial customers
recommended a rate increase of $139 million, which
included a $181 million increase related to net fuel costs.
Their lower revenue requirement reflects their lower
recommended return on equity of 10%, the use of
significantly lower depreciation rates and plant maintenance
expenses, as well as lower financing costs, among other
things. The large industrial customers’ testimony reflects
continuation of the FAC, as well as a modified approach for
the accounting and recovery of environmental costs. In
February 2010, UE filed its rebuttal testimony in this rate
case, which included, among other things, a modification of
its recommended return on equity to 10.8%. It is anticipated
that certain major changes to revenues, expenses, rate
base, and capital structure will be trued-up through January
31, 2010, in a March 2010 UE update. A MoPSC order is
expected by late May 2010 with new rates expected to be
effective in late June 2010.
Current lower power prices are very much linked to
weak economic conditions. Weak economic conditions
have reduced the demand for power and other energy
commodities. Ameren believes that when the economy
recovers, these prices should rise. In the meantime,
Ameren continues to look for opportunities to prudently
reduce operating and capital spending in the Merchant
Generation business, as well as protect and enhance
margins. Ameren’s Merchant Generation business output is
significantly hedged over the next few years. Such hedging
protects credit quality and reduces earnings and cash flow
volatility. In addition, Ameren continues to focus on
providing value-added electricity products to the market.
29
Leveraging Ameren’s competitive merchant generating
assets, Marketing Company has a track record of enhancing
margins through sales to wholesale and retail customers. To
strengthen Merchant Generation’s ability to successfully
weather current lower power prices, Ameren has reduced
planned operating and capital spending, improving the cash
flow outlook for the Merchant Generation business. Ameren
continues to evaluate Merchant Generation’s spending plans
in light of changing technologies, power prices and delivered
fuel costs in order to ensure that the lowest cost options are
identified in terms of both capital and ongoing operating
costs.
Between 2010 and 2017, Ameren expects that certain
Ameren Companies will be required to make cumulative
investments of between $1.6 billion and $1.9 billion to retrofit
their coal-fired power plants with pollution control equipment
in compliance with existing emissions-related environmental
laws and regulations. Any pollution control investments will
result in decreased plant availability during construction and
higher ongoing operating expenses. Approximately 20% of
this investment is expected to be in Ameren’s Missouri
Regulated operations, and it is therefore expected to be
recoverable from ratepayers, but subject to prudency
reviews.
Earnings
Ameren reported net income of $612 million, or $2.78 per
share, for 2009 compared with net income of $605 million, or
$2.88 per share, in 2008. Factors contributing to the 10 cent
decline in earnings per share in 2009 compared with 2008
included lower electricity and natural gas sales in Ameren’s
rate-regulated businesses and lower margins in its Merchant
Generation business, as a result of weak economic
conditions, milder 2009 weather and, in the Missouri
Regulated business, the impact of reduced sales to Noranda.
Higher depreciation and interest expense, the absence in
2009 of the benefit of a lump-sum payment from a coal
supplier for higher fuel costs in 2009 as a result of a
premature mine closure and contract termination, and an
increased average number of common shares outstanding
also affected comparative results. Offsetting factors included
new utility rates in Illinois and Missouri, favorable unrealized
MTM activity on derivatives, and lower operations and
maintenance expenses due, in part, to the absence of a
refueling and maintenance outage at the Callaway nuclear
plant in 2009.
Liquidity
As a result of turmoil in the capital and credit markets in
2008 and 2009, we sought to improve our liquidity position.
We replaced and extended the expiration of our credit
facilities and sought to reduce our reliance on borrowings
from these credit facilities, increase cash balances and
increase the equity content of our capitalization. We also
sought to eliminate debt at CILCORP as a step in simplifying
our organizational structure. In addition, Ameren also
reduced planned spending, headcount and capital investment
across the company to mitigate the negative impact on sales
of a weak economy and related power prices. At December
31, 2009, Ameren, on a consolidated basis, had available
liquidity, in the form of cash on hand and amounts available
under its existing credit facilities, of approximately
$1.9 billion, which was $0.6 billion more than it had at the end
of 2008. Cash flows from operations of $2.0 billion in 2009 at
Ameren, along with other funds, were used to pay dividends
to common shareholders of $338 million and to fund capital
expenditures of $1.7 billion.
Capital Spending
During 2009, Ameren was able to significantly defer or
reduce planned capital spending, including spending for
environmental compliance, compared with previous plans.
Initiatives to limit greenhouse gas emissions and to
address global climate change are subject to active
consideration in the U.S. Congress. Although we cannot
predict the date of enactment or the requirements of any
future climate change legislation or regulations, we believe it
is possible that some form of federal legislation or regulations
to control emissions of greenhouse gases will become law
during President Obama’s administration. Potential impacts
from the climate change legislation could vary depending
upon proposed CO2 emission limits, the timing of
implementation of those limits, the method of distributing
allowances, the degree to which offsets are allowed and
available, and provisions for cost containment measures.
Future federal and state legislation or regulations that
mandate limits on the emission of greenhouse gases would
result in significant increases in capital expenditures and
operating costs, which, in turn, could lead to increased
liquidity needs and higher financing costs. Moreover, to the
extent Ameren requests recovery of these costs through
rates, its regulators might deny some or all of, or defer timely
recovery of, these costs. Excessive costs to comply with
future legislation or regulations might force UE, Genco,
CILCO (through AERG) and EEI and other similarly-situated
electric power generators to close some coal-fired facilities,
and it could lead to possible impairment of assets and
reduced revenues. As a result, mandatory limits could have a
material adverse impact on Ameren’s, UE’s, Genco’s,
CILCO’s (through AERG) and EEI’s results of operations,
financial position, or liquidity.
General
Ameren, headquartered in St. Louis, Missouri, is a public
utility holding company under PUHCA 2005, administered by
FERC. Ameren’s primary assets are the common stock of its
subsidiaries. Ameren’s subsidiaries are separate,
independent legal entities with separate businesses, assets,
and liabilities. These subsidiaries operate, as the case may
be, rate-regulated electric generation, transmission, and
distribution businesses, rate-regulated natural gas
transmission and distribution businesses, and merchant
electric generation businesses in Missouri and Illinois.
Dividends on Ameren’s common stock and the payment of
other expenses by Ameren depend on distributions made to it
by its subsidiaries. See Note 1 – Summary of Significant
Accounting Policies under Part II, Item 8, of this report for a
detailed description of our principal subsidiaries.
UE operates a rate-regulated electric generation,
transmission and distribution business, and a rate-
30
regulated natural gas transmission and distribution
business in Missouri.
CIPS operates a rate-regulated electric and natural gas
transmission and distribution business in Illinois.
Genco operates a merchant electric generation business
in Illinois and Missouri.
CILCO operates a rate-regulated electric transmission
and distribution business, a merchant electric generation
business (through its subsidiary, AERG), and a rate-
regulated natural gas transmission and distribution
business, all in Illinois.
IP operates a rate-regulated electric and natural gas
transmission and distribution business in Illinois.
The financial statements of Ameren are prepared on a
consolidated basis and therefore include the accounts of its
majority-owned subsidiaries. All significant intercompany
transactions have been eliminated. All tabular dollar amounts
are expressed in millions, unless otherwise indicated.
In addition to presenting results of operations and
earnings amounts in total, we present certain information in
cents per share. These amounts reflect factors that directly
affect Ameren’s earnings. We believe this per share
information helps readers to understand the impact of these
factors on Ameren’s earnings per share. All references in this
report to earnings per share are based on average diluted
common shares outstanding during the applicable year.
RESULTS OF OPERATIONS
Earnings Summary
Our results of operations and financial position are
affected by many factors. Weather, economic conditions, and
the actions of key customers or competitors can significantly
affect the demand for our services. Our results are also
affected by seasonal fluctuations: winter heating and summer
cooling demands. The vast majority of Ameren’s revenues
are subject to state or federal regulation. This regulation has
a material impact on the price we charge for our services.
Merchant Generation sales are also subject to market
conditions for power. We principally use coal, nuclear fuel,
natural gas, and oil for fuel in our operations. The prices for
these commodities can fluctuate significantly due to the
global economic and political environment, weather, supply
and demand, and many other factors. We have natural gas
cost recovery mechanisms for our Illinois and Missouri gas
delivery service businesses, purchased power cost recovery
mechanisms for our Illinois electric delivery service
businesses, and a FAC for our Missouri electric utility
business. See Note 2 – Rate and Regulatory Matters under
Part II, Item 8, for a discussion of pending rate cases in
Missouri and Illinois, including UE’s request for approval to
implement an environmental cost recovery mechanism and to
continue its FAC. Fluctuations in interest rates and conditions
in the capital and credit markets affect our cost of borrowing
and our pension and postretirement benefits costs. We
employ various risk management strategies to reduce our
exposure to commodity risk and other risks inherent in our
business. The reliability of our power plants and transmission
and distribution systems and the level of purchased power
costs, operating and administrative costs, and capital
investment are key factors that we seek to control to optimize
our results of operations, financial position, and liquidity.
Net income attributable to Ameren Corporation was $612
million, or $2.78 per share, for 2009, $605 million, or $2.88
per share for 2008, and $618 million, or $2.98 per share, for
2007.
Net income attributable to Ameren Corporation increased
$7 million and its earnings per share decreased 10 cents in
2009 compared with 2008. Net income attributable to Ameren
Corporation increased in the Illinois Regulated and Missouri
Regulated segments by $92 million and $25 million,
respectively, in 2009 compared with 2008, while net income
attributable to Ameren Corporation in the Merchant
Generation segment decreased by $105 million in 2009
compared with 2008.
Compared with 2008 earnings, 2009 earnings were
negatively affected by:
higher dilution and financing costs (31 cents per share);
the impact on electric and natural gas margins in our
rate-regulated businesses of higher net fuel costs at UE
and lower demand (exclusive of weather impacts),
among other things (30 cents per share);
the absence in 2009 of the benefit of a settlement
agreement reached with a coal mine owner that
reimbursed Genco, in the form of a lump-sum payment,
for increased costs for coal and transportation incurred in
2008 and 2009 due to the premature closure of an Illinois
mine and contract termination (18 cents per share);
the impact of milder weather conditions on energy
demand (estimated at 15 cents per share);
increased depreciation and amortization expenses
(12 cents per share);
reduced sales to Noranda because of an extended
storm-related outage (11 cents per share);
the absence in 2009 of a MoPSC rate order establishing
two separate regulatory assets for previously incurred
storm and MISO related costs (11 cents per share);
increased expense related to work force reductions
through voluntary and involuntary separation programs
and asset impairment charges recorded primarily at
Genco in 2009 (7 cents per share);
increased taxes other than income taxes, primarily
because of higher property taxes (6 cents per share);
lower realized electric margins in the Merchant
Generation segment largely due to lower sales volumes
and higher fuel and related transportation costs (5 cents
per share); and
increased distribution system reliability expenditures
(5 cents per share).
Compared with 2008 earnings, 2009 earnings were
favorably affected by:
higher electric and natural gas delivery service rates,
effective October 1, 2008, in the Illinois Regulated
segment pursuant to an ICC consolidated rate order for
31
CIPS, CILCO and IP (40 cents per share);
higher electric rates, effective March 1, 2009, in the
Missouri Regulated segment pursuant to a MoPSC
rate order (40 cents per share);
favorable net unrealized MTM activity on derivatives
and from changes in the market value of investments
used to support Ameren’s deferred compensation
plans (21 cents per share);
Trails and Sterling Avenue generation facilities to their
estimated fair values as of December 31, 2008 (6
cents per share);
increased depreciation and amortization expenses
(6 cents per share);
the absence in 2008 of the reversal, recorded in 2007,
of the Illinois Customer Elect electric rate increase
phase-in plan accrual (5 cents per share);
decreased plant operations and maintenance expense
higher labor and employee benefit costs (5 cents per
share); and
higher bad debt expenses (3 cents per share).
Compared with 2007 earnings, 2008 earnings were
favorably affected by:
higher realized electric margins in the Merchant
Generation segment;
the absence in 2008 of costs that were incurred in
January 2007 associated with electric outages caused
by severe ice storms, and the amount of these costs
that UE will recover as a result of an accounting order
issued by the MoPSC, which was recorded as a
regulatory asset in 2008 (16 cents per share);
the reduced impact in 2008 of the electric rate relief
and customer assistance programs provided to certain
Ameren Illinois Utilities electric customers under the
2007 Illinois Electric Settlement Agreement (13 cents
per share);
the absence in 2008 of a March 2007 FERC order that
resettled costs among MISO market participants
retroactive to 2005 that was recorded in 2007, and the
subsequent recovery of a portion of these costs in
2008, through a MoPSC order (10 cents per share);
higher electric and natural gas delivery service rates in
the Illinois Regulated segment pursuant to the ICC
consolidated rate order for CIPS, CILCO, and IP
issued in September 2008 (9 cents per share);
the benefit of a settlement agreement with a coal mine
owner reached in June 2008 that reimbursed Genco,
in the form of a lump-sum payment, for increased
costs for coal and transportation that it expected to
incur in 2009 due to the premature closure of an
Illinois mine and contract termination (8 cents per
share);
higher electric rates, lower depreciation expense, and
decreased income tax expense in the Missouri
Regulated segment pursuant to the MoPSC electric
rate order for UE issued in May 2007 (8 cents per
share); and
the reduced impact of the Callaway nuclear plant
refueling and maintenance outage in 2008, as
compared with the prior-year refueling and
maintenance outage (4 cents per share).
The cents per share information presented above is
based on average shares outstanding in 2007.
(15 cents per share);
the absence in 2009 of a Callaway nuclear plant
refueling and maintenance outage (9 cents per share);
the absence in 2009 of asset impairment charges
recorded to adjust the carrying value of CILCO’s
(through AERG) Indian Trails and Sterling Avenue
generating facilities to their estimated fair values as of
December 31, 2008 (6 cents per share); and
the reduced impact in 2009 of the electric rate relief
and customer assistance programs provided to certain
Ameren Illinois Utilities electric customers under the
2007 Illinois Electric Settlement Agreement (5 cents
per share).
The cents per share information presented above is
based on average shares outstanding in 2008.
Net income attributable to Ameren Corporation
decreased $13 million and its earnings per share
decreased 10 cents in 2008 compared with 2007. Net
income attributable to Ameren Corporation increased in
the Merchant Generation segment by $71 million in 2008
compared with 2007, while net income attributable to
Ameren Corporation in the Missouri Regulated and Illinois
Regulated segments decreased by $47 million and
$15 million, respectively. Other net income decreased
$22 million in 2008 compared with 2007, primarily
because of net unrealized MTM losses on nonqualifying
hedges mainly related to fuel-related transactions and
reduced interest and dividend income.
Compared with 2007 earnings, 2008 earnings were
negatively affected by:
higher fuel and related transportation prices, excluding
net MTM losses on fuel-related transactions (27 cents
per share);
increased distribution system reliability expenditures
(16 cents per share);
higher plant operations and maintenance expenses
(16 cents per share);
the impact of unfavorable milder weather conditions on
energy demand (estimated at 16 cents per share);
net unrealized MTM losses on nonqualifying hedges
(11 cents per share);
higher dilution and financing costs (10 cents per
share);
asset impairment charges recorded to adjust the
carrying value of CILCO’s (through AERG) Indian
32
Because it is a holding company, Ameren’s net income and cash flows are primarily generated by its principal
subsidiaries: UE, CIPS, Genco, CILCO and IP. The following table presents the contribution by Ameren’s principal
subsidiaries to Ameren’s consolidated net income for the years ended December 31, 2009, 2008 and 2007:
Net income (loss):
UE(a) .......................................................................................................................................................................
CIPS .......................................................................................................................................................................
Genco .....................................................................................................................................................................
CILCO .....................................................................................................................................................................
IP ..........................................................................................................................................................................
Other(b) ...................................................................................................................................................................
Net income attributable to Ameren Corporation .............................................................................................................
2009
2008
2007
$ 259
26
155
134
77
(39 )
$ 612
$ 245
12
175
68
3
102
$ 605
$ 336
14
125
74
24
45
$ 618
(a)
(b)
Includes earnings from a 40% interest in EEI through February 29, 2008.
Includes earnings from other merchant generation, including CILCORP, as well as corporate, general and administrative expenses, and intercompany
eliminations. Includes a 40% interest in EEI through February 29, 2008, and an 80% interest in EEI since that date.
Below is a table of income statement components by segment for the years ended December 31, 2009, 2008 and
2007:
$
Other /
Intersegment
Eliminations
(22 )
-
(8 )
32
(26 )
(2 )
(11 )
(7 )
24
(20 )
2
(18 )
$
$ (47)
(5 )
(3 )
48
(28 )
(1 )
(15 )
(4 )
40
(15 )
2
(13 )
$
$
$
(51 )
(8 )
(5 )
76
(26 )
(1 )
(8 )
10
20
7
2
9
Total
$ 3,859
432
-
(1,738 )
(725 )
(412 )
48
(508 )
(332 )
624
(12 )
612
$
$ 3,882
415
-
(1,857 )
(685 )
(393 )
49
(440 )
(327 )
644
(39 )
605
$
$
$
3,729
379
-
(1,687 )
(681 )
(381 )
50
(423 )
(330 )
656
(38 )
618
2009
Electric margins ......................................................................................
Natural gas margins ................................................................................
Other revenues .......................................................................................
Other operations and maintenance .........................................................
Depreciation and amortization .................................................................
Taxes other than income taxes ...............................................................
Other income and (expenses) .................................................................
Interest charges ......................................................................................
Income (taxes) benefit.............................................................................
Net income (loss) ....................................................................................
Noncontrolling interest and preferred dividends .......................................
Net income (loss) attributable to Ameren Corporation ..............................
2008
Electric margins ......................................................................................
Natural gas margins ................................................................................
Other revenues .......................................................................................
Other operations and maintenance .........................................................
Depreciation and amortization .................................................................
Taxes other than income taxes ...............................................................
Other income and (expenses) .................................................................
Interest charges ......................................................................................
Income (taxes) benefit.............................................................................
Net income (loss) ....................................................................................
Noncontrolling interest and preferred dividends .......................................
Net income (loss) attributable to Ameren Corporation ..............................
2007
Electric margins ......................................................................................
Natural gas margins ................................................................................
Other revenues .......................................................................................
Other operations and maintenance .........................................................
Depreciation and amortization .................................................................
Taxes other than income taxes ...............................................................
Other income and (expenses) .................................................................
Interest charges ......................................................................................
Income (taxes) benefit.............................................................................
Net income .............................................................................................
Noncontrolling interest and preferred dividends .......................................
Net income attributable to Ameren Corporation .......................................
Missouri
Regulated
$ 1,983
73
4
(880)
(357)
(257)
56
(229)
(128)
265
(6)
259
$
$ 1,924
78
3
(922)
(329)
(240)
53
(193)
(134)
240
(6)
234
$
$
$
1,984
70
2
(900)
(333)
(234)
35
(194)
(143)
287
(6)
281
Illinois
Regulated
$ 886
359
4
(550)
(216)
(125)
2
(153)
(77)
130
(6)
124
$
$ 817
342
-
(627)
(219)
(126)
11
(144)
(16)
38
(6)
32
$
$
$
759
317
3
(550)
(217)
(121)
20
(132)
(25)
54
(7)
47
Merchant
Generation
$ 1,012
-
-
(340)
(126)
(28)
1
(119)
(151)
249
(2)
247
$
$
$
$
$
1,188
-
-
(356)
(109)
(26)
-
(99)
(217)
381
(29)
352
1,037
-
-
(313)
(105)
(25)
3
(107)
(182)
308
(27)
281
33
Margins
The following table presents the favorable (unfavorable) variations in the registrants’ electric and natural gas margins
from the previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. Natural
gas margins are defined as gas revenues less gas purchased for resale. The table covers the years ended December 31,
2009, 2008, and 2007. We consider electric and natural gas margins useful measures to analyze the change in
profitability of our electric and natural gas operations between periods. We have included the analysis below as a
complement to the financial information we provide in accordance with GAAP. However, these margins may not be a
presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful
than the GAAP information we provide elsewhere in this report.
2009 versus 2008
Ameren (a)
UE
CIPS
Genco
CILCO
IP
Electric revenue change:
Effect of weather (estimate) ................................................... $
Regulated rates:
Changes in base rates .....................................................
Noranda sales .................................................................
Illinois pass-through power supply costs ..........................
Sales price changes, including hedge effect ..........................
Off-system revenues .............................................................
2007 Illinois Electric Settlement Agreement, net of
reimbursement .................................................................
Supply Cost Adjustment factor ...............................................
Net unrealized MTM losses ...................................................
Generation output, load and other .........................................
Total electric revenue change ..................................................... $
Fuel and purchased power change:
Fuel:
(47 )
229
(50 )
(338 )
115
(89 )
15
7
(110 )
(190 )
(458 )
$
$
(33)
141
(50)
-
-
(89)
-
-
-
(25)
(56)
Generation and other ....................................................... $ 126
Net unrealized MTM gains ...............................................
118
Price ................................................................................
(83 )
Coal contract settlement ........................................................
(27 )
Purchased power ..................................................................
(25 )
Illinois pass-through power supply costs ................................
338
FERC-ordered MISO resettlements .......................................
(12 )
Total fuel and purchased power change ...................................... $ 435
Net change in electric margins ................................................ $
(23 )
Natural gas margins change:
$ 21
58
-
-
48
-
(12)
$ 115
59
$
$
(3)
$
-
-
-
136
-
7
-
-
(201)
$ (58)
$
79
33
(46)
(27)
-
-
-
$ 39
(19)
$
$
(4)
$
(7 )
(2)
-
(104)
60
-
4
1
-
3
$ (42)
$
2
7
(3)
-
18
104
-
$ 128
86
$
73
-
(145 )
-
-
2
4
-
(6 )
$ (79 )
$
-
-
-
-
-
145
-
$ 145
66
$
17
-
(89)
-
-
2
2
-
(7)
$ (78)
$
-
-
-
-
-
89
-
$ 89
11
$
Effect of weather (estimate) ................................................... $
Changes in base rates ...........................................................
Absence of capitalization of nonrecoverable gas costs...........
Net unrealized 2008 MTM losses...........................................
Other .....................................................................................
Net change in natural gas margins .......................................... $
(7 )
34
(5 )
12
(17 )
17
$
$
(1)
-
-
-
(4)
(5)
$
$
(1)
7
(1)
-
(4)
1
$
$
-
-
-
-
-
-
$
$
(1)
(6)
-
12
(8)
(3)
$
$
(4 )
33
(4 )
-
(2 )
23
34
2008 versus 2007
Ameren (a)
UE
CIPS
Genco
CILCO
IP
Electric revenue change:
Effect of weather (estimate) ................................................... $
Regulated rates:
Changes in base rates .....................................................
Illinois pass-through power supply costs ..........................
Sales price changes, including hedge effect ..........................
Off-system revenues, excluding estimated weather impact of
2007 Illinois Electric Settlement Agreement, net of
$53 million .......................................................................
reimbursement .................................................................
FERC-ordered MISO resettlements .......................................
Supply Cost Adjustment factor ...............................................
Net unrealized MTM gains .....................................................
Generation output, load and other .........................................
Total electric revenue change ..................................................... $
Fuel and purchased power change:
Fuel:
(59)
43
(91)
106
(42)
35
(17)
(2)
81
30
84
$
$
(36)
16
-
-
(47)
-
-
-
8
29
(30)
$
$
(6)
5
(58)
-
-
6
-
(2)
-
3
(52)
$
-
$
-
-
45
-
13
(12)
-
-
(14)
$ 32
$
(4)
-
15
18
-
9
(4)
5
-
51
90
$
$
(13 )
22
(48 )
-
-
7
-
(5 )
-
4
(33 )
Generation and other ....................................................... $
33
Net unrealized MTM losses ..............................................
(75)
Price ................................................................................
(93)
Coal contract settlement for 2009 ..........................................
27
Purchased power ..................................................................
39
Illinois pass-through power supply costs ................................
91
FERC-ordered MISO resettlements .......................................
47
Total fuel and purchased power change ...................................... $
69
Net change in electric margins ................................................ $ 153
Natural gas margins change:
$ 31
(39)
(56)
-
9
-
23
(32)
(62)
$
$
$
-
-
-
-
-
58
8
$ 66
14
$
Effect of weather (estimate) ................................................... $
Changes in base rates ...........................................................
Capitalization of nonrecoverable gas costs ............................
Net unrealized MTM losses ...................................................
Other .....................................................................................
Net change in natural gas margins .......................................... $
2
1
2
-
2
7
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
12
7
9
(6)
14
36
2
3
-
-
3
8
(a)
$
$
$
$
$
$
$
$
$
31
(18)
(13)
27
23
-
-
50
82
-
-
-
-
-
-
$
(32)
(3)
(15)
-
-
(15)
4
(61)
$
$ 29
$
-
-
-
-
-
48
12
60
$
$ 27
$
$
2
(5)
-
(6)
8
(1)
$
$
6
8
7
-
(3 )
18
2009 versus 2008
Ameren
Ameren’s electric margins decreased by $23 million,
or 1%, in 2009 compared with 2008. The following items
had an unfavorable impact on Ameren’s electric margins:
Higher net fuel expense at UE of $20 million resulting
from lower off-system revenues ($89 million), offset, in
part, by lower fuel-generation and other ($21 million)
and purchased power ($48 million).
Net unrealized MTM activity in the Merchant
Generation segment of $110 million (Marketing
Company net loss of $112 million and EEI net gain of
$2 million) on energy transactions, primarily related to
nonqualifying hedges of changes in market prices for
electricity.
Higher fuel expense at Genco as a result of its June
2008 settlement agreement with a coal mine owner to
receive a lump-sum payment of $60 million for the
early termination of a coal supply contract. This
payment compensated Genco, in total, for higher fuel
costs it incurred throughout 2008 ($33 million) and
2009 ($27 million). Because the entire settlement was
recorded in earnings in 2008, Ameren’s earnings in
2009 were comparatively lower than they otherwise
would have been.
Excluding the impact of the June 2008 settlement
agreement, 5% higher fuel prices in the Merchant
Generation segment.
Reduced sales by UE to Noranda, due to an extended
severe storm-related outage, which lowered electric
revenues by $50 million in 2009. See Outlook for
additional information on the Noranda plant outage.
Unfavorable weather conditions, as evidenced by a
7% reduction in cooling degree-days, which decreased
margins by $43 million.
Excluding the impact of UE’s reduced sales to
Noranda, lower weather-normalized end-use retail
sales volume of 4% in Ameren’s rate-regulated utilities,
largely a result of the economic slowdown, which
decreased margins by $23 million.
Decreased power plant utilization in the Merchant
Generation segment, primarily because of lower
market prices, which resulted in fewer opportunities for
economic sales, and transmission congestion, which
limited the period when power could be sold. Merchant
Generation’s baseload, coal-fired generating plants’
equivalent availability factors were 81% in 2009,
35
compared with 85% in 2008, and the average capacity
factor was 66% in 2009, compared with 76% in 2008.
The following items had a favorable impact on Ameren’s
electric margins for 2009 compared with 2008:
Higher electric rates at UE, effective March 1, 2009,
which increased margins by $141 million, and at the
Ameren Illinois Utilities, effective October 1, 2008, which
increased margins by $88 million.
Net unrealized MTM activity at UE of $58 million on
energy and fuel-related transactions. During 2009 UE
reversed and deferred as regulatory assets previously
recorded net MTM losses of $42 million on energy and
fuel-related transactions in the first quarter of 2009, when
these costs became probable of recovery because of the
FAC. See Note 7 – Derivative Financial Instruments
under Part II, Item 8, of this report, for additional
information.
Net unrealized MTM activity at the Merchant Generation
segment of $55 million (Genco – $33 million, CILCO –
$7 million, EEI – $15 million) on fuel-related transactions.
These were primarily associated with financial
instruments that were acquired to mitigate the risk of
rising diesel fuel price adjustments embedded in coal
transportation contracts.
The repricing of wholesale and retail electric power
supply agreements and financial swaps that settled at
higher margins at Merchant Generation.
Higher wholesale sales margins at UE of $32 million
because of additional customers and higher-priced
wholesale sales contracts. Power was available for sale
to wholesale customers as a result of reduced native
load demand.
The recovery of power supply costs incurred by the
Ameren Illinois Utilities of $7 million, including an
increase in Supply Cost Adjustment (SCA) factors as
approved in the 2008 ICC electric rate order.
A $15 million reduction in the impact of the 2007 Illinois
Electric Settlement Agreement.
Higher Callaway nuclear plant availability due to the
absence of a 30-day planned maintenance outage, which
occurred in the fourth quarter of 2008.
Ameren’s natural gas margins increased by $17 million,
or 4%, in 2009 compared with 2008. The following items had
a favorable impact on Ameren’s natural gas margins:
The Ameren Illinois Utilities’ net gas delivery service rate
increase, effective October 1, 2008, which increased
margins by $34 million.
The absence of net unrealized MTM losses at CILCO of
$12 million in 2009 on natural gas swaps.
The following items had an unfavorable impact on
Ameren’s natural gas margins in 2009 compared with 2008:
Unfavorable weather conditions, as evidenced by an 8%
reduction in heating degree-days, which decreased
margins by $7 million.
7% lower weather-normalized sales volumes, largely a
result of the economic slowdown, which decreased
margins by $9 million.
The absence of the capitalization of nonrecoverable
purchased gas costs in accordance with the September
2008 ICC gas rate order, which resulted in a one-time
increase in margins of $5 million in 2008.
Missouri Regulated (UE)
UE’s electric margins increased $59 million, or 3%, in
2009 compared with 2008. The following items had a
favorable impact on UE’s electric margins:
Higher electric rates, effective March 1, 2009, which
increased margins by $141 million.
Net unrealized MTM activity of $58 million on energy and
fuel-related transactions. During 2009 UE reversed and
deferred as regulatory assets previously recorded net
MTM losses of $42 million on energy and fuel-related
transactions in the first quarter of 2009, when these costs
became probable of recovery because of the FAC. See
Note 7 – Derivative Financial Instruments under Part II,
Item 8, of this report, for additional information.
Higher wholesale sales margins of $32 million due to
additional customers and higher-priced wholesale sales
contracts. Power was available for sale to wholesale
customers as a result of reduced native load demand.
Higher Callaway nuclear plant availability due to the
absence of a 30-day planned maintenance outage, which
occurred in the fourth quarter of 2008.
The following items had an unfavorable impact on UE’s
electric margins in 2009 compared with 2008:
Higher net fuel expense of $20 million resulting from
lower off-system revenues ($89 million), offset, in part, by
lower fuel-generation and other ($21 million) and
purchased power ($48 million).
Reduced sales to Noranda, due to an extended severe
storm-related outage, which lowered electric revenues by
$50 million. See Outlook for additional information on the
Noranda plant outage.
Unfavorable weather conditions, as indicated by a 13%
reduction in cooling degree-days during the third quarter,
which is UE’s peak cooling period, and a mild winter,
which decreased margins by $29 million.
Excluding the impact of reduced sales to Noranda, 2%
lower weather-normalized end-use retail sales volumes,
largely a result of the economic slowdown, which
decreased margins by $18 million.
The absence in 2009 of the benefits from a MoPSC order
that directed the recording of a regulatory asset related
to previously incurred costs for a 2007 FERC order,
which decreased margins by $12 million.
UE’s natural gas margins decreased by $5 million, or
6%, in 2009 compared with 2008, primarily because of an 8%
decrease in weather-normalized sales volumes in 2009.
Illinois Regulated
Illinois Regulated’s electric margins increased by
$69 million, or 8%, in 2009 compared with 2008. Illinois
Regulated’s natural gas margins increased by $17 million, or
5%, in 2009 compared with 2008. The Ameren Illinois
36
Utilities have a cost recovery mechanism for power
purchased on behalf of their customers. These pass-through
power costs do not affect margins; however, the electric
revenues and offsetting purchased power costs fluctuate
primarily because of customer switching and usage. See
below for explanations of electric and natural gas margin
variances for the Illinois Regulated segment.
CIPS
CIPS’ electric margins increased by $11 million, or 4%, in
2009 compared with 2008. The following items had a
favorable impact on electric margins:
Higher electric delivery service rates, effective October 1,
2008, which increased margins by $17 million in 2009.
The recovery of power supply costs incurred of
$2 million, including an increase in the SCA factors, as
approved in the 2008 ICC electric rate order.
A $2 million reduction in the impact of the 2007 Illinois
Electric Settlement Agreement.
The following items had an unfavorable impact on CIPS’
electric margins in 2009 compared with 2008:
Net transmission margins that were $4 million lower,
primarily because of reduced transmission service rates
that were based on lower transmission costs in the prior
year.
Unfavorable weather conditions, as evidenced by a 7%
reduction in cooling degree-days, which decreased
margins by $3 million.
CIPS’ natural gas margins increased by $1 million, or
1%, in 2009 compared with 2008. This was primarily due to
higher gas delivery service rates, effective October 1, 2008,
which increased margins by $7 million.
The following items had an unfavorable impact on CIPS’
natural gas margins in 2009 compared with 2008:
Unfavorable weather conditions, as evidenced by an 8%
reduction in heating degree-days, which decreased
margins by $1 million.
3% lower weather-normalized sales volumes for 2009,
largely a result of the economic slowdown, which
decreased margins by $2 million.
The absence of the capitalization of nonrecoverable
purchased gas costs in accordance with the September
2008 ICC gas rate order, which resulted in a one-time
increase in margins of $1 million in 2008.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s
change in electric margins by segment to CILCO’s total
change in electric margins for 2009 compared with 2008:
CILCO (Illinois Regulated)....................................
CILCO (AERG) ....................................................
Total change in electric margins ...........................
2009 versus 2008
$ (8 )
94
$ 86
CILCO’s (Illinois Regulated) electric margins decreased
by $8 million, or 5%, in 2009 compared with 2008. The
following items had an unfavorable impact on electric
margins:
Lower electric delivery service rates, effective October 1,
2008, which decreased margins by $2 million.
Unfavorable weather conditions, as evidenced by a 25%
reduction in cooling degree-days, which decreased
margins by $4 million.
10% lower weather-normalized sales volumes, primarily
in the lower-margin industrial customer sector, largely a
result of the economic slowdown, which decreased
margins by $1 million.
CILCO’s (Illinois Regulated) electric margins were
favorably affected in 2009 compared with 2008 by:
The recovery of power supply costs incurred of
$1 million, including an increase in the SCA factors, as
approved in the 2008 ICC electric rate order.
A $1 million reduction in the impact of the 2007 Illinois
Electric Settlement Agreement.
See Merchant Generation below for an explanation of
CILCO’s (AERG) electric margins in 2009 compared with
2008.
CILCO’s (Illinois Regulated) natural gas margins
decreased by $3 million, or 3%, in 2009 compared with 2008.
CILCO’s natural gas margins were unfavorably affected by:
12% lower weather-normalized sales volumes and lower
realized prices related to a contract with a large industrial
customer for 2009, largely a result of the economic
slowdown, which decreased margins by $8 million.
Lower gas delivery service rates, effective October 1,
2008, which decreased margins by $6 million.
Unfavorable weather conditions, as evidenced by a 5%
reduction in heating degree-days, which decreased
margins by $1 million.
CILCO’s natural gas margins were favorably affected in
2009 compared with 2008 by the absence of net unrealized
MTM losses of $12 million in 2009 on natural gas swaps.
IP
IP’s electric margins increased by $66 million, or 16%, in
2009 compared with 2008. The following items had a
favorable impact on electric margins:
Higher electric delivery service rates, effective October 1,
2008, which increased margins by $73 million.
The recovery of power supply costs incurred of
$4 million, including an increase in the SCA factors, as
approved in the 2008 ICC electric rate order.
A $2 million reduction in the impact of the 2007 Illinois
Electric Settlement Agreement.
IP’s electric margins were unfavorably affected in 2009
compared to 2008 by:
Unfavorable weather conditions, as evidenced by a 12%
reduction in cooling degree-days, which decreased
margins by $7 million.
37
Excluding the impact of the June 2008 settlement
agreement, 3% higher fuel prices.
Genco’s electric margins were favorably affected in 2009
compared with 2008 by:
Net unrealized MTM activity of $33 million on fuel-related
transactions. These were primarily associated with
financial instruments that were acquired to mitigate the
risk of rising diesel fuel price adjustments embedded in
coal transportation contracts.
Lower emission allowance costs because of lower prices
and reduced generation increased margins by
$11 million.
A $7 million reduction in the impact of the 2007 Illinois
Electric Settlement Agreement.
CILCO (AERG)
AERG’s electric margins increased by $94 million, or
43%, in 2009 compared with 2008. The following items had a
favorable impact on electric margins:
Higher revenues allocated to AERG under its power
supply agreement (AERG PSA) with Marketing
Company, which were because of higher reimbursable
expenses and higher generation relative to Genco in
accordance with the AERG PSA. AERG’s baseload coal-
fired generating plants’ equivalent availability and
average capacity factors were comparable to 2008.
Financial swaps also settled at higher margins, and new
higher-priced wholesale and retail electric power supply
agreements increased revenues.
Net unrealized MTM activity of $7 million on fuel-related
transactions. These were primarily associated with
financial instruments that were acquired to mitigate the
risk of rising diesel fuel price adjustments embedded in
coal transportation contracts.
Oil consumption was lower because of fewer plant
startups and lower oil prices in 2009, reducing costs by
$6 million.
A $3 million reduction in the impact of the 2007 Illinois
Electric Settlement Agreement.
Other Merchant Generation
Electric margins from Ameren’s other Merchant
Generation operations, primarily EEI and Marketing
Company, decreased by $251 million, or 66%, in 2009. Other
Merchant Generation electric margins were unfavorably
affected, compared with 2008, by:
Decreased power plant utilization, primarily because of
lower market prices, which resulted in fewer
opportunities for economic sales, and plant outages. The
average realized sales price for power including hedging
decreased by 27%. EEI’s baseload coal-fired generating
plant’s equivalent availability and average capacity
factors were 88% and 81%, respectively, in 2009,
compared with 92% and 91%, respectively, in 2008.
4% lower weather-normalized sales volumes, primarily in
the lower-margin industrial customer sector, largely as a
result of the economic slowdown, which decreased
margins by $6 million.
IP’s natural gas margins increased by $23 million, or
14%, in 2009 compared with 2008. This was primarily due to
higher gas delivery service rates, effective October 1, 2008,
which increased margins by $33 million.
The following items had an unfavorable impact on IP’s
natural gas margins in 2009 compared with 2008:
Unfavorable weather conditions, as evidenced by an 8%
reduction in heating degree-days, which decreased
margins by $4 million.
The absence of the capitalization of nonrecoverable
purchased gas costs in accordance with the September
2008 ICC gas rate order, which resulted in a one-time
increase in margins of $4 million in 2008.
4% lower weather-normalized sales volumes, largely a
result of the economic slowdown, which decreased
margins by $3 million.
Merchant Generation
Merchant Generation’s electric margins decreased by
$176 million, or 15%, in 2009 compared with 2008.
Genco
Genco’s electric margins decreased by $19 million, or
3%, in 2009 compared with 2008. The following items had an
unfavorable impact on electric margins:
Decreased power plant utilization, primarily due to lower
market prices, which resulted in fewer opportunities for
economic sales, and transmission congestion, which
limited the period when power could be sold. In addition,
one of Genco’s coal-fired power plants experienced a
transformer fire in September 2009, which put two units
out of service for a period of time. This contributed to a
reduction in Genco’s baseload coal-fired generating
plants’ equivalent availability factor to 81% in 2009,
compared with 86% in 2008. Genco’s average capacity
factor also decreased to 60% in 2009, compared with
73% in 2008.
Lower revenues allocated to Genco under its power
supply agreement (Genco PSA) with Marketing
Company, which were because of lower reimbursable
expenses and lower generation relative to AERG in
accordance with the Genco PSA, partially offset by
financial swaps settling at higher margins and new
higher-priced wholesale and retail electric power supply
agreements.
Higher fuel expense as a result of Genco’s June 2008
settlement agreement with a coal mine owner to receive
a lump-sum payment of $60 million for the early
termination of a coal supply contract. This payment
compensated Genco, in total, for higher fuel costs it
incurred throughout 2008 ($33 million) and 2009
($27 million). Because the entire settlement was
recorded in earnings in the second quarter of 2008,
Genco’s earnings in 2009 were comparatively lower than
they otherwise would have been.
38
27% higher fuel prices at EEI because of an increase in
transportation costs.
Net unrealized MTM activity (mostly at Marketing
Company) of $95 million on energy and fuel-related
transactions. These were primarily associated with
financial instruments that related to nonqualifying hedges
of changes in market prices for electricity.
2008 versus 2007
Ameren
Ameren’s electric margins increased by $153 million, or
4%, in 2008 compared with 2007. The following items had a
favorable impact on Ameren’s electric margins:
Net unrealized MTM gains of $81 million on energy
transactions, primarily related to nonqualifying hedges of
changes in market prices for electricity.
Increased Merchant Generation plant availability due to
the lack of an extended plant outage in 2008. Merchant
Generation’s baseload coal-fired generating plants’
average capacity and equivalent availability factors were
approximately 76% and 85%, respectively, in 2008
compared with 74% and 81%, respectively, in 2007.
Higher electric rates at the Ameren Illinois Utilities,
effective October 1, 2008, which increased margins by
$27 million and higher electric rates at UE, effective
June 4, 2007, increased margins by $16 million.
A $35 million reduction in the impact of the 2007 Illinois
Electric Settlement Agreement.
The absence in 2008 of a March 2007 FERC order that
resettled costs among MISO participants retroactive to
2005 that was recorded in 2007, and the subsequent
recovery of a portion of these costs in 2008 through a
MoPSC order. The net benefit to electric margins in 2008
of these items was $30 million.
Lower fuel expense at Genco as a result of a settlement
agreement with a coal mine owner reached in June
2008, which increased margins by $27 million. Genco
received a lump-sum payment for increased costs for
coal and transportation that it expected to incur in 2009
because of the premature closure of an Illinois mine and
contract termination.
Other MISO net purchased power costs, which
decreased by $23 million.
Merchant Generation emission allowance costs were
reduced by $8 million.
Merchant Generation capacity sales increased by
$6 million.
The following items had an unfavorable impact on
Ameren’s electric margins in 2008 compared with 2007:
Net unrealized MTM losses of $75 million on fuel-related
transactions. These were primarily associated with
financial instruments that were acquired to mitigate the
risk of rising diesel fuel price adjustments embedded in
coal transportation contracts for the period 2008 through
2012.
Unfavorable weather conditions, as evidenced by a 30%
reduction in cooling degree-days, which decreased
margins by $65 million. Compared with normal weather,
cooling degree-days in 2008 were 5% lower.
39
6% higher fuel prices.
Lower off-system margins due to reduced UE plant
availability, partially offset by an 8% increase in realized
prices and a 10% increase in hydroelectric generation.
Reduced Callaway nuclear plant availability was due to
unplanned plant outages, which offset the shorter
planned refueling and maintenance outage. UE’s coal-
fired generating plants’ average capacity and equivalent
availability factors were approximately 78% and 88%,
respectively, in 2008 compared with 80% and 89%,
respectively, in 2007.
Ameren’s natural gas margins increased by $36 million,
or 9%, in 2008 compared with 2007. The following items had
a favorable impact on Ameren’s natural gas margins:
Favorable weather conditions, as evidenced by a 13%
increase in heating degree-days, which increased
margins by $12 million. Compared with normal weather,
heating degree-days in 2008 were 7% higher.
Higher net gas rates at the Ameren Illinois Utilities,
effective October 1, 2008, which increased margins by
$4 million, and higher net gas rates at UE, effective April
2007, which increased margins by $3 million.
A September 2008 ICC rate order that concluded that a
portion of previously expensed nonrecoverable
purchased gas costs should be capitalized, which
increased margins by $9 million.
Increased weather-normalized sales volumes of 2% and
favorable customer sales mix, which increased margins
by $5 million.
Transportation revenues increased by $4 million.
Missouri Regulated (UE)
UE’s electric margins decreased $62 million, or 3%, in
2008 compared with 2007. The following items had an
unfavorable impact on UE’s electric margins:
Unfavorable weather conditions, as evidenced by a 29%
reduction in cooling degree-days, which decreased
margins by $42 million.
Net unrealized MTM losses of $39 million on fuel-related
transactions. These were primarily associated with
financial instruments that were acquired to mitigate the
risk of rising diesel fuel price adjustments embedded in
coal transportation contracts for the period 2008 through
2012.
5% higher fuel prices.
Replacement power insurance recoveries were
$12 million lower due to the lack of an extended plant
outage and an increase in insurance recovery deductible
limits.
Lower off-system margins because of reduced plant
availability, partially offset by an 8% increase in realized
prices and a 10% increase in hydroelectric generation.
Callaway nuclear plant availability was reduced because
of unplanned plant outages, which offset the shorter
planned refueling and maintenance outage. UE’s coal-
fired generating plants’ average capacity and equivalent
availability factors were approximately 78% and 88%,
respectively, in 2008, compared with 80% and 89%,
respectively in 2007.
The following items had a favorable impact on electric
CIPS’ natural gas margins increased by $7 million, or
10%, in 2008 compared with 2007. The following items had a
favorable impact on natural gas margins:
margins in 2008 compared with 2007:
Favorable customer sales mix, which increased margins
The absence in 2008 of a March 2007 FERC order that
resettled costs among MISO participants retroactive to
2005 that was recorded in 2007, and the subsequent
recovery of a portion of these costs in 2008 through a
MoPSC order. The net benefit to UE’s margins in 2008 of
these items was $23 million.
Other MISO net purchased power costs, which
decreased by $15 million.
Higher electric rates, effective June 4, 2007, which
increased margins by $16 million.
Net unrealized MTM gains of $8 million, primarily related
to nonqualifying hedges of changes in market prices for
electricity.
UE’s natural gas margins increased by $8 million, or
11%, in 2008 compared with 2007. The following items had a
favorable impact on natural gas margins:
Higher gas rates, effective April 2007, which increased
margins by $3 million.
Favorable customer sales mix, which increased margins
by $3 million.
Favorable weather conditions, as evidenced by a 12%
increase in heating degree-days, which increased
margins by $2 million.
Illinois Regulated
Illinois Regulated’s electric margins increased by
$58 million, or 8%, and natural gas margins increased by
$25 million, or 8%, in 2008 compared with 2007. The Ameren
Illinois Utilities have a cost recovery mechanism for power
purchased on behalf of their customers. These pass-through
power costs do not affect margins; however, the electric
revenues and offsetting purchased power costs fluctuate
primarily because of customer switching and usage. See
below for explanations of electric and natural gas margins
variances for the Illinois Regulated segment.
CIPS
CIPS’ electric margins increased by $14 million, or 6%, in
2008 compared with 2007. The following items had a
favorable impact on electric margins:
MISO purchased power costs were $8 million lower due
to the absence of the March 2007 FERC order.
Other MISO net purchased power costs, which
decreased by $5 million.
A $6 million reduced impact of the 2007 Illinois Electric
Settlement Agreement.
Higher electric delivery service rates, effective October 1,
2008, which increased margins by $5 million.
These favorable variances were partially offset by
unfavorable weather conditions, as evidenced by a 30%
reduction in cooling degree-days, which decreased electric
margins by $6 million.
by $2 million.
Favorable weather conditions, as evidenced by a 12%
increase in heating degree-days, which increased
margins by $2 million.
A September 2008 ICC rate order, that concluded that a
portion of previously expensed nonrecoverable
purchased gas costs should be capitalized, which
increased margins by $2 million.
Higher gas delivery service rates, effective in October
2008, which increased margins by $1 million.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s
change in electric margins by segment to CILCO’s total
change in electric margins for 2008 compared with 2007:
CILCO (Illinois Regulated)....................................
CILCO (AERG) ....................................................
Total change in electric margins ...........................
2008 versus 2007
$ 17
12
$ 29
CILCO’s (Illinois Regulated) electric margins increased
by $17 million, or 14%, in 2008 compared with 2007. The
following items had a favorable impact on electric margins:
Increased delivery and generation service margins of
$14 million due to increased sales volume and favorable
customer sales mix, and the reduced impact of monthly
MISO settlements that occurred in the prior year.
MISO purchased power costs were $4 million lower due
to the absence of the March 2007 FERC order.
A $3 million reduction in the impact of the 2007 Illinois
Electric Settlement Agreement.
These favorable variances were partially offset by
unfavorable weather conditions, as evidenced by a 28%
reduction in cooling degree-days, which decreased margins
by $4 million.
See Merchant Generation below for an explanation of
CILCO’s (AERG) electric margins in 2008 compared with
2007.
CILCO’s (Illinois Regulated) natural gas margins
decreased $1 million, or 1%, in 2008 compared with 2007.
The following items had an unfavorable impact on gas
margins:
Net unrealized MTM losses on natural gas swaps of
$6 million in 2008.
Lower gas delivery service rates, effective in October
2008, which decreased margins by $5 million.
The following items had a favorable impact on gas
margins in 2008 compared with 2007:
5% higher weather-normalized sales volumes and
favorable customer mix, which increased margins by
$8 million.
40
Favorable weather conditions, as evidenced by an
11% increase in heating degree-days, which
increased margins by $2 million.
IP
IP’s electric margins increased by $27 million, or 7%,
in 2008 compared with 2007. The following items had a
favorable impact on electric margins:
Higher electric delivery service rates, effective
October 1, 2008, which increased margins by $22
million.
MISO purchased power costs were $12 million lower
due to the absence of the March 2007 FERC order.
A $7 million reduction in the impact of the 2007 Illinois
Electric Settlement Agreement.
These favorable variances were partially offset by
unfavorable weather conditions, as evidenced by a 34%
reduction in cooling degree-days, which decreased
margins by $13 million.
IP’s natural gas margins increased by $18 million, or
12%, in 2008 compared with 2007. The following items
had a favorable impact on natural gas margins:
Higher gas delivery service rates, effective in October
2008, which increased margins by $8 million.
A September 2008 ICC rate order concluded that a
portion of previously expensed nonrecoverable
purchased gas costs should be capitalized, which
increased margins by $7 million.
Favorable weather conditions, as evidenced by a 15%
increase in heating degree-days, which increased
margins by $6 million.
These favorable variances were partially offset by a
4% decrease in weather-normalized sales volumes, which
decreased margins by $3 million.
Merchant Generation
Merchant Generation’s electric margins increased by
$151 million, or 15%, in 2008 compared with 2007.
Merchant Generation’s baseload coal-fired generating
plants’ average capacity and equivalent availability factors
were approximately 76% and 85%, respectively, in 2008
compared with 74% and 81%, respectively, in 2007. See
below for explanations of electric margins variances for
the Merchant Generation segment.
Genco
Genco’s electric margins increased by $82 million, or
16%, in 2008 compared with 2007. The following items
had a favorable impact on electric margins:
Lower fuel expense at Genco as a result of a
settlement agreement with a coal mine owner reached
in June 2008, which increased margin by $27 million.
Genco received a lump-sum payment for increased
costs for coal and transportation that it expected to
incur in 2009 because of the premature closure of an
Illinois mine and contract termination.
Increased revenues allocated to Genco under its
power supply agreement (Genco PSA) with Marketing
Company. Revenues from the Genco PSA increased
by 7% primarily because of the repricing of wholesale
and retail electric power supply agreements, and an
increase in reimbursable expenses in accordance with
the Genco PSA.
Purchased power costs were reduced by $17 million
due to the absence of MISO resettlement costs
experienced in early 2007.
A $13 million reduction in the 2007 Illinois Electric
Settlement Agreement.
Gains on the sales of excess oil and off-system
natural gas increased margins by $12 million.
Replacement power insurance recoveries were $9
million higher due to extended plant outages in 2008.
Lower emission allowance costs of $5 million due
primarily to an increase in low-sulfur coal consumption
in 2008.
The following items had an unfavorable impact on
electric margins in 2008 compared with 2007:
Excluding the impact of the June 2008 settlement
agreement, 2% higher fuel prices.
Net unrealized MTM losses of $18 million on fuel-
related transactions. These were primarily associated
with financial instruments that were acquired to
mitigate the risk of rising diesel fuel price adjustments
embedded in coal transportation contracts for the
period 2008 through 2012.
MISO-related revenues were $12 million lower due to
the absence of the March 2007 FERC order.
Decreased power plant utilization due to system
congestion. Genco’s baseload coal-fired generating
plants’ equivalent availability factors were comparable
year over year. However, the average capacity factor
was approximately 73% in 2008, compared with 75%
in 2007.
A $9 million decrease in revenues because of the
termination of an operating lease in February 2008
under which Genco leased certain CTs at a Joppa,
Illinois, site to its former parent, Development
Company. See Note 14 – Related Party Transactions
to our financial statements under Part II, Item 8, of this
report, for additional information.
CILCO (AERG)
AERG’s electric margins increased by $12 million, or
7%, in 2008 compared with 2007. The following items had
a favorable impact on electric margins:
Increased revenue allocated to AERG under its power
supply agreement (AERG PSA) with Marketing
Company. Revenues from the AERG PSA increased
24% primarily because of stronger generation
performance as a result of the lack of an extended
plant outage in 2008, the repricing of wholesale and
retail electric power supply agreements, and an
increase in reimbursable expenses in accordance with
the AERG PSA. AERG’s baseload coal-fired
generating plants’ average capacity and equivalent
41
availability factors were approximately 70% and 77%,
respectively, in 2008 compared with 55% and 61%,
respectively, in 2007.
A $6 million reduction in the impact of the 2007 Illinois
Electric Settlement Agreement.
The following items had an unfavorable impact on
electric margins in 2008 compared with 2007:
30% higher fuel prices, primarily due to a greater
percentage of higher-cost Illinois coal burned in 2008
and an increased amount of oil consumed during plant
start-ups.
nuclear plant refueling and maintenance outage in 2009, as
compared with costs of $30 million in 2008, also reduced
operations and maintenance expenses. Additionally, asset
impairment charges were lower by $7 million between years.
Reducing the benefit of these items was an increase of
$24 million in labor costs and the recognition of $17 million
for employee severance costs in 2009. In 2008, other
operations and maintenance expenses were reduced by a
MoPSC accounting order related to storm costs incurred in
2007, which resulted in UE recording a regulatory asset of
$25 million; no similar item occurred in 2009.
MISO-related revenues were $4 million lower due to the
Variations in other operations and maintenance
absence of the March 2007 FERC order.
Net unrealized MTM losses of $3 million on fuel-related
transactions. These were primarily associated with
financial instruments that were acquired to mitigate the
risk of rising diesel fuel price adjustments embedded in
coal transportation contracts for the period 2008 through
2012.
Other Merchant Generation
Electric margins from Ameren’s other Merchant
Generation operations, primarily from EEI and Marketing
Company, increased by $57 million, or 18%, in 2008. Other
Merchant Generation electric margins were unfavorably
affected compared with 2007 by:
9% higher fuel prices.
Net unrealized MTM losses of $8 million on fuel-related
transactions. These were primarily associated with
financial instruments that were acquired to mitigate the
risk of rising diesel fuel price adjustments embedded in
coal transportation contracts for the period 2008 through
2012.
Other Merchant Generation electric margins were
favorably affected by market price fluctuations during 2008,
which resulted in nonaffiliated MTM gains on energy
transactions of $73 million, primarily related to nonqualifying
hedges of changes in market prices for electricity.
Other Operations and Maintenance Expenses
2009 versus 2008
Ameren
Other operations and maintenance expenses decreased
$119 million in 2009 compared with 2008 because of several
factors. Coal-fired plant maintenance costs were reduced by
$48 million and bad debt expenses were lower by $44 million,
because of elevated levels of bad debt expense in 2008 as a
result of the transition to higher market-based rates at the
Ameren Illinois Utilities and the impact of the Illinois bad debt
rate adjustment mechanism (net of a related donation for
customer assistance programs) discussed in Note 2 – Rate
and Regulatory Matters under Part II, Item 8 of this report. A
favorable change of $37 million in unrealized net MTM
adjustments between periods resulting from changes in the
market value of investments used to support Ameren’s
deferred compensation plans and the absence of a Callaway
expenses in Ameren’s and CILCO’s business segments and
for the Ameren Companies between 2009 and 2008 were as
follows.
Missouri Regulated (UE)
Other operations and maintenance expenses decreased
$42 million. This was primarily because of a $32 million
reduction in coal-fired plant maintenance costs and the
absence of a Callaway nuclear plant refueling and
maintenance outage in 2009, as compared with costs of
$30 million in 2008. A favorable change of $19 million in
unrealized net MTM adjustments between periods, which
resulted from changes in the market value of investments
used to support Ameren’s deferred compensation plans, and
a $14 million decline in employee benefit costs also resulted
in decreased expenses between years.
Reducing the benefit of these items was a $21 million
increase in labor costs, the recognition of $8 million in
employee severance costs in 2009, and the absence of the
MoPSC storm cost accounting order of $25 million that
occurred in 2008, as described above. In addition to these
items, storm repair expenditures were higher in 2009 as a
result of a severe ice storm at the beginning of the year.
Illinois Regulated
Other operations and maintenance expenses decreased
$77 million in the Illinois Regulated segment, as discussed
below.
CIPS
Other operations and maintenance expenses decreased
$15 million, primarily because of a $10 million reduction in
bad debt expense, because of elevated levels of bad debt
expense in 2008 and the impact of the Illinois bad debt rate
adjustment mechanism (net of a related donation for
customer assistance programs), and a favorable change in
unrealized net MTM adjustments between periods resulting
from changes in the market value of investments used to
support Ameren’s deferred compensation plans.
CILCO (Illinois Regulated)
Other operations and maintenance expenses increased
$63 million, primarily because of higher labor and employee
benefit costs. These increases were primarily a result of work
performed on behalf of CIPS and IP as discussed below.
42
At the beginning of 2009, approximately 570
employees were transferred from Ameren Services to
CILCO (Illinois Regulated), which resulted in an increase
in other operations and maintenance expenses at CILCO
(Illinois Regulated) in 2009. These CILCO (Illinois
Regulated) employees also provide support services to
CIPS and IP. CILCO (Illinois Regulated) records
reimbursements from CIPS and IP for work performed by
its employees on their behalf as Operating Revenues –
Support Services – Affiliates on its statement of income,
which increased $70 million in 2009 compared with 2008.
Intercompany revenue and expenses associated with
these transactions are eliminated in consolidation within
the Illinois Regulated segment. See Note 14 – Related
Party Transactions to our financial statements under Part
II, Item 8, of this report for additional information on
CILCO (Illinois Regulated) support services.
Reducing the unfavorable effect of the above items
was a reduction in bad debt expense, because of elevated
levels of bad debt expense in 2008 and the impact of the
Illinois bad debt rate adjustment mechanism (net of a
related donation for customer assistance programs).
IP
IP’s other operations and maintenance expenses
decreased $43 million, primarily because of a $25 million
reduction in bad debt expense, because of elevated levels
of bad debt expense in 2008 and the impact of the Illinois
bad debt rate adjustment mechanism (net of a related
donation for customer assistance programs), a $6 million
decrease in distribution system reliability expenditures,
including reduced storm costs, and a favorable change in
unrealized net MTM adjustments between periods,
resulting from changes in the market value of investments
used to support Ameren’s deferred compensation plans.
Merchant Generation
Other operations and maintenance expenses
decreased $16 million in the Merchant Generation
segment, as discussed below.
Genco
Genco’s other operations and maintenance expenses
were comparable between years as employee severance
costs and expenses recognized for the termination of a rail
line extension project were reduced by lower plant
maintenance costs.
CILCO (AERG)
Other operations and maintenance expenses
decreased $22 million, primarily because of a $9 million
reduction in plant maintenance costs and an $11 million
reduction in asset impairment charges between years.
EEI
EEI’s other operations and maintenance expenses
increased $10 million, primarily because of higher plant
maintenance costs.
2008 versus 2007
Ameren
Ameren’s other operations and maintenance
expenses increased $170 million in 2008 compared with
2007. Labor costs increased by $52 million and plant
maintenance expenditures at coal-fired plants were higher
by $43 million due to outages. A $30 million increase in
distribution system reliability expenditures and a $10
million increase in information technology costs also
resulted in higher expenses. An unfavorable change of
$22 million in unrealized net MTM adjustments resulting
from changes in the market value of investments used to
support Ameren’s deferred compensation plans reduced
expenses between years. Bad debt expense increased by
$10 million, primarily because of the transition to higher
market-based rates at the Ameren Illinois Utilities.
Additionally, in the first quarter of 2007, a $15 million
accrual established in 2006 for contributions to assist
customers through the Illinois Customer Elect electric rate
increase phase-in plan was reversed because the plan
was terminated. There was no similar item in 2008.
Other operations and maintenance expenses also
increased in 2008 by $14 million, because of asset
impairment charges recorded during the fourth quarter of
2008 to adjust the carrying value of CILCO’s (through
AERG) Indian Trails and Sterling Avenue generation
facilities to their estimated fair values as of December 31,
2008. CILCO recorded an asset impairment charge of $12
million related to the Indian Trails cogeneration facility as
a result of the suspension of operations by the facility’s
only customer. CILCORP recorded a $2 million
impairment charge related to the Sterling Avenue CT
based on the expected net proceeds to be generated from
the sale of the facility in 2009. Because most of the
Sterling Avenue asset carrying value was recorded at
CILCORP, as a result of adjustments made during
purchase accounting, the write-down of the carrying value
of the Sterling Avenue CT did not result in an impairment
loss at CILCO (AERG).
Reducing the unfavorable effect of these items was a
reduction of $10 million in employee benefit costs, due to
changes in actuarial estimates, and an $18 million
decrease in storm expenditures, primarily in UE’s service
territory. Additionally, costs associated with the Callaway
nuclear plant refueling and maintenance outage in 2008
were $5 million lower than those for the refueling in 2007.
Other operations and maintenance expenses were further
reduced in 2008 by the MoPSC accounting order related
to 2007 storms, as discussed above.
Variations in other operations and maintenance
expenses in Ameren’s and CILCO’s business segments
and for the Ameren Companies between 2008 and 2007
were as follows.
Missouri Regulated (UE)
UE’s other operations and maintenance expenses
were higher by $22 million, primarily because of a $37
million increase in labor costs and a $29 million increase
in plant maintenance expenditures at coal-fired plants. An
unfavorable
43
change in unrealized net MTM adjustments resulting from
changes in the market value of investments used to
support Ameren’s deferred compensation plans and a $16
million increase in distribution system reliability
expenditures also resulted in incremental expenses.
Reducing the impact of these items were the effect of
the MoPSC accounting order discussed above, a
decrease in injuries and damages expenses between
years, and the reduced impact of the Callaway nuclear
plant refueling and maintenance outage in 2008 compared
with the refueling in 2007. Storm repair expenditures also
decreased by $31 million, further reducing other
operations and maintenance expenses.
Illinois Regulated
Other operations and maintenance expenses
increased $77 million in the Illinois Regulated segment, as
discussed below.
CIPS
Other operations and maintenance expenses
increased $24 million. The increase was primarily because
of an $11 million increase in distribution system reliability
expenditures, including storm costs, along with increased
labor costs and bad debt expense. Additionally, in the first
quarter of 2007, CIPS reversed an accrual of $4 million
established in 2006 for contributions to assist customers
through the Illinois Customer Elect electric rate increase
phase-in plan. There was no similar item in 2008.
CILCO (Illinois Regulated)
Other operations and maintenance expenses were
higher by $8 million, primarily because of a $5 million
increase in storm costs in 2008. Additionally, in the first
quarter of 2007, CILCO (Illinois Regulated) reversed an
accrual of $3 million established in 2006 for the Illinois
Customer Elect electric rate increase phase-in plan
contributions. There was no similar item in 2008. Lower
employee benefit costs reduced the effect of these
unfavorable items.
IP
Other operations and maintenance expenses
increased $47 million, due, in part, to a $17 million
increase in distribution system reliability expenditures,
including storm costs. Labor costs and bad debt expense
increased by $6 million each, and unrealized net MTM
adjustments resulting from changes in the market value of
investments used to support Ameren’s deferred
compensation plans also increased other operations and
maintenance expenses between years. Additionally, in the
first quarter of 2007, IP reversed an $8 million accrual
established in 2006 for the Illinois Customer Elect electric
rate increase phase-in plan contributions. There was no
similar item in 2008. Reducing the unfavorable effect of
these items was a reduction in employee benefit costs.
Merchant Generation
Other operations and maintenance expenses
increased $43 million in the Merchant Generation
segment, as discussed below.
Genco
Other operations and maintenance expenses
increased $12 million at Genco. Plant maintenance costs
were higher by $9 million, due to scheduled outages, and
labor costs increased by $5 million. Genco paid $3 million
to the IPA in 2007 as part of the 2007 Illinois Electric
Settlement Agreement. There was no similar item in 2008.
CILCO (AERG)
Other operations and maintenance expenses
increased $25 million at CILCO (AERG), primarily
because of a $12 million impairment charge recorded in
2008 related to the Indian Trails cogeneration plant
discussed above. Plant maintenance costs increased by
$7 million, due to scheduled outages, and labor costs
increased by $3 million. CILCO (AERG) paid $1.5 million
to the IPA in 2007 as part of the 2007 Illinois Electric
Settlement Agreement. There was no similar item in 2008.
EEI
Other operations and maintenance expenses were
comparable in 2008 and 2007.
Depreciation and Amortization
2009 versus 2008
Ameren
Ameren’s depreciation and amortization expenses
increased $40 million in 2009, as compared with 2008,
because of items noted below at the Ameren Companies.
Variations in depreciation and amortization expenses
in Ameren’s and CILCO’s business segments and for the
Ameren Companies between 2009 and 2008 were as
follows.
Missouri Regulated (UE)
Depreciation and amortization expenses increased
$28 million, primarily because of capital additions and
amortization of regulatory assets that resulted from UE’s
electric rate case in 2009.
Illinois Regulated
Depreciation and amortization expenses were
comparable between years in the Illinois Regulated
segment. As part of the consolidated electric and natural
gas rate order issued by the ICC in September 2008, the
ICC changed plant asset useful lives, effective October 1,
2008. This resulted in reductions in depreciation expense
at CIPS and CILCO (Illinois Regulated) and an increase in
depreciation expense at IP. Capital additions partially
offset the benefit of the rate order at CIPS and CILCO
(Illinois Regulated) and further
44
increased depreciation and amortization expenses at IP.
The net effect of the above items was an $18 million
reduction in depreciation and amortization expenses at
CILCO (Illinois Regulated) and a $14 million increase at
IP. Depreciation and amortization expenses at CIPS were
comparable between years.
Merchant Generation
Depreciation and amortization expenses increased
$17 million in the Merchant Generation segment, primarily
because of capital additions at CILCO (AERG) and $3
million of expense recorded by Genco in the third quarter
of 2009 for the retirement of two generation units at its
Meredosia power plant. Depreciation and amortization
expenses were comparable at EEI between years.
2008 versus 2007
Ameren
Ameren’s depreciation and amortization expenses
were comparable between periods. Increases in
depreciation expense, resulting from capital additions in
2008, were mitigated by a reduction in expense because
of changes in the useful lives of plant assets resulting from
rate orders in 2007 in Missouri and 2008 in Illinois, as
discussed below.
Variations in depreciation and amortization expenses
in Ameren’s and CILCO’s business segments and for the
Ameren Companies between 2008 and 2007 were as
follows.
Missouri Regulated (UE)
Depreciation and amortization expenses decreased
$4 million, primarily because of the extension of UE’s
nuclear and coal-fired plants’ useful lives for purposes of
calculating depreciation expense in conjunction with a
MoPSC electric rate order effective June 2007. Reducing
the benefit of this item was an increase in capital additions
in 2008.
Illinois Regulated
Depreciation and amortization expenses were
comparable in 2008 and 2007 in the Illinois Regulated
segment. The effect of the consolidated electric and
natural gas rate order issued by the ICC in 2008, as noted
above, resulted in reductions in depreciation expense at
CIPS and CILCO (Illinois Regulated) and an increase in
depreciation expense at IP. Capital additions partially
offset the benefit of the rate order at CIPS and CILCO
(Illinois Regulated) and further increased depreciation and
amortization expenses at IP.
Merchant Generation
Depreciation and amortization expenses increased
$4 million in the Merchant Generation segment.
Depreciation and amortization expenses increased $8
million at CILCO (AERG) because of capital additions in
2008. Genco’s depreciation and amortization expenses
decreased $4 million, primarily because of extended
useful lives resulting from a depreciation study completed
in September 2007, partially mitigated by capital additions.
EEI’s depreciation and amortization expenses were
comparable between years.
Taxes Other Than Income Taxes
2009 versus 2008
Ameren
Ameren’s taxes other than income taxes increased
$19 million, primarily because of higher property and
payroll taxes.
Variations in taxes other than income taxes in
Ameren’s and CILCO’s business segments and for the
Ameren Companies between 2009 and 2008 were as
follows.
Missouri Regulated (UE)
Taxes other than income taxes increased $17 million,
primarily because of higher property taxes.
Illinois Regulated
Taxes other than income taxes were comparable in
2009 and 2008 in the Illinois Regulated segment and at
CIPS, CILCO (Illinois Regulated), and IP.
Merchant Generation
Taxes other than income taxes were comparable
between years in the Merchant Generation segment and
at Genco, CILCO (AERG) and EEI.
2008 versus 2007
Ameren
Ameren’s taxes other than income taxes increased
$12 million, primarily because of higher property taxes and
higher gross receipts taxes. Increases in property taxes
were reduced by invested capital electricity distribution tax
credits in the Illinois Regulated segment. These credits
were related to payments made in a previous year.
Variations in taxes other than income taxes in
Ameren’s and CILCO’s business segments and for the
Ameren Companies between 2008 and 2007 were as
follows.
Missouri Regulated (UE)
UE’s taxes other than income taxes increased $6
million, primarily because of higher property taxes.
Illinois Regulated
Taxes other than income taxes increased $5 million in
the Illinois Regulated segment, primarily because of
higher excise taxes at CIPS, CILCO (Illinois Regulated),
and IP. Property taxes were comparable between years
as increases in 2008 were mitigated by the favorable
impact of the invested capital electricity distribution tax
credits discussed above.
45
Merchant Generation
Taxes other than income taxes were comparable in
2008 and 2007 in the Merchant Generation segment and
for Genco, CILCO (AERG) and EEI.
Other Income and Expenses
2009 versus 2008
Ameren
Other income and expenses were comparable in 2009
and 2008. Miscellaneous expenses decreased as
expenses associated with energy efficiency and customer
assistance programs under the 2007 Illinois Electric
Settlement Agreement were lower in 2009. However,
miscellaneous income declined because of reduced
interest income, partially offset by increased allowance for
funds used during construction.
Variations in other income and expenses in Ameren’s
and CILCO’s business segments and for the Ameren
Companies between 2009 and 2008 were as follows.
Missouri Regulated (UE)
Other income and expenses were comparable
between periods.
Illinois Regulated
Other income and expenses decreased $9 million in
the Illinois Regulated segment, and decreased at both
CIPS and IP, primarily because of lower interest income.
Decreased expenses associated with energy efficiency
and customer assistance programs under the 2007 Illinois
Electric Settlement Agreement mitigated this decrease.
Other income and expenses at CILCO (Illinois Regulated)
were comparable in 2009 and 2008.
Merchant Generation
Other income and expenses were comparable
between years in the Merchant Generation segment and
at Genco, CILCO (AERG) and EEI.
2008 versus 2007
Ameren
Other income and expenses were comparable in 2008
and 2007. Miscellaneous income increased $5 million,
primarily because of an increase at UE in allowance for
funds used during construction, reduced by lower interest
income. Miscellaneous expense increased $6 million,
primarily because of increased expenses associated with
contributions to social programs.
Variations in other income and expenses in Ameren’s
and CILCO’s business segments and for the Ameren
Companies between 2008 and 2007 were as follows.
46
Missouri Regulated (UE)
Miscellaneous income increased $24 million, primarily
because of an increase in allowance for funds used during
construction. This increase resulted from higher rates and
increased construction work in progress balances.
Miscellaneous expense was comparable between years.
Illinois Regulated
Other income and expenses decreased $9 million in
the Illinois Regulated segment and at CIPS, CILCO
(Illinois Regulated) and IP, primarily because of lower
interest income.
Merchant Generation
Other income and expenses in the Merchant
Generation segment and at Genco, CILCO (AERG) and
EEI were comparable in 2008 and 2007.
Interest Charges
2009 versus 2008
Ameren
Ameren’s interest charges increased $68 million
because of items noted below at the Ameren Companies
and because of the issuance of $425 million of senior
notes at Ameren in May 2009.
Variations in interest charges in Ameren’s and
CILCO’s business segments and for the Ameren
Companies between 2009 and 2008 were as follows.
Missouri Regulated (UE)
Interest charges increased $36 million, primarily
because of the issuance of $350 million, $450 million, and
$250 million of senior secured notes in March 2009, June
2008, and April 2008, respectively. The amortization of
fees related to new credit facilities entered into in the
second quarter of 2009 also increased interest charges.
The majority of the fees related to the new credit facilities
are being amortized over a two-year period. Additionally, a
reversal in interest charges previously accrued on
uncertain tax positions due to favorable income tax
settlements in 2008, with no similar item in 2009, had a
negative impact on 2009. The maturity of $148 million of
first mortgage bonds in May 2008 and refinancing of
auction-rate environmental improvement revenue bonds in
2008, along with a reduction of short-term borrowings,
mitigated the impact of the above items.
Illinois Regulated
Interest charges increased $9 million in the Illinois
Regulated segment because of the amortization of fees
related to a new credit facility entered into in the second
quarter of 2009 and as a result of matters as discussed
below.
CIPS
Interest charges were comparable in 2009 and 2008.
CILCO (Illinois Regulated)
Interest charges increased $8 million, primarily
because of the issuance of senior secured notes of $150
million in December 2008 at a higher rate than the short-
term borrowings it refinanced.
IP
Interest charges were comparable between years.
Increased interest charges resulting from the issuance of
senior secured notes of $400 million and $337 million in
October 2008 and April 2008, respectively, was mitigated
as the proceeds of these issuances were used to
refinance auction-rate pollution control revenue refunding
bonds, which bore default rates ranging from 12% to 18%,
and to reduce short-term borrowings.
Merchant Generation
Interest charges increased $20 million in the Merchant
Generation segment, because of items discussed below.
Additionally, CILCORP parent company recorded
amortization of fees related to new credit facilities entered
into in the second quarter of 2009 and had increased
intercompany borrowings.
Genco
Interest charges increased $4 million, primarily
because of the issuance of $300 million of senior
unsecured notes in April 2008.
CILCO (AERG)
Interest charges increased $12 million, primarily
because of increased intercompany borrowings.
EEI
Interest charges were comparable between years.
2008 versus 2007
Ameren
Interest charges increased $17 million. Long-term
debt issuances, net of maturities and redemptions, and
the cost of refinancing auction-rate environmental
improvement and pollution control revenue refunding
bonds resulted in increased interest expense in 2008.
These increases were reduced by income tax settlements
in 2008.
Variations in interest charges in Ameren’s and
CILCO’s business segments and for the Ameren
Companies between 2008 and 2007 were as follows.
Missouri Regulated (UE)
Interest charges were comparable between periods.
Interest charges associated with the issuance of senior
secured notes of $450 million, $250 million, and $425
million in June 2008, April 2008, and June 2007,
respectively, was
mitigated by a reduction in short-term borrowings, which
were reduced with proceeds from the senior secured
notes financings. The proceeds from these senior secured
notes financings were also used to refinance auction-rate
environmental improvement revenue refunding bonds, and
to fund the maturity of $148 million of first mortgage
bonds, and to reduce short-term borrowings. Additionally,
interest charges were reduced by $8 million because of a
reversal of interest charges previously accrued on
uncertain tax positions as a result of income tax
settlements in 2008.
Illinois Regulated
Interest charges increased $12 million in the Illinois
Regulated segment, as discussed below.
CIPS
Interest charges decreased $7 million, primarily
because of reduced short-term borrowings and a $3
million reduction from a reversal of interest charges
previously accrued on uncertain tax positions as a result
of an income tax settlement.
CILCO (Illinois Regulated)
Interest charges were comparable in 2008 and 2007.
IP
Interest charges increased $22 million, primarily
because of the issuance of $400 million, $337 million, and
$250 million of senior secured notes at IP in October
2008, April 2008, and November 2007, respectively. The
$337 million senior secured notes were issued to
refinance auction-rate pollution control revenue refunding
bonds, while proceeds from the other debt issuances were
used to reduce short-term borrowings.
Merchant Generation
Interest charges decreased $8 million in the Merchant
Generation segment, as discussed below.
Genco
Interest charges were comparable between periods.
Increased interest charges resulting from the issuance of
$300 million of senior unsecured notes in April 2008 was
mitigated by a corresponding reduction in short-term
borrowings. Additionally, interest charges were reduced by
$3 million as a result of an income tax settlement.
CILCO (AERG)
Interest charges decreased $4 million at CILCO
(AERG), primarily because of reduced short-term
borrowings.
EEI
Interest charges were comparable in 2008 and 2007.
47
Income Taxes
The following table presents effective income tax rates
by segment for the years ended December 31, 2009,
2008, and 2007:
Ameren ..............................................................
Missouri Regulated ............................................
Illinois Regulated ...............................................
Merchant Generation .........................................
2009
35%
33
37
38
2008
34%
36
30
36
2007
34%
33
32
37
2009 versus 2008
Ameren
Ameren’s effective tax rate in 2009 was higher than
the effective tax rate in 2008 due to variations discussed
below. Variations in effective tax rates for Ameren’s and
CILCO’s business segments and for the Ameren
Companies between 2009 and 2008 were as follows.
Missouri Regulated (UE)
UE’s effective tax rate was lower, primarily because of
higher favorable net amortization of property-related
regulatory assets and liabilities, partially mitigated by
changes to reserves for uncertain tax positions.
The effective tax rate increased, primarily because of
the decreased impact of Internal Revenue Code
Section 199
production activity deductions, along with changes to
reserves for uncertain tax positions.
CILCO (AERG)
The effective tax rate was lower, primarily because of
the increased impact of Internal Revenue Code
Section 199 production activity deductions, along with
changes to reserves for uncertain tax positions.
2008 versus 2007
Ameren
Ameren’s effective tax rate was comparable in 2008
and 2007. Favorable impacts of state audit settlements
and changes in state apportionment were offset by
unfavorable permanent items related to company-owned
life insurance as well as other variations discussed below
at the Ameren Companies.
Variations in effective tax rates for Ameren’s and
CILCO’s business segments and for the Ameren
Companies between 2008 and 2007 were as follows.
Illinois Regulated
Missouri Regulated (UE)
The effective tax rate was higher in the Illinois
Regulated segment because of items detailed below.
CIPS
The effective tax rate increased, primarily because of
the decreased impact of net amortization of property-
related regulatory assets and liabilities, investment tax
credit amortization, and permanent items on higher pretax
book income.
CILCO (Illinois Regulated)
The effective tax rate was higher, primarily because of
the decreased impact of permanent benefits, net
amortization of property-related regulatory assets and
liabilities, and investment tax credit amortization on higher
pretax book income.
IP
The effective tax rate decreased, primarily because of
the impact of permanent items on higher pretax book
income, along with changes to reserves for uncertain tax
positions.
Merchant Generation
The effective tax rate was higher in the Merchant
Generation segment because of items detailed below.
Genco
The effective tax rate increased, primarily because of
lower favorable net amortization of property-related
regulatory assets and liabilities, along with decreased
Internal Revenue Code Section 199 production activity
deductions in 2008.
Illinois Regulated
The effective tax rate decreased in the Illinois
Regulated segment because of items detailed below.
CIPS
The effective tax rate was lower, primarily because of
the impact of net amortization of property-related
regulatory assets and liabilities and permanent items on
lower pretax income in 2008.
CILCO (Illinois Regulated)
The effective tax rate was higher, primarily because of
lower tax credits, lower favorable net amortization of
property-related regulatory assets and liabilities, and lower
favorable permanent benefits related to company-owned
life insurance.
IP
The effective tax rate increased, primarily because of
lower favorable net amortization of property-related
regulatory assets and liabilities, lower tax credits, and the
impact of other permanent items as well as increased
reserves for uncertain tax positions on lower pretax book
income in 2008.
48
Merchant Generation
The effective tax rate decreased in the Merchant
Generation segment because of items detailed below.
Genco
The effective tax rate was lower, primarily because of
the increased impact of Internal Revenue Code Section 199
production activity deductions and research tax credits.
LIQUIDITY AND CAPITAL RESOURCES
CILCO (AERG)
The effective tax rate increased, primarily because of
the impact of Internal Revenue Code Section 199
production activity deductions.
The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO (Illinois
Regulated) and IP) continue to be a principal source of cash from operating activities for Ameren and its rate-regulated
subsidiaries. A diversified retail customer mix of primarily rate-regulated residential, commercial, and industrial classes
and a commodity mix of natural gas and electric service provide a reasonably predictable source of cash flows for
Ameren, UE, CIPS, CILCO (Illinois Regulated) and IP. For operating cash flows, Genco and AERG rely on power sales to
Marketing Company, which sold power through financial contracts that were part of the 2007 Illinois Electric Settlement
Agreement and various power procurement processes in the non-rate-regulated Illinois market. Marketing Company also
sells power through other primarily market-based contracts with wholesale and retail customers. In addition to cash flows
from operating activities, the Ameren Companies use available cash, credit facilities, money pool, or other short-term
borrowings from affiliates to support normal operations and other temporary capital requirements. The use of operating
cash flows and credit facility or short-term borrowings to fund capital expenditures and other investments may periodically
result in a working capital deficit, as was the case at December 31, 2009, for Genco and CILCO. The Ameren Companies
may reduce their credit facility or short-term borrowings with cash from operations or discretionarily with long-term
borrowings, or in the case of Ameren subsidiaries, with equity infusions from Ameren. The Ameren Companies expect to
incur significant capital expenditures over the next five years as they comply with environmental regulations and make
significant investments in their electric and natural gas utility infrastructure to improve overall system reliability. Ameren
intends to finance those capital expenditures and investments with a blend of equity and debt so that it maintains a capital
structure in its rate-regulated businesses, of approximately 50% to 55% equity. We plan to implement our long-term
financing plans for debt, equity, or equity-linked securities in order to finance our operations appropriately, meet
scheduled debt maturities, and maintain financial strength and flexibility.
In 2008 and 2009, the global capital and credit markets experienced extreme volatility. See Outlook for a discussion
of the implications of this volatility for our industry as a whole, including the Ameren Companies, and how we addressed
these issues.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years
ended December 31, 2009, 2008 and 2007:
Ameren(a) ...................................................... $ 1,977
972
UE ................................................................
191
CIPS .............................................................
232
Genco ...........................................................
263
CILCO ...........................................................
409
IP ................................................................
2009
Net Cash Provided By
Operating Activities
2008
$ 1,524
543
101
246
207
178
2007
$ 1,108
587
14
255
74
30
Net Cash (Used In)
Investing Activities
2008
2009
2007
$ (1,789) $ (2,097) $ (1,468)
(700)
(1,033)
(42)
(57)
(210)
(330)
(212)
(317)
(186)
(246)
(955)
(68)
(349)
(153)
(189)
Net Cash Provided By
(Used In) Financing Activities
2008
2009
2007
$ 342
$ 578
$ 310
250
297
305
(95 )
48
(70 )
121
(44)
84
(22 )
141
104
(80 )
162
112
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Cash Flows from Operating Activities
2009 versus 2008
Ameren’s cash from operating activities increased in
2009 compared with 2008. Operating activities associated
with the December 2005 Taum Sauk incident resulted in a
$256 million increase in cash during 2009, compared with
2008. The 2009 increase was a result of a $65 million
increase in insurance recoveries received as well as a
$191 million reduction in cash payments compared with
2008. See Note 15 – Commitments and Contingencies
under Part II, Item 8, of this report for information about
the Taum Sauk property insurance settlement agreement
with all but three of the property insurance carriers and the
related settlement payment received during 2009. Other
factors contributing to the increase in cash from operating
activities during 2009, compared with 2008, included a
$198 million decrease in the cost of natural gas purchased
for inventories because of lower prices, a $97 million
decrease, net of refunds, in income tax payments primarily
at UE as discussed below, and an increase in electric costs
over-recovered from Illinois customers under cost recovery
mechanisms. Additionally, as discussed in Results of
Operations, less cash was used for operations and
49
maintenance activities because many plant-related projects
were either reduced, deferred, or cancelled as well as the
absence of a Callaway nuclear plant refueling and
maintenance outage in 2009. Factors reducing the increase
in cash from operating activities during 2009, compared with
2008, included a $68 million increase in interest payments, a
decrease in natural gas costs over-recovered from customers
under the PGA, a $35 million increase in pension and
postretirement plan contributions, lower electric margins, as
discussed in Results of Operations, including the absence in
2009 of the 2008 lump-sum settlement payment received by
Genco from a coal mine owner for the early termination of a
coal supply contract, a $21 million decrease in customer
advances for construction, $16 million of employee
severance payments as a result of the 2009 voluntary and
involuntary separation programs, an increase in annual
incentive compensation payments, and an $8 million increase
in cash payments for major storm restoration costs.
UE’s cash from operating activities increased in 2009
compared with 2008. The increase was primarily due to net
income tax refunds of $208 million in 2009 compared with net
income tax payments of $130 million in 2008, and a
$256 million increase in cash from operating activities
associated with the December 2005 Taum Sauk incident, as
discussed above. The significant change in income taxes is
primarily a result of an acceleration of deductions due to
economic stimulus legislation and a change in tax treatment
of electric generation plant expenditures. Other factors
contributing to the increase in cash from operating activities
during 2009, compared with 2008, included a $20 million
decrease in the cost of natural gas purchased for inventories
because of lower prices, higher electric margins, as
discussed in Results of Operations, and an increase in
natural gas costs over-recovered from customers under the
PGA. Additionally, as discussed in Results of Operations,
less cash was used for operations and maintenance
activities, because several plant-related projects were either
reduced, deferred, or cancelled as well as the absence of a
Callaway nuclear plant refueling and maintenance outage in
2009. Factors reducing the increase in cash from operating
activities during 2009, compared with 2008, included the
collection of an $85 million affiliate receivable in 2008 that did
not occur in 2009, a $39 million increase in interest
payments, a $16 million increase in pension and other
postretirement plan contributions, a $10 million increase in
energy efficiency expenditures for new customer programs, a
$6 million increase in major storm restoration costs, and $6
million of employee severance payments as a result of the
2009 voluntary and involuntary separation programs.
CIPS’ cash from operating activities increased in 2009
compared with 2008. Factors contributing to the increase in
cash from operating activities during 2009, compared with
2008, included a $57 million net reduction in collateral posted
with suppliers due in part to improved credit ratings, a
$40 million decrease in the cost of natural gas purchased for
inventories because of lower prices, higher electric and
natural gas margins as discussed in Results of Operations,
an increase in electric costs over-recovered from customers
under cost recovery mechanisms, and a $5 million decrease
in interest payments. Additionally, more cash was collected in
2009 from receivables, because of colder weather in the
fourth quarter of 2008, compared with 2007. Factors reducing
the increase in cash from operating activities during 2009,
compared with 2008, included net income tax payments of
$24 million in 2009, compared with net income tax refunds of
$21 million in 2008, a decrease in natural gas costs over-
recovered from customers under the PGA, and a $5 million
increase in major storm restoration costs.
Genco’s cash from operating activities decreased in
2009 compared with 2008. Factors contributing to a decrease
in cash from operating activities during 2009, compared with
2008, included lower electric margins as discussed in Results
of Operations, including the 2008 lump-sum settlement
payment received from a coal mine owner as well as the
absence of $7 million, net of premiums, of replacement
power insurance recoveries received in 2008 from an affiliate
as the policy was not renewed. Other factors contributing to
the decrease in cash from operating activities during 2009,
compared with 2008, included a $23 million increase in
income tax payments, net of refunds, a $6 million increase in
interest payments, and $4 million of employee severance
payments as a result of the 2009 voluntary and involuntary
separation programs. Factors offsetting the decrease in cash
from operating activities during 2009, compared with 2008,
included reduced coal purchases in 2009 as generation
levels declined and a $10 million reduction in funding
required by the 2007 Illinois Electric Settlement Agreement.
CILCO’s cash from operating activities increased in 2009
compared with 2008. Factors contributing to the increase in
cash from operating activities during 2009, compared with
2008, included higher electric margins as discussed in
Results of Operations, a $58 million decrease in the cost of
natural gas purchased for inventories because of lower
prices, and a $45 million net reduction in collateral posted
with suppliers due in part to improved credit ratings.
Additionally, more cash was collected in 2009 from
receivables, because of colder weather in the fourth quarter
of 2008, compared with 2007. Factors reducing the increase
in cash from operating activities during 2009, compared with
2008, included net income tax payments of $82 million in
2009, compared with net income tax refunds of $15 million in
2008, increased coal purchases to build inventories at the
Duck Creek generating facility as a result of switching coal
blends in 2009, a $6 million increase in pension and other
postretirement plan contributions, a $6 million increase in
interest payments, the absence of $5 million, net of
premiums, of replacement power insurance recoveries
received in 2008 from an affiliate as the policy was not
renewed, a decrease in natural gas costs over-recovered
from customers under the PGA, and an increase in annual
incentive compensation payments.
IP’s cash from operating activities increased in 2009
compared with 2008. Factors contributing to the increase in
cash from operating activities during 2009, compared with
2008, included higher electric and natural gas margins as
discussed in Results of Operations, an $80 million decrease
in the cost of natural gas purchased for inventories because
50
of lower prices, a $74 million net decrease in collateral
posted with suppliers due in part to improved credit ratings,
an increase in electric costs over-recovered from customers
under cost recovery mechanisms, and a $3 million decrease
in major storm restoration costs. Additionally, more cash was
collected in 2009 from receivables, because of colder
weather in the fourth quarter of 2008, compared with 2007.
Factors reducing the increase in cash from operating
activities during 2009, compared with 2008, included net
income tax payments of $22 million in 2009, compared with
net income tax refunds of $43 million in 2008, a decrease in
natural gas cost over-recovered from customers under the
PGA, a $22 million increase in interest payments, and a $15
million reduction in customer advances for construction.
2008 versus 2007
Ameren’s cash from operating activities increased in
2008, compared to 2007, primarily because of higher electric
and natural gas margins as discussed in Results of
Operations, a $177 million decrease in income tax payments
(net of refunds), and improved collections of receivables in
2008. The reduction in income tax payments was largely
attributable to higher depreciation allowed for tax purposes.
In 2007, receivables from the Ameren Illinois Utilities had
increased due to the January 2, 2007, electric rate increases,
related uncertainty surrounding a potential electric settlement
agreement, and deterioration of collections. However,
collections improved in 2008. Additionally, Ameren
experienced an $87 million benefit to cash flows for 2008 as
compared with 2007 because of the timing of cash receipts
for MISO receivables. The 2007 Illinois Electric Settlement
Agreement also had a positive effect on cash from operations
in 2008 compared with 2007. Cash outflows in accordance
with the settlement, net of reimbursements from generators,
were $84 million less in 2008 than in 2007. See Note 2 –
Rate and Regulatory Matters under Part II, Item 8, of this
report for a discussion of the 2007 Illinois Electric Settlement
Agreement. In addition, Ameren’s cash flows from operations
increased in 2008 compared with 2007 because of a
$40 million reduction in storm restoration costs, over-
recovery under the PGAs, and a $27 million payment
received by Genco in 2008 as part of a coal contract
settlement for increased costs for coal and transportation that
Genco expected to incur in 2009 because of the premature
closure of an Illinois mine at the end of 2007. See Note 1 –
Summary of Significant Accounting Policies under Part II,
Item 8, for information on the coal contract settlement.
Factors that offset, in part, the favorable variance in cash
flows from operations in 2008 were a $93 million increase in
cash payments related to the December 2005 Taum Sauk
incident, net of insurance recoveries, an increase in natural
gas inventories resulting from price increases, higher interest
payments, and higher levels of collateral posted with
suppliers.
At UE, cash from operating activities decreased in 2008,
compared to 2007. The decrease is primarily due to a
$24 million increase in net income tax payments in 2008,
lower electric margins, increased system reliability
expenditures as discussed in Results of Operations, and
higher levels of net collateral posted with suppliers. Also
contributing to the unfavorable variance in 2008 was a
$93 million increase in cash payments related to the
December 2005 Taum Sauk incident, net of insurance
recoveries, and a $146 million net decrease in affiliate
payables. Factors increasing cash from operations included a
$34 million decrease in payments for storm restorations, a
decrease in other operations and maintenance expenditures
related to the Callaway nuclear plant refueling and
maintenance outage in 2008 as compared with the 2007
refueling and maintenance outage, reduction in interest
payments, and the collection in 2008 of an $85 million affiliate
receivable. In addition, cash flows from operations increased
in 2008 compared with 2007 because of the timing of cash
receipts for MISO receivables.
At CIPS, cash from operating activities increased in 2008
compared with 2007. The increase was primarily due to net
income tax refunds of $21 million in 2008, compared with net
income tax payments of $44 million in 2007, an increase in
gas cost over-recovery from customers under the PGA, a $7
million increase in customer advances for construction, and
favorable fluctuations in receivables and payables. In 2007,
receivables increased due to the January 2, 2007, electric
rate increases, related uncertainty surrounding a potential
settlement agreement, and deterioration of collections.
However, collections improved in 2008. The 2007 Illinois
Electric Settlement Agreement also had a positive effect on
cash from operations in 2008 compared with 2007. CIPS’
cash outflows from the settlement, net of reimbursements
from generators, were $26 million less in 2008 than in 2007.
CIPS experienced favorable fluctuations in intercompany
receivable and payable balances resulting from changes in
its year-end 2008 income tax position and a receivable
related to the 2007 Illinois Electric Settlement Agreement
compared with 2007. Partially offsetting the favorable
variance in cash flow from operations was a larger increase
in natural gas inventories in 2008 than in 2007, a decrease in
electric costs over-recovered from customers, and higher net
levels of collateral posted with suppliers.
Genco’s cash from operating activities decreased in
2008 compared with 2007 primarily due to an increase in fuel
inventory and an increase in net income tax payments of
$13 million. Reducing the unfavorable variance in cash flow
from operations were higher electric margins, a payment from
an Illinois coal mine owner for the premature closure of an
Illinois mine, as discussed above, and a $6 million reduction
in funding required by the 2007 Illinois Electric Settlement
Agreement in 2008 compared with 2007.
CILCO’s cash from operating activities increased in
2008, compared with 2007. The increase was primarily due
to net income tax refunds of $15 million in 2008 compared
with net income tax payments of $35 million in 2007, higher
electric margins, a reduction of coal inventory at AERG, an
increase in gas cost recovered from customers under a PGA,
an increase in electric cost over-recovered from customers,
and favorable fluctuations in receivables and payables. In
2007, receivables increased due to the January 2, 2007,
electric rate increases, related uncertainty surrounding a
51
potential settlement agreement, and deterioration of
collections. However, collections improved in 2008. The 2007
Illinois Electric Settlement Agreement also had a positive
effect on cash from operations in 2008 compared with 2007.
The cash outflows related to the settlement, including
AERG’s obligation, were $16 million lower in 2008 than in
2007. Partially offsetting these increases in cash from
operations were a larger increase in natural gas inventories
during 2008 compared with 2007, as both price and volumes
increased, and higher net levels of collateral posted with
suppliers.
IP’s cash from operating activities increased in 2008,
compared with 2007. The increase was primarily due to net
income tax refunds of $43 million in 2008, compared with net
income tax payments of $18 million in 2007, increased
electric and natural gas margins, an increase in gas cost
recovered from customers under a PGA, an increase in
electric power costs over-recovered from customers, a
$7 million increase in customer advances for construction,
and favorable fluctuations in receivables and payables. In
2007, receivables increased due to the January 2, 2007,
electric rate increases, related uncertainty surrounding a
potential settlement agreement, and deterioration of
collections. However, collections improved in 2008. The 2007
Illinois Electric Settlement Agreement also had a positive
effect on cash from operations in 2008 compared to 2007. IP
cash outflows related to the settlement, net of
reimbursements from generators, were $35 million lower in
2008 than in 2007. IP experienced favorable fluctuations in
intercompany receivable and payable balances resulting from
changes in its year-end 2008 income tax position and a
receivable related to the 2007 Illinois Electric Settlement
Agreement compared with 2007. In addition, operating cash
required for major repairs in response to 2008 storms was $8
million less than major storm repairs in 2007. Partially
offsetting these increases to operating cash flows were a
$10 million increase in interest payments and higher net
levels of collateral posted with suppliers.
Pension Funding
Ameren’s pension plans are funded in compliance with
income tax regulations and to meet federal funding or
regulatory requirements. As a result, Ameren expects to fund
its pension plans at a level equal to the greater of the pension
expense or the legally required minimum contribution.
Considering Ameren’s assumptions at December 31, 2009,
its investment performance in 2009, and its pension funding
policy, Ameren expects to make annual contributions of
$75 million to $225 million in each of the next five years, with
aggregate estimated contributions of $740 million. We expect
UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future
funding requirements to be 66%, 6%, 9%, 9% and 10%,
respectively. These amounts are estimates. They may
change with actual investment performance, changes in
interest rates, changes in our assumptions, any pertinent
changes in government regulations, and any voluntary
contributions. In 2009, Ameren contributed $99 million to its
pension plans. See Note 11 – Retirement Benefits under Part
II, Item 8, of this report and Outlook for additional information.
Cash Flows from Investing Activities
2009 versus 2008
Ameren used less cash for investing activities in 2009
than in 2008. Net cash used for capital expenditures
decreased in 2009 as a result of efforts to reduce, defer or
cancel capital expenditure programs in light of economic
conditions and the completion of power plant scrubber
projects in the Merchant Generation business. Additionally, a
$93 million decrease in nuclear fuel expenditures related to
timing of purchases and a $10 million decrease in emission
allowance purchases, because of lower prices and lower
generation levels as well as reduced emission levels resulting
from completion of plant scrubber projects in 2009, benefited
cash during 2009.
UE’s cash used in investing activities decreased during
2009, compared with 2008. Nuclear fuel expenditures
decreased $93 million as a result of the timing of purchases.
Cash used in investing activities in 2009 did not benefit from
the receipt of $36 million in proceeds from intercompany note
receivables with Ameren, and one of its subsidiaries, as
occurred during 2008. Capital expenditures were consistent
year over year. Reductions in planned capital expenditures
for distribution system and power plant improvements in 2009
were offset by increased expenditures to repair severe storm
damage and $93 million of Taum Sauk rebuild expenditures.
CIPS’ cash used in investing activities during 2009
increased compared with 2008. Capital expenditures
increased $14 million in 2009 from 2008 primarily because of
increased capital expenditures to repair severe storm
damage.
Genco’s cash used in investing activities increased in
2009 compared with 2008 because of $73 million of net
money pool advances in 2009. Capital expenditures
decreased $40 million, principally because of reduced
spending related to power plant scrubber projects. One
scrubber project was completed in November 2009 and a
second scrubber project is estimated to be completed in
2010. Emission allowance purchases decreased $11 million,
because of lower prices and lower generation levels as well
as reduced emission levels resulting from the completion of a
plant scrubber project in 2009, which resulted in a benefit to
cash in 2009.
CILCO’s cash used in investing activities decreased in
2009, compared with 2008, as a result of a $165 million
decrease in capital expenditures, primarily because of the
completion of a power plant scrubber project in March 2009
and other reductions in capital expenditures at AERG.
IP’s cash used in investing activities decreased in 2009
compared with 2008, primarily as a result of money pool
activity. During 2009, IP received a net repayment of
$44 million in money pool advances compared with
$44 million of net contributions during 2008. Partially
offsetting this benefit to cash was an increase in advances to
AITC for construction under a joint ownership agreement. IP
received funding for this construction under a generator
interconnection agreement related to on-going transmission
upgrade projects.
52
2008 versus 2007
Ameren used more cash for investing activities in
2008, than in 2007. Net cash used for capital expenditures
increased in 2008 as a result of power plant scrubber
projects, upgrades at various power plants, and reliability
improvements of the transmission and distribution system.
Additionally, increased purchases and higher prices
resulted in a $105 million increase in nuclear fuel
expenditures.
UE’s cash used in investing activities increased during
2008, compared with 2007. Nuclear fuel expenditures
increased $105 million resulting from increased purchases
for future refueling outages at its Callaway nuclear plant
and higher prices. In addition, capital expenditures
increased $249 million. This increase was a result of
increased spending related to a power plant scrubber
project, reliability improvements of the transmission and
distribution system, and various plant upgrades. This
increase was partially offset by UE’s receipt of $36 million
in proceeds from intercompany note receivables with
Ameren, and one of its subsidiaries.
CIPS’ cash used in investing activities during 2008
increased, compared with 2007. Capital expenditures
increased $17 million in 2008 from 2007, primarily
because of reliability improvements to the transmission
and distribution system. During both years, this was offset
by cash received from payments on an intercompany note
receivable from Genco.
Genco’s cash used in investing activities increased in
2008 compared with 2007. Capital expenditures increased
$126 million, principally because of a power plant
scrubber project. This increase was offset, in part, by a $7
million decrease in emission allowance purchases.
CILCO’s cash used in investing activities increased in
2008, compared with 2007. Cash used in investing
activities increased as a result of a $65 million increase in
capital expenditures, primarily because of a power plant
scrubber project and plant upgrades at AERG. The receipt
of net repayments of money pool advances in 2007
compared to 2008 also increased cash flows used in
investing activities in 2008.
IP’s cash used in investing activities increased in 2008
compared with 2007. Capital expenditures increased by
$8 million in 2008 from 2007, primarily because of
reliability improvements to the transmission and
distribution system. Net money pool advances increased
by $44 million in 2008 compared with 2007.
Capital Expenditures
The following table presents the capital expenditures
2009
by the Ameren Companies for the years ended
December 31, 2009, 2008, and 2007:
Capital Expenditures
Ameren(a) ................................ $ 1,704
872
UE ..........................................
110
CIPS .......................................
277
Genco .....................................
63
CILCO (Illinois Regulated) .......
CILCO (AERG) ........................
91
186
IP ..........................................
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Ameren’s 2009 capital expenditures principally
2008
$ 1,896
874
96
317
61
258
186
2007
$ 1,381
625
79
191
64
190
178
(a)
consisted of the following expenditures at its subsidiaries.
UE spent $173 million toward a scrubber at one of its
power plants and $93 million toward the Taum Sauk
rebuild, and it incurred storm-related expenditures of $78
million. CIPS, CILCO and IP incurred storm-related
expenditures of $29 million, $3 million, and $5 million,
respectively. At Genco and AERG, there were cash
outlays of $169 million and $38 million, respectively, for
power plant scrubber projects. The scrubbers are
necessary to comply with environmental regulations.
Other capital expenditures were made principally to
maintain, upgrade, and expand the reliability of the
transmission and distribution systems of UE, CIPS, CILCO
and IP as well as various plant upgrades.
Ameren’s 2008 capital expenditures principally
consisted of the following expenditures at its subsidiaries.
UE spent $149 million toward a scrubber at one of its
power plants, and incurred storm-related expenditures of
$12 million. CIPS and IP incurred storm-related
expenditures of $7 million and $8 million, respectively. At
Genco and AERG, there were cash outlays of $205 million
and $137 million, respectively, for power plant scrubber
projects. The scrubbers are necessary to comply with
environmental regulations. Other capital expenditures
were made principally to maintain, upgrade, and expand
the reliability of the transmission and distribution systems
of UE, CIPS, CILCO, and IP as well as various plant
upgrades.
Ameren’s 2007 capital expenditures principally
consisted of the following expenditures at its subsidiaries.
UE spent $101 million toward a scrubber at one of its
power plants, and incurred storm-related expenditures of
$56 million. IP incurred storm-related expenditures of $24
million. At Genco and AERG, there were cash outlays of
$102 million and $76 million, respectively, for power plant
scrubber projects. In conjunction with the scrubber project,
AERG also made expenditures for a power plant boiler
upgrade of $45 million. Other capital expenditures were
made principally to maintain, upgrade, and expand the
reliability of the transmission and distribution systems of
UE, CIPS, CILCO, and IP as well as various plant
upgrades.
53
In February 2008, the U.S. Court of Appeals for the
District of Columbia issued a decision that vacated the
federal Clean Air Mercury Rule. The court ruled that the EPA
erred in the method it used to remove electric generating
units from the list of sources subject to the MACT
requirements under the Clean Air Act. In February 2009, the
U.S. Supreme Court denied a petition for review filed by a
group representing the electric utility industry. The impact of
this decision is that the EPA will move forward with a MACT
standard for mercury emissions and other hazardous air
pollutants, such as acid gases. In a consent order, the EPA
agreed to propose the regulation by March 2011 and to
finalize the regulation by November 2011. Compliance is
expected to be required in 2015. We cannot predict at this
time the estimated capital or operating costs for compliance
with such future environmental rules.
In July 2008, the U.S. Court of Appeals for the District of
Columbia issued a decision that vacated the federal Clean
Air Interstate Rule. The court ruled that the regulation
contained several fatal flaws, including a regional cap-and-
trade program that cannot be used to facilitate the attainment
of ambient air quality standards for ozone and fine particulate
matter. In September 2008, the EPA, as well as several
environmental groups, a group representing the electric utility
industry, and the National Mining Association, all filed
petitions for rehearing with the U.S. Court of Appeals. In
December 2008, the U.S. Court of Appeals essentially
reversed its July 2008 decision to vacate the federal Clean
Air Interstate Rule. The U.S. Court of Appeals granted the
EPA petition for reconsideration and remanded the rule to the
EPA for further action to remedy the rule’s flaws in
accordance with the U.S. Court of Appeals’ July 2008 opinion
in the case. The impact of the decision is that the existing
Illinois and Missouri rules to implement the federal Clean Air
Interstate Rule will remain in effect until the federal Clean Air
Interstate Rule is revised by the EPA, at which point the
Illinois and Missouri rules may be subject to change. The
EPA has stated that it expects to issue a new proposed
version of the Clean Air Interstate Rule in 2010 and a final
version in 2011.
The state of Missouri has adopted rules to implement the
federal Clean Air Interstate Rule for regulating SO2 and NOx
emissions from electric generating units. The rules are a
significant part of Missouri’s plan to attain existing ambient
standards for ozone and fine particulates, as well as meeting
the federal Clean Air Visibility Rule. The rules are expected to
reduce NOx emissions by 30% and SO2 emissions by 75% by
2015. As a result of the Missouri rules, UE will use
allowances and install pollution control equipment. UE’s costs
to comply with SO2 emission reductions required by the
Clean Air Interstate Rule could increase materially if the EPA
determines that existing allowances granted to sources under
the Acid Rain Program cannot be used for compliance with
the Clean Air Interstate Rule, or if a new allowance program
is mandated by revisions to the Clean Air Interstate Rule.
Missouri also adopted rules to implement the federal
The following table estimates the capital expenditures
that will be incurred by the Ameren Companies from 2010
through 2014, including construction expenditures,
capitalized interest for the Merchant Generation business,
allowance for funds used during construction for our rate-
regulated utility business, and estimated expenditures for
compliance with environmental standards:
2010
2011 – 2014
Total
(a)
340 -
690 -
250 -
130 -
670 -
330 -
125 -
UE .................................... $
CIPS .................................
Genco ...............................
CILCO (Illinois
695 $ 2,565 - $ 3,465 $ 3,260 - $ 4,160
435 -
460
95
555
800 - 1,040
930
110
310 -
340
60
Regulated) ...................
400
CILCO (AERG) ..................
135 -
175
5
180
IP ....................................
845 - 1,085
910
175
EEI ....................................
340 -
450
10
460
Other .................................
175 -
170
50
220
Ameren(a) .......................... $ 1,200 $5,100 - $ 6,900 $ 6,300 - $ 8,100
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
UE’s estimated capital expenditures include
transmission, distribution, and generation-related
investments, as well as expenditures for compliance with
environmental regulations discussed below. CIPS’, CILCO’s
(Illinois Regulated), and IP’s estimated capital expenditures
are primarily for electric and natural gas transmission and
distribution-related investments. Genco’s estimated capital
expenditures are primarily for compliance with environmental
regulations and upgrades to existing coal and gas-fired
generating facilities. CILCO’s (AERG) estimate includes
capital expenditures primarily for compliance with
environmental regulations at its generating facilities.
We continually review our generation portfolio and
expected power needs. As a result, we could modify our plan
for generation capacity, which could include changing the
times when certain assets will be added to or removed from
our portfolio, the type of generation asset technology that will
be employed, and whether capacity or power may be
purchased, among other things. Any changes that we may
plan to make for future generating needs could result in
significant capital expenditures or losses being incurred,
which could be material.
Environmental Capital Expenditures
Ameren, UE, Genco, AERG and EEI will incur significant
costs in future years to comply with existing federal EPA and
state regulations regarding SO2 , NOx and mercury emissions
from coal-fired power plants.
In May 2005, the EPA issued regulations with respect to
SO2 and NOx emissions (the Clean Air Interstate Rule) and
mercury emissions (the Clean Air Mercury Rule). The federal
Clean Air Interstate Rule requires generating facilities in 28
eastern states, which include Missouri and Illinois, where our
generating facilities are located, and the District of Columbia
to participate in cap-and-trade programs to reduce annual
SO2 emissions, annual NOx emissions, and ozone season
NOx emissions. The cap-and-trade program for both annual
and ozone season NOx emissions went into effect on
January 1, 2009. The SO2 emissions cap-and-trade program
is scheduled to take effect in 2010.
54
Clean Air Mercury Rule. However, these rules are not
enforceable since the U.S. Court of Appeals decision to
vacate the federal Clean Air Mercury Rule.
We do not believe that the court decision that vacated
the federal Clean Air Mercury Rule will significantly affect
pollution control obligations in Illinois in the near term.
Under the MPS, as amended, Illinois generators may
defer until 2015 the requirement to reduce mercury
emissions by 90%, in exchange for accelerated installation
of NOx and SO2 controls. This rule, when fully
implemented, is expected to reduce mercury emissions by
90%, NOx emissions by 50%, and SO2 emissions by 70%
by 2015 in Illinois. To comply with the rule, Genco, CILCO
(AERG) and EEI have begun putting into service
equipment designed to reduce mercury emissions. Genco,
CILCO (AERG) and EEI will also need to install additional
pollution control equipment. Current plans include
installing scrubbers for SO2 reduction as well as optimizing
operations of selective catalytic reduction (SCR) systems
for NOx reduction at certain coal-fired plants in Illinois. The
Illinois Joint Committee on Administrative Rules approved
a rule amendment in June 2009 that revised certain
requirements of the MPS. As a result, Genco and CILCO
(AERG) collectively were able to defer to subsequent
years an estimated $300 million of environmental capital
expenditures originally scheduled for 2009 through 2011.
In March 2008, the EPA finalized regulations that will
lower the ambient standard for ozone. Illinois and Missouri
have each submitted their recommendations to the EPA
for designating nonattainment areas. A final action by the
EPA to designate nonattainment areas is expected in
March 2010. State implementation plans will need to be
submitted in 2013 unless Illinois and Missouri seek
extensions for various requirement dates. Additional
emission reductions may be required as a result of future
state implementation plans. In January 2010, the EPA
announced its plans to revise the ozone standard to a
level lower than the level set in 2008. At this time, we are
unable to determine the impact state implementation plans
for such regulations would have on our results of
operations, financial position, and liquidity.
The table below presents estimated capital costs that
are based on current technology to comply with state air
quality implementation plans, the MPS, federal ambient air
quality standards including ozone and fine particulates,
and the federal Clean Air Visibility rule. The estimates
shown in the table below could change depending upon
additional federal or state requirements, the requirements
under a MACT standard, new technology, variations in
costs of material or labor, or alternative compliance
strategies, among other factors. The timing of estimated
capital costs may also be influenced by whether emission
allowances are used to comply with any future rules,
thereby deferring capital investment. During 2009, Ameren
identified significant opportunities to defer or reduce
planned capital spending, which are reflected in the
estimates provided in the table. The capital cost estimates
are lower than previously anticipated, in part because of
Ameren’s ability to manage its generating fleet to minimize
emissions while complying with emission limits and air
permit requirements. Furthermore, previous estimates
included assumptions about potential and developing air
regulations, including rules that were subsequently
vacated by the courts. These estimates include capital
spending to comply primarily with existing and known
regulations as of December 31, 2009.
2010
2015 – 2017
$
2011– 2014
UE(a) ............ $
215
170 –
$
785
650 –
Genco ..........
150
120 –
AERG ..........
335
275 –
EEI ..............
Ameren ........ $ 265 $ 1,215 –
$ 1,485
(a) UE’s expenditures are expected to be recoverable in rates over time.
355 –
775 –
190 –
280 –
$ 150 $ 1,600 –
$ 25 –
30 –
65 –
0 –
$ 120 –
160 $
95
5
5
35 $
35
75
5
$ 410
915
230
345
$ 1,900
Total
In 2009, UE developed four-year and 20-year
Environmental Compliance Plans to comply with all
environmental regulations, including rules under the Clean
Water Act, to support its environmental cost recovery
mechanism tariff request, which was a part of its July 2009
electric rate case filing. The plans contain a
comprehensive assessment of environmental investments
likely to be required of UE. See Note 2 – Rate and
Regulatory Matters under Part II, Item 8, of this report for
additional information on UE’s pending electric rate case.
See Note 15 – Commitments and Contingencies
under Part II, Item 8, of this report for a further discussion
of environmental matters, including global climate change.
Cash Flows from Financing Activities
2009 versus 2008
As a result of turmoil in the capital and credit markets
in 2008 and 2009, we sought to improve our liquidity
position. We replaced and extended the expiration of our
credit facilities and sought to reduce our reliance on
borrowings from these credit facilities, increase cash
balances and increase the equity content of our
capitalization. We also sought to eliminate debt at
CILCORP as a step in simplifying our organizational
structure.
During 2009, Ameren and its subsidiaries issued
$1 billion of senior debt and $634 million in common stock
and used the proceeds to repurchase, redeem, and fund
maturities of $631 million of long-term debt, to reduce
short-term borrowings, and to fund capital expenditures
and other working capital needs at UE, CIPS, Genco,
CILCO and IP. Comparatively, during 2008, Ameren’s
subsidiaries issued $1.9 billion of senior debt and $154
million in common stock and used the proceeds to
repurchase, redeem, and fund maturities of $842 million of
long-term debt, reduce short-term borrowings, and fund
capital expenditures and other working capital needs at
UE, CIPS, Genco, CILCO and IP. Ameren’s capital
issuance costs increased in 2009 compared with 2008
because of $40 million in banking fees associated with the
2009 Multiyear Credit Agreements and the 2009 Illinois
Credit
55
Agreement and $17 million of issuance costs associated with
Ameren’s September 2009 common stock issuance, partially
offset by a decrease in issuance costs associated with long-
term debt. Benefiting 2009 cash from financing activities,
compared with 2008, was a $196 million decrease in
common stock dividends, and a $47 million increase in
generator advances received for construction under
generator interconnection agreements, net of repayments.
UE’s net cash provided by financing activities decreased
during 2009, compared with 2008, primarily because of
$251 million of short-term borrowings repayments in 2009
compared with net short-term borrowings of $169 million in
2008, a $350 million decrease in the issuances of long-term
debt, and a $184 million increase in net repayments under an
intercompany borrowing arrangement with Ameren. Benefits
to cash for 2009, compared with 2008, included a
$436 million capital contribution from Ameren funded by the
proceeds of Ameren’s September 2009 common stock
issuance, a $378 million decrease in redemptions of long-
term debt, and an $89 million decrease in common stock
dividend payments. The proceeds from the capital
contribution were primarily used to reduce outstanding short-
term borrowings.
CIPS’ net cash used in financing activities increased
during 2009 compared with 2008. CIPS used existing cash to
fund a net reduction in money pool borrowings, to pay
$47 million of dividends to Ameren in 2009, and to fund a
$3 million increase in debt issuance costs as a result of the
banking fees associated with the 2009 Illinois Credit
Agreement. Benefiting the 2009 period was a $66 million
capital contribution from Ameren.
Genco’s cash provided by financing activities increased
during 2009 compared with 2008, primarily as a result of a
$101 million reduction in dividends paid on common stock
and $100 million change in short-term borrowings
repayments. These benefits to cash during the 2009 period
were slightly offset by a $106 million decrease in net money
pool borrowings and a $51 million decrease in the issuance
of long-term debt.
CILCO had a net use of cash from financing activities in
2009, compared with a net source of cash in 2008 primarily
as a result of the change in CILCO’s money pool borrowings,
$127 million increase in repayments of short-term
borrowings, a $150 decrease in issuance of long-term debt,
and a $6 million increase in capital issuance costs as a result
of banking fees associated with the 2009 Illinois Credit
Agreement. During 2009, CILCO repaid a net $98 million to
the money pool; CILCO received $98 million of net
borrowings in 2008. Cash from financing activities benefited
from a $288 million increase in intercompany borrowings
from Ameren, a $51 million capital contribution from
CILCORP, and a $35 million decrease in redemptions of
long-term debt and preferred stock.
IP had a net use of cash from financing activities during
2009, compared with a net source of cash in 2008, primarily
as a result of a $730 million decrease in long-term debt
issuances. During 2009, cash from financing activities
benefited from $175 million decrease in net short-term
borrowings repayments, a $141 million decrease in
redemptions and maturities of long-term debt, including IP
SPT, $155 million capital contribution received from Ameren,
and a $40 million increase in net generator advances
received for construction under generator interconnection
agreements. During 2009, IP used existing cash to fund the
maturity of $250 million of its 7.50% mortgage bonds and to
pay banking fees associated with the 2009 Illinois Credit
Agreement. Comparatively, during 2008, IP issued
$730 million of senior secured notes to redeem all of IP’s
outstanding auction-rate pollution control revenue refunding
bonds, which had adjusted to higher interest rates as a result
of the collapse of the auction-rate securities market, and to
fund debt maturities and common stock dividends.
2008 versus 2007
During the year ended December 31, 2008, the Ameren
Companies issued $1.9 billion of senior debt. The proceeds
were used to repurchase, redeem, and fund maturities of
$842 million of long-term debt, to reduce short-term
borrowings, and to fund capital expenditures and other
working capital needs at UE, CIPS, Genco, CILCO and IP.
During the year ended December 31, 2007, net short-term
borrowings of $860 million and senior debt of $674 million
were used to fund $488 million of maturities of long-term
debt, to fund working capital needs at Ameren subsidiaries
and to build liquidity during a period of legislative uncertainty
in Illinois. Additionally, CILCO redeemed the remaining
shares of its 5.85% Class A preferred stock to complete the
mandatory sinking fund redemption requirement, which
resulted in a $16 million use of cash during 2008 compared
with 2007. Benefiting 2008, compared with 2007, was a
$63 million increase in proceeds from the issuance of
Ameren common stock, which resulted from increased sales
through Ameren’s 401(k) plan and DRPlus.
UE’s net cash from financing activities increased in the
year ended December 31, 2008, compared with the year
ended December 31, 2007. During 2008, UE used
$699 million in proceeds from the issuance of senior secured
notes to redeem outstanding auction-rate environmental
improvement revenue refunding bonds that had adjusted to
higher interest rates as a result of the collapse of the auction-
rate securities market, and to fund the maturity of
$148 million of UE’s 6.75% first mortgage bonds.
Additionally, net short-term borrowings increased
$321 million. These borrowings were primarily used to fund
working capital needs and capital expenditures. In 2007, UE
issued $424 million in senior secured notes and received a
$380 million capital contribution from Ameren to fund working
capital requirements and to reduce net short-term
borrowings.
CIPS had a net use of cash from financing activities in
2008, compared with a net source of cash in 2007. This
change occurred because CIPS used net money pool
borrowings and existing cash to fund a net reduction in short-
term borrowings, to redeem $35 million of auction-rate
environmental improvement revenue refunding bonds that
56
had adjusted to higher interest rates as a result of the
collapse of the auction-rate securities market, and to fund
the maturity of $15 million of its 5.375% senior secured
notes during 2008. In 2007, CIPS used net short-term
borrowings of $90 million to fund working capital needs to
build liquidity, and to fund $40 million of common stock
dividends.
Genco issued $300 million of 7.00% senior unsecured
notes during 2008, which resulted in a net source of cash
from financing activities compared with a net use of cash
in 2007. The proceeds from the issuance were used to
fund capital expenditures and other working capital
requirements, including a net reduction of $200 million of
short-term borrowings during 2008 compared with 2007.
CILCO’s cash provided by financing activities
decreased in 2008 compared with 2007. This decrease
was primarily the result of CILCO’s net repayments of
short-term borrowings during 2008 compared with 2007.
These repayments were funded by a net increase in
money pool borrowings of $98 million, primarily at AERG,
and CILCO’s issuance of $150 million of its 8.875% senior
secured notes. Partially offsetting the decrease were
reduced redemptions and maturities of long-term debt in
2008. During 2008, $19 million of auction-rate
environmental improvement revenue refunding bonds that
had adjusted to higher interest rates as a result of the
collapse of the auction-rate securities market were
redeemed at CILCO. In 2007, $50 million of CILCO’s
7.50% bonds matured.
IP’s cash from financing activities decreased in 2008,
compared with 2007. During 2008, IP issued $730 million
of senior secured notes and used the proceeds to redeem
all of IP’s outstanding auction-rate pollution control
revenue refunding bonds that had adjusted to higher rates
as a result of the collapse of the auction-rate securities
market and to repay short-term borrowings. Additionally,
during 2008, IP funded $60 million of common stock
dividends to Ameren and had net short-term borrowings
repayments of $175 million. Comparatively, during 2007,
IP issued $250 million of senior secured notes, paid $61
million of common stock dividends, and had $100 million
of net borrowings under the 2007 credit facility. These
borrowings were used to fund $87 million of long-term
debt maturities and $43 million of net money pool
repayments to build liquidity in 2007.
Credit Facility Borrowings and Liquidity
The liquidity needs of the Ameren Companies are
typically supported through the use of available cash,
short-term intercompany borrowings, or drawings under
committed bank credit facilities. See Note 4 – Credit
Facility Borrowings and Liquidity under Part II, Item 8, of
this report for additional information on credit facilities,
short-term borrowing activity, relevant interest rates, and
borrowings under Ameren’s utility and non-state-regulated
subsidiary money pool arrangements.
The following table presents the committed bank credit facilities of Ameren and the Ameren Companies, and their
availability as of December 31, 2009:
Credit Facility
Ameren, UE and Genco:
Ameren, CIPS, CILCO, and IP:
2009 Multiyear revolving(a)(b) .............................................................................................. July 2011
2009 Illinois revolving ........................................................................................................ June 2011
(a) Ameren Companies may access these credit facilities through intercompany borrowing arrangements.
(b)
Includes the 2009 Multiyear Credit Agreement and the Supplemental Agreement. The Supplemental Agreement will terminate in July 2010 with all
commitments and all outstanding amounts being consolidated with those under the 2009 Multiyear Credit Agreement. At that time, the combined maximum
amount available to all borrowers will be $1.0795 billion, and the UE and Genco Borrowing Sublimits remain the same; Ameren’s Sublimit changes to
$1.0795 billion.
In addition to amounts drawn on these facilities, the amount available is further reduced by standby letters of credit issued under the facilities. The amount of
such letters of credit at December 31, 2009, was $15 million.
(c)
Expiration
Amount Committed
Amount Available
$ 1,300
800
$ 555(c)
700
The combined maximum amount available to all of the
borrowers, collectively, under the 2009 Multiyear Credit
Agreement and the Supplemental Credit Agreement
(collectively, the “2009 Multiyear Credit Agreements”) is
$1.3 billion. The combined maximum amount available to
each borrower, individually, under the 2009 Multiyear
Credit Agreements is limited as follows: Ameren – $1.15
billion, UE – $500 million and Genco – $150 million (such
amounts being each borrower’s “Borrowing Sublimit”).
CIPS, CILCO, and IP have no borrowing authority or
liability under the 2009 Multiyear Credit Agreements.
These credit facilities were also available for use, subject
to applicable regulatory short-term borrowing
authorizations, by EEI or other Ameren non-state-
regulated subsidiaries through direct short-term
borrowings from Ameren and by most of
Ameren’s merchant generating subsidiaries, including, but
not limited to, Ameren Services, Resources Company,
AERG, Marketing Company and AFS, through a non-
state- regulated subsidiary money pool agreement.
Ameren has money pool agreements with and among its
subsidiaries to coordinate and to provide for certain short-
term cash and working capital requirements. Separate
money pools are maintained for utility and non-state-
regulated entities. In addition, a unilateral borrowing
agreement among Ameren, IP, and Ameren Services
enables IP to make short-term borrowings directly from
Ameren. The aggregate amount of borrowings outstanding
at any time by IP under the unilateral borrowing
agreement and the utility money pool agreement, together
with any outstanding external credit facility borrowings by
IP, may not exceed $500 million,
57
pursuant to authorization from the ICC. IP is not currently
borrowing under the unilateral borrowing agreement.
Ameren Services is responsible for operation and
administration of the money pool agreements. See Note 4
– Credit Facility Borrowings and Liquidity under Part II,
Item 8, of this report for a detailed explanation of the
money pool arrangements and the unilateral borrowing
agreement.
The combined maximum amount available to all
borrowers collectively under the 2009 Illinois Credit
Agreement is $800 million, and the combined maximum
amount available to each borrower individually, under the
2009 Illinois Credit Agreement is limited as follows:
Ameren – $300 million, CIPS – $135 million, CILCO –
$150 million, and IP – $350 million.
On January 21, 2009, Ameren entered into a
$20 million term loan agreement due January 20, 2010,
which was fully drawn on January 21, 2009. This term
loan agreement was repaid at maturity in January 2010.
See Note 4 – Credit Facility Borrowings and Liquidity
under Part II, Item 8, of this report for additional
information.
In addition to committed credit facilities, a further
source of liquidity for the Ameren Companies from time to
time is available cash and cash equivalents. At
December 31, 2009, Ameren, UE, CIPS, Genco, CILCO,
and IP had $622 million, $267 million, $28 million, $6
million, $88 million, and $190 million, respectively, of cash
and cash equivalents.
Long-term Debt and Equity
The issuance of short-term debt securities by
Ameren’s utility subsidiaries is subject to approval by
FERC under the Federal Power Act. In March 2008,
FERC issued an order authorizing these utility subsidiaries
to issue such securities subject to the following limits on
outstanding balances: UE – $1 billion, CIPS – $250
million, and CILCO – $250 million. The authorization was
effective as of April 1, 2008, and terminates on March 31,
2010. UE, CIPS and CILCO have pending requests with
FERC seeking authority to issue short-term debt securities
subject to limits on outstanding balances of $1 billion,
$300 million, and $250 million, respectively, for the period
April 1, 2010, through March 31, 2012. IP has unlimited
short-term borrowing authorization from FERC.
Genco was authorized by FERC in its March 2008
order to have up to $500 million of short-term debt
outstanding at any time. Genco is seeking a renewal of
that authorization. AERG and EEI have unlimited short-
term borrowing authorization from FERC.
The issuance of short-term debt securities by Ameren
is not subject to approval by any regulatory body.
The Ameren Companies continually evaluate the
adequacy and appropriateness of their credit
arrangements given changing business and credit market
conditions. When business and credit market conditions
warrant, changes may be made to existing credit
agreements or other short-term borrowing arrangements.
The following table presents the issuances of common stock and the issuances, redemptions, repurchases and
maturities of long-term debt and preferred stock (net of any issuance discounts and including any redemption premiums)
for the years 2009, 2008, and 2007 for the Ameren Companies. For additional information related to the terms and uses of
these issuances and the sources of funds and terms for the redemptions, see Note 5 – Long-term Debt and Equity
Financings under Part II, Item 8, of this report.
Issuances
Long-term debt
Ameren:
UE:
8.875% Senior unsecured notes due 2014 ..............................................
6.40% Senior secured notes due 2017 ....................................................
6.00% Senior secured notes due 2018 ....................................................
6.70% Senior secured notes due 2019 ....................................................
8.45% Senior secured notes due 2039 ....................................................
6.30% Senior unsecured notes due 2020 ................................................
7.00% Senior unsecured notes due 2018 ................................................
8.875% Senior secured notes due 2013 ..................................................
Genco:
CILCO:
IP:
6.125% Senior secured notes due 2017 ..................................................
6.25% Senior secured notes due 2018 ....................................................
9.75% Senior secured notes due 2018 ....................................................
Total Ameren long-term debt issuances ........................................................
Common stock
Ameren:
21,850,000 shares at $25.25 ...................................................................
DRPlus and 401(k) ..................................................................................
Month Issued, Redeemed,
Repurchased or Matured
2009
2008
2007
$
423
$
-
$
-
-
-
-
349
249
-
-
-
250
449
-
-
300
150
424
-
-
-
-
-
-
-
-
-
$ 1,021
-
336
394
$ 1,879
250
-
-
$ 674
$
552
82
$
-
154
$
-
91
May
June
April
June
March
November
April
December
November
April
October
September
Various
58
Month Issued, Redeemed,
Repurchased or Matured
2009
$
634
$ 1,655
2008
$
154
$ 2,033
2007
$
$
91
765
$
$
-
-
4
-
-
-
-
-
-
-
124
253
-
-
-
-
-
-
-
-
250
-
-
-
4
63
64
60
43
148
35
15
-
-
-
19
112
75
70
45
35
54
-
16
$
100
250
4
-
-
-
-
-
-
-
-
-
50
-
-
-
-
-
-
84
-
1
February
May
Various
April
May
May
May
May
April
December
October
December
January
April
May
May
May
May
June
Various
June
July
$
631
$
858
$
489
In July 2008, Ameren filed a Form S-3 registration
statement with the SEC authorizing the offering of six
million additional shares of its common stock under
DRPlus. Shares of common stock sold under DRPlus are,
at Ameren’s option, newly issued shares, treasury shares,
or shares purchased in the open market or in privately
negotiated transactions. Ameren is currently selling newly
issued shares of its common stock under DRPlus.
Ameren is also selling newly issued shares of
common stock under its 401(k) plan pursuant to an
effective SEC Form S-8 registration statement. Under
DRPlus and its 401(k) plan, Ameren issued 3.2 million,
4.0 million, and 1.7 million shares of common stock in
2009, 2008, and 2007, respectively, which were valued at
$82 million, $154 million, and $91 million for the respective
years.
In September 2009, Ameren issued and sold
21.85 million shares of its common stock at $25.25 per
share, for proceeds of $535 million, net of $17 million of
issuance costs. Ameren used the offering proceeds to
make
Total common stock issuances .....................................................................
Total Ameren long-term debt and common stock issuances ..........................
Redemptions, Repurchases and Maturities
Long-term debt
Ameren:
2002 5.70% notes due 2007 ....................................................................
Senior notes due 2007 ............................................................................
UE:
CIPS:
CILCORP:
CILCO:
IP:
City of Bowling Green capital lease (Peno Creek CT) ..............................
2000 Series B environmental improvement bonds due 2035 ....................
2000 Series A environmental improvement bonds due 2035 ....................
2000 Series C environmental improvement bonds due 2035 ....................
1991 Series environmental improvement bonds due 2020 .......................
6.75% Series first mortgage bonds due 2008 ...........................................
2004 Series pollution control bonds due 2025 ..........................................
5.375% Senior secured notes due 2008 ..................................................
8.70% Senior unsecured notes due 2009 ................................................
9.375% Senior bonds due 2029 ...............................................................
7.50% First mortgage bonds due 2007 ....................................................
2004 Series pollution control bonds due 2039 ..........................................
Series 2001 Non-AMT bonds due 2028 ...................................................
Series 2001 AMT bonds due 2017 ...........................................................
1997 Series A pollution control bonds due 2032 ......................................
1997 Series B pollution control bonds due 2032 ......................................
1997 Series C pollution control bonds due 2032 ......................................
Note payable to IP SPT:
5.65% Series due 2008 ......................................................................
7.50% Series mortgage bond due 2009 .............................................
Preferred Stock
CILCO:
5.85% Series .....................................................................................
Total Ameren long-term debt and preferred stock redemptions, repurchases
and maturities .........................................................................................
In November 2008, Ameren, CIPS, Genco, CILCO
and IP, filed a Form S-3 shelf registration statement
registering the issuance of an indeterminate amount of
certain types of securities, which expires in November
2011. In June 2008, UE filed a Form S-3 shelf registration
statement registering the issuance of an indeterminate
amount of certain types of securities, which expires in
June 2011.
The following table presents information with respect
to the Form S-3 shelf registration statements filed and
effective for certain Ameren Companies as of
December 31, 2009:
Effective
Date
Ameren ............................................... November 2008
UE .....................................................
June 2008
CIPS ................................................... November 2008
Genco ................................................. November 2008
CILCO ................................................ November 2008
IP ..................................................... November 2008
Authorized
Amount
Not Limited
Not Limited
Not Limited
Not Limited
Not Limited
Not Limited
59
investments in its rate-regulated utility subsidiaries in the
form of capital contributions as follows: UE – $436 million,
CIPS – $13 million, CILCO – $25 million, and IP –
$61 million.
Ameren, UE, CIPS, Genco, CILCO and IP may sell
securities registered under their effective registration
statements if market conditions and capital requirements
warrant such a sale. Any offer and sale will be made only
by means of a prospectus that meets the requirements of
the Securities Act of 1933 and the rules and regulations
thereunder.
Indebtedness Provisions and Other Covenants
See Note 4 – Credit Facility Borrowings and Liquidity
and Note 5 – Long-term Debt and Equity Financings under
Part II, Item 8, of this report for a discussion of covenants
and provisions (and applicable cross-default provisions)
contained in our bank credit and term loan facilities and in
certain of the Ameren Companies’ indenture agreements
and articles of incorporation.
At December 31, 2009, the Ameren Companies were
in compliance with their credit facility, indenture, and
articles of incorporation provisions and covenants.
We consider access to short-term and long-term
capital markets a significant source of funding for capital
requirements not satisfied by our operating cash flows.
Inability to raise capital on favorable terms, particularly
during times of uncertainty in the capital markets, could
negatively affect our ability to maintain and expand our
businesses. After assessing our current operating
performance, liquidity, and credit ratings (see Credit
Ratings below), 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
or make access to the capital markets uncertain or limited.
Such events could increase our cost of capital and
adversely affect our ability to access the capital markets.
Dividends
Ameren paid to its shareholders common stock
dividends totaling $338 million, or $1.54 per share, in
2009, $534 million, or $2.54 per share, in 2008, and $527
million, or $2.54 per share, in 2007. This resulted in a
payout rate based on net income of 55% in 2009, 88% in
2008, and 85% in 2007. Dividends paid to common
shareholders in relation to net cash provided by operating
activities for the same periods were 17% in 2009, 35% in
2008 and 48% in 2007.
The amount and timing of dividends payable on
Ameren’s common stock are within the sole discretion of
Ameren’s board of directors. The board of directors has
not set specific targets or payout parameters when
declaring common stock dividends. However, as it has
done in the past, the board of directors is expected to
consider various issues, including Ameren’s overall payout
ratio, payout ratios of our peers, projected cash flow and
potential future cash flow requirements, historical earnings
and cash flow, projected earnings, impacts of regulatory
orders or legislation, and other key business
considerations. On February 12, 2010, the board of
directors of Ameren declared a quarterly dividend on
Ameren’s common stock of 38.5 cents per share, payable
on March 31, 2010, to shareholders of record on
March 10, 2010.
Certain of our financial agreements and corporate
organizational documents contain covenants and
conditions that, among other things, restrict the Ameren
Companies’ payment of dividends in certain
circumstances. At December 31, 2009, none of these
circumstances existed at the Ameren Companies and, as
a result, they were allowed to pay dividends.
UE would be restricted as to dividend payments on its
common and preferred stock if it were to extend or defer
interest payments on its subordinated debentures. CIPS’
articles of incorporation and mortgage indentures require
its dividend payments on common stock to be based on
ratios of common stock to total capitalization and other
provisions related to certain operating expenses and
accumulations of earned surplus. Genco’s indenture
includes restrictions that prohibit it from making any
dividend payments on common stock if debt service
coverage ratios are below a defined threshold. CILCO has
restrictions in its articles of incorporation on dividend
payments on common stock relative to the ratio of its
balance of retained earnings to the annual dividend
requirement on its preferred stock.
60
UE, CIPS, Genco, CILCO and IP as well as certain
other nonregistrant Ameren subsidiaries are subject to
Section 305(a) of the Federal Power Act, which makes it
unlawful for any officer or director of a public utility, as
defined in the Federal Power Act, to participate in the
making or paying of any dividend from any funds “properly
included in capital account.” The meaning of this limitation
has never been clarified under the Federal Power Act or
FERC regulations; however, FERC has consistently
interpreted the provision to allow dividends to be paid as
long as (1) the source of the dividends is clearly disclosed,
(2) the dividends are not excessive and (3) there is no
self-dealing on the part of corporate officials. At a
minimum, Ameren believes that dividends can be paid by
its subsidiaries that are public utilities from net income and
retained earnings. In addition, under Illinois law, CIPS,
CILCO and IP may not pay any dividend on their
respective stock, unless, among other things, their
respective earnings and earned surplus are sufficient to
declare and pay a dividend after provision is made for
reasonable and proper reserves, or unless CIPS, CILCO
or IP has specific authorization from the ICC.
Contractual Obligations
The following table presents common stock dividends
paid by Ameren Corporation and by Ameren’s subsidiaries
to their respective parents.
UE
CIPS ...............................................
Genco .............................................
CILCO ............................................
IP .................................................
Nonregistrants ................................
Dividends paid by Ameren ..............
2009
$ 175
47
-
20
31
65
$ 338
2008
$ 264
-
101
-
60
109
$ 534
2007
$ 267
40
113
-
61
46
$ 527
Certain of the Ameren Companies have issued
preferred stock on which they are obligated to make
preferred dividend payments. Each company’s board of
directors considers the declaration of the preferred stock
dividends to shareholders of record on a certain date,
stating the date on which the dividend is payable and the
amount to be paid. See Note 10 – Preferred Stock under
Part II, Item 8, of this report for further detail concerning
the preferred stock issuances.
The following table presents our contractual obligations as of December 31, 2009. See Note 11 – Retirement Benefits
under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plans.
These expected pension funding amounts are not included in the table below. In addition, routine short-term purchase
order commitments are not included.
Ameren:(a)
Long-term debt and capital lease obligations(b)(c) ...........
Short-term debt and credit facility borrowings ................
Interest payments(d) ......................................................
Operating leases(e) ........................................................
2007 Illinois Electric Settlement Agreement ...................
Other obligations(f) ........................................................
Total cash contractual obligations .................................
UE:
Long-term debt and capital lease obligations(c) ..............
Interest payments(d) ......................................................
Operating leases(e) ........................................................
Other obligations(f) ........................................................
Total cash contractual obligations .................................
CIPS:
Long-term debt(c) ...........................................................
Interest payments(d) ......................................................
Operating leases(e) ........................................................
2007 Illinois Electric Settlement Agreement ...................
Other obligations(f) ........................................................
Total cash contractual obligations .................................
Genco:
Long-term debt(c) ...........................................................
Intercompany note payable – CIPS ...............................
Interest payments .........................................................
Operating leases(e) ........................................................
2007 Illinois Electric Settlement Agreement ...................
Other obligations(f) ........................................................
Total cash contractual obligations .................................
Total
Less than 1 Year
1 - 3 Years
3 - 5 Years
After 5 Years
$
7,333
850
5,276
351
3
7,048
$ 20,861
$
4,030
3,220
157
3,812
$ 11,219
$
$
$
$
422
286
2
(g )
346
1,056
1,025
45
679
133
1
648
2,531
$
204
20
467
37
3
1,714
$ 2,445
$
333
830
887
59
-
2,558
$ 4,667
$
940
-
812
52
-
996
$ 2,800
4
239
14
729
986
-
27
-
(g )
93
120
200
45
57
9
1
233
545
$
$
$
$
$
$
183
474
25
1,029
1,711
150
39
1
-
142
332
-
-
86
17
-
374
477
$
$
$
$
$
$
314
443
25
614
1,396
51
32
1
-
89
173
-
-
86
17
-
38
141
$
$
$
$
$
$
61
$
5,856
-
3,110
203
-
1,780
$ 10,949
$
$
$
$
$
$
3,529
2,064
93
1,440
7,126
221
188
-
-
22
431
825
-
450
90
-
3
1,368
CILCO:
Long-term debt .............................................................
Intercompany note payable – Ameren ...........................
Interest payments .........................................................
Operating leases(e) ........................................................
2007 Illinois Electric Settlement Agreement ...................
Other obligations(f) ........................................................
Total cash contractual obligations .................................
IP:
Long-term debt(b)(c) ........................................................
Interest payments .........................................................
Operating leases(e) ........................................................
2007 Illinois Electric Settlement Agreement ...................
Other obligations(f) ........................................................
Total cash contractual obligations .................................
Total
$
279
288
173
16
1
1,043
$ 1,800
$ 1,150
752
6
1
733
$ 2,642
Less than 1 Year
1 - 3 Years
3 - 5 Years
After 5 Years
$
-
288
21
1
1
263
$ 574
$
-
85
2
1
226
$ 314
$
1
-
42
2
-
428
$ 473
$
-
170
3
-
297
$ 470
$ 150
-
29
2
-
161
$ 342
$
-
170
1
-
87
$ 258
$ 128
-
81
11
-
191
$ 411
$ 1,150
327
-
-
123
$ 1,600
Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations.
(a)
(b) Excludes fair-market value adjustments of long-term debt of $6 million for IP.
(c) Excludes unamortized discount of $2 million at Ameren, $8 million at UE, $1 million at CIPS, $2 million at Genco, and $9 million at IP.
(d) The weighted average variable-rate debt has been calculated using the interest rate as of December 31, 2009.
(e) Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. Ameren’s $2 million annual obligation for these items is
included in the Less than 1 Year, 1 – 3 Years, and 3 – 5 Years columns. Amounts for After 5 Years are not included in the total amount because that period
is indefinite.
(f) See Other Obligations within Note 15 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items represented herein.
(g) Less than $1 million.
As of December 31, 2009, the amounts of
unrecognized tax benefits were $135 million, $88 million,
$- million, $28 million, $15 million and $- million for
Ameren, UE, CIPS, Genco, CILCO and IP, respectively. It
is reasonably possible to expect that the settlement of an
unrecognized tax benefit will result in an underpayment or
overpayment of tax and related interest. However, there is
a high degree of uncertainty with respect to the timing of
cash payments or receipts associated with unrecognized
tax benefits. The amount and timing of certain payments
or receipts is not reliably estimable or determinable at this
time. See Note 13 – Income Taxes under Part II, Item 8, of
this report for information regarding the Ameren
Companies’ unrecognized tax benefits and related
liabilities for interest expense.
Off-Balance-Sheet Arrangements
At December 31, 2009, none of the Ameren
Companies had any off-balance-sheet financing
arrangements other than operating leases entered into in
the ordinary course of business. None of the Ameren
Companies expect to engage in any significant off-
balance-sheet financing arrangements in the near future.
Credit Ratings
The following table presents the principal credit
ratings of the Ameren Companies by Moody’s, S&P, and
Fitch effective on the date of this report:
Ameren:
Issuer/corporate credit rating .........
Senior unsecured debt ..................
UE:
Issuer/corporate credit rating .........
Secured debt ................................
CIPS:
Issuer/corporate credit rating .........
Secured debt ................................
Senior unsecured debt ..................
Genco:
Issuer/corporate credit rating .........
Senior unsecured debt ..................
CILCO:
Issuer/corporate credit rating .........
Secured debt ................................
IP:
Issuer/corporate credit rating .........
Secured debt ................................
Moody’s Ratings Actions
Moody’s
S&P
Fitch
Baa3
Baa3
Baa2
A3
Baa3
Baa1
Baa3
-
Baa3
Baa3
Baa1
Baa3
Baa1
BBB-
BB+
BBB-
BBB
BBB-
BBB+
BBB-
BBB-
BBB-
BBB-
BBB+
BBB-
BBB
BBB+
BBB+
BBB+
A
BBB -
BBB+
BBB
BBB+
BBB+
BBB
A -
BBB -
BBB+
On January 29, 2009, Moody’s affirmed the ratings of
CIPS, CILCO and IP and changed their rating outlooks to
stable from positive. According to Moody’s, the change in
the rating outlooks of these three companies was based
on the near-term expiration of the 2007 and 2006 $500
million
62
S&P Ratings Actions
On February 25, 2009, S&P stated that it viewed the
reduction in Ameren’s dividend as credit supportive. S&P did
not make any changes in Ameren’s or its subsidiaries’ credit
ratings or outlooks as a result of this action. S&P raised the
business profile of UE to “excellent” from “strong” to reflect
the electric rate order issued by the MoPSC in January 2009,
which S&P viewed as constructive. S&P lowered the
business profile of CILCO to “satisfactory” from “strong.”
On February 25, 2010, S&P assigned improved business
risk profiles to CIPS and IP of “excellent” from “strong” and to
CILCO of “strong” from “satisfactory.”
Fitch Ratings Actions
On February 17, 2009, Fitch stated that the reduction in
Ameren’s common stock dividend and other cost cutting
measures would be favorable to bondholders and credit
quality. Fitch did not make any changes in Ameren’s or its
subsidiaries’ ratings or outlooks as a result of this action.
On March 9, 2009, Fitch lowered the credit ratings of UE
by one notch as follows: issuer rating to BBB+, senior
secured debt to A, subordinated debt to BBB+, and preferred
stock to BBB+. The rating outlook was changed to stable.
Fitch stated that these downgrades were made because of
deteriorating financial measures over the past several years
and the expectation that they will not improve materially
without further rate support. They noted the financial
deterioration was primarily due to increasing fuel and
operating costs and a large capital expenditure program.
On July 31, 2009, Fitch affirmed the credit rating of
Genco and changed its rating outlook to negative from stable.
Additionally, Fitch affirmed the credit ratings of Ameren with a
stable outlook. According to Fitch, the change in the credit
rating outlook of Genco was based on the unfavorable
outlook for wholesale energy prices and the sensitivity of the
company’s largely coal-fired generating fleet to greenhouse
gas and other environmental regulations. According to Fitch,
the affirmation of Ameren’s credit ratings and stable outlook
reflected the significant earnings and cash flow contribution
derived from regulated utilities, the beneficial impact of recent
rate increases in Illinois and Missouri, the savings generated
by the February 2009 dividend reduction, and steps taken to
maintain liquidity, including the renewal of bank credit
facilities.
On January 22, 2010, Fitch announced new guidelines
that affect its ratings on deferrable coupon hybrid securities
and preferred stock for utility issuers. Under these new
guidelines, Fitch will rate these securities two notches below
the issuer’s senior unsecured debt ratings. The prior
guidelines rated these securities one notch below. The
ratings for UE, CIPS, CILCO and IP’s preferred stock, and for
UE’s
credit facilities in January 2010 and related liquidity concerns.
Moody’s also on January 29, 2009, affirmed the ratings of
Ameren and UE with a stable outlook based on the January
2009 MoPSC electric rate order approving a rate increase
and a FAC for UE.
On February 16, 2009, Moody’s affirmed the ratings of
Ameren, UE, CIPS, Genco, CILCO, and IP with a stable
outlook. The affirmation reflected Moody’s view that
Ameren’s announcement to reduce its common dividend by
39% was a conservative, prudent, and credit positive action
that would conserve cash and support financial coverage
metrics. Moody’s stated that the more conservative dividend
payout should also help facilitate the renewal of Ameren’s
credit facilities that expired in 2010. They stated the dividend
reduction should continue to reduce reliance on the credit
facilities going forward and would likely be viewed favorably
by lenders considering renewing or entering into new facilities
with Ameren and its subsidiaries, which was important
considering constrained credit market conditions at that time.
According to Moody’s, the stable outlook on Ameren, UE,
CIPS, Genco, CILCO, and IP reflected constructive rate case
outcomes at UE, CIPS, CILCO and IP, including the approval
of a FAC at UE; the improving regulatory environments for
investor-owned utilities in Illinois and Missouri at that time;
and Moody’s expectation that financial and cash flow
coverage metrics should remain adequate to maintain current
rating levels. In addition, Moody’s noted that the dividend
reduction was supportive of the stable ratings outlooks and
provided Ameren and its subsidiaries additional cushion at
the rating levels.
On July 1, 2009, Moody’s stated that the successful
execution of new two-year bank credit facilities was
supportive of the credit quality of Ameren and its utility
subsidiaries. However, Moody’s did not make any changes in
Ameren’s or its subsidiaries’ ratings or outlooks as a result of
this action.
On August 3, 2009, Moody’s upgraded the majority of
senior secured debt ratings of investment-grade regulated
utilities by one notch. Senior secured debt ratings at UE were
upgraded from Baa1 to A3 and at CIPS and IP from Baa3 to
Baa2. Moody’s stated the rating action widened the notching
between most senior secured debt ratings and senior
unsecured debt ratings of investment-grade regulated utilities
to two notches from one previously. Moody’s noted the wider
notching was based on its analysis of the history of regulated
utility defaults, which indicated that regulated utilities have
defaulted at a lower rate and experienced lower loss given
default rates than nonfinancial, nonutility corporate issuers.
On August 13, 2009, Moody’s upgraded the ratings of
CIPS, CILCO and IP. Issuer/corporate credit ratings at CIPS,
CILCO and IP were upgraded from Ba1 to Baa3. Moody’s
also upgraded the senior secured debt ratings at CIPS,
CILCO and IP from Baa2 to Baa1. Moody’s cited the
execution of new bank credit facilities and an improved
political and regulatory environment in Illinois as the basis for
the return to investment grade status of the issuer/corporate
ratings. Moody’s also affirmed the ratings of Ameren, UE and
Genco and assigned a stable outlook for Ameren and all of
its rated subsidiaries.
63
7.69% subordinated deferrable interest debentures, were
affected by this industry-wide methodology change.
these events have several implications for our industry as a
whole, including Ameren. They include the following:
Collateral Postings
Any adverse change in the Ameren Companies’ credit
ratings may reduce access to capital and trigger additional
collateral postings and prepayments. Such changes may also
increase the cost of borrowing and fuel, power, and gas
supply, among other things, resulting in a negative impact on
earnings. Collateral postings and prepayments made with
external parties including postings related to exchange-
traded contracts at December 31, 2009, were $106 million,
$25 million, $3 million, $1 million, and $14 million at Ameren,
UE, CIPS, CILCO and IP, respectively. The amount of
collateral external counterparties posted with Ameren was
$12 million at December 31, 2009. Sub-investment-grade
issuer or senior unsecured debt ratings (lower than “BBB-” or
“Baa3”) at December 31, 2009, could have resulted in
Ameren, UE, CIPS, Genco, CILCO or IP being required to
post additional collateral or other assurances for certain trade
obligations amounting to $368 million, $129 million,
$29 million, $48 million, $44 million, and $52 million,
respectively.
Changes in commodity prices could trigger additional
collateral postings and prepayments at current credit ratings.
If market prices were 15% higher than December 31, 2009,
levels in the next twelve months and 20% higher thereafter
through the end of the term of the commodity contracts, then
Ameren, UE, CIPS, Genco, CILCO or IP could be required to
post additional collateral or other assurances for certain trade
obligations up to approximately $171 million, $82 million, $-
million, $- million, $9 million, and $- million, respectively. If
market prices were 15% lower than December 31, 2009,
levels in the next twelve months and 20% lower thereafter
through the end of the term of the commodity contracts, then
Ameren, UE, CIPS, Genco, CILCO or IP could be required to
post additional collateral or other assurances for certain trade
obligations up to approximately $329 million, $171 million,
$14 million, $- million, $53 million, and $50 million,
respectively.
The cost of borrowing under our credit facilities can also
increase or decrease depending upon the credit ratings of the
borrower. A credit rating is not a recommendation to buy, sell,
or hold securities. It should be evaluated independently of
any other rating. Ratings are subject to revision or withdrawal
at any time by the rating organization.
OUTLOOK
Below are some key trends that may affect the Ameren
Companies’ financial condition, results of operations, or
liquidity in 2010 and beyond.
Economy and Capital and Credit Markets
In 2008 and 2009, global capital and credit markets
experienced extreme volatility. While these markets improved
during 2009, the availability and cost of capital and economic
activity continue to be significantly affected. We believe that
Access to Capital Markets and Cost of Capital – The
extreme disruption in the capital markets limited the
ability of many companies, including the Ameren
Companies, to freely access the capital and credit
markets to support their operations and to refinance
debt. Ameren and its subsidiaries continued to have
access to the capital markets, as evidenced by
Ameren’s, UE’s, Genco’s, CILCO’s and IP’s sale of debt
securities in late 2008 and 2009, as well as Ameren’s
common stock offering in September 2009. This access
has been at commercially acceptable but higher rates in
the case of the issuance of certain debt securities.
Credit Facilities – On June 30, 2009, Ameren and certain
of its subsidiaries successfully reached definitive
multiyear credit facility agreements. These facilities
cumulatively provide $2.1 billion of credit through July 14,
2010, reducing to $1.8795 billion through June 30, 2011,
and to $1.0795 billion through July 14, 2011. The costs
of these credit facilities are significantly higher than the
facilities they replaced. The costs to enter into the
multiyear credit facility agreements were $40 million in
the aggregate (UE – $11 million, CIPS – $3 million,
Genco – $4 million, CILCORP – $14 million, CILCO –
$7 million, and IP – $7 million). The costs will be
amortized over the term of the facilities. In addition,
borrowing rates under the facilities increased
significantly, including, in the case of Ameren, from
LIBOR plus 0.5%, under the prior credit facilities, to
LIBOR plus 2.75%. Ameren intends to replace or extend
its credit facility agreements during 2010.
Economic Conditions – Weak economic conditions have
resulted in reduced power prices, lower customer sales
growth, or sales contraction, particularly with respect to
industrial sales, and higher financing costs, among other
things. Weak economic conditions also expose the
Ameren Companies to greater risk of default by
counterparties, potentially higher bad debt expenses,
and the risk of impairment of goodwill and long-lived
assets, among other things. Based on the results of the
annual goodwill impairment test completed as of
October 31, 2009, the estimated fair value of Ameren’s
Merchant Generation reporting unit exceeded its carrying
value by a nominal amount. The failure in the future of
this reporting unit, or any reporting unit, to achieve
forecasted operating results and cash flows or a further
decline of observable industry market multiples may
reduce its estimated fair value below its carrying value
and would likely result in the recognition of a goodwill
impairment charge. Although we are unable to predict
when the U.S. economy will fully recover from the
economic downturn, we currently expect economic
conditions to improve in 2010. We are unable to predict
the ultimate impact of the weak economy on our results
of operations, financial position, or liquidity.
Investment Returns – The disruption in the capital
markets, coupled with weak global economic conditions,
adversely affected financial markets. As a result, we
64
experienced lower-than-expected investment returns in
2008 in our pension and postretirement benefit plans.
During 2009, the actual return on investment of the
pension plan assets was equal to the expected
investment return while the actual return on investment
of postretirement benefit assets exceeded the expected
return. Lower returns increase our future pension and
postretirement expenses and pension funding levels. Our
future expenses and funding levels will also be affected
by future investment returns and future discount rate
levels.
Operating and Capital Expenditures – The Ameren
Companies will continue to make significant levels of
investments and incur expenditures for their electric and
natural gas utility infrastructure in order to improve
overall system reliability, comply with environmental
regulations, and improve plant performance. However, in
response to the significant level of disruption and
uncertainties in the capital and credit markets and weak
economic conditions that reduced power prices and to
help our customers with their future energy costs, we
reduced our planned capital expenditures for 2010
through 2013 by approximately $2 billion, as compared
to earlier plans. Ameren also took steps to control
operations and maintenance expenditures. Ameren is
managing power plant outages and labor costs, among
other things. Any expenditure control initiatives will be
balanced against a continued long-term commitment to
invest in our electric and natural gas infrastructure to
provide safe, reliable electric and natural gas delivery
services to our customers; to meet federal and state
environmental, reliability, and other regulations; and the
need to maintain a solid overall liquidity and credit ratings
profile to meet our operating, capital, and financing
needs under challenging capital and credit market
conditions.
Liquidity – At December 31, 2009, Ameren, on a
consolidated basis, had available liquidity, in the form of
cash on hand and amounts available under its existing
credit facilities, of approximately $1.9 billion, which was
$0.6 billion more than it had at the end of 2008.
We believe that our liquidity is adequate given our
expected operating cash flows, capital expenditures, and
related financing plans (including accessing our existing
credit facilities). However, there can be no assurance that
significant changes in economic conditions, further
disruptions in the capital and credit markets, or other
unforeseen events will not materially affect our ability to
execute our expected operating, capital or financing plans.
Current Capital Expenditure Plans
Between 2010 and 2017, Ameren expects to invest up to
$1.9 billion, in the aggregate, to retrofit its coal-fired
power plants with pollution control equipment in
compliance with emissions-related environmental laws
and regulations. Any pollution control investments will
result in decreased plant availability during construction
and significantly higher ongoing operating expenses.
Approximately 20% of this investment is expected to be
in our Missouri Regulated operations, and it is therefore
expected to be recoverable from ratepayers, subject to
prudency reviews. Regulatory lag may materially impact
the timing of such recovery and, therefore, our cash
flows and related financing needs. The recoverability of
amounts expended in Merchant Generation operations
will depend on whether market prices for power adjust as
a result of market conditions reflecting increased
environmental costs for coal-fired generators.
Future federal and state legislation or regulations that
mandate limits on emissions would result in significant
increases in capital expenditures and operating costs.
Excessive costs to comply with future legislation or
regulations might force Ameren and other similarly
situated electric power generators to close some coal-
fired facilities. Investments to control emissions at
Ameren’s coal-fired power plants to comply with future
legislation or regulations would significantly increase
future capital expenditures and operations and
maintenance expenses, which if excessive could result in
the closures of coal-fired power plants, impairment of
assets, or otherwise materially adversely affect Ameren’s
results of operations, financial position, and liquidity.
UE continues to evaluate its longer-term needs for new
baseload and peaking electric generation capacity. UE’s
integrated resource plan filed with the MoPSC in
February 2008 included the expectation that new
baseload generation capacity would be required in the
2018 to 2020 time frame. Due to the significant time
required to plan, acquire permits for, and build a
baseload power plant, UE continues to study future plant
alternatives, including energy efficiency programs that
could help defer new plant construction. UE introduced
multiple energy efficiency programs in 2009. The goal of
these and future UE energy efficiency programs is to
reduce usage by 540 megawatts by 2025, which is the
equivalent of a medium-size coal-fired power plant. UE
will consider all available and feasible generation options
to meet future customer requirements as part of an
integrated resource plan that UE will file with the MoPSC
in 2011.
In July 2008, UE filed an application with the NRC for a
combined construction and operating license for a new
1,600-megawatt nuclear unit at UE’s existing Callaway
County, Missouri, nuclear plant site. In June 2009, UE
requested the NRC suspend review of the COLA and all
activities related to the COLA. As of December 31, 2009,
UE had capitalized approximately $69 million as
construction work in progress related to the COLA. The
incurred costs will remain capitalized while management
assesses all options to maximize the value of its
investment in this project. If all efforts are permanently
abandoned with respect to the future construction of a
new nuclear unit or management concludes it is probable
the costs incurred will be disallowed in rates, it is
possible that a charge to earnings could be recognized in
a future period.
UE intends to submit a license extension application with
the NRC to extend its existing Callaway nuclear plant’s
65
operating license by 20 years so that the operating
license will expire in 2044. UE cannot predict whether or
when the NRC will approve the license extension.
Over the next few years, we expect to make significant
investments in our electric and natural gas infrastructure
and to incur increased operations and maintenance
expenses to improve overall system reliability. We are
projecting higher labor and material costs for these
capital expenditures. We expect these costs or
investments at our rate-regulated businesses to be
ultimately recovered in rates, subject to prudency
reviews by regulators, although rate case outcomes and
regulatory lag could materially impact the timing of such
recovery and, therefore, our cash flows, related financing
needs and the timing in which we are able to proceed
with these projects.
Ameren is evaluating opportunities to expand its
transmission assets. New transmission projects have the
potential to reduce congestion, improve reliability, and
facilitate movement of renewable energy, typically
generated in remote areas, to population centers where
demand is at its highest.
Increased investments for environmental compliance,
reliability improvement, and new baseload capacity will
result in higher depreciation and financing costs.
Revenues
The earnings of UE, CIPS, CILCO and IP are largely
determined by the regulation of their rates by state
agencies. Rising costs, including labor, material,
depreciation and financing costs, coupled with increased
capital and operations and maintenance expenditures
targeted at enhanced distribution system reliability and
environmental compliance, are expected. Ameren, UE,
CIPS, CILCO and IP anticipate regulatory lag until their
requests to increase rates to recover such costs on a
timely basis are granted by state regulators. Ameren,
UE, CIPS, CILCO and IP expect to file rate cases
frequently. UE has agreed not to file a natural gas
delivery rate case before March 15, 2010.
In current and future rate cases, UE, CIPS, CILCO and
IP will continue to seek cost recovery and tracking
mechanisms from their state regulators to reduce
regulatory lag.
In July 2009, a new law became effective in Illinois that
allows electric and natural gas utilities to recover through
a rate adjustment the difference between their actual bad
debt expense and the bad debt expense included in
their base rates. In February 2010, the ICC approved
the Ameren Illinois Utilities’ electric and natural gas rate
adjustment tariffs to recover bad debt expense not
recovered in rates. The tariffs provide utilities the ability
to adjust their base rates annually through a rate
adjustment mechanism that applies to 2008 and
subsequent years. The Ameren Illinois Utilities were
required to make a one-time donation of $10 million
(CIPS – $2 million, CILCO – $2 million, and IP –
$6 million) for customer assistance programs, as
required by the legislation. The amount of the required
one-time donation and the impact of the recovery of
2008 and 2009 bad debt expenses were reflected in
2009 earnings.
66
In June 2009, CIPS, CILCO and IP filed requests with
the ICC to increase their annual revenues for electric and
natural gas delivery services. The currently pending
requests, as amended, seek to increase annual
revenues from electric delivery service by $115 million in
the aggregate (CIPS – $38 million, CILCO – $17 million,
and IP – $60 million). The electric rate increase requests
are based on an 11.3% to 11.7% return on equity, a
capital structure composed of 44% to 49% equity, an
aggregate rate base for the Ameren Illinois Utilities of
$2.3 billion, and a test year ended December 31, 2008,
with certain known and measurable adjustments through
May 2010. The currently pending requests, as amended,
seek to increase annual revenues for natural gas delivery
service by $15 million in the aggregate (CIPS – $6
million, CILCO – $2 million, and IP – $7 million). The
natural gas rate increase requests are based on a 10.8%
to 11.2% return on equity, a capital structure composed
of 44% to 49% equity, an aggregate rate base for the
Ameren Illinois Utilities of $1.0 billion, and a test year
ended December 31, 2008, with certain known and
measurable adjustments through May 2010. The ICC
staff has recommended, as amended, a net increase in
revenues for electric delivery service for the Ameren
Illinois Utilities of $57 million in the aggregate (CIPS –
$21 million increase, CILCO – $5 million increase, and IP
– $31 million increase) and a net decrease in revenues
for natural gas delivery service of $11 million in the
aggregate (CILCO – $6 million decrease, and IP –
$5 million decrease). The ICC proceedings relating to the
proposed electric and natural gas delivery service rate
changes will take place over a period of up to 11 months,
and decisions by the ICC in such proceedings are
required by May 2010.
UE filed a request with the MoPSC in July 2009 to
increase its annual revenues for electric service by
$402 million. Included in this increase request was
approximately $227 million of anticipated increases in
normalized net fuel costs in excess of the net fuel costs
included in base rates previously authorized by the
MoPSC in its January 2009 electric rate order, which,
absent initiation of this general rate proceeding, would
have been eligible for recovery through UE’s existing
FAC. The initial electric rate increase was based on an
11.5% return on equity, a capital structure composed of
47.4% equity, a rate base for UE of $6.0 billion, and a
test year ended March 31, 2009, with certain pro forma
adjustments through the anticipated true-up date of
January 31, 2010. In February 2010, UE filed rebuttal
testimony relating to certain positions taken by
interveners in the rate case and modified its
recommended return on equity to 10.8%. The MoPSC
staff has recommended an increase to UE’s annual
revenues of between $218 million to $251 million.
Included in this recommendation was approximately
$214 million of increases in normalized net fuel costs.
The MoPSC proceeding relating to the proposed electric
service rate changes will take place over a period of
up to
11 months, and a decision by the MoPSC in such
proceeding is required by the end of June 2010.
As part of its filing, UE also requested that the MoPSC
approve the implementation of an environmental cost
recovery mechanism and a storm restoration cost tracker
as well as the continued use of the FAC and the
vegetation management and infrastructural inspection
cost tracking mechanism that the MoPSC previously
authorized in its January 2009 electric rate order. The
environmental cost recovery mechanism, if approved,
would allow UE to adjust electric rates twice each year
outside of general rate proceedings to reflect changes in
its costs prudently incurred to comply with federal, state,
or local environmental laws, regulations, or rules greater
than or less than the amount set in base rates. Rate
adjustments pursuant to this cost recovery mechanism
would not be permitted to exceed an annual amount
equal to 2.5% of UE’s gross jurisdictional electric
revenues and would be subject to prudency reviews by
the MoPSC. The storm restoration cost tracker would
permit UE a more timely recovery of storm restoration
operations and maintenance expenditures.
The MoPSC issued an electric rate order in January
2009 approving an increase in annual electric revenues
of approximately $162 million. New rates were effective
March 1, 2009. In addition, pursuant to the accounting
order issued by the MoPSC in April 2008, the rate order
concluded that the $25 million of operations and
maintenance expenses incurred as a result of a severe
ice storm in January 2007 should be amortized and
recovered over a five-year period starting March 1, 2009.
The MoPSC also allowed recovery of $12 million of costs
associated with a March 2007 FERC order that resettled
costs among MISO market participants. UE recorded a
regulatory asset for these costs at December 31, 2008,
which are being amortized and recovered over a two-
year period beginning March 1, 2009.
In its electric rate order issued in January 2009, the
MoPSC approved UE’s implementation of a FAC and a
vegetation management and infrastructure inspection
cost tracking mechanism. The FAC allows an adjustment
of electric rates three times per year for a pass-through
to customers of 95% of changes in fuel and purchased
power costs, net of off-system revenues, including MISO
costs and revenues, greater or less than the amount set
in base rates, subject to MoPSC prudency reviews. The
vegetation management and infrastructure inspection
cost tracking mechanism provides for the tracking of
expenditures that are greater or less than amounts
provided for in UE’s annual revenues for electric service
in a particular year, subject to a 10% limitation on
increases in any one year. The tracked amounts may be
reflected in rates set in future rate cases.
Even though Taum Sauk was not available to generate
electricity for off-system revenues during 2009, UE
included $19 million in the calculation of the FAC as if
Taum Sauk had generated off-system revenues.
Therefore, UE’s customers received the benefit of Taum
Sauk’s historical off-system revenues even though the
plant was not operational. UE’s earnings and cash flows
from operations will increase after Taum Sauk becomes
operational, which is expected to be in the second
quarter of 2010, since the adjustment factor will be
eliminated from the FAC calculation. Taum Sauk is
expected to increase UE’s 2010 margins by $1.8 million
per month, when Taum Sauk returns to service in the
second quarter of 2010.
UE provides power to Noranda’s smelter plant in
New Madrid, Missouri, which has historically used
approximately four million megawatthours of power
annually, making Noranda UE’s single largest customer.
As a result of a severe ice storm in January 2009,
Noranda’s smelter plant experienced a power outage
related to non-UE lines that deliver power to the
substation serving the plant. Noranda stated in its Annual
Report on Form 10-K for the year ended December 31,
2008, that the outage affected approximately 75% of the
smelter plant’s capacity. In a September 30, 2009, press
release, Noranda stated that its smelter plant had
initiated steps to return operations to full capacity. These
steps include restarting the third of its three production
lines. The smelter plant’s load has been rising steadily as
repairs have been made to its production lines, with full
production expected to be reached in the second quarter
of 2010. As a result, UE expects its margins from sales
to Noranda will increase by approximately $40 million in
2010 compared with 2009. UE’s July 2009 electric rate
case filing with the MoPSC seeks approval to revise the
tariff under which it serves Noranda to prospectively
address the significant lost revenues UE can incur due to
any future operational issues at Noranda’s smelter plant
like the revenue losses resulting from the January 2009
storm-related power outage.
As part of the 2007 Illinois Electric Settlement
Agreement, the Ameren Illinois Utilities entered into
financial contracts with Marketing Company (for the
benefit of Genco and AERG), to lock in energy prices for
400 to 1,000 megawatts annually of their round-the-clock
power requirements during the period June 1, 2008, to
December 31, 2012, at then-relevant market prices.
These financial contracts do not include capacity, are not
load-following products, and do not involve the physical
delivery of energy. Under the terms of the 2007 Illinois
Electric Settlement Agreement, these financial contracts
are deemed prudent, and the Ameren Illinois Utilities are
permitted full recovery of their costs in rates.
Volatile power prices in the Midwest can affect the
amount of revenues Ameren, Genco, CILCO (through
AERG) and EEI generate by marketing power into the
wholesale and spot markets and can influence the cost
of power purchased in the spot markets. Spot power
prices in the MISO were lower in 2009 than in 2008 and
should be significantly affected by any prospect of global
economic recovery, among other things.
With few scheduled maintenances outages in 2010
through 2012, the Merchant Generation segment expects
to have available generation of 35 million megawatthours
in each year. However, the Merchant Generation
segment’s actual generation levels will be significantly
67
impacted by market prices for power in those years,
among other things.
The availability and performance of Genco’s, AERG’s
and EEI’s electric generation fleet can materially affect
their revenues. The Merchant Generation segment
expects to generate 30.5 million megawatthours of power
from its coal-fired plants in 2010 (Genco – 15.6 million,
AERG – 7.4 million, EEI – 7.5 million) based on expected
power prices. Should power prices rise more than
expected, the Merchant Generation segment has the
capacity and availability to sell more generation.
The marketing strategy for the Merchant Generation
EEI – 100%) was delivered by rail from the Powder River
Basin in Wyoming. In the past, deliveries from the
Powder River Basin have occasionally been restricted
because of rail maintenance, weather, and derailments.
As of December 31, 2009, coal inventories for UE,
Genco, AERG and EEI were at targeted levels.
Disruptions in coal deliveries could cause UE, Genco,
AERG and EEI to pursue a strategy that could include
reducing sales of power during low-margin periods,
buying higher-cost fuels to generate required electricity,
or purchasing power from other sources.
Ameren’s fuel costs (including transportation) are
segment is to optimize generation output in a low risk
manner to minimize volatility of earnings and cash flow,
while seeking to capitalize on its low-cost generation fleet
to provide solid, sustainable returns. To accomplish this
strategy, the Merchant Generation segment has
established hedge targets for near-term years. Through a
mix of physical and financial sales contracts, Marketing
Company targets to hedge Merchant Generation’s
expected output by 80% to 90% for the following year,
50% to 70% for two years out, and 30% to 50% for three
years out. As of January 31, 2010, Marketing Company
had hedged approximately 26 million megawatthours of
Merchant Generation’s expected 2010 generation, at an
average price of $47 per megawatthour. For 2011,
Marketing Company had hedged approximately
18 million megawatthours of Merchant Generation’s
forecasted generation sales at an average price of $49
per megawatthour. For 2012, Marketing Company had
hedged approximately 12 million megawatthours of
Merchant Generation’s forecasted generation sales at an
average price of $53 per megawatthour. Marketing
Company has also entered into capacity-only sales
contracts for 2010, 2011, and 2012, resulting in expected
capacity-only revenues related to these contracts of $65
million, $45 million, and $15 million, respectively. Any
unhedged sales will be exposed to relevant market
prices at the time of the sale.
The development of a capacity market in MISO could
increase the electric margins of Genco, AERG and EEI.
A capacity requirement obligates a load serving entity to
acquire capacity sufficient to meet its obligations. MISO
continues to refine its treatment of capacity supply and
obligations, but development of a true capacity market
could still be several years away.
Current and future energy efficiency programs developed
by UE, CIPS, CILCO and IP and others could result in
reduced demand for our electric generation and our
electric and natural gas transmission and distribution
services. Our regulated operations will seek a regulatory
framework that allows either a return on these programs
or recovery of their costs.
Fuel and Purchased Power
In 2009, 83% of Ameren’s electric generation (UE – 75%,
Genco – 99%, AERG – 100%, EEI – 100%) was supplied
by coal-fired power plants. About 96% of the coal used
by these plants (UE – 96%, Genco – 99%, AERG – 89%,
expected to increase in 2010 and beyond. As of
December 31, 2009, Merchant Generation’s baseload
hedged fuel costs, which include coal, transportation,
diesel fuel surcharges, and other charges, had increased
from an average cost of approximately $20.25 per
megawatthour in 2009 to approximately $23.25 per
megawatthour in 2010, $25.50 per megawatthour in
2011, and $26.50 per megawatthour in 2012. See
Item 7A – Quantitative and Qualitative Disclosures About
Market Risk of this report for additional information about
the percentage of fuel and transportation requirements
that are price-hedged for 2010 through 2014.
Other Costs
In December 2005, there was a breach of the upper
reservoir at UE’s Taum Sauk pumped-storage
hydroelectric facility. This resulted in significant flooding
in the local area, which damaged a state park. UE settled
with the FERC and the state of Missouri all issues
associated with the December 2005 Taum Sauk incident.
UE has property and liability insurance coverage for the
Taum Sauk incident, subject to certain limits and
deductibles. Insurance does not cover lost electric
margins or penalties paid to FERC. UE received
approval from FERC to rebuild the upper reservoir at its
Taum Sauk plant and is in the process of testing the
rebuilt facility. UE expects the Taum Sauk plant to
become operational in the second quarter of 2010. The
estimated cost to rebuild the upper reservoir is in the
range of $490 million. Under UE’s insurance policies, all
claims by or against UE are subject to review by its
insurance carriers. In July 2009, three insurance carriers
filed a petition against Ameren in the Circuit Court of St.
Louis County, Missouri, seeking a declaratory judgment
that the property insurance policy does not require these
three insurers to indemnify Ameren for their share of the
entire cost of construction associated with the facility
rebuild design being used. The three insurers allege that
they, along with the other policy participants, presented a
rebuild design that was consistent with their insurance
coverage obligations and that the insurance policies do
not require these insurers to pay their share of the costs
of construction associated with the design being used.
These insurers have estimated a cost of approximately
$214 million for their rebuild design compared to the
estimated $490 million cost of the design approved by
68
FERC and implemented by Ameren. Ameren has filed
an answer and counterclaim in the Circuit Court of St.
Louis County, Missouri, against these insurers. The
counterclaim asserts that the three insurance carriers
have breached their obligations under the property
insurance policies issued to Ameren and UE. The
insurers that are parties to the litigation represent
approximately 40%, on a weighted-average basis, of
the property insurance policy coverage between the
disputed amounts of $214 million and $490 million. On
August 31, 2009, Ameren and the property insurance
carriers that are not parties to the above litigation
reached a settlement of any and all claims, liabilities,
and obligations arising out of, or relating to, coverage
under its property insurance policy, including those
related to the rebuilding of the facility and the
reimbursement of replacement power costs. All
payments from the settling insurance companies were
received by UE in September 2009. Until Ameren’s
remaining insurance claims and the related litigation
are resolved, among other things, we are unable to
determine the total impact the breach could have on
Ameren’s and UE’s results of operations, financial
position, and liquidity beyond those amounts already
recognized. Ameren and UE expect to recover,
through insurance, 80% to 90% of the total property
insurance claim for the Taum Sauk incident. Beyond
insurance, the recoverability of any Taum Sauk facility
rebuild costs from customers is subject to the terms
and conditions set forth in UE’s November 2007 State
of Missouri settlement agreement. Certain costs
associated with the Taum Sauk facility not recovered
from property insurers may be recoverable from UE’s
electric customers through rates established in rate
cases filed subsequent to the in-service date of the
rebuilt facility. As of December 31, 2009, UE had
capitalized in property and plant qualifying Taum
Sauk-related costs of $99 million that UE believes
qualify for potential recovery in electric rates under the
terms of the November 2007 State of Missouri
Settlement. The inclusion of such costs in UE’s
electric rates is subject to review and approval by the
MoPSC in a future rate case. Any amounts not
recovered through insurance, in electric rates, or
otherwise, could result in charges to earnings, which
could be material. See Note 15 – Commitments and
Contingencies under Part II, Item 8, of this report for
further discussion of Taum Sauk matters.
UE’s Callaway nuclear plant’s next scheduled
refueling and maintenance outage in the spring of
2010 is expected to last 35 days. During a scheduled
outage, which occurs every 18 months, maintenance
and purchased power costs increase, and the amount
of excess power available for sale decreases,
compared with non-outage years.
Over the next few years, we expect rising employee
benefit costs, as well as higher insurance premiums
as a result of insurance market conditions and loss
experience, among other things.
Other
A ballot initiative passed by Missouri voters in
November 2008 created a renewable energy portfolio
requirement. UE and other Missouri investor-owned
utilities will be required to purchase or generate
electricity from renewable energy sources equaling at
least 2% of native load sales by 2011, with that
percentage increasing in subsequent years to at least
15% by 2021, subject to a 1% limit on customer rate
impacts. At least 2% of each portfolio requirement
must be derived from solar energy. Compliance with
the renewable energy portfolio requirement can be
achieved through the procurement of renewable
energy or renewable energy credits. Rules
implementing the renewable energy requirement are
expected to be issued by the MoPSC in 2010. UE
expects that any related costs or investments would
ultimately be recovered in rates.
The U.S. Congress has considered legislation that
would require additional government regulation of
derivative and OTC transactions and that would
expand collateral requirements. Legislation of this
nature, if finalized and signed into law by the
President, could reduce the effectiveness of hedging,
increasing the volatility of earnings, and could require
increased collateral postings.
In 2009, the U.S. House of Representatives and the
U.S. Senate each passed its own version of
healthcare reform bills that would fundamentally
change the U.S. healthcare system. Due to the
uncertainty as to the final outcome of federal
healthcare reform legislation, Ameren is unable to
estimate the effects on any reform on its results of
operations, financial position and liquidity.
Resources Company, as part of an internal
reorganization, transferred its 80% ownership interest
in EEI to Genco, through a capital contribution, on
January 1, 2010.
In an attempt to improve access to capital, reduce
financing costs, and enhance administrative
efficiencies, among other things, several internal
reorganizations are being considered. CILCO is
evaluating the transfer of AERG to Genco, and the
Ameren Illinois Utilities are exploring a merger
whereby CIPS, CILCO and IP would become a single
legal entity. These internal reorganizations could
occur in 2010.
The above items could have a material impact on our
results of operations, financial position, and liquidity.
Additionally, in the ordinary course of business, we
evaluate our strategies to enhance our results of
operations, financial position, and liquidity. These
strategies may include acquisitions, divestitures,
opportunities to reduce costs or increase revenues, and
other strategic initiatives to increase Ameren’s stockholder
value. We are unable to predict which, if any, of these
initiatives will be executed. The execution of these
initiatives may have a material impact on our future results
of operations, financial position, and liquidity.
69
REGULATORY MATTERS
See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report.
ACCOUNTING MATTERS
Critical Accounting Estimates
Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of
appropriate technical accounting rules and guidance, as well as the use of estimates. These estimates involve judgments
regarding many factors which in and of themselves could materially affect the financial statements and disclosures. We
have outlined below the critical accounting estimates that we believe are most difficult, subjective, or complex. Any
change in the assumptions or judgments applied in determining the following matters, among others, could have a
material impact on future financial results.
Accounting Estimate
Regulatory Mechanisms and Cost Recovery
All of the Ameren Companies except Genco defer costs
in accordance with authoritative accounting guidance,
and make investments that they assume will be collected
in future rates.
Uncertainties Affecting Application
Regulatory environment and external regulatory
decisions and requirements
Anticipated future regulatory decisions and their
impact
Impact of deregulation, rate freezes, and competition
on ratemaking process and ability to recover costs
Basis for Judgment
We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions
where we operate or other factors that lead us to believe that cost recovery is probable. If facts and circumstances lead
us to conclude that a recorded regulatory asset is probably no longer recoverable or plant assets are probable of
disallowance, we record a charge to earnings, which could be material. See Note 2 – Rate and Regulatory Matters under
Part II, Item 8, of this report for quantification of these assets by registrant.
Unbilled Revenue
At the end of each period, UE, CIPS, CILCO and IP
project expected usage and estimate the amount of
revenue to record for services that have been provided
to customers but not yet billed.
Projecting customer energy usage
Estimating impacts of weather and other usage-
affecting factors for the unbilled period
Estimating loss of energy during transmission and
delivery
Basis for Judgment
We base our estimate of unbilled revenue each period on the volume of energy delivered, as valued by a model of billing
cycles and historical usage rates and growth by customer class for our service area. This figure is then adjusted for the
modeled impact of seasonal and weather variations based on historical results. See the balance sheets for each of the
Ameren Companies, excluding Genco, under Part II, Item 8, of this report for unbilled revenue amounts.
Derivative Financial Instruments
We account for derivative financial instruments and
measure their fair value in accordance with authoritative
accounting guidance. The identification and classification
of a derivative and the fair value of such derivative must
be determined. See Commodity Price Risk and Fair
Value of Contracts in Quantitative and Qualitative
Disclosures About Market Risk under Part II, Item 7A,
Note 7 – Derivative Financial Instruments and Note 8 -
Fair Value Measurements under Part II, Item 8, of this
report.
Our ability to assess whether derivative contracts
qualify for the NPNS exception.
Ameren’s ability to consume or produce notional
values of derivative contracts
Market conditions in the energy industry, especially the
effects of price volatility and liquidity
Valuation assumptions on longer term contracts due to
lack of observable inputs
Effectiveness of derivatives that have been designated
as hedges
Counterparty default risk
70
Accounting Estimate
Uncertainties Affecting Application
Basis for Judgment
We determine whether to exclude the fair value of certain derivatives from valuation under the normal purchase and
normal sales provisions of authoritative accounting guidance based upon our intent and ability to physically deliver
commodities purchased and sold. Further, our forecasted purchases and sales also support our designation of some
fair-valued derivative instruments as cash flow hedges. Fair value of our derivatives is measured in accordance with
authoritative accounting guidance, which provides a fair value hierarchy that prioritizes inputs to valuation techniques.
We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
When we do not have observable inputs, we use certain assumptions that market participants would use in pricing the
asset or liability, including assumptions about risks inherent in the inputs to the valuation. Our valuations also reflect our
own assessment of counterparty default risk, using the best internal and external information available. If we were
required to discontinue our use of the normal purchase and normal sales exception or cash flow hedge treatment for
some of our contracts, the impact of changes in fair value for the applicable contracts could be material to our earnings.
Valuation of Goodwill, Intangible Assets, Long-Lived Assets, and Asset Retirement Obligations
We periodically assess the carrying value of our
goodwill, intangible assets, and long-lived assets to
determine whether they are impaired. We also review for
the existence of asset retirement obligations. If an asset
retirement obligation is identified, we determine its fair
value and subsequently reassess and adjust the
obligation, as necessary.
Management’s identification of impairment indicators
Changes in business, industry, laws, technology, or
economic and market conditions
Valuation assumptions and conclusions
Our assessment of market participants
Estimated useful lives of our significant long-lived
assets
Actions or assessments by our regulators
Identification of an asset retirement obligation and
assumptions about the timing of asset removals
Basis for Judgment
Annually, or whenever events indicate a valuation may have changed, we use various methodologies we believe market
participants would use to determine valuations, including earnings before interest, taxes, depreciation and amortization
multiples, and discounted, undiscounted, and probabilistic discounted cash flow models with multiple operating
scenarios. The identification of asset retirement obligations is conducted through the review of legal documents and
interviews. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for quantification
of our goodwill, intangible assets, and asset retirement obligations. See Note 17 – Goodwill under Part II, Item 8, of this
report for additional information of our goodwill impairment evaluation.
Benefit Plan Accounting
Based on actuarial calculations, we accrue costs of
providing future employee benefits in accordance with
authoritative accounting guidance regarding benefit
plans. See Note 11 – Retirement Benefits under Part II,
Item 8, of this report.
Interest rates used in valuing benefit obligations
Future rate of return on pension and other plan assets
Health care cost trend rates
Timing of employee retirements and mortality
assumptions
Ability to recover certain benefit plan costs from our
ratepayers
Changing market conditions impacting investment and
interest rate environments
Basis for Judgment
Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension and other
postretirement benefit plan assets is based on our consistent application of assumption-setting methodologies and our
review of available historical, current, and projected rates, as applicable. See Note 11 – Retirement Benefits under Part
II, Item 8, of this report for sensitivity of Ameren’s benefit plans to potential changes in these assumptions.
Impact of Future Accounting Pronouncements
See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
71
EFFECTS OF INFLATION AND CHANGING PRICES
Ameren’s rates for retail electric and gas utility service
are regulated by the MoPSC and the ICC. Nonretail electric
rates are regulated by FERC. Adjustments to rates are based
on a regulatory process that reviews a historical period. As a
result, revenue increases will lag behind changing prices.
Inflation affects our operations, earnings, stockholders’
equity, and financial performance.
The current replacement cost of our utility plant
substantially exceeds our recorded historical cost. Under
existing regulatory practice, only the historical cost of plant is
recoverable from customers. As a result, cash flows designed
to provide recovery of historical costs through depreciation
might not be adequate to replace the plant in future years.
Ameren’s Merchant Generation businesses do not have
regulated recovery mechanisms and are therefore dependent
on market prices for power to reflect rising costs.
As a part of the electric rate order issued by the MoPSC
in January 2009, UE was granted permission to put in place,
effective March 1, 2009, a FAC. Historically, in UE’s Missouri
electric utility jurisdiction, there was no tariff for adjusting
rates to accommodate changes in the cost of fuel for electric
generation or the cost of purchased power. As part of its
pending electric rate case, UE requested the MoPSC to
approve the continued use of the FAC and implementation of
an environmental cost recovery mechanism. The
environmental cost recovery mechanism, if approved, would
allow UE to adjust electric rates twice each year outside of
general rate proceedings to reflect changes in its prudently
incurred costs to comply with federal, state, or local
environmental laws, regulations, or rules greater than or less
than the amount set in base rates. Rate adjustments
pursuant to this cost recovery mechanism would not be
permitted to exceed an annual amount equal to 2.5% of UE’s
gross jurisdictional electric revenues and would be subject to
prudency reviews by the MoPSC. UE’s request was
consistent with the environmental cost recovery rules
approved by the MoPSC in April 2009. UE will not be able to
implement an environmental cost recovery mechanism until
so authorized by the MoPSC as part of a rate case
proceeding. See Note 2 – Rate and Regulatory Matters under
Part II, Item 8, of this report for information on UE’s pending
electric rate case.
CIPS, CILCO and IP recover power supply costs from
electric customers by adjusting rates to accommodate
changes in power prices.
UE, CIPS, CILCO, and IP are affected by changes in the
cost of electric transmission services. FERC regulates the
rates charged and the terms and conditions for electric
transmission services. Each RTO separately files regional
transmission tariff rates for approval by FERC. All members
within that RTO are then subjected to those rates. As
members of MISO, UE’s CIPS’, CILCO’s and IP’s
transmission rates are calculated in accordance with MISO’s
rate formula. The transmission rate is updated in June of
each year based on FERC filings. This rate is charged
directly to wholesale customers. The Ameren Illinois Utilities
also charge this rate directly to alternative retail electric
suppliers. For the Ameren Illinois Utilities’ retail customers
who have not chosen an alternative retail electric supplier,
the transmission rate is collected through a rider mechanism.
This rate is not directly charged to Missouri retail customers
because the MoPSC includes transmission-related costs in
setting bundled retail rates in Missouri.
In our Missouri and Illinois retail gas utility jurisdictions,
changes in gas costs are generally reflected in billings to gas
customers through PGA clauses.
UE, Genco, and AERG are affected by changes in
market prices for natural gas to the extent that they must
purchase natural gas to run CTs. These companies have
structured various supply agreements to maintain access to
multiple gas pools and supply basins, and to minimize the
impact to their financial statements. See Quantitative and
Qualitative Disclosures About Market Risk – Commodity
Price Risk under Part II, Item 7A, below for additional
information. Also see Note 2 – Rate and Regulatory Matters
under Part II, Item 8, of this report for additional information
on the cost recovery mechanisms discussed above.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Market risk is the risk of changes in value of a physical
asset or a financial instrument, derivative or nonderivative,
caused by fluctuations in market variables such as interest
rates, commodity prices, and equity security prices. A
derivative is a contract whose value is dependent on, or
derived from, the value of some underlying asset. The
following discussion of our risk management activities
includes forward-looking statements that involve risks and
uncertainties. Actual results could differ materially from those
projected in the forward-looking statements. We handle
market risks in accordance with established policies, which
may include entering into various derivative transactions. In
the normal course of business, we also face risks that are
either nonfinancial or nonquantifiable. Such risks, principally
business, legal and operational risks, are not part of the
following discussion.
Our risk management objective is to optimize our
physical generating assets and to pursue market
opportunities within prudent risk parameters. Our risk
management policies are set by a risk management steering
committee, which is composed of senior-level Ameren
officers.
Interest Rate Risk
We are exposed to market risk through changes in
interest rates associated with:
long-term and short-term variable-rate debt;
fixed-rate debt; and
auction-rate long-term debt.
72
UE, CIPS, Genco, CILCO, AERG, IP, AFS and
Marketing Company may have credit exposure associated
with interchange or wholesale purchase and sale activity with
nonaffiliated companies. At December 31, 2009, UE’s, CIPS’,
Genco’s, CILCO’s, AERG’s, IP’s, AFS’, and Marketing
Company’s combined credit exposure to nonaffiliated non-
investment-grade trading counterparties was $2 million, net
of collateral (2008 – less than $1 million). We establish credit
limits for these counterparties and monitor the
appropriateness of these limits on an ongoing basis through
a credit risk management program. It involves daily exposure
reporting to senior management, master trading and netting
agreements, and credit support, such as letters of credit and
parental guarantees. We also analyze each counterparty’s
financial condition before we enter into sales, forwards,
swaps, futures or option contracts, and we monitor
counterparty exposure associated with our leveraged lease.
We estimate our credit exposure to MISO associated with the
MISO Energy and Operating Reserves Market to be
$13 million at December 31, 2009 (2008 – $46 million).
Equity Price Risk
Our costs for providing defined benefit retirement and
postretirement benefit plans are dependent upon a number of
factors, including the rate of return on plan assets. Ameren
manages plan assets in accordance with the “prudent
investor” guidelines contained in ERISA. Ameren’s goal is to
ensure that sufficient funds are available to provide the
benefits at the time they are payable and also to maximize
total return on plan assets and minimize expense volatility
consistent with its tolerance for risk. Ameren delegates
investment management to specialists in each asset class.
Where appropriate, Ameren provides the investment
manager with guidelines that specify allowable and prohibited
investment types. Ameren regularly monitors manager
performance and compliance with investment guidelines.
The expected return on plan assets is based on historical
and projected rates of return for current and planned asset
classes in the investment portfolio. Projected rates of return
for each asset class were estimated after an analysis of
historical experience, future expectations, and the volatility of
the various asset classes. After considering the target asset
allocation for each asset class, we adjusted the overall
expected rate of return for the portfolio for historical and
expected experience of active portfolio management results
compared with benchmark returns and for the effect of
expenses paid from plan assets.
In future years, the costs of such plans reflected in net
income, OCI, or regulatory assets, and cash contributions to
the plans could increase materially, without pension asset
portfolio investment returns equal to or in excess of our
assumed return on plan assets of 8%.
UE also maintains a trust fund, as required by the NRC
and Missouri law, to fund certain costs of nuclear plant
decommissioning. As of December 31, 2009, this fund was
We manage our interest rate exposure by controlling the
amount of these instruments we have within our total
capitalization portfolio and by monitoring the effects of market
changes in interest rates.
The following table presents the estimated increase in
our annual interest expense and decrease in net income if
interest rates were to increase by 1% on variable-rate debt
outstanding at December 31, 2009:
Interest Expense
$ 12
2
-
-
3
(c )
Ameren(b) .............................
UE .......................................
CIPS .....................................
Genco ...................................
CILCO ..................................
IP .......................................
(a) Calculations are based on an effective tax rate of 38%.
(b)
(c) Less than $1 million.
Includes intercompany eliminations.
Net Income(a)
$ (7 )
(1 )
-
-
(2 )
(c )
The estimated changes above do not consider the
potential reduced overall economic activity that would exist in
such an environment. In the event of a significant change in
interest rates, management would probably act to further
mitigate our exposure to this market risk. However, due to the
uncertainty of the specific actions that would be taken and
their possible effects, this sensitivity analysis assumes no
change in our financial structure.
Credit Risk
Credit risk represents the loss that would be recognized
if counterparties fail to perform as contracted. Exchange-
traded contracts are supported by the financial and credit
quality of the clearing members of the respective exchanges
and have nominal credit risk. In all other transactions, we are
exposed to credit risk in the event of nonperformance by the
counterparties to the transaction. See Note 7 – Derivative
Financial Instruments under Part II, Item 8, of this report for
information on the potential loss on counterparty exposure as
of December 31, 2009.
Our revenues are primarily derived from sales or delivery
of electricity and natural gas to customers in Missouri and
Illinois. Our physical and financial instruments are subject to
credit risk consisting of trade accounts receivables and
executory contracts with market risk exposures. The risk
associated with trade receivables is mitigated by the large
number of customers in a broad range of industry groups
who make up our customer base. At December 31, 2009, no
nonaffiliated customer represented more than 10%, in the
aggregate, of our accounts receivable. The risk associated
with the Ameren Illinois Utilities’ electric and natural gas trade
receivables is also mitigated by a rate adjustment mechanism
that allows the Ameren Illinois Utilities to recover the
difference between their actual bad debt expense and the
bad debt expense included in their base rates. UE and the
Ameren Illinois Utilities continue to monitor the impact of
increasing rates and a weak economic environment on
customer collections. UE and the Ameren Illinois Utilities
make adjustments to their allowance for doubtful accounts as
deemed necessary to ensure that such allowances are
adequate to cover estimated uncollectible customer account
balances.
73
presence in the market, we are able to identify and pursue
opportunities, which can generate additional returns
through portfolio management and trading activities. All of
this activity is performed within a controlled risk
management process. We establish value at risk (VaR)
and stop-loss limits that are intended to prevent any
negative material financial impact.
We manage risks associated with changing prices of
fuel for generation using techniques similar to those used
to manage risks associated with changing market prices
for electricity. Most UE, Genco and AERG fuel supply
contracts are physical forward contracts. Genco, AERG
and EEI do not have the ability to pass through higher fuel
costs to their customers for electric operations. Prior to
March 2009, UE did not have this ability either except
through a general rate proceeding. As a part of the
January 2009 MoPSC electric rate order, UE was granted
permission to put a FAC in place, which became effective
March 1, 2009. UE remains exposed to 5% of changes in
its fuel and purchased power costs, net of off-system
revenues. UE, Genco, AERG and EEI have entered into
long-term contracts with various suppliers to purchase
coal to manage their exposure to fuel prices. The coal
hedging strategy is intended to secure a reliable coal
supply while reducing exposure to commodity price
volatility. Price and volumetric risk mitigation is
accomplished primarily through periodic bid procedures,
whereby the amount of coal purchased is determined by
the current market prices and the minimum and maximum
coal purchase guidelines for the given year. UE, Genco,
AERG and EEI generally purchase coal up to five years in
advance, but we may purchase coal beyond five years to
take advantage of favorable deals or market conditions.
The strategy also allows for the decision not to purchase
coal to avoid unfavorable market conditions.
Transportation costs for coal and natural gas can be a
significant portion of fuel costs. UE, Genco, AERG and
EEI typically hedge coal transportation forward to provide
supply certainty and to mitigate transportation price
volatility. Natural gas transportation expenses for
Ameren’s gas distribution utility companies and the gas-
fired generation units of UE, Genco, AERG and EEI are
regulated by FERC through approved tariffs governing the
rates, terms, and conditions of transportation and storage
services. Certain firm transportation and storage capacity
agreements held by the Ameren Companies include rights
to extend the contracts prior to the termination of the
primary term. Depending on our competitive position, we
are able in some instances to negotiate discounts to these
tariff rates for our requirements.
invested primarily in domestic equity securities (67%) and
debt securities (33%). It totaled $293 million (2008 –
$239 million). By maintaining a portfolio that includes long-
term equity investments, UE seeks to maximize the
returns to be used to fund nuclear decommissioning costs
within acceptable parameters of risk. However, the equity
securities included in the portfolio are exposed to price
fluctuations in equity markets. The debt securities are
exposed to changes in interest rates. UE actively monitors
the portfolio by benchmarking the performance of its
investments against certain indices and by maintaining
and periodically reviewing established target allocation
percentages of the assets of the trust to various
investment options. UE’s exposure to equity price market
risk is in large part mitigated, because UE is currently
allowed to recover its decommissioning costs, which
would include unfavorable investment results, through
electric rates.
Commodity Price Risk
We are exposed to changes in market prices for
electricity, emission allowances, fuel, and natural gas.
UE’s, Genco’s, AERG’s and EEI’s risks of changes in
prices for power sales are partially hedged through sales
agreements. Genco, AERG and EEI also seek to sell
power forward to wholesale, municipal, and industrial
customers to limit exposure to changing prices. We also
attempt to mitigate financial risks through risk
management programs and policies, which include
forward-hedging programs, and the use of derivative
financial instruments (primarily forward contracts, futures
contracts, option contracts, and financial swap contracts).
However, a portion of the generation capacity of UE,
Genco, AERG and EEI is not contracted through physical
or financial hedge arrangements and is therefore exposed
to volatility in market prices.
The following table shows how our earnings might
decrease if power prices were to decrease by 1% on
unhedged economic generation for 2010 through 2013:
Ameren(b) .....................................................................
UE ...............................................................................
Genco ...........................................................................
CILCO (AERG) .............................................................
EEI ...............................................................................
(a) Calculations are based on an effective tax rate of 38%.
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries
and intercompany eliminations.
Net Income(a)
$ (22)
(7)
(8)
(3)
(6)
Ameren also uses its portfolio management and
trading capabilities both to manage risk and to deploy risk
capital to generate additional returns. Due to our physical
74
The following table presents the percentages of the projected required supply of coal and coal transportation for our
coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant, natural gas for our CTs, and retail distribution, as
appropriate, and purchased power needs of CIPS, CILCO and IP, which own no generation, that are price-hedged over
the five-year period 2010 through 2014, as of December 31, 2009. The projected required supply of these commodities
could be significantly affected by changes in our assumptions for such matters as customer demand for our electric
generation and our electric and natural gas distribution services, generation output, and inventory levels, among other
matters.
2010
Ameren:
Coal .......................................................................................................................................................................
97%
Coal transportation................................................................................................................................................. 100
Nuclear fuel ........................................................................................................................................................... 100
Natural gas for generation ......................................................................................................................................
73
Natural gas for distribution(a) ..................................................................................................................................
96
Purchased power for Illinois Regulated(b) ................................................................................................................
82
UE:
Coal .......................................................................................................................................................................
98%
Coal transportation................................................................................................................................................. 100
Nuclear fuel ........................................................................................................................................................... 100
Natural gas for generation ......................................................................................................................................
89
Natural gas for distribution(a) ..................................................................................................................................
97
CIPS:
Natural gas for distribution(a) ..................................................................................................................................
Purchased power(b) ................................................................................................................................................
Genco:
Coal .......................................................................................................................................................................
97%
Coal transportation................................................................................................................................................. 100
Natural gas for generation ...................................................................................................................................... 100
CILCO:
Coal (AERG) ..........................................................................................................................................................
97%
Coal transportation (AERG) ................................................................................................................................... 100
Natural gas for distribution(a) ..................................................................................................................................
93
Purchased power(b) ................................................................................................................................................
82
IP:
Natural gas for distribution(a) ..................................................................................................................................
Purchased power(b) ................................................................................................................................................
EEI:
Coal .......................................................................................................................................................................
97%
Coal transportation................................................................................................................................................. 100
99%
82
91%
82
2011
2012 – 2014
61%
93
89
8
45
55
61%
100
89
11
48
40%
55
61%
70
19
63%
100
47
55
46%
55
60%
100
15%
40
58
-
20
16
14%
44
58
-
27
17%
16
16%
24
-
18%
57
20
16
19%
16
14%
34
(a) Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2010 represents January 2010
through March 2010. The year 2011 represents November 2010 through March 2011. This continues each successive year through March 2014.
(b) Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of
demand. Larger customers are purchasing power from the competitive markets. See Note 2 – Rate and Regulatory Matters and Note 15 – Commitments and
Contingencies under Part II, Item 8, of this report for a discussion of the Illinois power procurement process and for additional information on the Ameren
Illinois Utilities’ purchased power commitments.
75
Fuel
Expense
Fuel
Expense
$ 17
7
6
1
2
Net
Income(a)
$ (12)
(7)
(3)
(1)
(1)
The following table shows how our total fuel expense
might increase and how our net income might decrease if
coal and coal transportation costs were to increase by 1%
on any requirements not currently covered by fixed-price
contracts for the five-year period 2010 through 2014.
Transportation
Coal
Net
Income(a)
$ (10)
(4)
(4)
(1)
(1)
Ameren(b) .................... $ 19
UE .............................. 11
Genco .........................
4
CILCO .........................
2
EEI ..............................
2
(a) Calculations are based on an effective tax rate of 38%.
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
In addition, coal and coal transportation costs are
sensitive to the price of diesel fuel as a result of rail freight
fuel surcharges. If diesel fuel costs were to increase or
decrease by $0.25/gallon, Ameren’s fuel expense could
increase or decrease by $10 million annually (UE –
$5 million, Genco – $2 million, AERG – $1 million and EEI
– $2 million). As of December 31, 2009, Ameren had a
price cap for approximately 93% of expected fuel
surcharges in 2010.
In the event of a significant change in coal prices, UE,
Genco, AERG and EEI would probably take actions to
further mitigate their exposure to this market risk.
However, due to the uncertainty of the specific actions that
would be taken and their possible effects, this sensitivity
analysis assumes no change in our financial structure or
fuel sources.
With regard to exposure for commodity price risk for
nuclear fuel, UE has both fixed-priced and base-price-
with- escalation agreements. It also uses inventories that
provide some price hedge to fulfill its Callaway nuclear
plant needs for uranium, conversion, enrichment, and
fabrication services. There is no fuel reloading scheduled
for 2012. UE has price hedges for 75% of the 2010 to
2014 nuclear fuel requirements.
Nuclear fuel market prices remain subject to an
unpredictable supply and demand environment. UE has
continued to follow a strategy of managing its inventory of
nuclear fuel as an inherent price hedge. New long-term
uranium contracts are almost exclusively market-price-
related with an escalating price floor. New long-term
enrichment contracts usually have some market-price-
related component. UE expects to enter into additional
contracts from time to time in order to supply nuclear fuel
during the expected life of the Callaway nuclear plant, at
prices that cannot now be accurately predicted. Unlike the
electricity and natural gas markets, nuclear fuel markets
have limited financial instruments available for price
hedging, so most hedging is done through inventories and
forward contracts, if they are available.
With regard to the electric generating operations for
UE, Genco and AERG that are exposed to changes in
market prices for natural gas used to run CTs, the natural
gas procurement strategy is designed to ensure reliable
and
76
immediate delivery of natural gas while minimizing costs.
We optimize transportation and storage options and price
risk by structuring supply agreements to maintain access
to multiple gas pools and supply basins.
Through the market allocation process, UE, CIPS,
Genco, CILCO and IP have been granted FTRs
associated with the MISO Energy and Operating Reserves
Market. In addition, Marketing Company has acquired
FTRs for its participation in the PJM-Northern Illinois
market. The FTRs are intended to mitigate expected
electric transmission congestion charges related to the
physical electricity business. Depending on the congestion
and prices at various points on the electric transmission
grid, FTRs could result in either charges or credits.
Complex grid modeling tools are used to determine which
FTRs to nominate in the FTR allocation process. There is
a risk of incorrectly modeling the amount of FTRs needed,
and there is the potential that the FTRs could be
ineffective in mitigating transmission congestion charges.
With regard to UE’s, CIPS’, CILCO’s and IP’s electric
and natural gas distribution businesses, exposure to
changing market prices is in large part mitigated by the
fact that there are cost recovery mechanisms in place.
These cost recovery mechanisms allow UE, CIPS, CILCO
and IP to pass on to retail customers prudently incurred
fuel, purchased power and gas supply costs. UE’s, CIPS’,
CILCO’s and IP’s strategy is designed to reduce the effect
of market fluctuations for our regulated customers. The
effects of price volatility cannot be eliminated. However,
procurement strategies involve risk management
techniques and instruments similar to those outlined
earlier, as well as the management of physical assets.
With regard to our exposure for commodity price risk
for construction and maintenance activities, Ameren is
exposed to changes in market prices for metal
commodities and labor availability.
See Supply for Electric Power under Part I, Item 1, of
this report for the percentages of our historical needs
satisfied by coal, nuclear power, natural gas, hydroelectric
power, and oil. Also see Note 15 – Commitments and
Contingencies under Part II, Item 8, of this report for
additional information.
Fair Value of Contracts
We use derivatives principally to manage the risk of
changes in market prices for natural gas, coal, diesel,
electricity, uranium, and emission allowances. Such price
fluctuations may cause the following:
an unrealized appreciation or depreciation of our
contracted commitments to purchase or sell when
purchase or sale prices under the commitments are
compared with current commodity prices;
market values of coal, natural gas, and uranium
inventories or emission allowances that differ from the
cost of those commodities in inventory; and
actual cash outlays for the purchase of these
commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are
governed by our risk management policies for forward
contracts, futures, options, and swaps. Our net positions
are continually assessed within our structured hedging
programs to determine whether new or offsetting
transactions are required. The goal of the hedging
program is generally to mitigate financial risks while
ensuring that sufficient volumes are available to meet our
requirements. Contracts we enter into as part of our risk
management program may be settled financially, settled
by physical delivery, or net settled with the counterparty.
See Note 7 – Derivative Financial Instruments under Part
II, Item 8, of this report for additional information.
The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-
to-market during the year ended December 31, 2009. We use various methods to determine the fair value of our
contracts. In accordance with hierarchy levels outlined in authoritative accounting guidance, the sources we used to
determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and
other modeling and valuation methods that are not corroborated by market data (Level 3). All of these contracts have
maturities of less than five years.
Fair value of contracts at beginning of year, net ....................... $
Contracts realized or otherwise settled during the period ..........
Changes in fair values attributable to changes in valuation
Ameren (a)
20
43
-
technique and assumptions ................................................
Fair value of new contracts entered into during the period ........
52
Other changes in fair value ......................................................
(98)
Fair value of contracts outstanding at end of year, net .............. $ 17
UE
$
16
(10)
-
22
(12)
$ 16
CIPS
$
(84)
54
-
(3)
(122)
$ (155)
Genco
$
(1)
1
-
11
2
$ 13
CILCO
$
(59) $
57
-
2
(75)
$ (75) $
IP
(134 )
102
-
(13 )
(202 )
(247)
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
The following table presents maturities of derivative contracts as of December 31, 2009, based on the hierarchy levels
used to determine the fair value of the contracts:
Sources of Fair Value
Ameren:
Level 1 .......................................................................................................
Level 2(a) ....................................................................................................
Level 3(b) ....................................................................................................
Total ..........................................................................................................
UE:
Level 1 .......................................................................................................
Level 2(a) ....................................................................................................
Level 3(b) ....................................................................................................
Total ..........................................................................................................
CIPS:
Level 1 .......................................................................................................
Level 2(a) ....................................................................................................
Level 3(b) ....................................................................................................
Total ..........................................................................................................
Genco:
Level 1 .......................................................................................................
Level 2(a) ....................................................................................................
Level 3(b) ....................................................................................................
Total ..........................................................................................................
CILCO:
Level 1 .......................................................................................................
Level 2(a) ....................................................................................................
Level 3(b) ....................................................................................................
Total ..........................................................................................................
Maturity
Less than
1 Year
Maturity
1 - 3 Years
Maturity
4 - 5 Years
Maturity in
Excess of
5 Years
Total
Fair Value
$
$
$
$
$
$
(8)
1
20
13
(3)
-
5
2
-
-
(53)
(53)
$
$
$
$
$
$
(4)
-
12
8
(3)
-
18
15
-
-
(102)
(102)
$
$
$
$
$
$
(1)
-
(3)
(4)
(1)
-
-
(1)
-
-
-
-
$
$
$
$
$
$
-
-
-
-
-
-
-
-
-
-
-
-
$
$
$
$
$
$
(13)
1
29
17
(7)
-
23
16
-
-
(155)
(155)
$ -
-
5
5
$
$ -
-
(22)
(22)
$
$ -
-
8
8
$
$ -
-
(53)
(53)
$
$ -
-
-
-
$
$ -
-
-
-
$
$ -
-
-
-
$
$ -
-
-
-
$
$ -
-
13
13
$
$ -
-
(75)
(75)
$
77
.
Sources of Fair Value
Maturity
Less than
1 Year
Maturity
1 - 3 Years
Maturity
4 - 5 Years
Maturity in
Excess of
5 Years
Total
Fair Value
IP:
Level 1 .......................................................................................................
Level 2(a) ....................................................................................................
Level 3(b) ....................................................................................................
Total ..........................................................................................................
(a) Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed price vs. floating over-the-counter natural gas swaps.
(b) Principally power forward contract values based on a Black-Scholes model that includes information from external sources and our estimates. Level 3 also
$ (1)
-
(160)
(161)
$ -
-
(2)
(2)
$ -
-
(84)
(84)
(1)
-
(246)
(247)
-
-
-
-
$
$
$
$
$
$
$
includes option contract values based on our estimates.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Corporation:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all
material respects, the financial position of Ameren Corporation and its subsidiaries at December 31, 2009 and 2008, and
the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in
conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the
financial statement schedules listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related consolidated financial statements. Also, in our
opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these
financial statements and financial statement schedules, for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report
on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these
financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting
based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material misstatement and whether effective
internal control over financial reporting was maintained in all material respects. Our audits of the financial statements
included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall
financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding
of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating
the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing
such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable
basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
78
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Union Electric Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all
material respects, the financial position of Union Electric Company and its subsidiaries at December 31, 2009 and 2008,
and the results of their operations and their cash flows for each of the three years in the period ended December 31,
2009, in conformity with accounting principles generally accepted in the United States of America. In addition, in our
opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material
respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
These financial statements and financial statement schedule are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits of these statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Central Illinois Public Service Company:
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material
respects, the financial position of Central Illinois Public Service Company at December 31, 2009 and 2008, and the results
of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with
accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial
statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related financial statements. These financial statements
and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of
these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of Ameren Energy Generating Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all
material respects, the financial position of Ameren Energy Generating Company and its subsidiaries at December 31,
2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended
December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on
these financial statements based on our audits. We conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test
79
basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Central Illinois Light Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all
material respects, the financial position of Central Illinois Light Company and its subsidiaries at December 31, 2009 and
2008, and the results of their operations and their cash flows for each of the three years in the period ended
December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. In
addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly,
in all material respects, the information set forth therein when read in conjunction with the related consolidated financial
statements. These financial statements and financial statement schedules are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial statements and financial statement schedules
based on our audits. We conducted our audits of these statements in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Illinois Power Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all
material respects, the financial position of Illinois Power Company and its subsidiary at December 31, 2009 and 2008, and
the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in
conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the
financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related consolidated financial statements. These financial
statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements and financial statement schedule based on our audits. We conducted
our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
February 26, 2010
80
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(In millions, except per share amounts)
Year Ended December 31,
2008
2009
2007
Operating Revenues:
Electric
Gas
Total operating revenues
Operating Expenses:
Fuel
Purchased power
Gas purchased for resale
Other operations and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating Income
Other Income and Expenses:
Miscellaneous income
Miscellaneous expense
Total other income
Interest Charges
Income Before Income Taxes
Income Taxes
Net Income
Less: Net Income Attributable to Noncontrolling Interests
Net Income Attributable to Ameren Corporation
Earnings per Common Share – Basic and Diluted
Dividends per Common Share
Average Common Shares Outstanding
$ 5,909
1,181
7,090
1,141
909
749
1,738
725
412
5,674
1,416
71
(23)
48
508
956
332
624
12
612
2.78
1.54
220.4
$
$
$
$ 6,367
1,472
7,839
1,275
1,210
1,057
1,857
685
393
6,477
1,362
80
(31)
49
440
971
327
644
39
605
2.88
2.54
210.1
$
$
$
$ 6,283
1,279
7,562
1,167
1,387
900
1,687
681
381
6,203
1,359
75
(25)
50
423
986
330
656
38
618
2.98
2.54
207.4
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
81
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
December 31,
2009
2008
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $24 and $28, respectively)
Unbilled revenue
Miscellaneous accounts and notes receivable
Materials and supplies
Mark-to-market derivative assets
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
Nuclear decommissioning trust fund
Goodwill
Intangible assets
Regulatory assets
Other assets
Total investments and other assets
TOTAL ASSETS
LIABILITIES AND EQUITY
Current Liabilities:
Current maturities of long-term debt
Short-term debt
Accounts and wages payable
Taxes accrued
Interest accrued
Customer deposits
Mark-to-market derivative liabilities
Other current liabilities
Total current liabilities
Credit Facility Borrowings
Long-term Debt, Net
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
Accumulated deferred investment tax credits
Regulatory liabilities
Asset retirement obligations
Pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 14, 15 and 16)
Ameren Corporation Stockholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 237.4 and 212.3,
respectively
Other paid-in capital, principally premium on common stock
Retained earnings
Accumulated other comprehensive loss
Total Ameren Corporation stockholders’ equity
Noncontrolling Interests
Total equity
TOTAL LIABILITIES AND EQUITY
$
622 $
434
367
308
782
121
208
2,842
17,610
92
516
427
315
842
207
209
2,608
16,567
293
831
129
1,430
655
3,338
239
831
167
1,653
606
3,496
$ 23,790 $ 22,671
$
204 $
20
694
54
110
101
109
419
1,711
830
7,113
2,554
94
1,338
429
1,165
496
6,076
380
1,174
813
54
107
126
155
268
3,077
-
6,554
2,131
100
1,291
406
1,495
438
5,861
2
5,412
2,455
(16)
7,853
207
8,060
2
4,780
2,181
-
6,963
216
7,179
$ 23,790 $ 22,671
The accompanying notes are an integral part of these consolidated financial statements.
82
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2008
2009
2007
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
$ 624
$ 644
$ 656
Gain on sales of emission allowances
Loss on asset impairments
Net mark-to-market gain on derivatives
Depreciation and amortization
Amortization of nuclear fuel
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits, net
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and other postretirement benefits
Counterparty collateral, net
Taum Sauk costs, net of insurance recoveries
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Nuclear fuel expenditures
Purchases of securities – nuclear decommissioning trust fund
Sales of securities – nuclear decommissioning trust fund
Purchases of emission allowances
Sales of emission allowances
Other
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Capital issuance costs
Short-term and credit facility borrowings, net
Dividends paid to noncontrolling interest holders
Redemptions, repurchases, and maturities:
Long-term debt
Preferred stock
Issuances:
Common stock
Long-term debt
Generator advances received for construction, net
Net cash provided by financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Cash Paid During the Year:
(6)
7
(23)
748
53
25
402
(17)
21
67
(42)
-
(66)
103
(9)
(17)
107
1,977
(1,704)
(80)
(383)
380
(4)
-
2
(1,789)
(338)
(65)
(324)
(21)
(631)
-
634
1,021
66
342
530
92
$ 622
(8)
14
(3)
705
37
20
167
(9)
12
(100)
57
(30)
83
113
(4)
(25)
(149)
1,524
(1,896)
(173)
(520)
497
(14)
6
3
(2,097)
(534)
(12)
(298)
(40)
(842)
(16)
154
1,879
19
310
(263)
355
$ 92
(8)
-
(3)
735
37
19
(28)
9
(172)
(88)
-
21
42
(44)
27
(39)
(56)
1,108
(1,381)
(68)
(142)
128
(24)
5
14
(1,468)
(527)
(4)
860
(32)
(488)
(1)
91
674
5
578
218
137
$ 355
Interest (net of $40, $41, and $31 capitalized, respectively)
Income taxes, net
$ 478
9
$ 409
106
$ 391
283
The accompanying notes are an integral part of these consolidated financial statements.
83
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock:
Beginning of year
Shares issued
Common stock, end of year
Other Paid-in Capital:
Beginning of year
Shares issued (less issuance costs of $17, $-, and $-, respectively)
Stock-based compensation cost
Other paid-in capital, end of year
Retained Earnings:
Beginning of year
Net income attributable to Ameren Corporation
Dividends
Adjustment to adopt new accounting standard
Retained earnings, end of year
Accumulated Other Comprehensive Income (Loss):
Derivative financial instruments, beginning of year
Change in derivative financial instruments
Derivative financial instruments, end of year
Deferred retirement benefit costs, beginning of year
Change in deferred retirement benefit costs
Deferred retirement benefit costs, end of year
Total accumulated other comprehensive income (loss), end of year
Total Ameren Corporation Stockholders’ Equity
Noncontrolling Interests:
Beginning of year
Net income attributable to noncontrolling interests
Dividends paid to noncontrolling interest holders
Noncontrolling interests, end of year
Total Equity
Comprehensive Income, Net of Taxes:
Net income
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes
(benefit) of $78, $65, and $(7), respectively
Reclassification adjustments for derivative (gains) included in net income, net of
income taxes of $82, $43, and $22, respectively
Reclassification adjustment due to implementation of FAC, net of income taxes
of $18, $-, and $-, respectively
Pension and other postretirement activity, net of income taxes (benefit) of $22,
$(45), and $1, respectively
2009
December 31,
2008
2007
$
$
2
-
2
$
2
-
2
2
-
2
4,780
617
15
5,412
2,181
612
(338)
-
2,455
4,604
154
22
4,780
2,110
605
(534)
-
2,181
4,495
91
18
4,604
2,024
618
(527)
(5)
2,110
48
(38)
10
(48)
22
(26)
(16)
$ 7,853
216
12
(21)
207
$ 8,060
9
39
48
27
(75)
(48)
-
$ 6,963
217
39
(40)
216
$ 7,179
60
(51)
9
2
25
27
36
$ 6,752
211
38
(32)
217
$ 6,969
$
624
$
644
$
656
103
(112)
(29)
22
608
(12)
$
116
(77)
-
(75)
608
(39)
$
(12)
(39)
-
25
630
(38)
Total Comprehensive Income, Net of Taxes
Comprehensive income attributable to noncontrolling interests
Total Comprehensive Income Attributable to Ameren Corporation, Net of
$
Taxes
Common stock shares at beginning of year
Shares issued
Common stock shares at end of year
$
596
$
569
$
592
212.3
25.1
237.4
208.3
4.0
212.3
206.6
1.7
208.3
The accompanying notes are an integral part of these consolidated financial statements.
84
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
Year Ended December 31,
2008
2009
2007
Operating Revenues:
Electric
Gas
Other
Total operating revenues
Operating Expenses:
Fuel
Purchased power
Gas purchased for resale
Other operations and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating Income
Other Income and Expenses:
Miscellaneous income
Miscellaneous expense
Total other income
Interest Charges
Income Before Income Taxes and Equity in Income of Unconsolidated
Investment
Income Taxes
Income Before Equity in Income of Unconsolidated Investment
Equity in Income of Unconsolidated Investment, Net of Taxes
Net Income
Preferred Stock Dividends
$ 2,700
170
4
2,874
593
124
97
880
357
257
2,308
566
$ 2,756
201
3
2,960
672
160
123
922
329
240
2,446
514
$ 2,786
174
1
2,961
608
192
104
900
333
234
2,371
590
63
(7)
56
62
(9)
53
38
(7)
31
229
193
194
393
128
265
-
265
6
374
134
240
11
251
6
427
140
287
55
342
6
Net Income Available to Common Stockholder
$
259
$
245
$
336
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
85
UNION ELECTRIC COMPANY
BALANCE SHEET
(In millions, except per share amounts)
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $6 and $8, respectively)
Accounts receivable – affiliates
Unbilled revenue
Miscellaneous accounts and notes receivable
Materials and supplies
Mark-to-market derivative assets
Current regulatory assets
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
Nuclear decommissioning trust fund
Intangible assets
Regulatory assets
Other assets
Total investments and other assets
TOTAL ASSETS
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt
Short-term debt
Intercompany note payable – Ameren
Accounts and wages payable
Accounts payable – affiliates
Taxes accrued
Interest accrued
Other current liabilities
Total current liabilities
Long-term Debt, Net
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
Accumulated deferred investment tax credits
Regulatory liabilities
Asset retirement obligations
Pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 14, 15 and 16)
Stockholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding
Other paid-in capital, principally premium on common stock
Preferred stock not subject to mandatory redemption
Retained earnings
Accumulated other comprehensive income
Total stockholders’ equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
December 31,
2009
2008
$
267 $
154
22
127
199
346
31
63
19
1,228
9,585
-
147
32
111
281
339
50
10
28
998
8,995
293
35
765
395
1,488
239
48
897
352
1,536
$ 12,301 $ 11,529
$
4 $
-
-
336
132
21
63
127
683
4,018
1,660
79
947
331
400
126
3,543
4
251
92
360
151
20
56
126
1,060
3,673
1,372
80
922
317
494
49
3,234
511
1,555
113
1,878
-
4,057
511
1,119
113
1,794
25
3,562
$ 12,301 $ 11,529
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
86
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
$ 265
$ 251
$ 342
Year Ended December 31,
2008
2009
2007
activities:
Gain on sales of emission allowances
Net mark-to-market (gain) loss on derivatives
Depreciation and amortization
Amortization of nuclear fuel
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits, net
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and other postretirement benefits
Taum Sauk costs, net of insurance recoveries
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Nuclear fuel expenditures
Money pool advances, net
Proceeds from intercompany note receivable
Purchases of securities – nuclear decommissioning trust fund
Sales of securities – nuclear decommissioning trust fund
Sales of emission allowances
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Dividends on preferred stock
Capital issuance costs
Short-term debt, net
Intercompany note payable – Ameren, net
Redemptions, repurchases, and maturities of long-term debt
Issuances of long-term debt
Capital contribution from parent
Other
Net cash provided by financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Cash Paid (Refunded) During the Year:
Interest (net of $23, $19, and $15 capitalized, respectively)
Income taxes, net
(5)
(29)
357
53
10
276
(30)
(58)
(2)
16
1
(58)
71
(2)
107
972
(872)
(80)
-
-
(383)
380
-
(955)
(175)
(6)
(14)
(251)
(92)
(4)
349
436
7
250
267
-
$ 267
(5)
29
329
37
6
89
(28)
60
(32)
(89)
(61)
42
64
-
(149)
543
(874)
(173)
-
36
(520)
497
1
(1,033)
(264)
(6)
(5)
169
92
(382)
699
-
2
305
(185)
185
-
$
(5)
(2)
333
37
6
1
(6)
(60)
(65)
42
12
39
(49)
18
(56)
587
(625)
(68)
3
-
(142)
128
4
(700)
(267)
(6)
(3)
(152)
(77)
(4)
424
380
2
297
184
1
$ 185
$ 212
(208)
$ 177
130
$ 203
106
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
87
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Capital contribution from parent
Other paid-in capital, end of year
Preferred Stock Not Subject to Mandatory Redemption
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Preferred stock dividends
Dividend-in-kind to Ameren
Adjustment to adopt new accounting standard
Retained earnings, end of year
Accumulated Other Comprehensive Income:
Beginning of year
Change in derivative financial instruments
Accumulated other comprehensive income, end of year
Total Stockholders’ Equity
Comprehensive Income, Net of Taxes:
Net income
Unrealized net gain on derivative hedging instruments, net of income taxes
of $11, $22, and $-, respectively
Reclassification adjustments for derivative (gains) included in net income, net
of income taxes of $8, $9, and $2, respectively
Reclassification adjustment due to implementation of FAC, net of income
taxes of $18, $-, and $-, respectively
Total Comprehensive Income, Net of Taxes
December 31,
2008
2007
2009
$
511
$
511
$
511
1,119
436
1,555
113
1,794
265
(175)
(6)
-
-
1,878
1,119
-
1,119
113
1,855
251
(264)
(6)
(42)
-
1,794
739
380
1,119
113
1,783
342
(267)
(6)
-
3
1,855
25
(25)
-
$ 4,057
3
22
25
$ 3,562
7
(4)
3
$ 3,601
$
265
$
251
$
342
17
(13)
(29)
240
36
(14)
-
273
-
(4)
-
338
$
$
$
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
88
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF INCOME
(In millions)
Year Ended December 31,
2008
2007
2009
Operating Revenues:
Electric
Gas
Other
Total operating revenues
Operating Expenses:
Purchased power
Gas purchased for resale
Other operations and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating Income
Other Income and Expenses:
Miscellaneous income
Miscellaneous expense
Total other income
Interest Charges
Income Before Income Taxes
Income Taxes
Net Income
Preferred Stock Dividends
$ 642
224
3
869
$ 720
259
3
982
$ 772
230
3
1,005
372
143
181
68
37
801
68
8
(2)
6
29
45
16
29
3
461
179
196
67
37
940
42
11
(3)
8
30
20
5
15
3
527
157
172
66
34
956
49
17
(3)
14
37
26
9
17
3
Net Income Available to Common Stockholder
$
26
$
12
$
14
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
89
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
BALANCE SHEET
(In millions)
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $5 and $6, respectively)
Accounts receivable – affiliates
Unbilled revenue
Miscellaneous accounts and notes receivable
Current portion of intercompany note receivable – Genco
Current portion of intercompany tax receivable – Genco
Materials and supplies
Counterparty collateral asset
Current regulatory assets
Deferred taxes
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
Intercompany note receivable – Genco
Intercompany tax receivable – Genco
Regulatory assets
Other assets
Total investments and other assets
TOTAL ASSETS
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt
Borrowings from money pool
Accounts and wages payable
Accounts payable – affiliates
Taxes accrued
Customer deposits
Mark-to-market derivative liabilities
Mark-to-market derivative liabilities – affiliates
Environmental remediation
Other current liabilities
Total current liabilities
Long-term Debt, Net
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes
Accumulated deferred investment tax credits
Regulatory liabilities
Pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 14 and 15)
Stockholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding
Other paid-in capital
Preferred stock not subject to mandatory redemption
Retained earnings
Total stockholders’ equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
December 31,
2009
2008
$
28
53
12
52
14
45
9
47
2
59
18
3
342
1,268
-
82
248
25
355
$ 1,965
$
-
82
4
74
1
42
9
70
21
32
5
2
342
1,212
45
93
195
33
366
$ 1,920
$
-
-
48
58
7
21
10
43
22
45
254
421
273
7
242
58
136
716
$
62
44
48
49
7
16
17
14
7
47
311
421
259
9
234
79
78
659
-
257
50
267
574
$ 1,965
-
191
50
288
529
$ 1,920
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
90
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2008
2009
2007
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
$
29
$
15
$
17
activities:
Depreciation and amortization
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits, net
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and other postretirement benefits
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Proceeds from intercompany note receivable – Genco
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Dividends on preferred stock
Capital issuance costs
Short-term debt, net
Money pool borrowings, net
Redemptions, repurchases, and maturities of long-term debt
Capital contribution from parent
Other
Net cash provided by (used in) financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Cash Paid (Refunded) During the Year:
Interest
Income taxes, net
68
2
(5)
41
23
15
-
19
(1)
-
191
67
1
(2)
(5)
(4)
14
(1)
(5)
21
-
101
66
1
(27)
(12)
5
(48)
(2)
14
(3)
3
14
(110)
42
(68)
(96)
39
(57)
(79)
37
(42)
(47)
(3)
(3)
(62)
(44)
-
66
(2)
(95)
28
-
28
27
24
$
$
-
(3)
-
(63)
44
(50)
-
2
(70)
(26)
26
-
32
(21)
(40)
(3)
-
90
-
-
1
-
48
20
6
26
36
44
$
$
$
$
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
91
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Capital contribution from parent
Other paid-in capital, end of year
Preferred Stock Not Subject to Mandatory Redemption
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Preferred stock dividends
Retained earnings, end of year
Accumulated Other Comprehensive Income:
Beginning of year
Change in derivative financial instruments
Accumulated other comprehensive income, end of year
Total Stockholders’ Equity
Comprehensive Income, Net of Taxes:
Net income
Reclassification adjustments for (gains) included in net income,
net of income taxes of $-, $-, and $1, respectively
Total Comprehensive Income, Net of Taxes
2009
December 31,
2008
2007
$
-
$
-
$
-
191
66
257
50
288
29
(47)
(3)
267
191
-
191
50
276
15
-
(3)
288
190
1
191
50
302
17
(40)
(3)
276
-
-
-
$ 574
$
$
29
-
29
-
-
-
$ 529
$
$
15
-
15
1
(1)
-
$ 517
$
$
17
(1)
16
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
92
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
Operating Revenues
Operating Expenses:
Fuel
Coal contract settlement
Purchased power
Other operations and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating Income
Other Income and Expenses:
Miscellaneous income
Miscellaneous expense
Total other income
Interest Charges
Income Before Income Taxes
Income Taxes
Net Income
Year Ended December 31,
2009
2008
$
850
$
908
2007
$
876
278
-
-
172
69
21
540
310
-
-
-
59
251
96
377
(60)
-
175
65
21
578
330
1
(1)
-
55
275
100
344
-
23
163
69
19
618
258
-
-
-
55
203
78
$ 155
$
175
$ 125
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
93
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable – affiliates
Miscellaneous accounts and notes receivable
Advances to money pool
Materials and supplies
Other current assets
Total current assets
Property and Plant, Net
Intangible Assets
Other Assets
TOTAL ASSETS
Current Liabilities:
LIABILITIES AND STOCKHOLDER’S EQUITY
Current maturities of long-term debt
Current portion of intercompany note payable – CIPS
Borrowings from money pool
Accounts and wages payable
Accounts payable – affiliates
Current portion of intercompany tax payable – CIPS
Taxes accrued
Deferred taxes
Other current liabilities
Total current liabilities
Long-term Debt, Net
Intercompany Note Payable – CIPS
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
Accumulated deferred investment tax credits
Intercompany tax payable – CIPS
Asset retirement obligations
Pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 14 and 15)
Stockholder’s Equity:
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding
Other paid-in capital
Retained earnings
Accumulated other comprehensive loss
Total stockholder’s equity
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
December 31,
2009
2008
$
6
103
22
73
132
10
346
2,135
34
20
$ 2,535
$
2
88
20
-
122
5
237
1,950
49
8
$ 2,244
$
200
45
-
71
36
9
17
26
34
438
823
-
190
4
82
53
51
32
412
$
-
42
80
82
58
9
16
15
28
330
774
45
136
6
93
49
67
49
400
-
503
396
(37)
862
$ 2,535
-
503
241
(49)
695
$ 2,244
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
94
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2008
2009
2007
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
$
155
$
175
$
125
activities:
Gain on sales of emission allowances
Net mark-to-market (gain) loss on derivatives
Depreciation and amortization
Amortization of debt issuance costs and discounts
Deferred income taxes and investment tax credits, net
Loss on asset impairment
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and other postretirement benefits
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Money pool advances, net
Purchases of emission allowances
Sales of emission allowances
Other
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Capital issuance costs
Short-term debt, net
Money pool borrowings, net
Intercompany note payable – CIPS
Issuances of long-term debt
Capital contribution from parent
Net cash provided by (used in) financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Cash Paid During the Year:
Interest (net of $11, $10, and $6 capitalized, respectively)
Income taxes, net
-
(17)
86
2
55
6
-
(17)
(10)
(9)
1
7
(28)
1
232
(2)
16
92
-
14
-
-
(18)
(29)
(11)
1
12
(5)
1
246
(2)
(2)
101
-
30
-
1
10
3
(4)
(7)
3
(8)
5
255
(277)
(73)
(2)
1
2
(349)
(317)
-
(13)
2
(2)
(330)
(191)
-
(20)
1
-
(210)
-
(6)
-
(80)
(42)
249
-
121
4
2
6
56
85
(101)
(2)
(100)
26
(39)
300
-
84
-
2
2
51
62
$
$
(113)
-
100
(69)
(37)
-
75
(44)
1
1
2
53
49
$
$
$
$
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
95
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Capital contribution from parent
Other paid-in capital, end of year
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Adjustment to adopt new accounting standard
Retained earnings, end of year
Accumulated Other Comprehensive Loss:
Derivative financial instruments, beginning of year
Change in derivative financial instruments
Derivative financial instruments, end of year
Deferred retirement benefit costs, beginning of year
Change in deferred retirement benefit costs
Deferred retirement benefit costs, end of year
Total accumulated other comprehensive loss, end of year
Total Stockholder’s Equity
Comprehensive Income, Net of Taxes:
Net income
Unrealized net (loss) on derivative hedging instruments, net of
income taxes (benefit) of $-, $-, and $(2), respectively
Reclassification adjustments for derivative gains included in net
income, net of income taxes of $-, $3, and $1, respectively
Pension and other postretirement activity, net of income taxes
(benefit) of $9, $(19), and $5, respectively
Total Comprehensive Income, Net of Taxes
December 31,
2009
2008
$
-
$
-
503
-
503
241
155
-
-
396
(6)
-
(6)
(43)
12
(31)
(37)
$ 862
$
155
-
-
503
-
503
167
175
(101)
-
241
(1)
(5)
(6)
(21)
(22)
(43)
(49)
695
175
-
(5)
$
$
2007
$
-
428
75
503
156
125
(113)
(1)
167
3
(4)
(1)
(24)
3
(21)
(22)
648
125
(3)
(1)
$
$
12
167
(22)
148
$
$
3
124
$
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
96
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
Year Ended December 31,
2008
2009
2007
Operating Revenues:
Electric
Gas
Support services – affiliates
Other
Total operating revenues
Operating Expenses:
Fuel
Purchased power
Gas purchased for resale
Other operations and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating Income
Other Income and Expenses:
Miscellaneous income
Miscellaneous expense
Total other expenses
Interest Charges
Income Before Income Taxes
Income Taxes
Net Income
Preferred Stock Dividends
$
729
277
70
6
1,082
115
169
189
260
70
27
830
252
1
(5)
(4)
41
207
72
135
1
Net Income Available to Common Stockholder
$
134
$
$
771
375
-
1
1,147
121
291
284
217
77
25
1,015
132
2
(5)
(3)
21
$
681
329
-
1
1,011
71
280
237
184
73
23
868
143
5
(6)
(1)
27
108
115
39
69
1
68
39
76
2
74
$
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
97
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable –trade (less allowance for doubtful accounts of $3 and $3, respectively)
Accounts receivable – affiliates
Unbilled revenue
Miscellaneous accounts and notes receivable
Materials and supplies
Current regulatory assets
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
Intangible assets
Regulatory assets
Other assets
Total investments and other assets
TOTAL ASSETS
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt
Borrowings from money pool
Intercompany note payable – Ameren
Accounts and wages payable
Accounts payable – affiliates
Taxes accrued
Mark-to-market derivative liabilities
Mark-to-market derivative liabilities – affiliates
Other current liabilities
Total current liabilities
Long-term Debt, Net
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
Accumulated deferred investment tax credits
Regulatory liabilities
Pension and other postretirement benefits
Asset retirement obligations
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 14 and 15)
Stockholders’ Equity:
Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding
Other paid-in capital
Preferred stock not subject to mandatory redemption
Retained earnings
Accumulated other comprehensive loss
Total stockholders’ equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
December 31,
2009
2008
$
88
39
68
43
16
107
29
18
408
1,789
1
162
22
185
$ 2,382
$
-
62
51
65
-
131
24
35
368
1,734
1
171
22
194
$ 2,296
$
-
-
288
62
50
5
10
19
72
506
279
214
4
209
193
34
88
742
$
236
98
-
117
83
8
21
7
62
632
279
171
5
206
216
28
75
701
-
480
19
354
2
855
$ 2,382
-
429
19
240
(4)
684
$ 2,296
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
98
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
$
135
$
69
$
76
Year Ended December 31,
2008
2007
2009
activities:
Net mark-to-market (gain) loss on derivatives
Depreciation and amortization
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits, net
Loss on asset impairment
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and postretirement benefits
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Money pool advances, net
Purchases of emission allowances
Other
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Dividends on preferred stock
Capital issuance costs
Short-term debt, net
Intercompany note payable – Ameren, net
Money pool borrowings, net
Redemptions, repurchases, and maturities of:
Long-term debt
Preferred stock
Issuances of long-term debt
Capital contribution from parent
Other
Net cash provided by (used in) financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Cash Paid (Refunded) During the Year:
Interest (net of $1, $8, and $8 capitalized, respectively)
Income taxes, net
(10)
72
3
40
1
9
24
(38)
(3)
21
-
9
263
(154)
-
(1)
2
(153)
9
77
1
15
12
(17)
(21)
65
5
(7)
10
(11)
207
-
74
1
(1)
-
(32)
(17)
(6)
(2)
(7)
(13)
1
74
(319)
-
-
2
(317)
(254)
42
-
-
(212)
(20)
(1)
(7)
(236)
288
(98)
-
(1)
(1)
(109)
-
98
-
-
-
51
1
(22)
88
-
88
37
82
(19)
(16)
150
-
2
104
(6)
6
-
24
(15)
$
$
$
$
-
(2)
-
180
-
-
(50)
(1)
-
14
-
141
3
3
6
30
35
$
$
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
99
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Capital contribution from parent
Other paid-in capital, end of year
Preferred Stock Not Subject to Mandatory Redemption
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Preferred stock dividends
Adjustment to adopt new accounting standard
Retained earnings, end of year
Accumulated Other Comprehensive Income (Loss):
Derivative financial instruments, beginning of year
Change in derivative financial instruments
Derivative financial instruments, end of year
Deferred retirement benefit costs, beginning of year
Change in deferred retirement benefit costs
Deferred retirement benefit costs, end of year
Total accumulated other comprehensive income (loss), end of year
Total Stockholders’ Equity
Comprehensive Income, Net of Taxes:
Net income
Unrealized net (loss) on derivative hedging instruments, net of income taxes
(benefit) of $-, $-, and $(1), respectively
Reclassification adjustments for derivative (gains) included in net income, net
of income taxes of $-, $1, and $1, respectively
Pension and other postretirement activity, net of income taxes (benefit) of $4,
$(4), and $2, respectively
Total Comprehensive Income, Net of Taxes
December 31,
2008
$
-
429
-
429
19
172
69
-
(1)
-
240
1
(1)
-
1
(5)
(4)
(4)
$ 684
2009
$
-
429
51
480
19
240
135
(20)
(1)
-
354
-
-
-
(4)
6
2
2
$ 855
2007
$
-
415
14
429
19
99
76
-
(2)
(1)
172
4
(3)
1
(2)
3
1
2
$ 622
$ 135
$ 69
$ 76
-
-
-
(1)
(1)
(2)
6
$ 141
(5)
$ 63
3
$ 76
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
100
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
Year Ended December 31,
2008
2007
2009
Operating Revenues:
Electric
Gas
Other
Total operating revenues
Operating Expenses:
Purchased power
Gas purchased for resale
Other operations and maintenance
Depreciation and amortization
Amortization of regulatory assets
Taxes other than income taxes
Total operating expenses
Operating Income
Other Income and Expenses:
Miscellaneous income
Miscellaneous expense
Total other income
Interest Charges
Income Before Income Taxes
Income Taxes
Net Income
Preferred Stock Dividends
$ 992
501
11
1,504
509
310
275
99
17
64
1,274
230
3
(3)
-
98
132
53
79
2
Net Income Available to Common Stockholder
$
77
$
$ 1,071
620
5
1,696
654
452
318
85
17
67
1,593
103
11
(5)
6
99
10
5
5
2
3
$ 1,104
540
2
1,646
714
390
271
80
16
66
1,537
109
14
(5)
9
77
41
15
26
2
$
24
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
101
ILLINOIS POWER COMPANY
BALANCE SHEET
(In millions)
ASSETS
Current Assets:
Cash and cash equivalents
Accounts receivable –trade (less allowance for doubtful accounts of $9 and $12,
respectively)
Accounts receivable – affiliates
Unbilled revenue
Miscellaneous accounts and notes receivable
Advances to money pool
Materials and supplies
Counterparty collateral
Current regulatory assets
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
Goodwill
Regulatory assets
Other assets
Total investments and other assets
TOTAL ASSETS
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt
Accounts and wages payable
Accounts payable – affiliates
Taxes accrued
Customer deposits
Mark-to-market derivative liabilities
Mark-to-market derivative liabilities – affiliates
Environmental remediation
Current regulatory liabilities
Other current liabilities
Total current liabilities
Long-term Debt, Net
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
Regulatory liabilities
Pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Commitments and Contingencies (Notes 2, 14 and 15)
Stockholders’ Equity:
Common stock, no par value, 100.0 shares authorized – 23.0 shares outstanding
Other paid-in-capital
Preferred stock not subject to mandatory redemption
Retained earnings
Accumulated other comprehensive income
Total stockholders’ equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
December 31,
2009
2008
$
190
$
50
107
49
94
23
-
112
5
86
21
687
2,450
214
540
51
805
$ 3,942
$
-
98
117
6
46
20
65
59
24
70
505
1,147
232
88
238
281
839
156
23
133
-
44
144
35
58
20
663
2,329
214
517
47
778
$ 3,770
$ 250
94
105
8
50
36
20
18
23
48
652
1,150
176
76
314
151
717
-
1,349
46
53
3
1,451
$ 3,942
-
1,194
46
7
4
1,251
$ 3,770
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
102
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2008
2009
2007
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
$
79
$
5
$
26
activities:
Depreciation and amortization
Amortization of debt issuance costs and premium/discounts
Deferred income taxes
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued
Assets, other
Liabilities, other
Pension and other postretirement benefits
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Advances to AITC for construction
Money pool advances, net
Other
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Dividends on preferred stock
Capital issuance costs
Short-term debt, net
Money pool borrowings, net
Redemptions, repurchases, and maturities of long-term debt
Issuance of long-term debt
Capital contribution from parent
IP SPT maturities
Generator advances received for construction, net
Overfunding of TFNs
Net cash provided by (used in) financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Cash Paid (Refunded) During the Year:
Interest (net of $2, $1, and $1 capitalized, respectively)
Income taxes, net
Noncash investing activity – asset transfer from AITC
113
6
54
(2)
14
33
75
(2)
28
11
-
409
(186)
(47)
44
-
(189)
(31)
(2)
(7)
-
-
(250)
-
155
-
55
-
(80)
140
50
190
96
22
26
$
$
93
9
26
-
(26)
(10)
70
1
(8)
23
(5)
178
105
8
4
(1)
(51)
(12)
(38)
-
(27)
21
(5)
30
(186)
(13)
(44)
(3)
(246)
(178)
(6)
-
(2)
(186)
(60)
(2)
(5)
(175)
-
(337)
730
-
(54)
15
-
112
44
6
50
75
(43)
-
$
$
(61)
(2)
(2)
100
(43)
-
250
-
(87)
4
3
162
6
-
6
65
18
-
$
$
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
103
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Capital contribution from parent
Other paid-in capital, end of year
Preferred Stock Not Subject to Mandatory Redemption
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Preferred stock dividends
Retained earnings, end of year
Accumulated Other Comprehensive Income:
Beginning of year
Change in deferred retirement benefit costs
Total accumulated other comprehensive income, end of year
Total Stockholders’ Equity
Comprehensive Income, Net of Taxes:
Net income
Pension and other postretirement activity, net of income taxes of $-,
$-, and $-, respectively
Total Comprehensive Income, Net of Taxes
2009
$
-
1,194
155
1,349
46
7
79
(31)
(2)
53
4
(1)
3
$ 1,451
$
$
79
(1)
78
December 31,
2008
2007
$
-
$
-
1,194
-
1,194
46
1,194
-
1,194
46
64
5
(60)
(2)
7
4
-
4
$ 1,251
$
$
5
-
5
101
26
(61)
(2)
64
5
(1)
4
$ 1,308
$
$
26
(1)
25
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
104
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (Consolidated)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
AMEREN ENERGY GENERATING COMPANY
(Consolidated)
CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)
ILLINOIS POWER COMPANY (Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
December 31, 2009
NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General
Ameren, headquartered in St. Louis, Missouri, is a
public utility holding company under PUHCA 2005,
administered by FERC. Ameren’s primary assets are the
common stock of its subsidiaries. Ameren’s subsidiaries
are separate, independent legal entities with separate
businesses, assets, and liabilities. These subsidiaries
operate, as the case may be, rate-regulated electric
generation, transmission and distribution businesses, rate-
regulated natural gas transmission and distribution
businesses, and merchant electric generation businesses
in Missouri and Illinois. Dividends on Ameren’s common
stock and the payment of other expenses by Ameren
depend on distributions made to it by its subsidiaries.
Ameren’s principal subsidiaries are listed below. Also see
the Glossary of Terms and Abbreviations at the front of
this report.
UE, or Union Electric Company, also known as
AmerenUE, operates a rate-regulated electric
generation, transmission and distribution business,
and a rate-regulated natural gas transmission and
distribution business in Missouri. UE was incorporated
in Missouri in 1922 and is successor to a number of
companies, the oldest of which was organized in 1881.
It is the largest electric utility in the state of Missouri. It
supplies electric and natural gas service to a 24,000-
square-mile area located in central and eastern
Missouri. This area has an estimated population of
2.8 million and includes the Greater St. Louis area. UE
supplies electric service to 1.2 million customers and
natural gas service to 126,000 customers.
CIPS, or Central Illinois Public Service Company, also
known as AmerenCIPS, operates a rate-regulated
electric and natural gas transmission and distribution
business in Illinois. CIPS was incorporated in Illinois in
1923 and is successor to a number of companies, the
oldest of which was organized in 1902. It supplies
electric and natural gas utility service to portions of
central, west central and southern Illinois having an
estimated population of 1.1 million in an area of 20,500
square miles. CIPS supplies electric service to
383,000 customers and natural gas service to 182,000
customers.
Genco, or Ameren Energy Generating Company,
operates a merchant electric generation business in
Illinois and Missouri. Genco was incorporated in Illinois
in March 2000. Genco’s coal, and natural gas and oil-
fired electric generating facilities, are expected to have
capacity of 3,454, 1,578, and 169 megawatts,
respectively, at the time of the 2010 peak summer
electrical demand.
CILCO, or Central Illinois Light Company, also known
as AmerenCILCO, operates a rate-regulated electric
transmission and distribution business, a merchant
electric generation business (through its subsidiary
AERG), and a rate-regulated natural gas transmission
and distribution business, all in Illinois. CILCO was
incorporated in Illinois in 1913. It supplies electric and
natural gas utility service to portions of central and
east central Illinois in areas of 3,700 and 4,500 square
miles, respectively, with an estimated population of
0.6 million. CILCO supplies electric service to 211,000
customers and natural gas service to 214,000
customers. AERG, a wholly owned subsidiary of
CILCO, is expected to have capacity of 1,125
megawatts from its coal-fired electric generating
facilities at the time of the 2010 peak summer electrical
demand.
IP, or Illinois Power Company, also known as
AmerenIP, operates a rate-regulated electric and
natural gas transmission and distribution business in
Illinois. IP was incorporated in 1923 in Illinois. It
supplies electric and natural gas utility service to
portions of central, east central, and southern Illinois,
serving a population of 1.5 million in an area of 15,000
square miles, contiguous to our other service
territories. IP supplies electric service to 617,000
customers and natural gas service to 417,000
customers, including most of the Illinois portion of the
Greater St. Louis area.
Ameren has various other subsidiaries responsible for
the short- and long-term marketing of power, procurement
of fuel, management of commodity risks, and provision of
other shared services. Ameren has an 80% ownership
interest in EEI, which until February 29, 2008, was held
40% by UE and 40% by Development Company. Ameren
consolidates EEI for financial reporting purposes. UE
reported EEI under the equity method until February 29,
2008. Effective February 29, 2008, UE’s and Development
Company’s ownership interests in EEI were transferred to
Resources Company through an internal reorganization.
UE’s interest in EEI was transferred at book value
indirectly through a dividend to Ameren. On January 1,
2010, as part of an internal reorganization, Resources
Company transferred its 80% stock ownership interest in
EEI to Genco through a capital contribution. See Note 14
– Related Party Transactions for additional information.
The following table presents summarized financial
2009
information of EEI (in millions):
For the years ended December 31,
2007
Operating revenues .............................. $ 303 $ 520 $ 427
Operating income .................................
216
Net income ...........................................
136
As of December 31,
2009 2008 2007
86 $ 76 $
Current assets ...................................... $
69
172
Noncurrent assets .................................
140
124
165
Current liabilities ...................................
93
60
48
Noncurrent liabilities ..............................
43
10
226
142
19
10
2008
105
The financial statements of Ameren, Genco and
CILCO are prepared on a consolidated basis. CIPS has
no subsidiaries and therefore is not consolidated. UE had
a subsidiary in 2007 (Union Electric Development
Corporation), but in January 2008 this subsidiary was
transferred to Ameren in the form of a stock dividend.
Accordingly, UE’s financial statements were prepared on a
consolidated basis for 2007 only. IP had a subsidiary in
2007 (Illinois Gas Supply Company) that was dissolved at
December 31, 2007. Accordingly, IP’s financial statements
were prepared on a consolidated basis for 2007 only. All
significant intercompany transactions have been
eliminated. All tabular dollar amounts are in millions,
unless otherwise indicated.
Our accounting policies conform to GAAP. Our
financial statements reflect all adjustments (which include
normal, recurring adjustments) that are necessary, in our
opinion, for a fair presentation of our results. The
preparation of financial statements in conformity with
GAAP requires management to make certain estimates
and assumptions. Such estimates and assumptions affect
reported amounts of assets and liabilities, the disclosure
of contingent assets and liabilities at the dates of financial
statements, and the reported amounts of revenues and
expenses during the reported periods. Actual results could
differ from those estimates.
Regulation
Certain Ameren subsidiaries are regulated by the
MoPSC, the ICC, the NRC, and FERC. In accordance with
authoritative accounting guidance regarding accounting
for the effects of certain types of regulation, UE, CIPS,
CILCO and IP defer certain costs as assets pursuant to
actions of our rate regulators or the expected ability to
recover such costs in rates charged to customers. UE,
CIPS, CILCO and IP also defer certain amounts as
liabilities pursuant to actions of regulators or the
expectation that such amounts will be returned to
customers in future rates. Regulatory assets and liabilities
are amortized consistent with the period of expected
regulatory treatment. See Note 2 – Rate and Regulatory
Matters for additional information on regulatory assets and
liabilities. Assets are also recorded as construction work in
progress and property and plant, net. See Note 3 –
Property and Plant, Net.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and
temporary investments purchased with an original maturity
of three months or less.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts represents our
best estimate of existing accounts receivable that will
ultimately be uncollectible. The allowance is calculated by
applying estimated write-off factors to various classes of
outstanding receivables, including unbilled revenue. The
write-off factors used to estimate uncollectible accounts
are based upon consideration of both historical collections
experience and management’s best estimate of future
collections success given the existing and anticipated
future collections environment. See Note 2 – Rate and
Regulatory Matters for additional information regarding
regulatory recovery of uncollectible accounts receivable by
the Ameren Illinois Utilities.
Materials and Supplies
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost
method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant
assets when installed, as appropriate. The following table presents a breakdown of materials and supplies for each of the
Ameren Companies at December 31, 2009 and 2008:
CIPS
$
-
32
15
$ 47
$
-
54
16
Genco
CILCO
IP
$
97
-
35
$
38
45
24
$ 132
$ 107
$
92
-
30
$
32
75
24
$
-
84
28
$ 112
$
-
117
27
$ 144
$ 70
$ 122
$ 131
2009:
Fuel(b) ...................................................................................
Gas stored underground .......................................................
Other materials and supplies .................................................
2008:
Fuel(b) ...................................................................................
Gas stored underground .......................................................
Other materials and supplies .................................................
Ameren (a)
UE
$ 315
183
284
$ 782
$ 290
277
275
$ 842
$ 154
22
170
$ 346
$ 139
32
168
$ 339
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
(b) Consists of coal, oil, paint, propane, and tire chips.
106
Property and Plant
Goodwill and Intangible Assets
We capitalize the cost of additions to and betterments
of units of property and plant. The cost includes labor,
material, applicable taxes, and overhead. An allowance for
funds used during construction, as discussed specifically
below, is also capitalized as a cost of our rate-regulated
assets. Interest during construction is capitalized as a cost
of merchant generation assets. Maintenance
expenditures, including nuclear refueling and maintenance
outages, are expensed as incurred. When units of
depreciable property are retired, the original costs, less
salvage values, are charged to accumulated depreciation.
Asset removal costs incurred by our merchant generation
operations that do not constitute legal obligations are
expensed as incurred. Asset removal costs accrued by
our rate-regulated operations that do not constitute legal
obligations are classified as a regulatory liability. See
Asset Retirement Obligations below and Note 3 – Property
and Plant, Net, for additional information.
Depreciation
Depreciation is provided over the estimated lives of
the various classes of depreciable property by applying
composite rates on a straight-line basis to the cost basis
of such property. The provision for depreciation for the
Ameren Companies in 2009, 2008 and 2007 generally
ranged from 3% to 4% of the average depreciable cost.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the
allowance for funds used during construction, or the cost
of borrowed funds and the cost of equity funds (preferred
and common stockholders’ equity) applicable to rate-
regulated construction expenditures, as is the utility
industry accounting practice. Allowance for funds used
during construction does not represent a current source of
cash funds. This accounting practice offsets the effect on
earnings of the cost of financing current construction, and
it treats such financing costs in the same manner as
construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of
allowance for funds used during construction and other
construction costs occurs when completed projects are
placed in service and reflected in customer rates. The
following table presents the annual allowance for funds
used during construction rates that were utilized during
2009, 2008, and 2007:
2009
Ameren ................................ 6% – 10 %
UE ......................................
CIPS ....................................
CILCO .................................
IP ......................................
6
6
10
9
2008
1% – 7 %
7
1
1
5
2007
6% – 7%
6
6
7
6
Goodwill. Goodwill represents the excess of the
purchase price of an acquisition over the fair value of the
net assets acquired. Ameren’s goodwill relates to its
acquisition of IP and an additional 20% EEI ownership
interest acquired in 2004 as well as its acquisition of
CILCORP and Medina Valley in 2003. IP’s goodwill relates
to the acquisition of IP in 2004. See Note 17 – Goodwill for
additional information.
Intangible Assets. We evaluate intangible assets for
impairment if events or changes in circumstances indicate
that their carrying amount might be impaired. Ameren’s,
UE’s, Genco’s and CILCO’s intangible assets at
December 31, 2009 and 2008, consisted of emission
allowances. See also Note 15 – Commitments and
Contingencies for additional information on emission
allowances.
The following table presents the SO2 and NOx
emission allowances held and the related aggregate SO2
and NOx emission allowance book values that were
carried as intangible assets as of December 31, 2009.
Emission allowances consist of various individual
emission allowance certificates and do not expire.
Emission allowances are charged to fuel expense as they
are used in operations.
SO2 and NOX in tons
Ameren(d) ...................
UE .............................
Genco .........................
CILCO (AERG) ...........
EEI .............................
Book Value(c)
$ 129(e)
35
34
1
5
(a)
SO2
3,028,000
1,610,000
743,000
354,000
321,000
(b)
NO X
25,091
13,677
9,258
210
1,946
(a) Vintages are from 2009 to 2019. Each company possesses additional
allowances for use in periods beyond 2019.
(b) Vintage is 2009.
(c) The book value represents SO2 and NOx emission allowances for use in
periods through 2039. The book value at December 31, 2008, for
Ameren, UE, Genco, CILCO (AERG), and EEI was $167 million, $48
million, $49 million, $1 million, and $9 million, respectively.
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Includes $30 million and $24 million of fair-market value adjustments
recorded in connection with Ameren’s 2003 acquisition of CILCORP and
Ameren’s 2004 acquisition of an additional 20% ownership interest in
EEI, respectively.
The following table presents amortization expense
(d)
(e)
recorded in connection with the usage of emission
allowances, net of gains from emission allowance sales,
for Ameren, UE, Genco and CILCO (AERG) during the
years ended December 31, 2009, 2008, and 2007:
Ameren(a)(b) ...........................
UE ........................................
Genco ....................................
CILCO (AERG) ......................
2009
$ 24
(5)
16
2
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Includes allowances consumed that were recorded through purchase
accounting.
(c) Less than $1 million.
2008
$ 28
(5)
25
(c)
2007
$ 35
(5)
30
1
(a)
(b)
107
Impairment of Long-lived Assets
We evaluate long-lived assets classified as held and
used for impairment when events or changes in
circumstances indicate that the carrying value of such assets
may not be recoverable. Whether impairment has occurred is
determined by comparing the estimated undiscounted cash
flows attributable to the assets with the carrying value of the
assets. If the carrying value exceeds the undiscounted cash
flows, we recognize an impairment charge equal to the
carrying value of the assets in excess of estimated fair value.
In the period in which we determine an asset meets the held
for sale criteria, we record an impairment charge to the extent
the book value exceeds its fair value less cost to sell. In
2009, Genco recorded asset impairment charges of $6
million as a result of the termination of a rail line extension
project at a subsidiary of Genco and to adjust the carrying
value of an office building owned by Genco to its estimated
fair value as of December 31, 2009. The charge related to
the office building was based on the expected net proceeds
to be generated from its sale in 2010. In addition, CILCO
recorded an asset impairment charge of $1 million to adjust
the carrying value of CILCO’s (AERG’s) Indian Trails
generation facility’s estimated fair value as of December 31,
2009. This charge was based on the net proceeds generated
from the sale of the facility in January 2010.
In 2008, asset impairment charges were recorded to
adjust the carrying value of CILCO’s (AERG’s) Indian Trails
and Sterling Avenue generation facilities to their estimated
fair values as of December 31, 2008. CILCO recorded an
asset impairment charge of $12 million related to the Indian
Trails generation facility as a result of the suspension of
operations by the facility’s only customer. CILCORP recorded
a $2 million impairment charge related to the Sterling Avenue
CT. The charge was based on the net proceeds generated
from the sale of the facility in 2009.
The 2009 and 2008 asset impairment charges were
recorded in Operating Expenses – Other Operations and
Maintenance Expense in the applicable statements of income
and were included in Merchant Generation segment results.
Investments
Ameren and UE evaluate for impairment the investments
held in UE’s nuclear decommissioning trust fund. Losses on
assets in the trust fund could result in higher funding
requirements for decommissioning costs, which UE believes
would be recovered in electric rates paid by its customers.
Accordingly, Ameren and UE recognize a regulatory asset on
their balance sheets for losses on investments held in the
nuclear decommissioning trust fund. See Note 9 – Nuclear
Decommissioning Trust Fund Investments for additional
information.
Environmental Costs
Liabilities for environmental costs are recorded on an
undiscounted basis when it is probable that a liability has
been incurred and the amount of the liability can be
reasonably estimated. Estimated environmental expenditures
are regularly reviewed and updated. Costs are expensed or
deferred as a regulatory asset when it is expected that the
costs will be recovered from customers in future rates. If
environmental expenditures are related to facilities currently
in use, such as pollution control equipment, the cost is
capitalized and depreciated over the expected life of the
asset.
Unamortized Debt Discount, Premium, and Expense
Discount, premium, and expense associated with long-
term debt are amortized over the lives of the related issues.
Revenue
Operating Revenues
UE, CIPS, Genco, CILCO and IP record operating
revenue for electric or natural gas service when it is delivered
to customers. We accrue an estimate of electric and natural
gas revenues for service rendered but unbilled at the end of
each accounting period.
Trading Activities
We present the revenues and costs associated with
certain energy derivative contracts designated as trading on
a net basis in Operating Revenues – Electric and Other.
Nuclear Fuel
UE’s cost of nuclear fuel is amortized to fuel expense on
a unit-of-production basis. Spent fuel disposal cost is based
on net kilowatthours generated and sold, and that cost is
charged to expense.
Purchased Gas, Power and Fuel Rate-adjustment
Mechanisms
Ameren’s utility subsidiaries have various rate-
adjustment mechanisms in place that provide for the recovery
of purchased natural gas and electric fuel and purchased
power costs.
In UE’s, CIPS’, CILCO’s, and IP’s retail natural gas utility
jurisdictions, changes in natural gas costs are generally
reflected in billings to their natural gas utility customers
through PGA clauses. The difference between actual natural
gas costs and costs billed to customers in a given period are
deferred and included in Other Current Assets or Other
Current Liabilities on the balance sheet of Ameren and in
Current Regulatory Assets or Current Regulatory Liabilities
on the balance sheet of UE, CIPS, CILCO and IP. The
deferred amounts are either billed or refunded to natural gas
utility customers in a subsequent period.
In the Ameren Illinois Utilities’ retail electric utility
jurisdictions, changes in purchased power costs are generally
reflected in billings to their electric utility customers through
pass-through rate-adjustment clauses.
108
The difference between actual purchased power costs and
costs billed to customers in a given period are deferred and
included in Other Current Assets or Other Current Liabilities
on the balance sheet of Ameren and in Current Regulatory
Assets or Current Regulatory Liabilities on the balance
sheets of CIPS, CILCO and IP. The deferred amounts are
either billed or refunded to electric utility customers in a
subsequent period.
In 2009, UE implemented a FAC for its retail electric
jurisdiction. The FAC allows an adjustment of electric rates
three times per year for a pass-through to customers of 95%
of changes in fuel and purchased power costs, net of off-
system revenues, including MISO costs and revenues,
greater or less than the amount set in base rates, subject to
MoPSC prudency review. The difference between the costs
of fuel incurred and the cost of fuel recovered from UE’s
customers are deferred and included in Other Current Assets
or Other Current Liabilities on the balance sheet of Ameren
and in Current Regulatory Assets or Current Regulatory
Liabilities on the balance sheet of UE. The deferred amounts
are either billed or refunded to UE’s electric utility customers
in a subsequent period.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are
recorded by Ameren, UE, CIPS, CILCO and IP using
settlement information provided by MISO. These purchase
and sale transactions are accounted for on a net hourly
position. We record net purchases in a single hour in
Operating Expenses – Purchased Power and net sales in a
single hour in Operating Revenues – Electric in our
statements of income. On occasion, prior period transactions
will be resettled outside the routine settlement process
because of a change in MISO’s tariff or a material
interpretation thereof. In these cases, Ameren, UE, CIPS,
CILCO and IP recognize expenses associated with
resettlements once the resettlement is probable and the
resettlement amount can be estimated. Ameren, UE, CIPS,
CILCO and IP recognize revenues associated with
resettlements in accordance with authoritative guidance on
revenue recognition.
Stock-based Compensation
Stock-based compensation cost is measured at the grant
date based on the fair value of the award. Ameren
recognizes as compensation expense the estimated fair
value of stock-based compensation on a straight-line basis
over the requisite service period. See Note 12 – Stock-based
Compensation for additional information.
Excise Taxes
Excise taxes imposed on us are reflected on Missouri
electric, Missouri natural gas, and Illinois natural gas
customer bills. They are recorded gross in Operating
Revenues and Operating Expenses – Taxes Other Than
Income Taxes on the statement of income. Excise taxes
reflected on Illinois electric customer bills are imposed on the
consumer and are therefore not included in revenues and
expenses. They are recorded as tax collections payable and
included in Taxes Accrued on the balance sheet. The
following table presents excise taxes recorded in Operating
Revenues and Operating Expenses – Taxes Other than
Income Taxes for the years ended 2009, 2008 and 2007:
2009
2008
2007
Ameren ...................................................... $ 168 $ 172 $ 166
UE ............................................................
110
CIPS ..........................................................
15
CILCO .......................................................
11
IP ............................................................
30
112
15
11
30
109
16
13
34
Income Taxes
Ameren uses an asset and liability approach for its
financial accounting and reporting of income taxes, in
accordance with authoritative accounting guidance. Deferred
tax assets and liabilities are recognized for transactions that
are treated differently for financial reporting and income tax
return purposes. These deferred tax assets and liabilities are
calculated based on statutory tax rates.
We recognize that regulators will probably reduce future
revenues for deferred tax liabilities initially recorded at rates
in excess of the current statutory rate. Therefore, reductions
in the deferred tax liability, which were recorded because of
decreases in the statutory rate, were credited to a regulatory
liability. A regulatory asset has been established to recognize
the probable future recovery in rates of future income taxes
resulting principally from the reversal of allowance for funds
used during construction, that is, equity and temporary
differences related to property and plant acquired before
1976 that were unrecognized temporary differences prior to
the adoption of the authoritative accounting provisions for
income taxes.
Investment tax credits used on tax returns for prior years
have been deferred for book purposes; the credits are being
amortized over the useful lives of the related investment.
Deferred income taxes were recorded on the temporary
difference represented by the deferred investment tax credits
and a corresponding regulatory liability. This recognizes the
expected reduction in rate revenue for future lower income
taxes associated with the amortization of the investment tax
credits. See Note 13 – Income Taxes.
UE, CIPS, Genco, CILCO, and IP are parties to a tax
sharing agreement with Ameren that provides for the
allocation of consolidated tax liabilities. The tax sharing
agreement provides that each party is allocated an amount of
tax similar to that which would be owed had the party been
separately subject to tax. Any net benefit attributable to the
parent is reallocated to other members. That allocation is
treated as a contribution of capital to the party receiving the
benefit.
Noncontrolling Interests
Ameren’s noncontrolling interests comprise the 20% of
EEI’s net assets not owned by Ameren and the preferred
109
stock not subject to mandatory redemption of the Ameren
subsidiaries. These noncontrolling interests are classified
as a component of equity separate from Ameren’s equity
in its consolidated balance sheet.
Earnings per Share
There were no material differences between Ameren’s
basic and diluted earnings per share amounts in 2009,
2008, and 2007. The number of stock options, restricted
stock shares, and performance share units outstanding
was immaterial. The assumed stock option conversions
increased the number of shares outstanding in the diluted
earnings per share calculation by 16,841 shares in 2008
and 35,545 shares in 2007. There were no assumed stock
option conversions in 2009, as the remaining stock
options were not dilutive.
Accounting Changes and Other Matters
The following is a summary of recently adopted
authoritative accounting guidance as well as guidance
issued but not yet adopted that could impact the Ameren
Companies.
Noncontrolling Interests in Consolidated Financial
Statements
In December 2007, the FASB issued authoritative
guidance that established accounting and reporting
standards for minority interests, which were
recharacterized as noncontrolling interests. This guidance
requires noncontrolling interests to be classified as a
component of equity separate from the parent’s equity;
purchases or sales of equity interests that do not result in
a change in control to be accounted for as equity
transactions; net income attributable to the noncontrolling
interest to be included in consolidated net income in the
statement of income; and upon a loss of control, the
interest sold, as well as any interest retained, to be
recorded at fair value, with any gain or loss recognized in
earnings. We adopted the provisions of this guidance at
the beginning of 2009. It applied prospectively, except for
the presentation and disclosure requirements, for which it
applied retroactively. See Noncontrolling Interests above
for additional information.
Disclosures about Derivative Instruments and Hedging
Activities
In March 2008, the FASB issued amended
authoritative guidance that requires entities to provide
greater transparency in interim and annual financial
statements about how and why the entity uses derivative
instruments, how the instruments and related hedged
items are accounted for, and how the instruments and
related hedged items affect the financial position, results
of operations, and cash flows of the entity. This guidance
requires qualitative disclosures about objectives and
strategies for using derivatives, quantitative disclosures
about fair value amounts of and gains and losses on
derivative instruments, and disclosures about credit-risk-
related contingent features in derivative agreements. The
adoption of this guidance, effective for us in the first
quarter of 2009, did not have a material impact on our
results of operations, financial position, or liquidity
because it required enhanced disclosure only. See Note 7
– Derivative Financial Instruments for additional
information.
Employers’ Disclosures about Postretirement Benefit Plan
Assets
In December 2008, the FASB issued authoritative
guidance regarding additional disclosures related to
pension and other postretirement benefit plan assets.
Required additional disclosures include those related to
the investment allocation decision-making process, the fair
value of each major category of plan assets and the inputs
and valuation techniques used to measure fair value and
significant concentrations of risk within the plan assets.
The adoption of this guidance, effective for us as of
December 31, 2009, did not have a material impact on our
results of operations, financial position, or liquidity,
because it provided enhanced disclosure requirements
only. See Note 11 – Retirement Benefits for additional
information.
Determining Fair Value When the Volume and Level of
Activity for the Asset or Liability Have Significantly
Decreased and Identifying Transactions That Are Not
Orderly
In April 2009, the FASB issued additional authoritative
guidance regarding the factors that should be considered
in estimating fair value when there has been a significant
decrease in market activity for an asset or liability. The
guidance, which applies to all fair value measurements,
does not change the objective of a fair value
measurement. The adoption of this guidance, effective for
us as of June 30, 2009, did not have a material impact on
our results of operations, financial position, or liquidity.
Recognition and Presentation of Other-Than-Temporary
Impairments
In April 2009, the FASB issued authoritative guidance
that established a new method of recognizing and
reporting other-than-temporary impairments of debt
securities. It contains additional annual and interim
disclosure requirements related to debt and equity
securities. Under the new guidance, an impairment of debt
securities is other-than-temporary if (1) the entity intends
to sell the security, (2) it is more likely than not that the
entity will be required to sell the security before recovery
of its amortized cost basis, or (3) the entity does not
expect to recover the security’s entire amortized cost
basis. The adoption of this guidance, effective for us as of
June 30, 2009, did not have a material impact on our
results of operations, financial position, or liquidity.
Subsequent Events
In May 2009, the FASB issued authoritative guidance
that established general standards of accounting for, and
disclosure of, events that occur after the balance sheet
date
110
but before financial statements are issued or are available
to be issued. The adoption of this guidance, effective for
us as of June 30, 2009, did not have a material impact on
our results of operations, financial position, or liquidity. In
February 2010, the FASB issued amended guidance
which was effective upon issuance. The adoption of the
amended guidance did not have a material impact on our
results of operations, financial position, or liquidity.
The FASB Accounting Standards Codification and the
Hierarchy of Generally Accepted Accounting Principles
In June 2009, the FASB issued the FASB Accounting
Standards Codification (the “Codification”), which is the
primary source of authoritative GAAP to be applied by
nongovernmental entities. Rules and interpretive releases
of the SEC under authority of federal securities laws are
also sources of authoritative GAAP for SEC registrants.
The Codification modifies the hierarchy of GAAP to
include only two levels: authoritative and nonauthoritative.
The Codification supersedes all non-SEC accounting and
reporting standards. The adoption of the Codification,
effective for us as of July 1, 2009, did not affect our results
of operations, financial position, or liquidity.
Variable-Interest Entities
In June 2009, the FASB issued amended authoritative
guidance that significantly changes the consolidation rules
for VIEs. The guidance requires an enterprise to
qualitatively assess the determination of the primary
beneficiary of a VIE based on whether the entity (1) has
the power to direct matters that most significantly affect
the activities of the VIE, and (2) has the obligation to
absorb losses or the right to receive benefits of the VIE
that could potentially be significant to the VIE. Further, the
guidance requires an ongoing reconsideration of the
primary beneficiary. It also amends the events that trigger
a reassessment of whether an entity is a VIE. The
adoption of this guidance, effective for us as of January 1,
2010, did not have a material impact on our results of
operations, financial position, or liquidity.
Disclosures about Fair Value Measurements
In January 2010, the FASB issued amended
authoritative guidance regarding fair value measurements.
This guidance requires disclosures regarding significant
transfers into and out of Level 1 and Level 2 fair value
measurements. It also requires information on purchases,
sales, issuances, and settlements on a gross basis in the
reconciliation of Level 3 fair value measurements. Further,
the FASB clarified guidance regarding the level of
disaggregation, inputs, and valuation techniques. This
guidance was effective for us in the first quarter of 2010,
with the exception of guidance applicable to detailed Level
3 reconciliation disclosures, which will be effective for us
in the first quarter of 2011. The adoption of this guidance
will not have a material impact on our results of
operations, financial position, or liquidity because it
provides enhanced disclosure requirements only.
Asset Retirement Obligations
Authoritative accounting guidance requires us to
record the estimated fair value of legal obligations
associated with the retirement of tangible long-lived assets
in the period in which the liabilities are incurred and to
capitalize a corresponding amount as part of the book
value of the related long-lived asset. In subsequent
periods, we are required to make adjustments to AROs
based on changes in the estimated fair values of the
obligations. Corresponding increases in asset book values
are depreciated over the remaining useful life of the
related asset. Uncertainties as to the probability, timing, or
amount of cash flows associated with AROs affect our
estimates of fair value. Ameren, UE, Genco and CILCO
have recorded AROs for retirement costs associated with
UE’s Callaway nuclear plant decommissioning costs,
asbestos removal, ash ponds, and river structures. In
addition, Ameren, UE, CIPS, and IP have recorded AROs
for the disposal of certain transformers.
Asset removal costs accrued by our rate-regulated
operations that do not constitute legal obligations are
classified as a regulatory liability. See Note 2 – Rate and
Regulatory Matters.
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2009
and 2008:
Balance at December 31, 2007 ...............................................................................
Liabilities settled ................................................................................................
Accretion in 2008(f) ............................................................................................
Change in estimates(g) .......................................................................................
Balance at December 31, 2008 ...............................................................................
Liabilities incurred..............................................................................................
Liabilities settled ................................................................................................
Accretion in 2009(f) ............................................................................................
Change in estimates(h) .......................................................................................
Balance at December 31, 2009 ...............................................................................
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
decommissioning of the Callaway nuclear plant.
111
Ameren (a)(b)(c)
$ 567
(3)
33
(186)
$ 411
(e)
$
(3)
24
2
$ 434
UE (b)
$ 476
(e)
27
(186)
$ 317
-
$
(2)
18
(2)
$ 331
CIPS (d) Genco (c)
$ 2
-
(e )
-
$ 2
-
$
-
(e )
(e )
$ 2
$ 52
(1)
3
(e)
$ 54
-
$
(e)
4
(e)
$ 58
CILCO
$ 28
(2)
2
(e)
$ 28
$ (e)
(e)
2
4
$ 34
IP (d)
$ 2
(e )
(e )
-
$ 2
$ -
-
(e )
(e )
$ 2
(a)
(b) The nuclear decommissioning trust fund assets of $293 million and $239 million as of December 31, 2009 and 2008, respectively, were restricted for
(c) Balance included $5 million in Other Current Liabilities on the balance sheet.
(d) Balance included in Other Deferred Credits and Liabilities on the balance sheet.
(e) Less than $1 million.
(f) All accretion expense was recorded as an increase to regulatory assets, except for Genco and CILCO (AERG).
(g) UE changed estimates related to its Callaway nuclear plant decommissioning costs based on a cost study performed in 2008, a change in assumptions
related to plant life, and a decline in the cost escalation factor assumptions.
(h) UE and CILCO changed estimates for asbestos removal. Additionally, CILCO changed related estimates to retirement costs for its ash ponds.
Variable-Interest Entities
According to authoritative accounting guidance
regarding variable-interest entities (VIEs), an entity is
considered a VIE if it does not have sufficient equity to
finance its activities without assistance from variable-
interest holders, or if its equity investors lack any of the
following characteristics of a controlling financial interest:
control through voting rights, the obligation to absorb
expected losses, or the right to receive expected residual
returns. Ameren and its subsidiaries review their equity
interests, debt obligations, leases, contracts, and other
agreements to determine their relationship to a VIE. We
have determined that the following significant VIEs were
held by the Ameren Companies at December 31, 2009:
Affordable housing partnership investments. At
December 31, 2009 and 2008, Ameren had investments in
multiple affordable housing and low-income real estate
development partnerships as well as an investment in a
commercial real estate development partnership of
$64 million and $82 million in the aggregate, respectively.
For these variable-interests, Ameren is a limited partner. It
owns less than a 50 percent interest and receives the
benefits and accepts the risks consistent with its limited
partner interest. We have concluded that Ameren is not
the primary beneficiary of any of the VIEs related to these
investments because Ameren would not absorb a majority
of the entity’s losses. These investments are classified as
Other Assets on Ameren’s consolidated balance sheet.
The maximum exposure to loss as a result of these
variable interests is limited to the investments in these
arrangements.
Coal Contract Settlement
In June 2008, Genco entered into a settlement
agreement with a coal mine owner. The owner provided
Genco with a lump-sum payment of $60 million in July
2008 because of the coal supplier’s premature closing of a
mine and the early termination of a coal supply contract.
The settlement agreement compensated Genco, in total,
for higher fuel costs it incurred in 2008 ($33 million) and in
2009 ($27 million) as a result of the mine closure and
contract termination.
Employee Separation and Other Charges
In the third quarter of 2009, Ameren initiated a
voluntary separation program that provided eligible
management employees the opportunity to voluntarily
terminate their employment and receive benefits
consistent with Ameren’s standard management
severance program. This program was offered to eligible
management employees at Ameren’s subsidiaries,
including UE, CIPS, Genco, CILCO and IP. Additionally, in
November 2009, Ameren initiated an involuntary
separation program to reduce additional management
positions under terms and benefits consistent with
Ameren’s standard management severance
program. Ameren recorded a pretax charge to earnings of
$17 million in 2009 (UE – $8 million, CIPS – $1 million,
Genco – $5 million, CILCO – $2 million, and IP – $1
million) for the severance costs related to both the
voluntary and involuntary separation programs as well as
for Merchant Generation staff reductions announced in the
third quarter of 2009. These charges were recorded in
other operations and maintenance expense in the
applicable statements of income. Substantially all of this
amount was paid prior to December 31, 2009. The
number of positions eliminated as a result of these
separation programs, including the Merchant Generation
staff reductions, was approximately 300. In addition to
these programs, Genco recorded a $4 million pretax
charge to earnings in 2009 in connection with the
retirement of two generating units at its Meredosia power
plant and for related obsolete inventory.
NOTE 2 – RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory
proceedings and related lawsuits. We are unable to
predict the ultimate outcome of these matters, the timing
of the final decisions of the various agencies and courts,
or the impact on our results of operations, financial
position, or liquidity.
Missouri
2009 Electric Rate Order
In January 2009, the MoPSC issued an order
approving an increase for UE in annual revenues of
approximately $162 million for electric service and the
implementation of a FAC and a vegetation management
and infrastructure inspection cost tracking mechanism,
among other things. The rate changes necessary to
implement the provisions of the MoPSC order were
effective March 1, 2009. In February 2009, Noranda, UE’s
largest electric customer, and the Missouri Office of Public
Counsel appealed certain aspects of the MoPSC decision
to the Circuit Court of Pemiscot County, Missouri, the
Circuit Court of Stoddard County, Missouri, and the Circuit
Court of Cole County, Missouri. In September 2009, the
Circuit Court of Pemiscot County granted Noranda’s
request to stay the electric rate increase granted by the
January 2009 MoPSC order as it applies specifically to
Noranda’s electric service account until the court renders
its decision on the appeal. The merits of the appeal
continue to be briefed by the parties. A decision is likely to
be issued by the Circuit
112
Court of Pemiscot County in the second quarter of 2010.
During the stay, Noranda will pay into the court registry
the contested portion of its monthly billings, approximately
$0.5 million per month based on current usage levels. If
UE wins the appeal, it will receive those monthly
payments plus interest.
Pending Electric Rate Case
UE filed a request with the MoPSC in July 2009 to
increase its annual revenues for electric service by
$402 million. Included in this increase request was
approximately $227 million of anticipated increases in
normalized net fuel costs in excess of the net fuel costs
included in base rates previously authorized by the
MoPSC in its January 2009 electric rate order, which,
absent initiation of this general rate proceeding, would
have been eligible for recovery through UE’s existing FAC.
The balance of the increase request is based primarily on
investments made to continue systemwide reliability
improvements for customers, increases in costs essential
to generating and delivering electricity, and higher
financing costs. The initial electric rate increase request
was based on an 11.5% return on equity, a capital
structure composed of 47.4% equity, a rate base for UE of
$6.0 billion, and a test year ended March 31, 2009, with
certain pro-forma adjustments through the anticipated
true-up date of January 31, 2010. In February 2010, UE
filed rebuttal testimony relating to certain positions taken
by interveners in the rate case and modified its
recommended return on equity to 10.8%.
UE’s initial filing included a request for interim rate
relief, which would have placed into effect approximately
$37 million of the requested increase prior to completion
of the full rate case. In January 2010, the MoPSC denied
UE’s request for interim rate relief.
As part of its filing, UE also requested that the MoPSC
approve the implementation of an environmental cost
recovery mechanism and a storm restoration cost tracker.
The environmental cost recovery mechanism, if approved,
would allow UE to adjust electric rates twice each year
outside of general rate proceedings to reflect changes in
its prudently incurred costs to comply with federal, state,
or local environmental laws, regulations, or rules greater
than or less than the amount set in base rates. Rate
adjustments pursuant to this cost recovery mechanism
would not be permitted to exceed an annual amount equal
to 2.5% of UE’s gross jurisdictional electric revenues and
would be subject to prudency reviews by the MoPSC.
UE’s request was consistent with the environmental cost
recovery rules approved by the MoPSC in April 2009. The
storm restoration cost tracker would permit UE a more
timely recovery of storm restoration operations and
maintenance expenditures.
In addition, UE requested that the MoPSC approve
the continued use of the FAC and the vegetation
management and infrastructure inspection cost tracking
mechanism that the MoPSC previously authorized in its
January 2009 electric rate order, and the continued use of
the regulatory tracking mechanism for pension and
postretirement benefit costs that the MoPSC previously
authorized in its May 2007 electric rate order. The UE
request included the discontinuation of the SO2 emission
allowance sales tracker.
UE’s filing with the MoPSC also seeks approval to
revise the tariff under which it serves Noranda to
prospectively address the significant lost revenues UE can
incur due to any future operational issues at Noranda’s
smelter plant in southeastern Missouri, such as the
revenue losses resulting from the January 2009 storm-
related power outage.
The MoPSC staff has responded to the UE request for
an electric service rate increase. The MoPSC staff has
recommended an increase to UE’s annual revenues of
between $218 million to $251 million based on a return on
equity range of 9.0% to 9.7%. Included in this
recommendation was approximately $214 million of
increases in normalized net fuel costs. Other parties also
made recommendations through testimony filed in this
case. MoPSC staff and other parties have expressed
opposition to some of the requested cost recovery
mechanisms as well as the proposed Noranda tariff
revision.
The MoPSC proceeding relating to the proposed
electric service rate changes will take place over a period
of up to 11 months, and a decision by the MoPSC in such
proceeding is required by the end of June 2010. Hearings
are scheduled in March 2010. UE cannot predict the level
of any electric service rate change the MoPSC may
approve, when any rate change may go into effect,
whether the cost recovery mechanisms and trackers
requested will be approved or continued, or whether any
rate change that may eventually be approved will be
sufficient to enable UE to recover its costs and earn a
reasonable return on its investments when the rate
change goes into effect.
Renewable Energy Portfolio Requirement
A ballot initiative passed by Missouri voters in
November 2008 created a renewable energy portfolio
requirement. UE and other Missouri investor-owned
utilities will be required to purchase or generate electricity
from renewable energy sources equaling at least 2% of
native load sales by 2011, with that percentage increasing
in subsequent years to at least 15% by 2021, subject to a
1% limit on customer rate impacts. At least 2% of each
portfolio requirement must be derived from solar energy.
Compliance with the renewable energy portfolio
requirement can be achieved through the procurement of
renewable energy or renewable energy credits. Rules
implementing the renewable energy portfolio requirement
are expected to be issued by the MoPSC in 2010. UE
expects that any related costs or investments would
ultimately be recovered in rates. In January 2010, UE
issued an RFP to solicit solar renewable energy credits
and energy in 2011 to meet the solar portion of this
requirement. UE is currently evaluating the responses.
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Missouri Energy Efficiency Investment Act
In July 2009, the Missouri governor signed a law that
went into effect in August 2009, which, among other things,
allows electric utilities to recover costs related to MoPSC-
approved energy efficiency programs. Recovery is permitted
only if the program is approved by the MoPSC, results in
energy savings, and is beneficial to all customers in the class
for which the program is proposed. The new law could
potentially, among other things, allow UE to earn a return on
its energy efficiency programs equivalent to the return UE
could earn with supply-side capital investments, such as new
power plants.
Illinois
2008 Electric and Natural Gas Delivery Service Rate Order
On September 24, 2008, the ICC issued a consolidated
order approving a net increase in annual revenues for electric
delivery service of $123 million in the aggregate (CIPS – $22
million increase, CILCO – $3 million decrease, and IP – $104
million increase) and a net increase in annual revenues for
natural gas delivery service of $38 million in the aggregate
(CIPS – $7 million increase, CILCO – $9 million decrease,
and IP – $40 million increase), based on a 10.65% return on
equity with respect to electric delivery service and a 10.68%
return on equity with respect to natural gas delivery service.
These rate changes were effective on October 1, 2008.
In October 2008, CIPS, CILCO and IP and other parties
requested that the ICC rehear certain aspects of its
September 2008 consolidated order. In November 2008, the
ICC denied all rate order rehearing requests filed by the
Ameren Illinois Utilities and other parties. In December 2008,
the Illinois attorney general appealed the rate order to the
Appellate Court of Illinois, Fourth District, specifically, the
ICC’s affirmation of the recovery of a certain amount of fixed
costs in the customer charge. In December 2009, the
Appellate Court denied the Illinois attorney general’s appeal
and sustained the ICC rate order.
Pending Electric and Natural Gas Delivery Service Rate
Cases
In June 2009, CIPS, CILCO and IP filed requests with
the ICC to increase their annual revenues for electric delivery
service. The currently pending requests, as amended, seek
to increase annual revenues from electric delivery service by
$115 million in the aggregate (CIPS – $38 million, CILCO –
$17 million, and IP – $60 million). Additionally, the Ameren
Illinois Utilities requested moving more of the electric delivery
costs into the monthly non-volumetric charge, similar to the
natural gas delivery rate design change approved by the ICC
in 2008. The electric rate increase requests were based on
an 11.3% to 11.7% return on equity, a capital structure
composed of 44% to 49% equity, an aggregate rate base for
the Ameren Illinois Utilities of $2.3 billion, and a test year
ended December 31, 2008, with certain known and
measurable adjustments through May 2010.
CIPS, CILCO and IP also filed requests with the ICC in
June 2009 to increase their annual revenues for natural gas
delivery service. The currently pending requests, as
amended, seek to increase annual revenues for natural gas
delivery service by $15 million in the aggregate (CIPS –
$6 million, CILCO – $2 million, and IP – $7 million). The
natural gas rate increase requests were based on a 10.8% to
11.2% return on equity, a capital structure composed of 44%
to 49% equity, an aggregate rate base for the Ameren Illinois
Utilities of $1.0 billion, and a test year ended December 31,
2008, with certain known and measurable adjustments
through May 2010.
The ICC staff has responded to the filed requests by the
Ameren Illinois Utilities. The ICC staff has recommended, as
amended, a net increase in revenues for electric delivery
service for the Ameren Illinois Utilities of $57 million in the
aggregate (CIPS – $21 million increase, CILCO – $5 million
increase, and IP – $31 million increase) and a net decrease
in revenues for natural gas delivery service of $11 million in
the aggregate (CILCO – $6 million decrease and IP – $5
million decrease). The ICC staff position was based on a
10.1% to 10.4% return on equity for electric delivery service
and a 9.4% to 9.6% return on equity for natural gas delivery
service. Other parties also made recommendations through
testimony filed in the electric and natural gas delivery service
rate cases.
In February 2010, administrative law judges issued a
consolidated proposed order, which included a
recommended revenue increase for electric delivery service
for the Ameren Illinois Utilities of $66 million in the aggregate
(CIPS – $26 million increase, CILCO – $6 million increase,
and IP – $34 million increase) and a recommended revenue
net decrease for natural gas delivery service of $10 million in
the aggregate (CIPS – $1 million increase, CILCO – $ 6
million decrease, and IP – $5 million decrease). The ICC is
not bound by the proposed order issued by the administrative
law judges.
The ICC proceedings relating to the proposed electric
and natural gas delivery service rate changes will take place
over a period of up to 11 months, and decisions by the ICC in
such proceedings are required by May 2010. The Ameren
Illinois Utilities cannot predict the level of any delivery service
rate changes the ICC may approve, when any rate changes
may go into effect, or whether any rate changes that may
eventually be approved will be sufficient to enable the
Ameren Illinois Utilities to recover their costs and earn a
reasonable return on their investments when the rate
changes go into effect.
2007 Illinois Electric Settlement Agreement
In 2007, key stakeholders in Illinois agreed to avoid rate
rollback and freeze legislation that would impose a tax on
electric generation. These stakeholders wanted to address
the increase in electric rates and the future power
procurement process in Illinois. The terms of the agreement
included a comprehensive rate relief and customer
assistance program. The 2007 Illinois Electric Settlement
Agreement provided approximately $1 billion of funding
114
from 2007 to 2010 for rate relief for certain electric customers
in Illinois, including approximately $488 million for customers
of the Ameren Illinois Utilities. Pursuant to the 2007 Illinois
Electric Settlement Agreement, the Ameren Illinois Utilities,
Genco, and CILCO (AERG) agreed to make aggregate
contributions of $150 million over the four-year period, with
$60 million coming from the Ameren Illinois Utilities (CIPS –
$21 million; CILCO – $11 million; IP – $28 million), $62
million from Genco, and $28 million from CILCO (AERG).
See Note 15 –Commitments and Contingencies for
information on the remaining contributions to be made as of
December 31, 2009.
The Ameren Illinois Utilities, Genco, and CILCO (AERG)
recognize in their financial statements the costs of their
respective rate relief contributions and program funding
under the 2007 Illinois Electric Settlement Agreement in a
manner corresponding with the timing of the funding. As a
result, Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco,
and CILCO (AERG) incurred charges to earnings, primarily
recorded as a reduction to electric operating revenues, during
the year ended December 31, 2009, of $25 million, $3 million,
$2 million, $5 million, $10 million, and $5 million, respectively
(year ended December 31, 2008 – $42 million, $6 million, $3
million, $8 million, $17 million, and $8 million, respectively)
under the terms of the 2007 Illinois Electric Settlement
Agreement.
Other electric generators and utilities in Illinois agreed to
contribute $851 million to the comprehensive rate relief and
customer assistance program. Contributions by the other
electric generators (the generators) and utilities to the
comprehensive program are subject to funding agreements.
Under these agreements, at the end of each month, the
Ameren Illinois Utilities send a bill, due in 30 days, to the
generators and utilities for their proportionate share of that
month’s rate relief and assistance. If any escrow funds have
been provided by the generators, these funds will be drawn
upon before reimbursement is sought from the generators. At
December 31, 2009, Ameren, CIPS, CILCO (Illinois
Regulated) and IP had receivable balances from nonaffiliated
Illinois generators for reimbursement of customer rate relief
and program funding of $10 million, $3 million, $2 million, and
$5 million, respectively. See Note 14 – Related Party
Transactions for information on the impact of intercompany
settlements.
The 2007 Illinois Electric Settlement Agreement provided
that if before August 1, 2011, legislation is enacted in Illinois
freezing or reducing retail electric rates, or imposing or
authorizing a new tax, special assessment, or fee on the
generation of electricity, then the remaining commitments
under the 2007 Illinois Electric Settlement Agreement would
expire, and any funds set aside in support of the
commitments would be refunded to the utilities and
Generators.
Power Procurement
As part of the 2007 Illinois Electric Settlement
Agreement, the reverse auction used for power procurement
in Illinois was discontinued. However, one-third of the existing
supply contracts from the September 2006 reverse power
procurement auction remain in place through May 2010. A
new competitive power procurement process led by the IPA,
which was established as a part of the 2007 Illinois Electric
Settlement Agreement, was implemented beginning in
January 2009. In January 2009, the ICC approved the
electric power procurement plan filed by the IPA for both the
Ameren Illinois Utilities and Commonwealth Edison
Company. The plan outlined the wholesale products that the
IPA procured on behalf of the Ameren Illinois Utilities for the
period June 1, 2009, through May 31, 2014. The IPA
procured capacity, energy swaps, and renewable energy
credits through an RFP process on behalf of the Ameren
Illinois Utilities in the second quarter of 2009. See Note 14 –
Related Party Transactions and Note 15 – Commitments and
Contingencies for additional information about the Ameren
Illinois Utilities’ purchased power agreements.
In December 2009, the ICC approved a plan for
procurement of electric power for the Ameren Illinois Utilities
and Commonwealth Edison Company for the period June 1,
2010, through May 31, 2015. The IPA will procure energy
swaps, capacity and renewable energy credits and long-term
renewable supply. The exact dates of each procurement
event have not been determined. Following successful
completion of the proposed 2010 procurement events, the
Ameren Illinois Utilities will have sufficient capacity and
energy hedges in place for 100% of their expected supply
obligation for the period June 2010 through May 2011, 70%
of their expected supply obligation for the period June 2011
through May 2012, and 44% of their expected supply
obligations for the period June 2012 through May 2013. The
Ameren Illinois Utilities will also have sufficient renewable
energy credits to satisfy the 2010 planning year requirement
along with 20-year renewable supply contracts consisting of
600,000 megawatthours per year of renewable energy power
and credits with deliveries beginning June 1, 2012.
Also as part of the 2007 Illinois Electric Settlement
Agreement, the Ameren Illinois Utilities entered into financial
contracts with Marketing Company (for the benefit of Genco
and AERG), to lock in energy prices for 400 to 1,000
megawatts annually of their round-the-clock power
requirements during the period June 1, 2008, to
December 31, 2012, at relevant market prices. See Note 7 –
Derivative Financial Instruments and Note 14 – Related Party
Transactions for additional information on these financial
contracts.
ICC Reliability Audit
In August 2007, the ICC retained Liberty Consulting
Group to investigate, analyze, and report to the ICC on the
Ameren Illinois Utilities’ transmission and distribution systems
and reliability following the July 2006 wind storms and a
November 2006 ice storm. In October 2008, Liberty
Consulting Group presented the ICC with a final report
containing recommendations for the Ameren Illinois Utilities
to improve their systems and their response to emergencies.
The ICC directed the Ameren Illinois Utilities to present to the
ICC a plan to implement Liberty Consulting Group’s
115
recommendations. The plan was submitted to the ICC in
November 2008. Liberty Consulting Group will monitor the
Ameren Illinois Utilities’ efforts to implement the
recommendations and any initiatives that the Ameren Illinois
Utilities undertake. The Ameren Illinois Utilities expect they
could incur an estimated $20 million ($15 million for
distribution and $5 million for transmission) of capital costs
and an estimated $66 million ($50 million for distribution and
$16 million for transmission) of cumulative operations and
maintenance expenses for the 2010 through 2013 time frame
in order to implement the recommendations.
In December 2009, the Ameren Illinois Utilities requested
ICC approval of a rider mechanism to recover the
distribution-related costs associated with the Liberty
Consulting Group’s recommendations. This request replaced
a previous request for a rider mechanism, which had been
part of the pending electric delivery rate cases. There is no
statutory date by which the ICC must act, and no schedule is
currently in place for this request.
The Ameren Illinois Utilities have committed to
implement various audit recommendations, as outlined in
their November 2008 plan. However, in order to fulfill that
commitment in a timely manner, they must be able to
synchronize the timing of their distribution-implementation
expenditures with the recognition of those costs in rates.
Without the necessary funding or a rider mechanism to
recover the distribution costs, the Ameren Illinois Utilities may
defer some of the projects until the distribution costs can be
recovered either in base rates or through some other cost
recovery mechanism.
Transmission-related costs, as incurred, will be
recoverable through FERC’s ratemaking proceedings.
Illinois 2009 Energy Legislation
In July 2009, a new law became effective in Illinois that,
among other things, established new energy efficiency
targets for Illinois natural gas utilities, developed a
percentage of income payment plan for low-income utility
customers, and allowed electric and natural gas utilities to
recover through a rate adjustment the difference between
their actual bad debt expense and the bad debt expense
included in their base rates. In February 2010, the ICC
approved the Ameren Illinois Utilities’ electric and natural gas
rate adjustment tariffs to recover bad debt expense not
recovered in base rates. The tariffs provide utilities the ability
to adjust their base rates annually through a rate adjustment
mechanism that applies to 2008 and subsequent years. Upon
ICC approval of the rate adjustment tariffs in February 2010,
the Ameren Illinois Utilities made a one-time $10 million
donation (CIPS – $2 million, CILCO – $2 million, and IP – $6
million) for customer assistance programs, as required by the
legislation. The amount of the required one-time donation
and the impact of the net recovery of 2008 and 2009 bad
debt expenses were reflected in 2009 earnings.
Federal
Regional Transmission Organization
UE, CIPS, CILCO and IP are transmission-owning
members of MISO, which is a FERC-regulated RTO that
provides transmission tariff administration services for electric
transmission systems. In early 2004, UE received
authorization from the MoPSC to participate in MISO for a
five-year period, with further participation subject to approval
by the MoPSC. The MoPSC required UE to file a study
evaluating the costs and benefits of its participation in MISO
prior to the end of the five-year period. The MoPSC also
directed UE to enter into a service agreement with MISO to
provide transmission service to UE’s bundled retail
customers. The service agreement’s primary function was to
ensure that the MoPSC continued to set the transmission
component of UE’s rates to serve its bundled retail
load. Among other things, the service agreement provided
that UE would not pay MISO for transmission service to UE’s
bundled retail customers. FERC approved the service
agreement in the form that was acceptable to the MoPSC.
Due to changes to MISO’s allocation of transmission
revenues to transmission owners, UE believed it should have
received incremental annual transmission revenues of $60
million as of February 2008 in accordance with its service
agreement with MISO. Numerous transmission owners in
MISO, along with MISO itself as the tariff administrator,
filed with FERC in December 2007 requesting changes to the
MISO tariff to prevent UE from collecting these additional
transmission revenues. In December 2007, UE filed a protest
to these proposed MISO tariff changes, calling them
unauthorized and improper in light of the MoPSC’s
requirement for the service agreement between UE and
MISO discussed above. In February 2008, FERC issued an
order accepting the tariff changes proposed by MISO and by
certain transmission owners in MISO. In March 2008, UE
filed a request with FERC for a rehearing of its order. In April
2008, FERC suspended UE’s request for rehearing to allow
time for further consideration by FERC. UE is unable to
predict if or when FERC may issue a further order in this
proceeding.
As required by the MoPSC, UE filed a study in November
2007 with the MoPSC evaluating the costs and benefits of
UE’s participation in MISO. UE’s filing noted a number of
uncertainties associated with the cost-benefit study, including
issues associated with the UE-MISO service agreement and
MISO revenue allocation, as discussed above. In June 2008,
a stipulation and agreement among UE, the MoPSC staff,
MISO and other parties to the proceeding was filed with the
MoPSC, which provided for UE’s continued, conditional
MISO participation through April 30, 2012. The stipulation
and agreement gives UE the right to seek permission from
the MoPSC for early withdrawal from MISO if UE determines
that sufficient progress toward mitigating some of the
continuing uncertainties respecting its MISO participation is
not being made. The MoPSC issued an order, effective
September 19, 2008, approving the stipulation and
agreement. If UE were to withdraw from MISO in the future, it
might need to
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obtain FERC approval and to meet conditions imposed by
FERC, in addition to obtaining MoPSC’s approval.
Seams Elimination Cost Adjustment
Pursuant to a series of FERC orders, FERC put Seams
Elimination Cost Adjustment (SECA) charges into effect on
December 1, 2004, subject to refund and hearing
procedures. The SECA charges were a transition mechanism
in place for 16 months, from December 1, 2004, to March 31,
2006, to compensate transmission owners in MISO and PJM
for revenues lost when FERC eliminated the regional
through-and-out rates previously applicable to transactions
crossing the border between MISO and PJM. The SECA
charge was a nonbypassable surcharge payable by load-
serving entities in proportion to the benefit they realized from
the elimination of the regional through-and-out rates as of
December 1, 2004. The MISO transmission owners
(including UE, CIPS, CILCO and IP) and the PJM
transmission owners filed their proposed SECA charges in
November 2004, as compliance filings pursuant to FERC
order. A FERC administrative law judge issued an initial
decision in August 2006, recommending that FERC reject
both of the SECA compliance filings (the filing for SECA
charges made by the transmission owners in the MISO and
the filing for SECA charges made by the transmission owners
in PJM). Several parties filed rehearing requests of this initial
decision. There is no date scheduled for FERC to act on the
initial decision. Both before and after the initial decision,
various parties (including UE, CIPS, CILCO and IP as part of
the group of MISO transmission owners) filed numerous
bilateral or multiparty settlements. To date, FERC has
approved many of the settlements and has rejected none of
the settlements. Neither the MISO transmission owners,
including UE, CIPS, CILCO and IP, nor the PJM transmission
owners have been able to settle with all parties. During the
transition period of December 1, 2004, to March 31, 2006,
Ameren, UE, CIPS, and IP received net revenues from the
SECA charges of $10 million, $3 million, $1 million, and $6
million, respectively. CILCO’s net SECA charges were less
than $1 million. In December 2009, a party that has not
settled its SECA charges filed with the U.S. Court of Appeals
for the District of Columbia Circuit seeking an order directing
the FERC to resolve the SECA matters. In response to this
filing, in January 2010, FERC agreed to issue an order on the
SECA initial decision and rehearing requests by the end of
May 2010. While we cannot predict the ultimate outcome of
the SECA proceedings, we do not believe the outcome of the
proceedings will have a material effect on UE’s, CIPS’,
CILCO’s and IP’s costs and revenues.
FERC Order – MISO Charges
In May 2007, UE, CIPS, CILCO and IP filed with the U.S.
Court of Appeals for the District of Columbia Circuit an
appeal of FERC’s March 2007 order involving the reallocation
of certain MISO operational costs among MISO participants
retroactive to 2005. In August 2007, the court granted
FERC’s motion to hold the appeal in abeyance until the end
of the continuing proceedings at FERC regarding these
costs. Other MISO participants also filed appeals. On
August 10, 2007, UE, CIPS, CILCO, and IP filed a complaint
with FERC regarding the MISO tariff’s allocation methodology
for these same MISO operational charges. In November
2007, FERC issued two orders relative to these allocation
matters. One of these orders addressed requests for
rehearing of prior orders in the proceedings, and one
concerned MISO’s compliance with FERC’s orders to date in
the proceedings. In December 2007, UE, CIPS, CILCO and
IP requested FERC’s clarification or rehearing of its
November 2007 order regarding MISO’s compliance with
FERC’s orders. UE, CIPS, CILCO and IP maintained that
MISO was required to reallocate certain of MISO’s
operational costs among MISO market participants, which
would result in refunds to UE, CIPS, CILCO and IP
retroactive to April 2006. On November 7, 2008, FERC
issued an order granting the request for clarification. FERC
directed MISO to reallocate certain MISO operational costs
among MISO participants and provide refunds for the period
April 2006 to August 2007 (“November 7, 2008 Clarification
Order”). On November 10, 2008, FERC granted further relief
requested in the complaints filed by UE, CIPS, CILCO, IP
and others regarding further reallocation for these MISO
operational charges and directed MISO to calculate refunds
for the period from August 10, 2007, forward (“November 10,
2008 Complaint Order”).
Several parties to these proceedings protested MISO’s
proposed implementation of these refunds, requested
rehearing of FERC’s orders and, in some cases, appealed
FERC’s orders to the courts. In March 2009, MISO began
resettling its markets to provide refunds as FERC directed
retroactive from August 10, 2007. In May 2009, FERC issued
an order that upheld most of the conclusions of the
November 10, 2008 Complaint Order but changed the
effective date for refunds such that certain operational costs
will be allocated among MISO market participants beginning
November 10, 2008, instead of August 10, 2007. In June
2009, UE, CIPS, CILCO and IP filed for rehearing of the May
2009 order regarding the change to the refund effective date.
This rehearing request is pending.
With respect to the November 7, 2008 Clarification
Order, in June 2009 FERC issued an order dismissing
rehearing requests of such clarification order and waiving
refunds of amounts billed that were included in the MISO
charge, under the assumption that there was a rate mismatch
for the period April 25, 2006, through November 4, 2007. UE,
CIPS, CILCO and IP filed a request for rehearing in July
2009. This rehearing request is pending.
With respect to the two rehearing requests discussed
above, UE, CIPS, CILCO and IP do not believe that the
ultimate resolution of either request will have a material effect
on their results of operations, financial position, or liquidity.
MISO and PJM Dispute Resolution
During 2009, MISO and PJM discovered an error in the
calculation quantifying certain transactions between the
117
RTOs. The error, which originated in April 2005, at the
initiation of the MISO Energy and Operating Reserves Market
was corrected prospectively in June 2009. Since discovering
the error, MISO and PJM have worked jointly to estimate its
financial impact on the respective markets. MISO and PJM
are in agreement about the methodology used to recalculate
the market flows occurring from June 2007 to June 2009 for
the resettlement due from PJM to MISO estimated at $65
million. MISO and PJM are not in agreement about the
methodology used to recalculate the market flows occurring
from April 2005 to May 2007, nor are they in agreement
about the resettlement amount. To resolve this issue, MISO
and PJM have agreed to participate in FERC’s dispute
resolution and settlement process in order to determine a
resettlement amount for the entire period from April 2005 to
June 2009. In October 2009, an administrative law judge was
appointed as mediator, and multiple settlement conferences
were held at FERC in late 2009 and early 2010. A final
settlement between MISO and PJM, if and when reached, will
probably require filings to be made by PJM and MISO with
FERC. Ameren and its subsidiaries may receive a to-be-
determined portion of the resettlement amount due from PJM
to MISO. No prospective refund has been recorded related to
this matter. Until a settlement has been reached and
approved by FERC, we cannot predict the ultimate impact of
these proceedings on Ameren’s, UE’s, CIPS’, Genco’s,
CILCORP’s, CILCO’s and IP’s results of operations, financial
position, or liquidity.
UE Power Purchase Agreement with Entergy Arkansas, Inc.
In July 2007, FERC issued a series of orders addressing
a complaint filed by the Louisiana Public Service Commission
(LPSC) against Entergy Arkansas, Inc. (Entergy) and certain
of its affiliates. The complaint alleged unjust and
unreasonable cost allocations. As a result of the FERC
orders, Entergy began billing UE for additional charges under
a 165-megawatt power purchase agreement, and UE paid
these charges. Additional charges continued during the
remainder of the term of the power purchase agreement,
which expired on August 31, 2009. Although UE was not a
party to the FERC proceedings that gave rise to these
additional charges, UE has intervened in related FERC
proceedings. UE also filed a complaint with FERC against
Entergy and Entergy Services, Inc. in April 2008 to challenge
the additional charges. In September 2008, the presiding
FERC administrative law judge issued an initial decision
finding that Entergy’s allocation of such additional charges to
UE was just and reasonable. In January 2010, FERC issued
an opinion reversing the administrative law judge’s initial
decision and ruling that Entergy may not pass additional
charges to UE. In February 2010, Entergy filed a request for
rehearing of the January 2010 opinion. UE has recorded the
additional charges related to the July 2007 order, but has not
recorded any prospective refund. UE is unable to predict how
or when the FERC will rule on the motions. Therefore, UE is
unable to predict whether FERC ultimately will order Entergy
to refund to UE the additional charges.
Additionally, LPSC appealed FERC’s orders regarding
LPSC’s complaint against Entergy Services, Inc. to the U.S.
Court of Appeals for the District of Columbia. In April 2008,
that court ordered further FERC proceedings regarding the
LPSC complaint. The court ordered FERC to explain its
previous denial of retroactive refunds and the implementation
of prospective charges. FERC’s decision on remand of the
retroactive impact of these issues could have a financial
impact on UE. UE is unable to predict how FERC will
respond to the court’s decisions. UE estimates that it could
incur an additional expense of up to $25 million if FERC
orders retroactive application for the years 2001 to 2005,
although FERC’s ruling in January 2010, discussed above,
assuming it is upheld after any rehearings or appeals, likely
will prevent FERC from ordering UE to pay any amounts
retroactively. Based on existing facts and circumstances, UE
believes that the likelihood of incurring this $25 million
expense is not probable. Thus no liability has been recorded
as of December 31, 2009. UE plans to participate in any
proceeding that FERC initiates to address the court’s
decisions.
Nuclear Combined Construction and Operating License
Application
In July 2008, UE filed an application with the NRC for a
combined construction and operating license for a new
1,600-megawatt nuclear unit at UE’s existing Callaway
County, Missouri, nuclear plant site. UE also signed contracts
for COLA-related services and certain long lead-time nuclear-
unit related equipment (heavy forgings).
In early 2009, the Missouri Clean and Renewable Energy
Construction Act was separately introduced in both the
Missouri Senate and House of Representatives. One purpose
of these bills was to allow the MoPSC to authorize utilities to
recover the costs of financing and tax payments associated
with a new generating plant while that plant is being
constructed. Recovery of actual construction costs still would
not begin until a plant goes into service. UE believes
legislation allowing timely recovery of financing costs during
construction must be enacted in order for it to build a new
nuclear unit to meet its baseload generation capacity needs.
However, passage of this or other legislation was not a
commitment or guarantee that UE would build a new nuclear
unit.
In April 2009, senior management of UE announced that
they had asked the legislative sponsors of the Missouri Clean
and Renewable Energy Construction Act to withdraw the bills
from consideration by the Missouri General Assembly. UE
believed that the legislation being considered in the Missouri
Senate in its then proposed form would not provide UE with
the financial and regulatory certainty it needed to pursue the
project. As a result, UE announced that it was suspending its
efforts to build a new nuclear unit at its existing Missouri
nuclear plant site. In June 2009, UE requested the NRC
suspend review of the COLA and all activities related to the
COLA. The contract for COLA-related services was amended
in December 2009 in several respects, including changes to
the termination provisions in
118
light of UE’s decision to suspend its efforts to build a new
nuclear unit. UE will consider all available and feasible
generation options to meet future customer requirements
as part of an integrated resource plan that UE will file with
the MoPSC in 2011.
As of December 31, 2009, UE had capitalized
approximately $69 million as construction work in progress
related to the COLA. The incurred costs will remain
capitalized while management assesses all options to
maximize the value of its investment in this project. If all
efforts are permanently abandoned or management
concludes it is probable the cost incurred will be
disallowed in rates, it is possible that a charge to earnings
could be recognized in a future period.
Prior to June 30, 2009, UE made contractual
payments to the heavy forgings manufacturer of $14
Regulatory Assets and Liabilities
million and had remaining contractual commitments of $81
million. In July 2009, when an agreement was reached
with the heavy forgings manufacturer to terminate the
heavy forgings procurement agreement, $5 million in
previous payments was retained by the manufacturer as a
penalty for terminating the contract. That amount was
charged to earnings in June 2009.
Pumped-storage Hydroelectric Facility Relicensing
In June 2008, UE filed a relicensing application with
FERC to operate its Taum Sauk pumped-storage
hydroelectric facility for another 40 years. The current
FERC license expires on June 30, 2010. Approval and
relicensure are expected in 2012. Operations are
permitted to continue under the current license while the
application for relicensing is pending.
In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of
regulation, UE, CIPS, CILCO and IP defer certain costs pursuant to actions of regulators or based on the expected ability
to recover such costs in rates charged to customers. UE, CIPS, CILCO and IP also defer certain amounts pursuant to
actions of regulators or based on the expectation that such amounts will be returned to customers in future rates. The
following table presents our regulatory assets and regulatory liabilities at December 31, 2009 and 2008:
2009:
Current regulatory assets:
Under-recovered FAC(b)(c) .....................................................................
Under-recovered Illinois electric power costs(b)(d)...................................
Under-recovered PGA(b)(d) ....................................................................
MTM derivative assets(e) .......................................................................
Total current regulatory assets(f) .................................................................
Noncurrent regulatory assets:
Pension and postretirement benefit costs(g)...........................................
Income taxes(h) .....................................................................................
Asset retirement obligation(i) .................................................................
Callaway costs(b)(j) ................................................................................
Unamortized loss on reacquired debt(b)(k) ..............................................
Recoverable costs – contaminated facilities(l) ........................................
IP integration(m) ....................................................................................
Recoverable costs – debt fair value adjustment(n) .................................
MTM derivatives assets(o) .....................................................................
SO2 emission allowances sale tracker(p) ...............................................
FERC-ordered MISO resettlements – March 2007(q) .............................
Vegetation management and infrastructure inspection(r) ........................
Storm costs(s) .......................................................................................
Demand-side costs(t) ............................................................................
Reserve for workers’ compensation liabilities(u) .....................................
Bad debt rider(v) ....................................................................................
Other(w) ................................................................................................
Total noncurrent regulatory assets .............................................................
Current regulatory liabilities:
Over-recovered FAC(x) ..........................................................................
Over-recovered Illinois electric power costs(d) .......................................
Over-recovered PGA(d) .........................................................................
MTM derivative liabilities(y) ....................................................................
Total current regulatory liabilities(z) .............................................................
Ameren (a)
UE
CIPS
CILCO
IP
$ 39
-
-
24
$ 63
$ 288
272
31
55
26
-
-
-
10
16
7
7
27
15
9
-
2
$ 765
$ 10
-
4
11
$ 25
$
$
-
2
4
53
59
$
75
5
2
-
5
47
-
-
103
-
-
-
-
-
3
7
1
$ 248
$
$
-
7
2
1
10
$
$
-
2
-
27
29
$
93
1
1
-
5
-
-
-
57
-
-
-
-
-
-
4
1
$ 162
$
$
-
17
4
2
23
$
$
-
1
-
85
86
$ 203
2
2
-
20
103
17
6
164
-
-
-
-
-
3
19
1
$ 540
$
$
-
20
3
1
24
$
39
5
4
62
$ 110
$ 659
280
36
55
56
150
17
6
49
16
7
7
27
15
15
30
5
$ 1,430
$
$
10
44
13
15
82
119
Noncurrent regulatory liabilities:
Income taxes(aa)....................................................................................
Removal costs(bb) .................................................................................
Emission allowances(cc) ........................................................................
Vegetation management and infrastructure inspection(dd) .....................
MTM derivative liabilities(ee) ..................................................................
Bad debt rider(ff) ....................................................................................
Pension and postretirement benefit costs tracker(gg) ..............................
Total noncurrent regulatory liabilities ..........................................................
2008:
Current regulatory assets:
Under-recovered Illinois electric power costs(b)(d)...................................
Under-recovered PGA(b)(d) ....................................................................
MTM derivative assets(e) .......................................................................
Total current regulatory assets(f) .................................................................
Noncurrent regulatory assets:
Pension and postretirement benefit costs(g)...........................................
Income taxes(h) .....................................................................................
Asset retirement obligation(i) .................................................................
Callaway costs(b)(j) ................................................................................
Unamortized loss on reacquired debt(b)(k) ..............................................
Recoverable costs – contaminated facilities(l) ........................................
IP integration(m) ....................................................................................
Recoverable costs – debt fair value adjustment(n) .................................
MTM derivative assets(o) .......................................................................
SO2 emission allowances sale tracker(p) ...............................................
FERC-ordered MISO resettlements - March 2007(q) ..............................
Vegetation management and infrastructure inspection(r) .......................
Storm costs(s) .......................................................................................
Demand-side costs(t) ............................................................................
Reserve for workers’ compensation liabilities(u) .....................................
Other(w) ................................................................................................
Total noncurrent regulatory assets .............................................................
Current regulatory liabilities:
Over-recovered Illinois electric power costs(d) .......................................
Over-recovered PGA(d) .........................................................................
Total current regulatory liabilities(z) .............................................................
Noncurrent regulatory liabilities:
Income taxes(aa)....................................................................................
Removal costs(bb) .................................................................................
Emission allowances(cc) ........................................................................
Pension and postretirement benefit costs tracker(gg) ..............................
MISO resettlements(hh)..........................................................................
Total noncurrent regulatory liabilities ..........................................................
Ameren (a)
UE
CIPS
CILCO
IP
160
$
1,084
35
2
14
2
41
$ 1,338
$
$
2
1
79
82
$
936
255
65
58
63
97
33
10
39
13
12
9
33
4
15
11
$ 1,653
$
$
22
42
64
180
$
1,018
47
41
5
$ 1,291
$ 141
716
35
2
12
-
41
$ 947
$
$
-
-
10
10
$ 410
248
60
58
30
-
-
-
6
13
12
9
33
4
9
5
$ 897
$
$
-
2
2
$ 154
675
47
41
5
$ 922
$
10
231
-
-
-
1
-
$ 242
$
$
1
1
30
32
$ 107
6
2
-
5
18
-
-
52
-
-
-
-
-
3
2
$ 195
$
$
6
14
20
$
14
220
-
-
-
$ 234
$
9
199
-
-
1
-
-
$ 209
$
$
-
-
24
24
$ 125
-
1
-
5
8
-
-
30
-
-
-
-
-
-
2
$ 171
$
$
$
$
10
9
19
12
194
-
-
-
206
$
$
$
$
-
86
-
-
1
1
-
88
1
-
57
58
$ 294
1
2
-
23
71
33
10
78
-
-
-
-
-
3
2
$ 517
$
$
$
$
6
17
23
-
76
-
-
-
76
Includes intercompany eliminations.
(a)
(b) These assets earn a return.
(c) Under-recovered fuel costs for the accumulation periods from June 2009 through September 2009 and October 2009 through December 2009. Recovery of
the earlier accumulation period will begin in February 2010 while the recovery of the later accumulation period will begin in June 2010.
(d) Costs under- or over-recovered from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.
(e) Current portion of deferral of commodity-related derivative MTM losses, as well as the current portion of the MTM losses on financial contracts entered into
by the Ameren Illinois Utilities with Marketing Company. See Illinois – Power Procurement Plan discussion above for additional information.
Included in Current Regulatory Assets on the balance sheet of UE, CIPS, CILCO and IP and in Other Current Assets on the balance sheet of Ameren.
(f)
(g) These costs are being amortized in proportion to the recognition of prior service costs (credits), transition obligations (assets), and actuarial losses (gains)
attributable to Ameren’s pension plan and postretirement benefit plans. See Note 11 – Retirement Benefits for additional information.
(h) Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 – Income Taxes for amortization period.
120
(l)
(i) Recoverable costs for AROs at our rate-regulated operations, including net realized and unrealized gains and losses related to the nuclear decommissioning
(k) Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the remaining lives of the old debt
trust fund investments. See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.
(j) UE’s Callaway nuclear plant operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the
date the plant was reflected in rates. These costs are being amortized over the remaining life of the plant’s current operating license through 2024.
issuances if no new debt was issued.
The recoverable portion of accrued environmental site liabilities, primarily collected from electric and natural gas customers through ICC-approved cost
recovery riders in Illinois. The period of recovery will depend on the timing of actual expenditures. See Note 15 – Commitments and Contingencies for
additional information.
IP, these costs are recoverable in rates through 2010.
the related debt, beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007.
Marketing Company. See Illinois – Power Procurement Plan discussion above for additional information.
(o) Deferral of commodity-related derivative MTM losses, as well as the MTM losses on financial contracts entered into by the Ameren Illinois Utilities with
(m) Reorganization costs related to the integration and restructuring of IP into the Ameren system. Pursuant to the ICC order approving Ameren’s acquisition of
(n) A portion of IP’s unamortized debt fair value adjustment recorded upon Ameren’s acquisition of IP. This portion is being amortized over the remaining life of
(p) A regulatory tracking mechanism for gains on sales of SO2 emission allowances, net of SO2 premiums incurred under the terms of coal procurement
contracts, plus any SO2 discounts received under such contracts, as approved in a MoPSC order. In its pending rate case, UE requested the discontinuation
of this tracker.
(q) Costs associated with a March 2007 FERC order that resettled costs among MISO market participants. The costs were previously charged to expense but
were recorded as a regulatory asset. They will be amortized over a two-year period beginning March 1, 2009, as approved by the January 2009 MoPSC
electric rate order.
(r) A regulatory tracking mechanism for the difference between the level of vegetation management and infrastructure inspection costs incurred by UE and the
level of such costs built into electric rates. UE’s vegetation management and infrastructure inspection costs from January 1, 2008, through February 28,
2009, exceeded the amount allowed in base rates. The excess costs incurred between January 1, 2008, through September 30, 2008, are being amortized
over three years, beginning on March 1, 2009, as approved by the January 2009 MoPSC electric rate order. The amortization period for the excess costs
incurred from October 1, 2008, through February 28, 2009, will be determined in UE’s pending electric rate case.
(s) Actual storm costs in a test year that exceed the MoPSC staff’s normalized storm costs for rate purposes. The 2006 storm costs are being amortized over
five years, beginning on June 4, 2007. The 2008 storm costs are being amortized over five years, beginning on March 1, 2009. In addition, the balance
includes January 2007 ice storm costs that UE will recover as a result of a MoPSC accounting order issued in April 2008. These costs will be amortized over
five years, beginning on March 1, 2009, as approved by the January 2009 MoPSC electric rate order.
costs are being amortized over ten years, beginning on March 1, 2009, as approved by the January 2009 MoPSC electric rate order.
(t) Demand-side costs, including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. These
(u) Reserve for workers’ compensation claims.
(v) A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by the Ameren Illinois Utilities and the level of such costs
built into electric and natural gas rates. The under-recovery relating to 2008 will be recovered from customers from March 2010 through December 2010. The
under-recovery relating to 2009 will be recovered from customers from June 2010 through May 2011.
Includes costs related to the Ameren Illinois Utilities’ November 2007 electric and natural gas delivery service rate cases. The costs associated with the
Ameren Illinois Utilities’ electric delivery service rate cases are being amortized over a three-year period; the costs associated with the Ameren Illinois
Utilities’ natural gas delivery service rate cases are being amortized over a five-year period, as approved in the 2008 ICC rate order. In addition, the balance
includes funding for low-income weatherization and other miscellaneous items.
through September 2010.
Included in Current Regulatory Liabilities on the balance sheet of IP and in Other Current Liabilities on the balance sheets of Ameren, UE, CIPS and CILCO.
(y) Current portion of deferral of commodity-related derivative MTM gains.
(z)
(aa) Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 – Income Taxes for amortization period.
(bb) Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our rate-regulated
(x) Over-recovered fuel costs for the accumulation period from March 2009 through May 2009. Customer refunds began in October 2009 and will continue
(w)
operations. See discussion in Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.
(cc) The deferral of gains on emission allowance vintage swaps UE entered into during 2005. This gain will be amortized through February 2011.
(dd) A regulatory tracking mechanism for the difference between the level of vegetation management and infrastructure inspection costs incurred by UE and the
level of such costs built into electric rates. This over-recovery relates to the period March 1, 2009, through December 31, 2009. The amortization period for
this over-recovery will be determined in a future UE electric rate case.
(ee) Deferral of commodity-related derivative MTM gains.
(ff) A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by the Ameren Illinois Utilities and the level of such costs
(gg) A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by UE under GAAP and the level
built into electric and natural gas rates. The over-recovery relating to 2009 will be refunded to customers June 2010 through May 2011.
of such costs built into electric rates effective June 4, 2007, as approved in a MoPSC order.
Charges discussion above for additional information.
(hh) A portion of UE’s expected refund relating to MISO resettlements associated with the November 2008 FERC orders. See Federal – FERC Order – MISO
UE, CIPS, CILCO and IP continually assess the recoverability of their regulatory assets. Under current accounting
standards, regulatory assets are written off to earnings when it is no longer probable that such amounts will be recovered
through future revenues. To the extent that payments of regulatory liabilities are no longer probable, the amounts are
credited to earnings.
121
NOTE 3 – PROPERTY AND PLANT, NET
The following table presents property and plant, net, for each of the Ameren Companies at December 31, 2009 and
2008:
2009:
Property and plant, at original cost:
Electric .............................................................
Gas ..................................................................
Other ................................................................
Less: Accumulated depreciation and
amortization .....................................................
Construction work in progress:
Nuclear fuel in process .....................................
Other ................................................................
Property and plant, net ...........................................
2008:
Property and plant, at original cost:
Electric .............................................................
Gas ..................................................................
Other ................................................................
Less: Accumulated depreciation and
amortization .....................................................
Construction work in progress:
Ameren (a)(b)
UE(b)
CIPS
Genco
$ 22,486
1,583
406
24,475
8,787
15,688
271
1,651
$ 17,610
$ 21,244
1,505
381
23,130
8,499
14,631
$ 13,627
363
85
14,075
5,760
8,315
271
999
$ 9,585
$ 13,214
347
76
13,637
5,539
8,098
$ 1,796
374
6
2,176
923
1,253
-
15
$ 1,268
$ 1,744
365
6
2,115
915
1,200
$ 2,730
-
6
2,736
1,032
1,704
-
431
$ 2,135
$ 2,451
-
6
2,457
1,013
1,444
CILCO
(Illinois
Regulated)
$
987
520
3
1,510
730
780
-
12
792
954
506
3
1,463
721
742
-
12
754
$
$
$
CILCO
(AERG)
$ 1,251
-
2
1,253
295
958
-
39
997
948
-
2
950
329
621
-
359
980
$
$
$
IP
$ 1,966
603
21
2,590
176
2,414
-
36
$ 2,450
$ 1,840
565
21
2,426
152
2,274
-
55
$ 2,329
Nuclear fuel in process .....................................
Other ................................................................
Property and plant, net ...........................................
-
506
$ 1,950
Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations.
190
1,746
$ 16,567
190
707
$ 8,995
-
12
$ 1,212
(a)
(b) Amounts in Ameren and UE include two electric generation CTs under two separate capital lease agreements with a gross asset value of $226 million and
$222 million at December 31, 2009 and 2008, respectively. The total accumulated depreciation associated with the two CTs was $41 million and $36 million
at December 31, 2009 and 2008, respectively.
The following table provides accrued capital expenditures at December 31, 2009, 2008, and 2007, which represent
noncash investing activity excluded from the statements of cash flows:
2009 ........................................................................................................................
2008 ........................................................................................................................
2007 ........................................................................................................................
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
NOTE 4 – CREDIT FACILITY BORROWINGS AND LIQUIDITY
Ameren (a)
$ 143
213
153
UE
$ 86
110
76
CIPS
$ 7
3
3
Genco
$ 23
41
28
CILCO
$ 6
45
35
IP
$ 18
14
7
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term
intercompany borrowings, or drawings under committed bank credit facilities.
122
The following table summarizes the borrowing activity and relevant interest rates under the $1.15 billion credit facility
described below for the years ended December 31, 2009 and 2008, respectively, and excludes letters of credit issued
under the credit facility:
2009 Multiyear Credit Agreement ($1.15 billion)(a)
2009:
Average daily borrowings outstanding during 2009 ....................................................
Outstanding credit facility borrowings at period end ...................................................
Weighted-average interest rate during 2009 ..............................................................
Peak credit facility borrowings during 2009(b) .............................................................
Peak interest rate during 2009 ..................................................................................
Prior $1.15 Billion Credit Facility
2008:
Average daily borrowings outstanding during 2008 ....................................................
Outstanding credit facility borrowings at period end ...................................................
Weighted-average interest rate during 2008 ..............................................................
Peak credit facility borrowings during 2008 ................................................................
Peak interest rate during 2008 ..................................................................................
Ameren
(Parent)
$ 307
646
2.15%
$ 699
5.50%
$ 389
275
3.58%
$ 675
7.25%
UE
$ 266
-
1.72%
$ 457
5.50%
$ 154
251
3.25%
$ 493
5.65%
Genco
$
54
-
2.70%
$ 133
3.56%
$
41
-
3.97%
$ 150
5.53%
Total
$
$
627
646
2.02%
940
5.50%
$
584
526
3.52%
$ 1,068
7.25%
(a) The 2009 Multiyear Credit Agreement amended and restated the Prior $1.15 Billion Credit Facility. Therefore, information in this table includes borrowing
(b) The timing of peak credit facility borrowings varies by company. Therefore, the amounts presented by company might not equal the total peak credit facility
activity under the Prior $1.15 Billion Credit Facility.
borrowings for the period. The simultaneous peak credit facility borrowings under all credit facilities during 2009 were $1 billion.
The following table summarizes the borrowing activity and relevant interest rates under the $150 million Supplemental
Agreement described below for the year ended December 31, 2009:
Supplemental Agreement ($150 million)
2009:
Average daily borrowings outstanding during 2009 ........................................................
Outstanding credit facility borrowings at period end .......................................................
Weighted-average interest rate during 2009 ..................................................................
Peak credit facility borrowings during 2009(a) .................................................................
Peak interest rate during 2009 ......................................................................................
(a) The timing of peak credit facility borrowings varies by company and therefore the amounts presented by company might not equal the total peak credit facility
74
84
3.56%
$ 109
5.50%
42
84
3.58%
91
$
5.50%
12
-
3.52%
17
3.56%
20
-
3.62%
53
5.50%
borrowings for the period. The simultaneous peak credit facility borrowings under all credit facilities during 2009 were $1 billion.
The following table summarizes the borrowing activity and relevant interest rates under the $800 million 2009 Illinois
Genco
Total
UE
$
$
$
$
$
$
Ameren
(Parent)
Credit Agreement described below for the year ended December 31, 2009:
2009 Illinois Credit Agreement ($800 million)
2009:
Average daily borrowings outstanding during 2009 .....................................
Outstanding credit facility borrowings at period end ....................................
Weighted-average interest rate during 2009 ...............................................
Peak credit facility borrowings during 2009(a) ..............................................
Peak interest rate during 2009 ...................................................................
Ameren
(Parent)
$ 68
100
3.54%
$ 200
3.56%
CIPS
$ -
-
-
$ -
-
CILCO
(Parent)
$ -
-
-
-
-
$
IP
$ -
-
-
$ -
-
Total
$
68
100
3.54%
$ 200
3.56%
(a) The timing of peak credit facility borrowings varies by company. Therefore, the amounts presented by company may not equal the total peak credit facility
borrowings for the period. The simultaneous peak credit facility borrowings under all credit facilities during 2009 were $1 billion.
123
The following table summarizes the borrowing activity and relevant interest rates under the 2007 $500 million credit
facility, which was terminated during 2009, for the years ended December 31, 2009 and 2008:
2007 $500 Million Credit Facility (Terminated)
2009:
Average daily borrowings outstanding during 2009( b) ..............................
Outstanding credit facility borrowings at period end ..................................
Weighted-average interest rate during 2009( b) ........................................
Peak credit facility borrowings during 2009(b) (c) ........................................
Peak interest rate during 2009( b) .............................................................
2008:
Average daily borrowings outstanding during 2008 ...................................
Outstanding credit facility borrowings at period end ..................................
Weighted-average interest rate during 2008 .............................................
Peak credit facility borrowings during 2008 ...............................................
Peak interest rate during 2008 .................................................................
CIPS
$ -
-
-
-
-
$
$
$
-
-
-
-
-
CILCO
(Parent)
$
$
-
-
-
-
-
$
56
-
4.02%
75
$
6.47%
IP
-
-
-
-
-
$
$
$ 133
-
4.28%
$ 200
6.15%
AERG
$
59
-
1.42%
$ 100
3.25%
$
95
85
3.95%
$ 150
6.22%
Total (a)
$
$
$
$
68
-
1.47%
135
3.25%
384
85
4.25%
500
6.66%
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
(b) Calculated through the termination date.
(c) The timing of peak credit facility borrowings varies by company. Therefore, the amounts presented by company might not equal the total peak credit facility
borrowings for the period. The simultaneous peak credit facility borrowings under all credit facilities during 2009 were $1 billion.
The following table summarizes the borrowing activity and relevant interest rates under the 2006 $500 million credit
facility, which was terminated during 2009, for the years ended December 31, 2009 and 2008:
CIPS
2006 $500 Million Credit Facility (Terminated)
2009:
Average daily borrowings outstanding during 2009( b) ............................ $
Outstanding credit facility borrowings at period end ................................
Weighted-average interest rate during 2009( b) ......................................
Peak credit facility borrowings during 2009( c)(b) ..................................... $
Peak interest rate during 2009( b) ...........................................................
2008:
Average daily borrowings outstanding during 2008 ................................. $
58
Outstanding credit facility borrowings at period end ................................
62
Weighted-average interest rate during 2008 ...........................................
4.21%
Peak credit facility borrowings during 2008 ............................................. $ 135
Peak interest rate during 2008 ...............................................................
6.31%
5
-
2.02%
62
2.02%
CILCO
(Parent)
$
$
-
-
-
-
-
$
37
-
3.78%
75
$
5.98%
IP
-
-
-
-
-
$
$
$
27
-
4.08%
$ 150
6.50%
AERG
$
96
-
1.34%
$ 151
2.72%
$ 151
151
3.94%
$ 200
7.01%
Total (a)
$
$
$
$
150
-
1.54%
263
3.29%
323
263
4.07%
465
7.01%
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
(b) Calculated through the termination date.
(c) The timing of peak credit facility borrowings varies by company. Therefore, the amounts presented by company might not equal the total peak credit facility
borrowings for the period. The simultaneous peak credit facility borrowings under all facilities during 2009 were $1 billion.
On June 30, 2009, Ameren and certain of its
subsidiaries entered into multiyear credit facility
agreements with 24 international, national, and regional
lenders, with no single lender providing more than $146
million of credit. These facilities, as described below,
cumulatively provide $2.1 billion of credit through July 14,
2010, reducing to $1.8795 billion through June 30, 2011,
and to $1.0795 billion through July 14, 2011.
2009 Multiyear Credit Agreements
On June 30, 2009, Ameren, UE, and Genco entered
into an agreement (the “2009 Multiyear Credit
Agreement”) to amend and restate the $1.15 billion five-
year revolving credit agreement that was originally entered
into on July 14, 2005, amended and restated as of
July 14, 2006, and due to expire in July 2010 (the “Prior
$1.15 Billion Credit Facility”). Ameren, UE, and Genco
also entered into a $150 million Supplemental Credit
Agreement to the 2009 Multiyear Credit Agreement (the
“Supplemental Agreement”), which provides Ameren, UE,
and Genco with an additional facility of $150 million with
terms and conditions substantially identical to the 2009
Multiyear Credit Agreement. Collectively, these
agreements are the “2009 Multiyear Credit Agreements.”
The obligations of each borrower under the 2009
Multiyear Credit Agreements are several and not joint.
Except under limited circumstances relating to expenses
and indemnities, the obligations of UE or Genco are not
guaranteed by Ameren or by any other subsidiary of
Ameren. The combined maximum amount available to all
of the borrowers, collectively, under the 2009 Multiyear
Credit Agreements is $1.3 billion, and the combined
maximum amount available to each borrower, individually,
under the 2009 Multiyear Credit Agreements is limited as
follows: Ameren – $1.15 billion, UE – $500 million and
Genco – $150 million (such amounts being each
borrower’s “Borrowing Sublimit”). CIPS, CILCO and IP
have no borrowing authority or liability under the 2009
Multiyear Credit Agreements.
124
On July 14, 2010, when the Supplemental Agreement
terminates, all commitments and all outstanding amounts
under the Supplemental Agreement will be consolidated
with those under the 2009 Multiyear Credit Agreement,
and the combined maximum amount available to all
borrowers will be $1.0795 billion. The UE and Genco
Borrowing Sublimits will remain as noted above; the
Ameren sublimit will change to $1.0795 billion. Ameren
has the option of seeking additional commitments from
existing or new lenders to increase the total facility size to
$1.3 billion after July 14, 2010. The 2009 Multiyear Credit
Agreement will terminate with respect to Ameren on
July 14, 2011, one year after the Prior $1.15 Billion Credit
Facility. The Borrowing Sublimits of UE and Genco will
continue to be subject to extensions on a 364-day basis
(but in no event later than July 14, 2011). The current
maturity date of their Borrower Sublimits under the 2009
Multiyear Credit Agreements is June 29, 2010.
The obligations of all borrowers under the 2009
Multiyear Credit Agreements are unsecured. The interest
rates applicable to loans under the 2009 Multiyear Credit
Agreements will be either the alternate base rate, as
defined, plus the margin applicable to the particular
borrower or the eurodollar rate plus the margin applicable
to the particular borrower. The applicable margins will be
determined by reference to such borrower’s long-term
unsecured credit ratings in effect at the time. A
competitive bid rate is also available if requested by a
borrower. Letters of credit in an aggregate undrawn face
amount not to exceed $287.5 million are available for
issuance for account of the borrowers under the 2009
Multiyear Credit Agreements (but within the $1.3 billion
overall combined facility limitation).
Under the 2009 Multiyear Credit Agreements, the
principal amount of each revolving loan will be due and
payable no later than the final maturity of the agreements,
for Ameren, and the last day of the then applicable 364-
day period for UE and Genco. Ameren, UE and Genco will
use the proceeds of any borrowings under the 2009
Multiyear Credit Agreements for general corporate
purposes, including working capital, and to fund loans
under the Ameren money pool arrangements.
2009 Illinois Credit Agreement
Also on June 30, 2009, Ameren, CIPS, CILCO, and IP
entered into an $800 million multiyear, senior secured
credit agreement (the “2009 Illinois Credit Agreement”).
The 2009 Illinois Credit Agreement replaced the Ameren
Illinois Utilities’ $500 million credit facility dated July 14,
2006 (the “2006 $500 Million Credit Facility
(Terminated)”), and their $500 million credit facility dated
February 9, 2007 (the “2007 $500 Million Credit Facility
(Terminated)”), each as previously amended (collectively,
the “Terminated Illinois Credit Facilities”). They were
terminated when the 2009 Illinois Credit Agreement went
into effect.
Ameren was not a borrower under the Terminated
Illinois Credit Facilities, but it is a borrower under the 2009
Illinois Credit Agreement. AERG was a borrower under the
Terminated Illinois Credit Facilities, but it was not party to
or a borrower under the 2009 Illinois Credit Agreement. All
obligations of AERG under the Terminated Illinois Credit
Facilities have been repaid, and all liens securing such
obligations have been released. AERG expects to meet its
external liquidity needs through borrowings under the
Ameren non-state-regulated subsidiary money pool
arrangements or other liquidity arrangements.
The obligations of each borrower under the 2009
Illinois Credit Agreement are several and not joint. They
are not guaranteed by Ameren or any other subsidiary of
Ameren. The maximum amount available to each
borrower under the facility is limited as follows: Ameren –
$300 million, CIPS – $135 million, CILCO – $150 million
and IP – $350 million (such amounts being such
borrower’s “Borrowing Sublimit”).
The 2009 Illinois Credit Agreement will terminate with
respect to all borrowers on June 30, 2011. Each borrowing
under the 2009 Illinois Credit Agreement must be repaid
no later than 364 days after such borrowing. In each case,
the borrower may on such date make a new borrowing, or
convert or continue such borrowing as a new borrowing
subject to satisfaction of the applicable conditions. The
obligations of the Ameren Illinois Utilities under the 2009
Illinois Credit Agreement are secured by the issuance of
mortgage bonds, for collateral support, by each such utility
under its respective mortgage indenture, in an amount
equal to its respective Borrowing Sublimit. Ameren’s
obligations are unsecured.
Loans are available on a revolving basis under the
2009 Illinois Credit Agreement. They may be repaid and,
subject to satisfaction of the conditions to borrowing,
reborrowed from time to time. At the election of each
borrower, the interest rates applicable under the 2009
Illinois Credit Agreement are the alternate base rate, as
defined, plus the margin applicable to the particular
borrower or the eurodollar rate plus the margin applicable
to the particular borrower. The applicable margins will be
determined, in the case of Ameren, by Ameren’s long-term
unsecured credit ratings in effect, at the time, and in the
case of the Ameren Illinois Utilities, such utility’s long-term
secured credit ratings at the time. Letters of credit in an
aggregate undrawn face amount not to exceed $200
million are also available for issuance for the account of
the borrowers under the 2009 Illinois Credit Agreement
(but within the $800 million overall facility limitation).
Due to outstanding borrowings under the 2009
Multiyear Credit Agreements and the 2009 Illinois Credit
Agreement (including reductions for $15 million of letters
of credit issued under the 2009 Multiyear Credit
Agreements), the available amounts under the facilities at
December 31, 2009, were $555 million and $700 million,
respectively.
Other Agreements
On January 21, 2009, Ameren entered into a
$20 million term loan agreement due January 20, 2010,
125
which was fully drawn on January 21, 2009. The average
annual interest rate for borrowing under the $20 million
term loan agreement was 2.03% during the year ended
December 31, 2009. This term loan agreement was repaid
at maturity in January 2010.
On June 25, 2008, Ameren entered into a $300 million
term loan agreement due June 24, 2009, which was fully
drawn on June 26, 2008. The average annual interest rate
for borrowing under the $300 million term loan agreement
was 1.97% during the period it was outstanding in 2009.
This term loan was repaid at maturity in June 2009 with
proceeds from the issuance by Ameren of $425 million
principal amount of senior unsecured notes due May
2014. See Note 5 – Long-term Debt and Equity
Financings.
Indebtedness Provisions and Other Covenants
The 2009 Multiyear Credit Agreements contain
conditions to borrowings and issuances of letters of credit,
including the absence of default or unmatured default,
material accuracy of representations and warranties
(excluding any representation after the closing date as to
the absence of material adverse change and material
litigation), and required regulatory authorizations. The
2009 Multiyear Credit Agreements also contain
nonfinancial covenants, including restrictions on the ability
to incur liens, to transact with affiliates, to dispose of
assets, and to merge with other entities. In addition,
Ameren and certain subsidiaries are restricted to limited
investments in and other transfers to affiliates, including
investments in the Ameren Illinois Utilities and their
subsidiaries.
The 2009 Multiyear Credit Agreements contain
identical default provisions including a cross default of a
borrower to the occurrence of a default by such borrower
under any other agreement covering indebtedness of such
borrower and certain subsidiaries (other than project
finance subsidiaries and non-material subsidiaries) in
excess of $25 million in the aggregate. A default by an
Ameren Illinois utility under the 2009 Illinois Credit
Agreement does not constitute a default under the 2009
Multiyear Credit Agreements. Any default of Ameren
under the 2009 Illinois Credit Agreement that occurs solely
as a result of a default by an Ameren Illinois utility
thereunder will not constitute a default under either of the
2009 Multiyear Credit Agreements while Ameren is
otherwise in compliance with all of its obligations under
the 2009 Illinois Credit Agreement.
The 2009 Multiyear Credit Agreements require
Ameren, UE and Genco each to maintain consolidated
indebtedness of not more than 65% of its consolidated
total capitalization pursuant to a calculation set forth in the
facilities. All of the consolidated subsidiaries of Ameren,
including the Ameren Illinois Utilities, are included for
purposes of determining compliance with this
capitalization test with respect to Ameren. Failure to
satisfy the capitalization covenant constitutes a default
under the 2009 Multiyear Credit Agreements. As of
December 31, 2009, the ratios of consolidated
indebtedness to total consolidated capitalization,
calculated in accordance with the provisions of the 2009
Multiyear Credit Agreements, were 51%, 48% and 54%,
for Ameren, UE and Genco, respectively.
The 2009 Illinois Credit Agreement contains
conditions to borrowings and issuance of letters of credit,
including the absence of default or unmatured default,
material accuracy of representations and warranties
(excluding, for so long as ratings conditions shall be
satisfied, any representation after the closing date as to
the absence of material adverse change and material
litigation, which is new to the 2009 Illinois Credit
Agreement), and required regulatory authorizations. The
rating condition is satisfied if the borrower has a Moody’s
rating of Baa3 or higher or an S&P rating of BBB- or
higher (in the case of Ameren, with respect to senior
unsecured long-term debt, and in the case of the Ameren
Illinois Utilities, with respect to senior secured long-term
debt). The 2009 Illinois Credit Agreement contains
nonfinancial covenants, including restrictions on the ability
to incur liens, to transact with affiliates, to dispose of
assets, and to merge with other entities. The Ameren
Illinois Utilities may engage in certain mergers or similar
transactions that may cause their utility operations to be
conducted by a single legal entity. In addition, the 2009
Illinois Credit Agreement has nonfinancial covenants that
limit the ability of a borrower to invest in or to transfer
assets to affiliates, covenants regarding the status of the
collateral securing the 2009 Illinois Credit Agreement, and
maintenance of the validity of the security interests
therein.
The 2009 Illinois Credit Agreement contains default
provisions. Defaults under the 2009 Illinois Credit
Agreement apply separately to each borrower; provided
that a default by an Ameren Illinois utility will constitute a
default by Ameren. Defaults include a cross default of a
borrower to the occurrence of a default by such borrower
under any other agreement covering indebtedness of such
borrower and certain subsidiaries (other than project
finance subsidiaries and non-material subsidiaries) in
excess of $25 million in the aggregate. A default by Genco
or UE under the 2009 Multiyear Credit Agreements does
not constitute an event of default under the 2009 Illinois
Credit Agreement. Any default of Ameren under the 2009
Multiyear Credit Agreements that occurs solely as a result
of a default by UE or Genco thereunder will not constitute
a default under the 2009 Illinois Credit Agreement while
Ameren is otherwise in compliance with all of its
obligations under the 2009 Multiyear Credit Agreements.
Furthermore, under the 2009 Illinois Credit Agreement, the
occurrence of a default resulting from an event or
conditions effecting AERG shall be deemed to constitute a
default with respect to Ameren under the 2009 Illinois
Credit Agreement, but shall not in itself constitute a default
with respect to CILCO, unless the liability that CILCO has
for such default or such underlying event or condition
giving rise to such default would otherwise constitute a
default with respect to CILCO if the underlying event or
condition had occurred or existed at CILCO.
126
The 2009 Illinois Credit Agreement requires Ameren
and each Ameren Illinois utility to maintain consolidated
indebtedness of not more than 65% of its consolidated
total capitalization pursuant to a defined calculation. All of
the consolidated subsidiaries of Ameren are included for
purposes of determining compliance with this
capitalization test with respect to Ameren. As of
December 31, 2009, the ratios of consolidated
indebtedness to total consolidated capitalization for
Ameren, CIPS, CILCO and IP, calculated in accordance
with the provisions of the 2009 Illinois Credit Agreement,
were 51%, 44%, 41%, and 46%, respectively. In addition,
Ameren is required to maintain a ratio of consolidated
funds from operations plus interest expense to
consolidated interest expense of 2.0 to 1, at the end of the
most recent four fiscal quarters, calculated and subject to
adjustment in accordance with the 2009 Illinois credit
agreement. Ameren’s ratio as of December 31, 2009, was
4.6 to 1. Failure to satisfy these covenants constitutes a
default under the 2009 Illinois Credit Agreement.
In addition, the 2009 Illinois Credit Agreement
prohibits CILCO from issuing any preferred stock if, after
such issuance, the aggregate liquidation value of all
CILCO preferred stock issued after June 30, 2009, would
exceed $50 million.
None of Ameren’s credit facilities or financing
arrangements contain credit rating triggers that would
cause default or acceleration of repayment of outstanding
balances. At December 31, 2009, management believes
that the Ameren Companies were in compliance with their
credit facilities and term loan agreement provisions and
covenants.
Money Pools
Ameren has money pool agreements with and among
its subsidiaries to coordinate and provide for certain short-
term cash and working capital requirements. Separate
money pools are maintained for utility and non-state-
regulated entities. Ameren Services is responsible for the
operation and administration of the money pool
agreements.
Utility
Through the utility money pool, the pool participants
may access the committed credit facilities. CIPS, CILCO
and IP borrow from each other through the utility money
pool agreement subject to applicable regulatory short-term
borrowing authorizations. Ameren Services administers
the utility money pool and tracks internal and external
funds separately. Ameren and AERG may participate in
the utility money pool only as lenders. Internal funds are
surplus funds contributed to the utility money pool from
participants. The primary source of external funds for the
utility money pool are the 2009 Multiyear Credit
Agreements and the 2009 Illinois Credit Agreement. The
total amount available to the pool participants from the
utility money pool at any given time is reduced by the
amount of borrowings by their affiliates, but increased to
the extent that the pool participants have surplus funds or
contribute funds from other external sources. The
availability of funds is also determined by funding
requirement limits established by regulatory
authorizations. CIPS, CILCO and IP rely on the utility
money pool to coordinate and provide for certain short-
term cash and working capital requirements. Borrowers
receiving a loan under the utility money pool agreement
must repay the principal amount of such loan, together
with accrued interest. The rate of interest depends on the
composition of internal and external funds in the utility
money pool. The average interest rate for borrowing under
the utility money pool for the year ended December 31,
2009, was 0.19% (2008 – 2.85%).
Non-state-regulated Subsidiaries
Ameren Services, Resources Company, Genco,
AERG, Marketing Company, AFS, and other non-state-
regulated Ameren subsidiaries have the ability, subject to
Ameren parent company authorization and applicable
regulatory short-term borrowing authorizations, to access
funding from the 2009 Multiyear Credit Agreements
through a non-state-regulated subsidiary money pool
agreement. The total amount available to the pool
participants at any time is reduced by borrowings made by
Ameren’s subsidiaries, but is increased to the extent that
other pool participants advance surplus funds to the non-
state-regulated subsidiary money pool or remit funds from
other external sources. See the discussion above for the
amount available under the 2009 Multiyear Credit
Agreements at December 31, 2009. The non-state-
regulated subsidiary money pool was established to
coordinate and to provide short-term cash and working
capital for Ameren’s non-state-regulated activities.
Borrowers receiving a loan under the non-state-regulated
subsidiary money pool agreement must repay the principal
amount of such loan, together with accrued interest. The
rate of interest depends on the composition of internal and
external funds in the non-state-regulated subsidiary
money pool. These rates are based on the cost of funds
used for money pool advances. The average interest rate
for borrowing under the non-state-regulated subsidiary
money pool for the year ended December 31, 2009 was
1.64% (2008 – 3.51%).
See Note 14 – Related Party Transactions for the
amount of interest income and expense from the money
pool arrangements recorded by the Ameren Companies
for the years ended December 31, 2009, 2008, and 2007.
In addition, a unilateral borrowing agreement exists
between Ameren, IP, and Ameren Services, which
enables IP to make short-term borrowings directly from
Ameren. The aggregate amount of borrowings outstanding
at any time by IP under the unilateral borrowing
agreement and the utility money pool agreement, together
with any outstanding external credit facility borrowings by
IP, may not exceed $500 million, pursuant to authorization
from the ICC. IP is not currently borrowing under the
unilateral borrowing agreement. Ameren Services is
responsible for operation and administration of the
unilateral borrowing agreement.
127
NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding for the Ameren Companies as of December 31, 2009 and
2008:
Ameren (Parent):
UE:
First mortgage bonds:(a)
8.875% Senior unsecured notes due 2014 ...........................................................................................................................
Less: Unamortized discount and premium .......................................................................................................................
Long-term debt, net ...................................................................................................................................................
5.25% Senior secured notes due 2012(b) ..............................................................................................................................
4.65% Senior secured notes due 2013(b) ..............................................................................................................................
5.50% Senior secured notes due 2014(b) ..............................................................................................................................
4.75% Senior secured notes due 2015(b) ..............................................................................................................................
5.40% Senior secured notes due 2016(b) ..............................................................................................................................
6.40% Senior secured notes due 2017(b) ..............................................................................................................................
6.00% Senior secured notes due 2018(b) ..............................................................................................................................
5.10% Senior secured notes due 2018(b) ..............................................................................................................................
6.70% Senior secured notes due 2019(b) ..............................................................................................................................
5.10% Senior secured notes due 2019(b) ..............................................................................................................................
5.00% Senior secured notes due 2020(b) ..............................................................................................................................
5.45% Series due 2028(c)......................................................................................................................................................
5.50% Senior secured notes due 2034(b) ..............................................................................................................................
5.30% Senior secured notes due 2037(b) ..............................................................................................................................
8.45% Senior secured notes due 2039(b) ..............................................................................................................................
Environmental improvement and pollution control revenue bonds:(a)(b)(c)(d)
1992 Series due 2022 ..........................................................................................................................................................
1998 Series A due 2033 .......................................................................................................................................................
1998 Series B due 2033 .......................................................................................................................................................
1998 Series C due 2033 .......................................................................................................................................................
Subordinated deferrable interest debentures:
Capital lease obligations:
7.69% Series A due 2036(e) ..................................................................................................................................................
City of Bowling Green capital lease (Peno Creek CT) ...........................................................................................................
Audrain County capital lease (Audrain County CT) ...............................................................................................................
Total long-term debt, gross .............................................................................................................................................
Less: Unamortized discount and premium .......................................................................................................................
Less: Maturities due within one year ...............................................................................................................................
Long-term debt, net ...................................................................................................................................................
CIPS:
First mortgage bonds:(a)
6.625% Senior secured notes due 2011(b) ............................................................................................................................
7.61% Series 1997-2 due 2017 ............................................................................................................................................
6.125% Senior secured notes due 2028(b) ............................................................................................................................
6.70% Senior secured notes due 2036(b) ..............................................................................................................................
Environmental improvement and pollution control revenue bonds:
2000 Series A 5.50% due 2014 ............................................................................................................................................
1993 Series C-1 5.95% due 2026 .........................................................................................................................................
1993 Series C-2 5.70% due 2026 .........................................................................................................................................
1993 Series B-1 due 2028(d) .................................................................................................................................................
Total long-term debt, gross .............................................................................................................................................
Less: Unamortized discount and premium .......................................................................................................................
Long-term debt, net ...................................................................................................................................................
Genco:
Unsecured notes:
Senior notes Series D 8.35% due 2010 ................................................................................................................................
Senior notes Series F 7.95% due 2032 .................................................................................................................................
Senior notes Series H 7.00% due 2018 ................................................................................................................................
Senior notes Series I 6.30% due 2020 ..................................................................................................................................
Total long-term debt, gross .............................................................................................................................................
Less: Unamortized discount and premium .......................................................................................................................
Less: Maturities due within one year ...............................................................................................................................
Long-term debt, net ...................................................................................................................................................
2009
2008
$
$
$
425
(2)
423
173
200
104
114
260
425
250
200
450
300
85
44
184
300
350
47
60
50
50
66
78
240
4,030
(8)
(4)
$ 4,018
$
$
150
40
60
61
51
35
8
17
422
(1)
421
$
200
275
300
250
1,025
(2)
(200)
823
$
$
$
$
-
-
-
173
200
104
114
260
425
250
200
450
300
85
44
184
300
-
47
60
50
50
66
82
240
3,684
(7)
(4)
$ 3,673
$
$
$
$
150
40
60
61
51
35
8
17
422
(1)
421
200
275
300
-
775
(1)
-
774
128
8.70% Senior notes due 2009...............................................................................................................................................
9.375% Senior bonds due 2029 ............................................................................................................................................
Fair-market value adjustments ...................................................................................................................................................
Total long-term debt, gross .............................................................................................................................................
Less: Maturities due within one year ...............................................................................................................................
Long-term debt, net ...................................................................................................................................................
8.875% Senior secured notes due 2013(b) ............................................................................................................................
6.20% Senior secured notes due 2016(b) ..............................................................................................................................
6.70% Senior secured notes due 2036(b) ..............................................................................................................................
Environmental improvement and pollution-control revenue bonds:(a)(c)
6.20% Series 1992B due 2012 .............................................................................................................................................
5.90% Series 1993 due 2023................................................................................................................................................
Long-term debt, net ...................................................................................................................................................
CILCORP (Parent):
Unsecured notes:
CILCO:
First mortgage bonds:(a)
IP:
Mortgage bonds:(a)
7.50% Series due 2009 ........................................................................................................................................................
6.25% Senior secured notes due 2016(b) ..............................................................................................................................
6.125% Senior secured notes due 2017(b) ............................................................................................................................
6.250% Senior secured notes due 2018(b) ............................................................................................................................
9.750% Senior secured notes due 2018(b) ............................................................................................................................
Pollution control revenue bonds:(a)(c)
5.70% 1994A Series due 2024 .............................................................................................................................................
5.40% 1998A Series due 2028 .............................................................................................................................................
5.40% 1998B Series due 2028 .............................................................................................................................................
Fair-market value adjustments ...................................................................................................................................................
Total long-term debt, gross .............................................................................................................................................
Less: Unamortized discount and premium .......................................................................................................................
Less: Maturities due within one year ...............................................................................................................................
Long-term debt, net ...................................................................................................................................................
Ameren consolidated long-term debt, net ...................................................................................................................................
2009
2008
$
$
$
$
$
-
2
-
2
-
2
150
54
42
1
32
279
-
75
250
337
400
36
19
33
6
1,156
(9)
-
$ 1,147
$ 7,113
$
$
$
$
$
124
210
49
383
(126)
257
150
54
42
1
32
279
250
75
250
337
400
36
19
33
10
1,410
(10)
(250)
$ 1,150
$ 6,554
(a) At December 31, 2009, most property and plant was mortgaged under, and subject to liens of, the respective indentures pursuant to which the bonds were
issued. Substantially all of the long-term debt issued by UE, CIPS (excluding the tax-exempt debt), CILCO and IP is secured by a lien on substantially all of
its property and franchises.
(b) These notes are collaterally secured by first mortgage bonds issued by UE, CIPS, CILCO, or IP, respectively, and will remain secured at each company until
the following series are no longer outstanding with respect to that company: UE – 5.45% Series due 2028 (currently callable at 101% of par, declining to
100% of par in October 2010), 6.00% Series due 2018, and 6.70% Series due 2019; CIPS – 7.61% Series 1997-2 due 2017 (currently callable at 102.28% of
par, declining annually thereafter to 100% of par in June 2012); CILCO – 6.20% Series 1992B due 2012 (currently callable at 100% of par), 5.90% Series
1993 due 2023 (currently callable at 100% of par), and 8.875% Series due 2013; IP – 6.125% Series due 2017, 6.25% Series due 2018, 9.75% Series due
2018, and all IP pollution control revenue bonds.
6.20% Series 1992B and 5.90% Series 1993 bonds are backed by an insurance guarantee policy.
Interest rates, and the periods during which such rates apply, vary depending on our selection of certain defined rate modes. Maximum interest rates could
range up to 18% depending upon the series of bonds. The average interest rates for the years 2009 and 2008 were as follows:
(c) Environmental improvement or pollution control series secured by first mortgage bonds. In addition, all of the series except UE’s 5.45% Series and CILCO’s
(d)
2009
UE 1992 Series ................................................................................................ 0.68%
UE 1998 Series A ............................................................................................. 0.99%
UE 1998 Series B ............................................................................................. 1.02%
UE 1998 Series C ............................................................................................. 0.99%
CIPS 1993 Series B-1....................................................................................... 1.34%
2008
3.66%
3.97%
3.71%
4.06%
1.98%
(e) Under the terms of the subordinated debentures, UE may, under certain circumstances, defer the payment of interest for up to five years. If UE should elect
to defer interest payments, UE dividend payments to Ameren would be prohibited. UE has not elected to defer any interest payments.
129
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren
Companies at December 31, 2009:
Ameren
(Parent)(a)
2010 ................................... $
-
2011 ...................................
-
2012 ...................................
-
2013 ...................................
-
2014 ...................................
425
Thereafter ...........................
-
Total ................................... $ 425
$
UE (a)
4
5
178
205
109
3,529
$ 4,030
CIPS (a)
-
$
150
-
-
51
221
$ 422
Genco (a)(b)
$
200
-
-
-
-
825
$ 1,025
CILCORP
(Parent)
-
$
-
-
-
-
2
$ 2
CILCO
-
$
-
1
150
-
128
$ 279
$
IP (a)(c)
-
-
-
-
-
1,150
$ 1,150
Ameren
Consolidated
$
204
155
179
355
585
5,855
$ 7,333
respectively.
(a) Excludes unamortized discount and premium of $2 million, $8 million, $1 million, $2 million, and $9 million at Ameren (Parent), UE, CIPS, Genco, and IP,
(b) Excludes $45 million due in 2010 related to a note payable to an affiliate. See Note 14 – Related Party Transactions for additional information.
(c) Excludes $6 million related to IP’s long-term debt fair-market value adjustments, which are being amortized to interest expense over the remaining life of the debt.
All of the Ameren Companies expect to fund maturities of long-term debt, short-term borrowings, credit facility
borrowings and contractual obligations through a combination of cash flow from operations and external financing. See
Note 4 – Credit Facility Borrowings and Liquidity for a discussion of external financing availability.
In November 2008, Ameren, CIPS, Genco, CILCO
and IP, filed a Form S-3 shelf registration statement
registering the issuance of an indeterminate amount of
certain types of securities, which expires in November
2011. In June 2008, UE filed a Form S-3 shelf registration
statement registering the issuance of an indeterminate
amount of certain types of securities, which expires in
June 2011.
The following table presents information with respect
to the Form S-3 shelf registration statements filed and
effective for certain Ameren Companies as of
December 31, 2009:
Effective Date
Authorized
Amount
Ameren ................................................. November 2008 Not limited
UE .......................................................
June 2008 Not limited
CIPS ..................................................... November 2008 Not limited
Genco ................................................... November 2008 Not limited
CILCO .................................................. November 2008 Not limited
IP ....................................................... November 2008 Not limited
Ameren
In July 2008, Ameren filed a Form S-3 registration
statement with the SEC authorizing the offering of six
million additional shares of its common stock under the
DRPlus. Shares of common stock sold under DRPlus are,
at Ameren’s option, newly issued shares, treasury shares,
or shares purchased in the open market or in privately
negotiated transactions. Ameren is currently selling newly
issued shares of its common stock under DRPlus.
Ameren is also selling newly issued shares of
common stock under its 401(k) plan pursuant to an
effective SEC Form S-8 registration statement. Under
DRPlus and its 401(k) plan, Ameren issued 3.2 million,
4.0 million, and 1.7 million shares of common stock in
2009, 2008, and 2007, respectively, which were valued at
$82 million, $154 million, and $91 million for the respective
years.
In May 2009, Ameren issued $425 million of 8.875%
senior unsecured notes due May 15, 2014, with interest
payable semiannually on May 15 and November 15 of
each year, beginning November 15, 2009. Ameren
received net proceeds of $420 million, which were used,
together with other corporate funds, to repay borrowings
under its $300 million term loan agreement and, by way of
a capital contribution to CILCORP, providing funds for
CILCORP to repay its outstanding 8.70% senior notes on
their due date of October 15, 2009.
In September 2009, Ameren issued and sold
21.85 million shares of its common stock at $25.25 per
share, for proceeds of $535 million, net of $17 million of
issuance costs. Ameren used the net offering proceeds to
make investments in its rate-regulated utility subsidiaries
in the form of equity capital contributions as follows: UE –
$436 million, CIPS – $13 million, CILCO – $25 million, and
IP – $61 million.
UE
In April 2008, UE issued $250 million of 6.00% senior
secured notes due April 1, 2018, with interest payable
semiannually on April 1 and October 1 of each year,
beginning in October 2008. These notes are secured by
first mortgage bonds. UE received net proceeds of $248
million, which were used to redeem certain of UE’s
outstanding auction-rate environmental improvement
revenue refunding bonds discussed below and to repay
short-term debt. In connection with this issuance of $250
million of senior secured notes, UE agreed that, so long as
these senior secured notes are outstanding, it would not,
prior to maturity, cause a first mortgage bond release date
to occur.
In April 2008, $63 million of UE’s Series 2000B
auction-rate environmental improvement revenue
refunding bonds were redeemed at par value plus accrued
interest.
In May 2008, $43 million of UE’s Series 1991,
$64 million of UE’s Series 2000A and $60 million of UE’s
Series 2000C auction-rate environmental improvement
130
revenue refunding bonds were redeemed at par value plus
accrued interest. Also, in May 2008, $148 million of UE’s
6.75% Series first mortgage bonds matured and were retired.
In June 2008, UE issued $450 million of 6.70% senior
secured notes due February 1, 2019, with interest payable
semiannually on February 1 and August 1 of each year,
beginning in February 2009. These notes are secured by first
mortgage bonds. UE received net proceeds of $446 million,
which was used to repay short-term debt. A portion of that
debt had been incurred so that UE could pay at maturity the
6.75% Series first mortgage bonds noted above. In
connection with this issuance of $450 million of senior
secured notes, UE agreed that, so long as these senior
secured notes are outstanding, it would not, prior to maturity,
cause a first mortgage bond release date to occur. The first
mortgage bond release date is the date at which the security
provided by the pledge under UE’s first mortgage indenture
would no longer be available to holders of any outstanding
series of its senior secured notes and such indebtedness
would become senior unsecured indebtedness.
In March 2009, UE issued $350 million of 8.45% senior
secured notes due March 15, 2039, with interest payable
semiannually on March 15 and September 15 of each year,
beginning in September 2009. These notes are secured by
first mortgage bonds. UE received net proceeds of $346
million, which were used to repay short-term debt. In
connection with this issuance of $350 million of senior
secured notes, UE agreed that, so long as these senior
secured notes are outstanding, it would not, prior to maturity,
cause a first mortgage bond release date to occur.
CIPS
In April 2008, $35 million of CIPS’ Series 2004 auction-
rate environmental improvement revenue refunding bonds
were redeemed at par value plus accrued interest.
In December 2008, $15 million of CIPS’ 5.375% senior
secured notes matured and were retired.
Genco
In April 2008, Genco issued and sold, with registration
rights in a private placement, $300 million of 7.00% senior
unsecured notes due April 15, 2018, with interest payable
semiannually on April 15 and October 15 of each year,
beginning in October 2008. Genco received net proceeds of
$298 million, which was used to fund capital expenditures, to
repay short-term debt, and for other general corporate
purposes. Genco exchanged the outstanding unregistered
unsecured notes for registered unsecured notes in July 2008.
In November 2009, Genco issued $250 million of 6.30%
senior unsecured notes due April 1, 2020, with interest
payable semiannually on April 1 and October 1 of each year,
beginning in April 2010. Genco received net proceeds of
$247 million, which were used to repay short-term debt, and
for general corporate purposes.
CILCORP
In October 2009, $124 million of CILCORP’s 8.70%
senior notes matured and were retired.
In December 2009, CILCORP paid $256 million,
including tender offer and consent payments and accrued
interest, in connection with the repurchase and cancellation
of $208 million principal amount outstanding of its 9.375%
senior bonds. After the repurchase, approximately $2 million
principal amount of senior bonds remained outstanding.
Sufficient consents were received to approve the adoption of
amendments to eliminate certain restrictive covenants to the
related indenture. As a result of this cancellation, fair-market
value adjustments related to the senior bonds were reduced
by $44 million during 2009.
In February 2010, CILCORP completed a covenant
defeasance of its remaining outstanding 9.375% senior
bonds due 2029 by depositing approximately $2.7 million in
U.S. government obligations and cash with the indenture
trustee. This deposit will be used solely to satisfy the principal
and remaining interest obligations on these bonds. In
connection with this covenant defeasance, the lien on the
capital stock of CILCO securing these bonds was released.
CILCO
In April 2008, $19 million of CILCO’s Series 2004
auction-rate environmental improvement revenue refunding
bonds were redeemed at par value plus accrued interest.
In July 2008, CILCO redeemed the remaining 165,000
shares of its 5.85% Class A preferred stock at a redemption
price of $100 per share plus accrued and unpaid dividends.
The redemption completed CILCO’s mandatory redemption
obligations for this series of preferred stock.
In December 2008, CILCO issued $150 million of
8.875% senior secured notes due December 15, 2013, with
interest payable semiannually on June 15 and December 15
of each year, beginning in June 2009. These notes are
secured by first mortgage bonds. CILCO received net
proceeds of $149 million, which were used to repay short-
term borrowings. In connection with this issuance of
$150 million of senior secured notes, CILCO agreed that, so
long as these senior secured notes are outstanding, it would
not, prior to maturity, cause a first mortgage bond release
date to occur. The mortgage bond release date is the date at
which the security provided by the pledge under CILCO’s first
mortgage indenture would no longer be available to holders
of any outstanding series of its senior secured notes and
such indebtedness would become senior unsecured
indebtedness.
IP
In April 2008, IP issued and sold, with registration rights
in a private placement, $337 million of 6.25% senior secured
notes due April 1, 2018, with interest payable semiannually
on April 1 and October 1 of each year, beginning in October
2008. IP received net proceeds of $334 million, which were
used to redeem all of IP’s
131
outstanding auction-rate pollution control revenue
refunding bonds during May and June 2008, as discussed
below. In connection with IP’s April 2008 issuance of
$337 million of senior secured notes, IP agreed that, so
long as these senior secured notes are outstanding, it
would not, prior to maturity, cause a first mortgage bond
release date to occur. The mortgage bond release date is
the date at which the security provided by the pledge
under IP’s first mortgage indenture would no longer be
available to holders of any outstanding series of its senior
secured notes and such indebtedness would become
senior unsecured indebtedness. IP exchanged the
outstanding unregistered secured notes for registered
secured notes in June 2008.
In May 2008, IP redeemed its $112 million Series
2001 Non-AMT, $75 million Series 2001 AMT, $70 million
1997 Series A, and $45 million 1997 Series B auction-rate
pollution control revenue bonds at par value plus accrued
interest. In June 2008, IP redeemed its $35 million 1997
Series C auction-rate pollution control revenue bonds at
par value plus accrued interest.
payable to IP SPT. Previous redemptions occurred in the
first and second quarters of 2008 for $19 million and
$20 million, respectively. This was the remaining
outstanding amount of $864 million of TFNs issued by the
IP SPT in December 1998.
In October 2008, IP issued and sold, with registration
rights in a private placement, $400 million of 9.75% senior
secured notes due November 15, 2018, with interest
payable semiannually on November 15 and May 15 of
each year, beginning in May 2009. IP received net
proceeds of $391 million, which were used to repay short-
term debt. In connection with IP’s October 2008 issuance
of $400 million of senior secured notes, IP agreed that, so
long as these senior secured notes are outstanding, it
would not, prior to maturity, cause a first mortgage bond
release date to occur. In February 2009, IP commenced
an offer to exchange the outstanding unregistered secured
notes for registered secured notes. In March 2009, IP
exchanged all $400 million of its unregistered 9.75%
senior secured notes for a like amount of registered 9.75%
senior secured notes due November 15, 2018.
In September 2008, IP redeemed the remaining
In June 2009, $250 million of IP’s 7.50% series first
portion of its $54 million principal amount 5.65% note
mortgage bonds matured and were retired.
Indenture Provisions and Other Covenants
UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions
related to issuances of first mortgage bonds and preferred stock. UE, CIPS, CILCO and IP are required to meet certain
ratios to issue additional first mortgage bonds and preferred stock. However, not meeting these ratios would not result in a
default under these covenants and provisions. The following table includes the required and actual earnings coverage
ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended
December 31, 2009, at an assumed interest and dividend rate of 8%.
Required Interest
Coverage Ratio(a)
Actual Interest
Coverage Ratio Bonds Issuable(b)
Required Dividend
Coverage Ratio(c)
2.9
4.2
7.6
3.6
UE ..................................... 2.0
CIPS ................................... 2.0
CILCO ................................ 2.0 (d)
IP ..................................... 2.0
(a) Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when
2.5
1.5
2.5
1.5
$ 1,255
344
214
1,191
additional first mortgage bonds are issued on the basis of retired bonds.
(b) Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also
include bonds issuable based on retired bond capacity of $95 million, $18 million, $44 million, and $536 million, at UE, CIPS, CILCO and IP, respectively.
(c) Coverage required on the annual interest charges on all long-term debt (CIPS only) and the annual dividend on preferred stock outstanding and to be issued,
as required in the respective company’s articles of incorporation. For CILCO, this ratio must be met for a period of 12 consecutive calendar months within the
15 months immediately preceding the issuance.
In lieu of meeting the interest coverage ratio requirement, CILCO may attempt to meet an earnings requirement of at least 12% of the principal amount of all
mortgage bonds outstanding and to be issued. For the 12 months ended December 31, 2009, CILCO had earnings equivalent to at least 38% of the principal
amount of all mortgage bonds outstanding.
(e) See Note 4 – Credit Facility Borrowings and Liquidity for a discussion regarding a restriction on the issuances of preferred stock by CILCO.
(d)
Actual Dividend
Coverage Ratio
44.6
2.0
155.0
1.8
Preferred Stock
Issuable
$ 1,251
114
50 (e)
244
UE, CIPS, Genco, CILCO and IP as well as certain
other nonregistrant Ameren subsidiaries are subject to
Section 305(a) of the Federal Power Act, which makes it
unlawful for any officer or director of a public utility, as
defined in the Federal Power Act, to participate in the
making or paying of any dividend from any funds “properly
included in capital account.” The meaning of this limitation
has never been clarified under the Federal Power Act or
FERC regulations; however, FERC has consistently
interpreted the provision to allow dividends to be paid as
long as (1) the source of the dividends is clearly disclosed,
(2) the dividends are not excessive and (3) there is no
self-dealing on the part of corporate officials. At a
minimum, Ameren believes that dividends can be paid by
its subsidiaries that are public utilities from net income and
retained earnings. In addition, under Illinois law, CIPS,
CILCO and IP may not pay any dividend on their
respective stock, unless, among other things, their
respective earnings
132
and earned surplus are sufficient to declare and pay a
dividend after provision is made for reasonable and proper
reserves, or unless CIPS, CILCO or IP has specific
authorization from the ICC.
UE’s mortgage indenture contains certain provisions
that restrict the amount of common dividends that can be
paid by UE. Under this mortgage indenture, $31 million of
total retained earnings was restricted against payment of
common dividends, except those dividends payable in
common stock, which left $1.8 billion of free and
unrestricted retained earnings at December 31, 2009.
CIPS’ articles of incorporation and mortgage
indentures require its dividend payments on common
stock to be based on ratios of common stock to total
capitalization and other provisions related to certain
operating expenses and accumulations of earned surplus.
CILCO’s articles of incorporation prohibit the payment
of dividends on its common stock from either paid-in
surplus or any surplus created by a reduction of stated
capital or capital stock. Dividend payment is also
prohibited if at the time of dividend declaration the earned
surplus account (after deducting the payment of such
dividends) would not contain an amount at least equal to
two times the annual dividend requirement on all
outstanding shares of CILCO’s preferred stock.
Genco’s indenture includes provisions that require
Genco to maintain certain interest coverage and debt-to-
capital ratios in order for Genco to pay dividends, to make
certain principal or interest payments, to make certain
loans to or investments in affiliates, or to incur additional
indebtedness. The following table summarizes these
ratios for the 12 months ended December 31, 2009:
Required
Interest
Coverage
Ratio
Genco(a) .................. 1.75(b)
(a)
Actual
Interest
Coverage
Ratio
5.62
Required
Debt-to-
Capital
Ratio
60%
Actual
Debt-to-
Capital
Ratio
52%
Interest coverage ratio relates to covenants about certain dividend,
principal, and interest payments on certain subordinated intercompany
borrowings. The debt-to-capital ratio relates to a debt incurrence
covenant, which also requires an interest coverage ratio of 2.5 for the
four fiscal quarters most recently ended.
(b) Ratio excludes amounts payable under Genco’s intercompany note to
CIPS. The ratio must be met both for the prior four fiscal quarters and for
the succeeding four six-month periods.
Genco’s debt incurrence-related ratio restrictions and
restricted payment limitations under its indenture may be
disregarded if both Moody’s and S&P reaffirm the ratings
of Genco in place at the time of the debt incurrence after
considering the additional indebtedness.
In order for the Ameren Companies to issue securities
in the future, they will have to comply with all applicable
tests in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2009, none of the Ameren
Companies had any off-balance-sheet financing
arrangements, other than operating leases entered into in
the ordinary course of business. None of the Ameren
Companies expect to engage in any significant off-
balance-sheet financing arrangements in the near future.
133
NOTE 6 – OTHER INCOME AND EXPENSES
The following table presents Other Income and Expenses for each of the Ameren Companies for the years ended
December 31, 2009, 2008, and 2007:
Ameren:(a)
Miscellaneous income:
Interest and dividend income ...................................................................................................................................
Interest income on industrial development revenue bonds .......................................................................................
Allowance for equity funds used during construction ................................................................................................
Other .......................................................................................................................................................................
Total miscellaneous income ..........................................................................................................................................
Miscellaneous expense:
Donations ................................................................................................................................................................
Other .......................................................................................................................................................................
Total miscellaneous expense ........................................................................................................................................
UE:
Miscellaneous income:
Interest and dividend income ...................................................................................................................................
Interest income on industrial development revenue bonds .......................................................................................
Allowance for equity funds used during construction ................................................................................................
Other .......................................................................................................................................................................
Total miscellaneous income ..........................................................................................................................................
Miscellaneous expense:
Donations ................................................................................................................................................................
Other .......................................................................................................................................................................
Total miscellaneous expense ........................................................................................................................................
CIPS:
Miscellaneous income:
Interest and dividend income ...................................................................................................................................
Other .......................................................................................................................................................................
Total miscellaneous income ..........................................................................................................................................
Miscellaneous expense:
Donations ................................................................................................................................................................
Other .......................................................................................................................................................................
Total miscellaneous expense ........................................................................................................................................
Genco:
Miscellaneous income:
Interest and dividend income ...................................................................................................................................
Total miscellaneous income ..........................................................................................................................................
Miscellaneous expense:
Other .......................................................................................................................................................................
Total miscellaneous expense ........................................................................................................................................
CILCO:
Miscellaneous income:
Interest and dividend income ...................................................................................................................................
Other .......................................................................................................................................................................
Total miscellaneous income ..........................................................................................................................................
Miscellaneous expense:
Donations ................................................................................................................................................................
Other .......................................................................................................................................................................
Total miscellaneous expense ........................................................................................................................................
IP:
Miscellaneous income:
Interest and dividend income ...................................................................................................................................
Allowance for equity funds used during construction ................................................................................................
Other .......................................................................................................................................................................
Total miscellaneous income ..........................................................................................................................................
Miscellaneous expense:
Donations ................................................................................................................................................................
Other .......................................................................................................................................................................
Total miscellaneous expense ........................................................................................................................................
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
134
2009
2008
2007
$
2
28
36
5
$ 71
$ (12)
(11)
$ (23)
$
1
28
33
1
$ 63
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(3)
(4)
(7)
5
3
8
(1)
(1)
(2)
-
-
-
-
1
-
1
(1)
(4)
(5)
$
-
2
1
$ 3
$
$
(2)
(1)
(3)
$ 15
28
28
9
$ 80
$ (13)
(18)
$ (31)
$
5
28
28
1
$ 62
$
$
(3)
(6)
(9)
$
9
2
$ 11
$
$
$
$
$
$
$
$
$
$
(2)
(1)
(3)
1
1
(1)
(1)
1
1
2
(2)
(3)
(5)
$
5
-
6
$ 11
$
$
(3)
(2)
(5)
$ 27
28
5
15
$ 75
$
$
(13)
(12)
(25)
$
4
28
4
2
$ 38
$
$
(2)
(5)
(7)
$ 16
1
$ 17
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(2)
(1)
(3)
-
-
-
-
4
1
5
(1)
(5)
(6)
8
-
6
14
(3)
(2)
(5)
NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of
changes in market prices for natural gas, coal, diesel,
electricity, uranium, and emission allowances. Such price
fluctuations may cause the following:
an unrealized appreciation or depreciation of our
contracted commitments to purchase or sell when
purchase or sale prices under the commitments are
compared with current commodity prices;
market values of coal, natural gas, and uranium
inventories or emission allowances that differ from the
cost of those commodities in inventory; and
actual cash outlays for the purchase of these
commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are
governed by our risk management policies for forward
contracts, futures, options, and swaps. Our net positions
are continually assessed within our structured hedging
programs to determine whether new or offsetting
transactions are required. The goal of the hedging
program is generally to mitigate financial risks while
ensuring that sufficient volumes are available to meet our
requirements. Contracts we enter into as part of our risk
management program may be settled financially, settled
by physical delivery, or net settled with the counterparty.
The following table presents open gross derivative volumes by commodity type as of December 31, 2009:
Commodity
NPNS
Contracts(a)
Cash Flow
Hedges(b)
Quantity
Other
Derivatives(c)
Derivatives Subject to
Regulatory Deferral(d)
Coal (in tons)
Natural gas (in mmbtu)
Ameren(e) ............................................................................... 114,747,000
UE .........................................................................................
80,540,000
Genco ....................................................................................
17,403,000
CILCO ....................................................................................
7,782,000
Ameren(e) ............................................................................... 164,843,000
UE .........................................................................................
21,683,000
CIPS ......................................................................................
27,625,000
Genco ....................................................................................
(f )
CILCO ....................................................................................
49,580,000
IP .........................................................................................
65,956,000
Heating oil (in gallons)
Ameren(e) ...............................................................................
UE .........................................................................................
Genco ....................................................................................
CILCO ....................................................................................
Power (in megawatthours)
(f )
(f )
(f )
(f )
Ameren(e) ...............................................................................
UE .........................................................................................
CIPS ......................................................................................
CILCO ....................................................................................
IP .........................................................................................
Uranium (in pounds)
Ameren ..................................................................................
UE .........................................................................................
75,948,000
3,579,000
(f )
(f )
(f )
32,136,000
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
28,104,000
5,390,000
(f )
7,383,000
(f )
(f )
94,254,000
(f )
48,126,000
21,286,000
22,182,000
608,000
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
(f )
136,266,000
20,730,000
22,228,000
(f )
36,368,000
56,941,000
117,300,000
117,300,000
(f )
(f )
35,871,000
4,071,000
10,494,000
5,406,000
15,900,000
250,000
250,000
(a) Contracts through December 2013, March 2015, and September 2035 for coal, natural gas, and power, respectively.
(b) Contracts through December 2012 for power.
(c) Contracts through April 2012, December 2013, and May 2013 for natural gas, heating oil, and power, respectively.
(d) Contracts through October 2015, December 2013, December 2012, and November 2011 for natural gas, heating oil, power, and uranium, respectively.
(e)
(f) Not applicable.
Includes amounts from Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Authoritative accounting guidance regarding derivative
instruments requires that all contracts considered to be
derivative instruments be recorded on the balance sheet
at their fair values, unless the NPNS exception applies.
See Note 8 – Fair Value Measurements for discussion of
our methods of assessing the fair value of derivative
instruments. Many of our physical contracts, such as our
coal and purchased power contracts, qualify for the NPNS
exception to derivative accounting rules. The revenue or
expense recorded in connection with NPNS contracts is
recognized at the contract price upon physical delivery.
If we determine that a contract meets the definition of
a derivative and is not eligible for the NPNS exception, we
review the contract to determine if it qualifies for hedge
accounting treatment. We also consider whether gains or
losses resulting from such derivatives qualify for
regulatory deferral. Contracts that qualify for cash flow
hedge accounting treatment are recorded at fair value with
135
changes in fair value charged or credited to accumulated
OCI in the period in which the change occurs, to the
extent the hedge is effective. To the extent the hedge is
ineffective, the related changes in fair value are charged
or credited to the statement of income in the period in
which the change occurs. When the contract is settled or
delivered, the net gain or loss is recorded in the statement
of income.
Derivative contracts that qualify for regulatory deferral
are recorded at fair value, with changes in fair value
recorded as regulatory assets or regulatory liabilities in the
period in which the change occurs. Regulatory assets or
regulatory liabilities are amortized to the statement of
income as related losses and gains are reflected in rates
charged to customers.
Certain derivative contracts are entered into on a
regular basis as part of our risk management program but
do not qualify for the NPNS exception, hedge accounting,
or regulatory deferral accounting. Such contracts are
recorded at fair value, with changes in fair value charged
or credited to the statement of income in the period in
which the change occurs.
Authoritative accounting guidance permits companies
to offset fair value amounts recognized for the right to
reclaim cash collateral (a receivable) or the obligation to
return cash collateral (a liability) against fair value
amounts recognized for derivative instruments that are
executed with the same counterparty under the same
master netting arrangement. The Ameren Companies did
not elect to adopt this guidance for any eligible financial
instruments or other items.
The following table presents the carrying value and balance sheet classification of all derivative instruments as of
December 31, 2009:
Balance Sheet Location
Ameren (a)
UE
CIPS
Genco
CILCO
IP
Derivative assets designated as hedging instruments
Commodity contracts:
Power ........................................... MTM derivative assets ............................
Other assets ...........................................
Total assets ...........................................
Derivative liabilities designated as hedging instruments
Commodity contracts:
Power ........................................... MTM derivative liabilities .........................
Total liabilities .......................................
Derivative assets not designated as hedging instruments
Commodity contracts:
Natural gas.................................... MTM derivative assets ............................
Other current assets ................................
Other assets ...........................................
Heating oil ..................................... MTM derivative assets ............................
Other current assets ................................
Other assets ...........................................
Power ........................................... MTM derivative assets ............................
Other assets ...........................................
Total assets ...........................................
Derivative liabilities not designated as hedging instruments
Commodity contracts:
$ 20
4
$ 24
$
$
1
1
$ 19
-
4
39
-
41
43
10
$ 156
$
$
-
-
-
$ (b )
-
$
$ 2
-
-
22
-
23
7
-
$ 54
Natural gas.................................... MTM derivative liabilities .........................
Other current liabilities .............................
Other deferred credits and liabilities.........
Heating oil ..................................... MTM derivative liabilities .........................
Other current liabilities .............................
Other deferred credits and liabilities.........
Power ........................................... MTM derivative liabilities .........................
MTM derivative liabilities - affiliates .........
Other current liabilities .............................
Other deferred credits and liabilities.........
Uranium ........................................ MTM derivative liabilities .........................
Other current liabilities .............................
Other deferred credits and liabilities.........
Total liabilities .......................................
$ (b )
10
6
(b )
9
3
(b )
(b )
8
-
(b )
1
1
$ 38
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
$ 55
-
44
15
-
5
37
(b )
-
4
1
-
1
$ 162
(a)
(b) Balance sheet line item not applicable to registrant.
$ (b )
-
-
$
$
$
-
-
$ (b )
1
-
(b )
-
-
(b )
-
$ 1
$ 8
-
8
-
-
-
2
43
-
95
-
-
-
$ 156
$ (b)
-
-
$
$ (b)
-
$
$ (b)
-
-
(b)
9
9
(b)
-
$ 18
$ (b)
1
-
(b)
3
1
(b)
(b)
-
-
(b)
-
-
$ 5
$ (b )
-
-
$
$
$
-
-
$ (b )
2
1
(b )
4
4
(b )
-
$ 11
$ 7
-
8
2
-
-
1
19
-
49
-
-
-
$ 86
$
$
$
$
$
$
(b )
-
-
-
-
(b )
1
1
(b )
-
-
(b )
-
2
$ 17
-
19
-
-
-
3
65
-
145
-
-
-
$ 249
136
The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in
accumulated OCI and regulatory assets or regulatory liabilities as of December 31, 2009 and 2008:
2009:
Cumulative gains (losses) deferred in accumulated OCI:
Power forwards(b) ....................................................................................
Interest rate swaps(c)(d) ............................................................................
Cumulative gains (losses) deferred in regulatory liabilities or assets:
Natural gas swaps, forwards and futures contracts(e) ...............................
Power forwards(f) .....................................................................................
Heating oil options and swaps(g) ..............................................................
Uranium swaps(h).....................................................................................
2008:
Cumulative gains (losses) deferred in accumulated OCI:
Power forwards(b) ....................................................................................
Interest rate swaps(c)(d) ............................................................................
Cumulative losses deferred in regulatory assets:
Natural gas swaps, forwards and futures contracts(e) ...............................
Power forwards(f) .....................................................................................
Ameren (a)
UE
CIPS
Genco
CILCO
IP
$ 24
(10)
(75)
(10)
5
(2)
$ 84
(11)
(118)
-
$
-
-
(13 )
(1 )
5
(2 )
$ 40
-
(16 )
-
$
-
-
(15 )
(140 )
-
-
$
-
-
(27 )
(56 )
$
-
(10 )
-
-
-
-
$
-
(11 )
-
-
$
-
-
(12 )
(69 )
-
-
$
-
-
(25 )
(29 )
$
$
-
-
(34)
(213)
-
-
-
-
(50)
(85)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) Represents net gains associated with power forwards at Ameren as of December 31, 2009. The power forwards are a partial hedge of electricity price
(c)
(d)
exposure through August 2012 as of December 31, 2009. Current gains of $22 million and $123 million were recorded at Ameren as of December 31, 2009
and 2008, respectively. UE recorded current gains of $39 million as of December 31, 2008.
Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover
the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period that began in June 2002. The carrying value at
December 31, 2009 and 2008, was $1 million and $2 million, respectively. Over the next twelve months, $0.7 million of the gain will be amortized.
Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest
rate risks associated with Genco’s April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April
2008. The carrying value at December 31, 2009 and 2008, was a loss of $11 million and $13 million, respectively. Over the next twelve months, $1.4 million
of the loss will be amortized.
(e) Represents net losses associated with natural gas swaps, forwards and futures contracts. The swaps, forwards and futures contracts are a partial hedge of
natural gas requirements through October 2014 at IP, through March 2015 at UE and CIPS, and through October 2015 at CILCO, in each case as of
December 31, 2009. Current gains deferred as regulatory liabilities include $1 million, $1 million, $2 million, and $1 million at UE, CIPS, CILCO and IP,
respectively, as of December 31, 2009. Current losses deferred as regulatory assets include $8 million, $8 million, $7 million, and $17 million at UE, CIPS,
CILCO and IP, respectively, as of December 31, 2009. Current gains deferred as regulatory liabilities include $10 million, $16 million, $17 million, and $36
million at UE, CIPS, CILCO and IP, respectively, as of December 31, 2008.
(f) Represents net losses associated with power forwards. The power forwards are a partial hedge of power price exposure through December 2011 at UE and
December 2012 at CIPS, CILCO and IP, in each case as of December 31, 2009. Current gains deferred as regulatory liabilities include $5 million at UE as of
December 31, 2009. Current losses deferred as regulatory assets include $6 million, $45 million, $20 million, and $68 million at UE, CIPS, CILCO and IP,
respectively, as of December 31, 2009. Current losses deferred as regulatory assets include $14 million, $7 million, and $21 million at CIPS, CILCO and IP,
respectively, as of December 31, 2008.
(g) Represents net gains on heating oil options and swaps at UE. The options and swaps are a partial hedge of our transportation costs for coal through
(h) Represents net losses on uranium swaps at UE. The swaps are a partial hedge of our uranium requirements through November 2011 as of December 31,
December 2013 as of December 31, 2009. Current gains deferred as regulatory liabilities include $5 million at UE as of December 31, 2009. Current losses
deferred as regulatory assets include $9 million at UE as of December 31, 2009.
2009. Current losses deferred as regulatory assets include $1 million at UE as of December 31, 2009.
Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to
the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of
the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit
risk management program involves establishing credit limits and collateral requirements for counterparties, using master
trading and netting agreements, and reporting daily exposure to senior management.
We believe that entering into master trading and netting agreements mitigates the level of financial loss that could
result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following
master trading and netting agreements: (1) International Swaps and Derivatives Association agreement, a standardized
financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison
Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of
wholesale power; and (3) North American Energy Standards Board Inc. agreement, a standardized contract for the
purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale
and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level
by counterparty.
137
Concentrations of Credit Risk
In determining our concentrations of credit risk related to derivative instruments, we review our individual
counterparties and categorize each counterparty into one of eight groupings according to the primary business in which
each engages. The following table presents the maximum exposure as of December 31, 2009, if counterparty groups
were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of
financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding
right to net transactions based on master trading and netting agreements.
Affiliates (a)
Ameren( b ) .................. $ 517
UE .............................
-
CIPS ...........................
-
Genco .........................
-
CILCO ........................
-
IP .............................
-
Coal
Producers
$ 9
5
-
2
1
-
Electric
Utilities
$ 23
7
-
2
-
-
Financial
Companies
$ 123
30
1
3
3
2
Commodity
Marketing
Companies
$ 16
2
-
1
-
-
Municipalities/
Cooperatives
$ 165
22
-
-
-
-
Oil and
Gas
Companies
$ 11
-
-
6
-
1
Retail
Companies
$ 63
-
-
-
-
-
Total
$ 927
66
1
14
4
3
(a) Primarily comprised of Marketing Company’s exposure to Ameren Illinois Utilities related to financial contracts. The exposure is not eliminated at the
consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14 – Related Party
Transactions for additional information on these financial contracts.
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The following table presents the amount of cash collateral held from counterparties as of December 31, 2009, based
(b)
on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the
individual master trading and netting agreements:
Affiliates
Coal
Producers
$ -
Electric
Utilities
$ -
Financial
Companies
$ 7
Commodity
Marketing
Companies
$ 3
Municipalities/
Cooperatives
$ -
Oil and
Gas
Companies
$ -
Retail
Companies
$ -
Total
$ 10
Ameren(a) ................... $ -
(a) Represents amounts held by Marketing Company. As of December 31, 2009, Ameren registrant subsidiaries held no cash collateral.
The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading
and netting agreements. Collateral includes both cash collateral and other collateral held. Other collateral consisted of
letters of credit in the amount of $32 million, $1 million and $1 million held by Ameren, UE and Genco, respectively, as of
December 31, 2009. The following table presents the potential loss after consideration of collateral and application of
master trading and netting agreements as of December 31, 2009:
Affiliates (a)
Ameren(b) ................... $ 515
UE .............................
-
CIPS ...........................
-
Genco .........................
-
CILCO ........................
-
IP .............................
-
Coal
Producers
$ -
-
-
-
-
-
Electric
Utilities
$ 11
5
-
2
-
-
Financial
Companies
$ 93
26
-
-
1
-
Commodity
Marketing
Companies
$ 3
1
-
-
-
-
Municipalities/
Cooperatives
$ 132
21
-
-
-
-
Oil and
Gas
Companies
$ 10
-
-
5
-
1
Retail
Companies
$ 61
-
-
-
-
-
Total
$ 825
53
-
7
1
1
(a) Primarily comprised of Marketing Company’s exposure to Ameren Illinois Utilities related to financial contracts. The exposure is not eliminated at the
consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14 – Related Party
Transactions for additional information on these financial contracts.
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b)
138
Derivative Instruments with Credit Risk-Related Contingent Features
Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to
experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding
performance of an obligation requested adequate assurance of performance, additional collateral postings might be
required. The following table presents, as of December 31, 2009, the aggregate fair value of all derivative instruments with
credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of
additional collateral required to be posted with counterparties. The additional collateral required is the net liability position
allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features
underlying these agreements were triggered on December 31, 2009, and (2) those counterparties with rights to do so
requested collateral:
Cash
Collateral Posted
Ameren(c) ..............................................................................
$ 61
UE ........................................................................................
8
CIPS ......................................................................................
3
Genco ....................................................................................
-
CILCO ...................................................................................
-
IP ........................................................................................
11
(a) Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
(b) As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral
Aggregate Amount of Additional
Collateral Required(b)
$ 367
129
29
48
44
52
Aggregate Fair Value of
Derivative Liabilities(a)
$ 500
151
41
60
56
71
required to be posted is determined after consideration of the effects of such agreements.
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(c)
Cash Flow Hedges
The following table presents the pretax net gain or loss associated with derivative instruments designated as cash
flow hedges for the year ended December 31, 2009:
Derivatives in
Cash Flow
Hedging
Relationship
Amount of
Gain (Loss)
Recognized in OCI
on Derivatives(a)
Location of (Gain) Loss
Reclassified from
Accumulated OCI into
Income(b)
Amount of
(Gain) Loss
Reclassified from
Accumulated OCI
into Income(b)
Location of Gain (Loss)
Recognized in Income on
Derivatives(c)
Amount of Gain
(Loss) Recognized
in Income on
Derivatives(c)
Ameren:(d)
Power .....................................
Interest rate(e) ..........................
Power .....................................
UE:
Genco:
$ 41
-
(21 )
Operating Revenues –
Electric
Interest Charges
Operating Revenues –
Electric
$ (101)
(f)
(19)
Operating Revenues –
Electric
Interest Charges
Operating Revenues –
Electric
Interest Charges
$
(16 )
-
2
-
Interest Charges
Interest rate(e) ..........................
(a) Effective portion of gain (loss).
(b) Effective portion of (gain) loss on settlements.
(c)
(d)
(e) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-
Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
Includes amounts from Ameren registrants and nonregistrant subsidiaries.
year period.
Less than $1 million.
-
(f)
(f)
139
Other Derivatives
The following table represents the net change in market value associated with derivatives not designated as hedging
instruments for the year ended December 31, 2009:
Ameren(a)
UE
Genco
CILCO
Derivatives Not Designated
as Hedging Instruments
Location of Gain (Loss)
Recognized in Income on
Derivatives
Natural gas (generation) ....................................... Operating Expenses - Fuel.............................
Natural gas (resale) .............................................. Operating Revenues - Gas.............................
Heating oil ............................................................ Operating Expenses - Fuel.............................
Power ................................................................... Operating Revenues - Electric .......................
SO2 emission allowances ..................................... Operating Expenses - Fuel.............................
Natural gas (generation) ....................................... Operating Expenses - Fuel.............................
Heating oil ............................................................ Operating Expenses - Fuel.............................
Total
Natural gas (generation) ....................................... Operating Expenses - Fuel.............................
Heating oil ............................................................ Operating Expenses - Fuel.............................
SO2 emission allowances ..................................... Operating Expenses - Fuel.............................
Total
Natural gas (resale) .............................................. Operating Revenues - Gas.............................
Heating oil ............................................................ Operating Expenses - Fuel.............................
Total
Total
Amount of Gain (Loss)
Recognized in Income
on Derivatives
$
5
6
52
(25 )
1
$ 39
2
$
25
$ 27
(1 )
$
17
1
$ 17
6
$
4
$ 10
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Derivatives Subject to Regulatory Deferral
The following table represents the net change in
market value associated with derivatives that qualify for
regulatory deferral for the year ended December 31, 2009:
Derivatives
Subject to
Regulatory
Deferral
UE
Ameren(a) Natural gas ......................................
Heating oil .......................................
Power ..............................................
Uranium...........................................
Total
Natural gas ......................................
Heating oil .......................................
Power ..............................................
Uranium...........................................
Total
Natural gas ......................................
Power ..............................................
Total
Natural gas ......................................
Power ..............................................
Total
Natural gas ......................................
Power ..............................................
Total
CILCO
CIPS
IP
(a)
Includes intercompany eliminations.
$
$
Amount of Gain
(Loss) Recognized
in Regulatory
Liabilities or
Assets on
Derivatives
41
$
5
(8 )
(2 )
36
3
5
(1 )
(2 )
5
12
(85 )
(73 )
11
(38 )
(27 )
$
$ 15
(127 )
(112 )
$
$
$
$
$
UE, CIPS, CILCO and IP believe derivative gains and
losses deferred as regulatory assets and regulatory
liabilities are probable of recovery or refund through future
rates charged to customers. Regulatory assets and
regulatory liabilities are amortized to operating expenses
as related losses and gains are reflected in revenue
through rates charged to customers. Therefore, gains and
losses on these derivatives have no effect on operating
income.
As part of the electric rate order issued by the MoPSC
in January 2009, UE was granted permission to implement
a FAC, which was effective March 1, 2009. UE uses
derivatives to mitigate its exposure to changing prices of
fuel for generation and related transportation costs, and
for power price volatility. In connection with the MoPSC’s
approval of the FAC, gains and losses associated with
these types of derivatives are considered refundable to, or
recoverable from, customers and thus represent
regulatory liabilities or regulatory assets, respectively.
During the first quarter of 2009, UE recorded a net
regulatory liability of $5 million associated with the
reclassification of unrealized gains and losses previously
recorded in accumulated OCI and earnings related to
open UE derivative positions with delivery dates
subsequent to March 1, 2009. The reclassification of
previously recorded unrealized gains associated with the
derivatives resulted in a $47 million reduction of
accumulated OCI. The reclassification of previously
recognized unrealized losses resulted in a $42 million
increase in pretax earnings, of which $38 million offset fuel
expense and $4 million increased operating revenues.
See Note 2 – Rate and Regulatory Matters for additional
information on the FAC.
140
As part of the 2007 Illinois Electric Settlement
Agreement and the 2009 RFP process, the Ameren Illinois
Utilities entered into financial contracts with Marketing
Company. These financial contracts are derivative
instruments. They are accounted for as cash flow hedges
by Marketing Company and as derivatives subject to
regulatory deferral by the Ameren Illinois Utilities.
Consequently, the Ameren Illinois Utilities and Marketing
Company record the fair value of the contracts on their
respective balance sheets and the changes to the fair
value in regulatory assets or liabilities by the Ameren
Illinois Utilities and OCI by Marketing Company. In
Ameren’s consolidated financial statements, all financial
statement effects of the derivative instruments are
eliminated. See Note 14 – Related Party Transactions
under Part II, Item 8 of the Form 10-K for additional
information on these financial contracts.
NOTE 8 – FAIR VALUE MEASUREMENTS
Fair value is defined as the exchange price that would
be received for an asset or paid to transfer a liability (an
exit price) in the principal or most advantageous market
for the asset or liability in an orderly transaction between
market participants on the measurement date. We use
various methods to determine fair value, including market,
income, and cost approaches. With these approaches, we
adopt certain assumptions that market participants would
use in pricing the asset or liability, including assumptions
about market risk or the risks inherent in the inputs to the
valuation. Inputs to valuation can be readily observable,
market-corroborated, or unobservable. We use valuation
techniques that maximize the use of observable inputs
and minimize the use of unobservable inputs. Authoritative
accounting guidance established a fair value hierarchy
that prioritizes the inputs used to measure fair value. All
financial assets and liabilities carried at fair value are
classified and disclosed in one of the following three
hierarchy levels:
Level 1: Inputs based on quoted prices in active markets
for identical assets or liabilities. Level 1 assets and
liabilities are primarily exchange-traded derivatives and
assets, including U.S. treasury securities and listed equity
securities, such as those held in UE’s Nuclear
Decommissioning Trust Fund.
Level 2: Market-based inputs corroborated by third-party
brokers or exchanges based on transacted market data.
Level 2 assets and liabilities include certain assets held in
UE’s Nuclear Decommissioning Trust Fund, including
corporate bonds and other fixed-income securities, and
certain over-the-counter derivative instruments, including
natural gas swaps and financial power transactions.
Derivative instruments classified as Level 2 are valued
using corroborated observable inputs, such as pricing
services or prices from similar instruments that trade in
liquid markets. Our development and corroboration
process entails obtaining multiple quotes or prices from
outside sources. To derive our forward view to price our
derivative instruments at fair value, we average the
midpoints of the bid/ask spreads. To validate forward
prices obtained from outside parties, we compare the
pricing to recently settled market transactions.
Additionally, a review of all sources is performed to
identify any anomalies or potential errors. Further, we
consider the volume of transactions on certain trading
platforms in our reasonableness assessment of the
averaged midpoint.
Level 3: Unobservable inputs that are not corroborated by
market data. Level 3 assets and liabilities are valued
based on internally developed models and assumptions or
methodologies that use significant unobservable inputs.
Level 3 assets and liabilities include derivative instruments
that trade in less liquid markets, where pricing is largely
unobservable, including the financial contracts entered
into between the Ameren Illinois Utilities and Marketing
Company. We value Level 3 instruments by using pricing
models with inputs that are often unobservable in the
market, as well as certain internal assumptions. Our
development and corroboration process entails obtaining
multiple quotes or prices from outside sources. As a part
of our reasonableness review, an evaluation of all sources
is performed to identify any anomalies or potential errors.
We perform an analysis each quarter to determine the
appropriate hierarchy level of the assets and liabilities
subject to fair value measurements. Financial assets and
liabilities are classified in their entirety according to the
lowest level of input that is significant to the fair value
measurement. All assets and liabilities whose fair value
measurement is based on significant unobservable inputs
are classified as Level 3.
In accordance with applicable authoritative accounting
guidance, we consider nonperformance risk in our
valuation of derivative instruments by analyzing the credit
standing of our counterparties and considering any
counterparty credit enhancements (e.g., collateral). The
guidance also requires that the fair value measurement of
liabilities reflect the nonperformance risk of the reporting
entity, as applicable. Therefore, we have factored the
impact of our credit standing as well as any potential credit
enhancements into the fair value measurement of both
derivative assets and derivative liabilities. Included in our
valuation, and based on current market conditions, is a
valuation adjustment for counterparty default derived from
market data such as the price of credit default swaps,
bond yields, and credit ratings. Ameren recorded losses
totaling less than $1 million in 2009 related to valuation
adjustments for counterparty default risk. At December 31,
2009, the counterparty default risk valuation adjustment
related to net derivative (assets) liabilities totaled $3
million, $- million, $6 million, $- million, $8 million, and $10
million for Ameren, UE, CIPS, Genco, CILCO and IP,
respectively.
141
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value
on a recurring basis as of December 31, 2009:
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant Other
Unobservable Inputs
(Level 3)
Derivative assets(b) ...................................................
Nuclear Decommissioning Trust Fund(c) ...................
Derivative assets......................................................
Nuclear Decommissioning Trust Fund(c) ...................
Derivative assets(b) ...................................................
Derivative assets(b) ...................................................
Derivative assets(b) ...................................................
Derivative assets(b) ...................................................
Derivative liabilities(b) ................................................
Derivative liabilities(b) ................................................
Derivative liabilities(b) ................................................
Derivative liabilities(b) ................................................
Derivative liabilities(b) ................................................
Derivative liabilities(b) ................................................
$ 13
232
1
232
-
-
-
-
$ 26
8
-
-
-
1
$
3
60
2
60
-
-
-
-
$
2
2
-
-
-
-
$ 164
-
51
-
1
18
11
2
$ 135
28
156
5
86
248
Total
$ 180
292
54
292
1
18
11
2
$ 163
38
156
5
86
249
Assets:
Ameren(a)
UE
CIPS
Genco
CILCO
IP
Liabilities:
Ameren(a)
UE
CIPS
Genco
CILCO
IP
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 million of receivables, payables, and accrued income, net.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value
on a recurring basis as of December 31, 2008:
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant Other
Unobservable Inputs
(Level 3)
Other current assets .................................................
Derivative assets(b) ...................................................
Nuclear Decommissioning Trust Fund(c) ...................
Derivative assets ......................................................
Nuclear Decommissioning Trust Fund(c) ...................
Derivative liabilities(b) ................................................
Derivative liabilities(b) ................................................
Derivative liabilities(b) ................................................
Derivative liabilities(b) ................................................
Derivative liabilities(b) ................................................
Derivative liabilities(b) ................................................
$
-
1
164
-
164
$
9
-
-
-
4
-
$
$
-
19
81
14
81
6
3
-
-
-
-
$
6
234
2
36
2
$ 219
31
84
1
55
134
Total
$
6
254
247
50
247
$ 234
34
84
1
59
134
Assets:
Ameren(a)
UE
Liabilities:
Ameren(a)
UE
CIPS
Genco
CILCO
IP
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes ($8) million of receivables, payables, and accrued income, net.
142
The following table summarizes the changes in the fair value associated with financial assets and liabilities classified
as Level 3 in the fair value hierarchy for the year ended December 31, 2009:
Realized and Unrealized Gains
(Losses)
Included in
Regulatory
Assets/
Liabilities
-
$
(85 )
$
8
(161 )
-
(77 )
(264 )
-
$
Included
in OCI
-
$
$ 58
37
(10 )
-
(5 )
(15 )
-
$
Included in
Earnings(a)
-
$
$ 75
-
-
4
(18)
-
-
$
Total
Realized
and
Unrealized
Gains
(Losses)
-
$
$ 48
45
(171)
4
(100)
(279)
-
$
Purchases,
Issuances,
and Other
Settlements,
Net
-
$
$ 35
(6)
100
10
80
167
(2)
$
Net
Transfers
into (out of)
Level 3
(6)
$
$ (69)
(21)
-
-
-
-
$ -
Ending
Balance at
December 31,
2009
$
$
-
29
23
(155)
13
(75)
(246)
-
$
$
Change in
Unrealized
Gains (Losses)
Related to
Assets/
Liabilities Still
Held at
December 31,
2009
$
$
-
(2)
2
(107)
-
(54)
(172)
-
Other current assets Ameren .......... $
Net derivative
contracts
Beginning
Balance at
January 1,
2009
6
Ameren .......... $ 15
5
UE .................
(84 )
CIPS ..............
(1 )
Genco ............
(55 )
CILCO ...........
(134 )
IP ...................
2
Ameren .......... $
Nuclear
Decommissioning
Trust Fund
UE .................
2
-
-
-
-
(2)
-
-
-
(a) See Note 7 – Derivative Financial Instruments for additional information regarding the recording of net gains and losses on derivatives to the statement of
income.
The following table summarizes the changes in the fair value associated with financial assets and liabilities classified
as Level 3 in the fair value hierarchy for the year ended December 31, 2008:
Realized and Unrealized Gains
(Losses)
Included in
Regulatory
Assets/
Liabilities
-
(35 )
13
(127 )
-
(43 )
(209 )
-
Included
in OCI
- $
$
$ 13 $
13
-
-
-
-
- $
$
Included in
Earnings
-
$
$ (18)
1
(1)
(2)
(34)
(1)
$ -
Total
Realized
and
Unrealized
Gains
(Losses)
-
$
(40 )
$
27
(128 )
(2 )
(77 )
(210 )
-
$
Purchases,
Issuances,
and Other
Settlements,
Net
$
$
-
8
(42)
6
-
1
21
(3)
$
Change in
Unrealized
Gains (Losses)
Related to
Assets/
Liabilities Still
Held at
December 31,
2008
-
$
$ (206 )
(6 )
(106 )
-
(62 )
(174 )
$ -
Net
Transfers
into (out of)
Level 3
$ 6
$ 28
17
-
-
-
-
-
$
$
$
Ending
Balance at
December 31,
2008
6
15
5
(84 )
(1 )
(55 )
(134 )
2
$
Other current assets Ameren .......... $
Net derivative
contracts
Beginning
Balance at
January 1,
2008
-
Ameren .......... $ 19
UE ..................
3
CIPS ..............
38
Genco ............
1
CILCO ............
21
IP ...................
55
Ameren .......... $
5
Nuclear
Decommissioning
Trust Fund
UE ..................
5
-
-
-
-
(3)
-
2
-
Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a
higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or
(2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level
because the lowest significant input became observable during the period. Transfers between Level 2 and Level 3 were
primarily caused by changes in availability of financial power trades observable on electronic exchanges from previous
periods. Any reclassifications are reported as transfers in/out of Level 3 at the fair value measurement reported at the
beginning of the period in which the changes occur.
See Note 11 – Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement
plan assets as of December 31, 2009, as well as a table summarizing the changes in Level 3 plan assets during 2009.
The Ameren Companies’ carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings,
and accounts payable approximate fair value because of the short-term nature of these instruments. The estimated fair
value of long-term debt and preferred stock is based on the quoted market prices for same or similar issues for companies
with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments.
143
The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock
at December 31, 2009 and 2008:
Ameren:(a)(b)
Long-term debt and capital lease obligations (including current portion) ...............
Preferred stock ....................................................................................................
UE:
Long-term debt and capital lease obligations (including current portion) ...............
Preferred stock ....................................................................................................
CIPS:
Long-term debt (including current portion) ............................................................
Preferred stock ....................................................................................................
Genco:
Long-term debt (including current portion) ............................................................
CILCO:
Long-term debt (including current portion) ............................................................
Preferred stock ....................................................................................................
IP:
Long-term debt (including current portion) ............................................................
Preferred stock ....................................................................................................
2009
Carrying Amount
Fair Value
Carrying Amount
Fair Value
2008
$ 7,317
195
$ 4,022
113
$ 421
50
$ 7,719
150
$ 4,152
95
$
436
31
$ 6,934
195
$ 3,677
113
$
421
50
$ 6,144
100
$ 3,156
62
$
371
22
$ 1,023
$ 1,046
$
774
$
661
$ 279
19
$ 1,147
46
$
311
15
$ 1,295
35
$
279
19
$ 1,400
46
$
255
10
$ 1,326
24
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) Preferred stock along with the 20% noncontrolling interest of EEI is recorded in Noncontrolling Interests on the balance sheet.
NOTE 9 – NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS
UE has investments in debt and equity securities that are held in a trust fund for the purpose of funding the
decommissioning of its Callaway nuclear plant. See Note 16 – Callaway Nuclear Plant for additional information. We have
classified these investments as available for sale, and we have recorded all such investments at their fair market value at
December 31, 2009, and 2008.
Investments in the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities,
with the balance invested in debt securities. Due to market conditions in 2008, the equity securities weighting was less
than targeted levels at December 31, 2008. In January 2009, UE rebalanced its investments to align with its targeted
equity securities weighting.
The following table presents proceeds from the sale of investments in UE’s nuclear decommissioning trust fund and
the gross realized gains and losses resulting from those sales for the years ended December 31, 2009, 2008, and 2007:
Proceeds from sales .............................................................................................................................................................
Gross realized gains .............................................................................................................................................................
Gross realized losses ............................................................................................................................................................
2009
$ 380
5
10
2008
$ 497
5
8
2007
$ 128
4
3
Net realized and unrealized gains and losses are deferred and recorded as regulatory assets or regulatory liabilities
on Ameren’s and UE’s Consolidated Balance Sheets. This reporting is consistent with the method used to account for the
decommissioning costs recovered in rates. Gains or losses associated with assets in the trust fund could result in lower or
higher funding requirements for decommissioning costs, which are expected to be reflected in electric rates paid by UE’s
customers. See Note 2 – Rate and Regulatory Matters.
144
The following table presents the costs and fair values of investments in debt and equity securities in UE’s nuclear
Cost
Gross Unrealized Gain
Gross Unrealized Loss
decommissioning trust fund at December 31, 2009 and 2008:
Security Type
2009:
Debt securities ..................................................................
Equity securities ................................................................
Cash .................................................................................
Other(b) .............................................................................
Total .................................................................................
2008:
Debt securities ..................................................................
Equity securities ................................................................
Cash .................................................................................
Other(b) .............................................................................
Total .................................................................................
(a) Amount less than $1 million.
(b) Represents payables relating to pending security purchases, net of receivables related to pending securities sales and interest receivables.
The following table presents the costs and fair values of investments in debt securities in UE’s nuclear
$ 95
137
(a )
1
$ 233
$ 109
123
2
(8 )
$ 226
$ 3
72
-
-
$ 75
$ 5
40
-
-
$ 45
$ 1
14
-
-
$ 15
$ 3
29
-
-
$ 32
decommissioning trust fund according to their contractual maturities at December 31, 2009:
Fair Value
$ 97
195
(a)
1
$ 293
$ 111
134
2
(8)
$ 239
Less than 5 years .................................................................................................................................................................
5 years to 10 years ...............................................................................................................................................................
Due after 10 years ................................................................................................................................................................
Total .....................................................................................................................................................................................
Cost
$ 50
25
20
$ 95
Fair Value
$ 51
26
20
$ 97
We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust
fund, recorded as regulatory assets as discussed above. Decommissioning will not occur until the operating license for
our nuclear facility expires. UE intends to submit a license extension application to the NRC to extend the Callaway
nuclear plant’s operating license to 2044. The following table presents the fair value and the gross unrealized losses of
the available-for-sale securities held in UE’s nuclear decommissioning trust fund. They are aggregated by investment
category and the length of time that individual securities have been in a continuous unrealized loss position at
December 31, 2009:
Debt securities ..............................................................................
Equity securities ............................................................................
Total .............................................................................................
(a) Amount less than $1 million.
NOTE 10 – PREFERRED STOCK
Less than 12 Months
Gross
Unrealized
Losses
$ 1
2
$ 3
Fair Value
$ 26
4
$ 30
12 Months or Greater
Gross
Unrealized
Losses
$ (a)
12
$ 12
Fair Value
$ 1
27
$ 28
Total
Fair Value
$ 27
31
$ 58
Gross
Unrealized
Losses
$ 1
14
$ 15
All classes of UE’s, CIPS’, CILCO’s and IP’s preferred stock are entitled to cumulative dividends and have voting
rights. The following table presents the outstanding preferred stock of UE, CIPS, CILCO and IP that is not subject to
mandatory redemption. The preferred stock is redeemable, at the option of the issuer, at the prices presented as of
December 31, 2009 and 2008:
UE:
Without par value and stated value of $100 per share, 25 million shares authorized
$3.50 Series
$3.70 Series
$4.00 Series
$4.30 Series
$4.50 Series
$4.56 Series
$4.75 Series
$5.50 Series A
$7.64 Series
Total ...................................................................................................................................
130,000 shares .........................................................................
40,000 shares .........................................................................
150,000 shares .........................................................................
40,000 shares .........................................................................
213,595 shares .........................................................................
200,000 shares .........................................................................
20,000 shares .........................................................................
14,000 shares .........................................................................
330,000 shares .........................................................................
Redemption Price (per share)
2009
2008
$ 110.00
104.75
105.625
105.00
110.00(a)
102.47
102.176
110.00
101.27(b)
$ 13
4
15
4
21
20
2
1
33
$ 113
$ 13
4
15
4
21
20
2
1
33
$ 113
145
Redemption Price (per share)
2009
2008
CIPS:
With par value of $100 per share, 2 million shares authorized
4.00% Series
150,000 shares ......................................................................
4.25% Series
50,000 shares ......................................................................
4.90% Series
75,000 shares ......................................................................
4.92% Series
50,000 shares ......................................................................
5.16% Series
50,000 shares ......................................................................
6.625% Series
125,000 shares ......................................................................
Total .............................................................................................................................
CILCO:
With par value of $100 per share, 1.5 million shares authorized
$ 101.00
102.00
102.00
103.50
102.00
100.00
4.50% Series
4.64% Series
Total .............................................................................................................................
111,264 shares ..................................................................................................................
79,940 shares ..................................................................................................................
$ 110.00
102.00
IP:
With par value of $50 per share, 5 million shares authorized
4.08% Series
4.20% Series
4.26% Series
4.42% Series
4.70% Series
7.75% Series
Total .............................................................................................................................
Less: Shares of IP preferred stock owned by Ameren ........................................................
Total Ameren .....................................................................................................................
225,510 shares ..................................................................................................................
143,760 shares ..................................................................................................................
104,280 shares ..................................................................................................................
102,190 shares ..................................................................................................................
145,170 shares ..................................................................................................................
191,765 shares ..................................................................................................................
$ 51.50
52.00
51.50
51.50
51.50
50.00
$ 15
5
8
5
5
12
$ 50
$ 11
8
$ 19
$ 12
7
5
5
7
10
$ 46
(33)
$ 195
$ 15
5
8
5
5
12
$ 50
$ 11
8
$ 19
$ 12
7
5
5
7
10
$ 46
(33 )
$ 195
In the event of voluntary liquidation, $105.50.
(a)
(b) Redemption price as of December 31, 2009. Declining to $100 per share in 2012.
In addition, the Ameren Companies have classes of preferred stock that are authorized but no shares of which are
outstanding. Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no shares outstanding.
CIPS has 2.6 million shares of no par value preferred stock authorized, with no shares outstanding. UE has 7.5 million
shares of $1 par value preference stock authorized, with no such preference stock outstanding. CILCO has 2 million
shares of no par value preference stock authorized, with no such preference stock outstanding. CILCO also has
3.5 million shares of no par value preferred stock authorized, with no shares outstanding. IP has 5 million shares of no par
value serial preferred stock authorized and 5 million shares of no par value preference stock authorized, with no such
serial preferred stock and preference stock outstanding.
NOTE 11 – RETIREMENT BENEFITS
The primary objective of the Ameren retirement plan and postretirement benefit plans is to provide eligible employees
with pension and postretirement health care and life insurance benefits. We offer defined benefit and postretirement
benefit plans covering substantially all employees of UE, CIPS, CILCO, IP, EEI, and Ameren Services and certain
employees of Resources Company and its subsidiaries, including Genco. Ameren uses a measurement date of
December 31 for its pension and postretirement benefit plans.
The following table presents the benefit liability recorded on the balance sheets of each of the Ameren Companies as
of December 31, 2009:
Ameren(a) .................................................................................................................................................................................................................. $ 1,171
UE ............................................................................................................................................................................................................................
403
CIPS ..........................................................................................................................................................................................................................
59
Genco ........................................................................................................................................................................................................................
51
CILCO .......................................................................................................................................................................................................................
194
IP ............................................................................................................................................................................................................................
238
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
146
Ameren recognizes the underfunded status of its pension and postretirement plans as a liability on its balance sheet,
with offsetting entries to accumulated OCI and regulatory assets, in accordance with authoritative accounting guidance.
The following table presents the funded status of our pension and postretirement benefit plans as of December 31, 2009
and 2008. It also provides the amounts included in regulatory assets and accumulated OCI at December 31, 2009 and
2008, that have not been recognized in net periodic benefit costs.
Accumulated benefit obligation at end of year ..........................................
Change in benefit obligation:
Net benefit obligation at beginning of year ..........................................
Service cost .......................................................................................
Interest cost .......................................................................................
Plan amendments ..............................................................................
Participant contributions .....................................................................
Actuarial (gain) loss ............................................................................
Benefits paid ......................................................................................
Federal subsidy on benefits paid ........................................................
Net benefit obligation at end of year .........................................................
Change in plan assets:
Fair value of plan assets at beginning of year .....................................
Actual return on plan assets ...............................................................
Employer contributions .......................................................................
Federal subsidy on benefits paid ........................................................
Participant contributions .....................................................................
Benefits paid ......................................................................................
Fair value of plan assets at end of year ....................................................
Funded status – deficiency.......................................................................
Accrued benefit cost at December 31 .......................................................
Amounts recognized in the balance sheet consist of:
Current liability ...................................................................................
Noncurrent liability ..............................................................................
Total ...................................................................................................
Amounts recognized in regulatory assets consist of:
Net actuarial loss ................................................................................
Prior service cost (credit) ....................................................................
Transition obligation ...........................................................................
Amounts recognized in accumulated OCI consist of:
Net actuarial loss ................................................................................
Prior service cost (credit) ....................................................................
Total ...................................................................................................
2009
Pension Benefits(a)
$ 3,041
Postretirement
Benefits(a)
(b )
$
2008
Pension Benefits(a)
$ 3,051
Postretirement
Benefits(a)
(b)
$
$ 3,303
68
186
-
-
(133)
(169)
(b)
3,255
2,393
172
99
-
-
(169)
2,495
760
760
$
$
$
$
$
3
757
760
487
33
-
28
8
556
$ 1,182
19
66
-
17
(74 )
(72 )
5
1,143
593
140
49
5
17
(72 )
732
411
411
3
408
411
167
(37 )
9
25
(13 )
151
$
$
$
$
$
$ 3,076
60
186
2
-
145
(166 )
(b )
3,303
2,698
(205 )
66
-
-
(166 )
2,393
910
$ 910
$
2
908
$ 910
$ 597
40
-
57
10
$ 704
$ 1,253
18
70
-
14
(105)
(73)
5
1,182
787
(187)
47
5
14
(73)
593
589
589
2
587
589
327
(40)
12
43
(16)
326
$
$
$
$
$
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
(b) Not applicable.
The market value of plan assets in 2008 declined by 7% and 26% for the pension and postretirement benefit plans,
respectively. In 2008, investment losses in Ameren’s pension plan were partially offset by a gain on interest rate swaps,
which had a notional value of $700 million at December 31, 2008. The swaps were intended to mitigate the impacts on the
funded status of the plan resulting from decreases in the discount rate in the calculation of the pension liability. During
2008, U.S. Treasury yields declined significantly, which resulted in Ameren’s pension plan recognizing a $336 million net
gain from its interest rate swaps. Ameren closed its interest rate swap position in early 2009. Prior to closing its swap
position, U.S. Treasury yields increased, which resulted in Ameren’s pension plan recognizing a $74 million net loss in
2009. Ameren’s postretirement benefit plans did not have a similar interest rate hedge.
The following table presents the assumptions used to determine our benefit obligations at December 31, 2009 and
2008:
Discount rate at measurement date ..................................................................................
Increase in future compensation ......................................................................................
Medical cost trend rate (initial)..........................................................................................
Medical cost trend rate (ultimate) .....................................................................................
Years to ultimate rate .......................................................................................................
Pension Benefits
2008
2009
5.75%
5.75%
3.50
4.00
-
-
-
-
-
-
Postretirement Benefits
2008
2009
5.75%
5.75%
3.50
4.00
6.50
7.00
5.00
5.00
3 years
4 years
147
Investment Strategy and Policies
Ameren manages plan assets in accordance with the
“prudent investor” guidelines contained in ERISA. The
investment committee, to the extent authority is delegated
to it by the finance committee of Ameren’s board of
directors, implements investment strategy and asset
allocation guidelines for the plan assets. The investment
committee is composed of members of senior
management. The investment committee’s goals are
twofold: first, to ensure that sufficient funds are available
to provide the benefits at the time they are payable, and
second, to maximize total return on plan assets and
minimize expense volatility consistent with its tolerance for
risk. Ameren delegates investment management to
specialists in each asset class. As appropriate, Ameren
provides the investment manager with guidelines that
specify allowable and prohibited investment types. The
investment committee regularly monitors manager
performance and compliance with investment guidelines.
The expected return on plan assets is based on
historical and projected rates of return for current and
planned asset classes in the investment portfolio.
Projected rates of return for each asset class were
estimated after an analysis of historical experience, future
expectations, and the volatility of the various asset
classes. After considering the target asset allocation for
each asset class, we adjusted the overall expected rate of
return for the portfolio for historical and expected
experience of active portfolio management results
compared with benchmark returns and for the effect of
expenses paid from plan assets. The Ameren Companies
will utilize an expected return on plan assets of 8% in
2010. No plan assets are expected to be returned to
Ameren during 2010.
Ameren determines discount rate assumptions by
using an interest rate yield curve pursuant to authoritative
accounting guidance on the determination of discount
rates used for defined benefit plan obligations. The yield
curve is based on the yields of over 500 high-quality
corporate bonds with maturities between zero and 30
years. A theoretical spot-rate curve constructed from this
yield curve is then used as a guide to develop a discount
rate matching the plans’ payout structure.
Funding
Pension benefits are based on the employees’ years
of service and compensation. Ameren’s pension plan is
funded in compliance with income tax regulations and
federal funding or regulatory requirements. As a result,
Ameren expects to fund its pension plan at a level equal to
the greater of the pension expense or the legally required
minimum contribution. Considering Ameren’s assumptions
at December 31, 2009, its investment performance in
2009, and its pension funding policy, Ameren expects to
make annual contributions of $75 million to $225 million in
each of the next five years, with aggregate estimated
contributions of $740 million. We expect UE’s, CIPS’,
Genco’s, CILCO’s, and IP’s portion of the future funding
requirements to be 66%, 6%, 9%, 9%, and 10%,
respectively. These amounts are estimates. They may
change based on actual investment performance,
changes in interest rates, changes in our assumptions,
any pertinent changes in government regulations, and any
voluntary contributions. Our funding policy for
postretirement benefits is primarily to fund the Voluntary
Employee Beneficiary Association (VEBA) trusts to match
the annual postretirement expense.
The following table presents the cash contributions
made to our defined benefit retirement plan and to our
postretirement plans during 2009 and 2008:
Pension Benefits
2008
2009
Ameren(a) ................... $ 99
$ 66
UE ............................. 42
29
CIPS ...........................
6
4
Genco .........................
5
4
CILCO ........................ 12
6
IP ............................. 10
9
Postretirement
Benefits
2009
$ 49
13
1
-
7
20
2008
$ 47
10
1
-
7
21
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
148
Ameren’s investment committee strives to assemble a portfolio of diversified assets that does not create a significant
concentration of risks. The investment committee develops asset allocation guidelines between asset classes, and it
creates diversification through investments in assets that differ by type (equity, debt, real estate, private equity), duration,
market capitalization, country, style (growth or value) and industry, among other factors. The diversification of assets is
displayed in the target allocation table below. The investment committee also routinely rebalances the plan assets to
adhere to the diversification goals. The investment committee’s strategy reduces the concentration of investment risk;
however, Ameren is still subject to overall market risk. The following table presents our target allocations for 2010 and our
pension and postretirement plans’ asset categories as of December 31, 2009 and 2008.
Asset
Category
Target Allocation
2010
Pension Plan:
Cash and cash equivalents ................................................................................
Equity securities:
U.S. large capitalization ................................................................................
U.S. small and mid capitalization ..................................................................
International and emerging markets ..............................................................
Total equity ........................................................................................................
Debt securities ...................................................................................................
Real estate ........................................................................................................
Private equity .....................................................................................................
Total ..................................................................................................................
Postretirement Plans:
Cash and cash equivalents ................................................................................
Equity securities:
U.S. large capitalization ................................................................................
U.S. small and mid capitalization ..................................................................
International .................................................................................................
Total equity ........................................................................................................
Debt securities ...................................................................................................
Total ..................................................................................................................
0 - 5%
29 - 39
2 - 12
9 - 19
50 - 60
35 - 45
0 - 9
0 - 4
0 - 10%
33 - 43
3 - 13
10 - 20
55 - 65
30 - 40
Percentage of Plan Assets at December 31,
2009
2008
1%
32
10
15
57
37
4
1
100%
4%
39
10
12
61
35
100%
1%
16
10
9
35
56
6
2
100%
6%
20
21
12
53
41
100%
In general, the U.S. large capitalization equity investments are passively managed or indexed, whereas the
international, emerging markets, U.S. small capitalization, and U.S. mid capitalization equity investments are actively
managed by investment managers. Debt securities include a broad range of fixed income vehicles. Debt security
investments in high-yield securities, emerging market securities, and non-U.S. dollar-denominated securities are owned
by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active management
by investment managers. Real estate investments include private real estate vehicles; however, Ameren does not, by
policy, hold direct investments in real estate property. Ameren’s investment in private equity funds consists of 13 different
limited partnerships, with invested capital ranging from $200,000 to $10 million individually, which invest primarily in a
diversified number of small U.S.-based companies. No further commitments may be made to private equity investments
without approval by the finance committee of the board of directors. Additionally, Ameren’s investment committee allows
investment managers to use derivatives, such as index futures, exchange traded funds, foreign exchange futures, and
options, in certain situations, to increase or to reduce market exposure in an efficient and timely manner.
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2009. The
fair value of an asset is the amount that would be received upon sale in an orderly transaction between market
participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are
recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value
because of the short-term nature of these instruments. Investments traded in active markets on national or international
securities exchanges are valued at closing prices on the last business day on or before the measurement date. Securities
traded in over-the-counter markets are valued based on quoted market prices, broker or dealer quotations, or alternative
pricing sources with reasonable levels of price transparency. Derivative contracts are valued at fair value, as determined
by the investment managers (or independent third parties on behalf of the investment managers), who use proprietary
models and take into consideration exchange quotations on underlying instruments, dealer quotations, and other market
information. The fair value of real estate is based on annual appraisal reports prepared by an independent real estate
appraiser.
149
The following table sets forth, utilizing the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the
pension plan assets measured at fair value as of December 31, 2009:
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
$
Cash and cash equivalents ..................................................................
Equity securities:
1
Significant Other
Observable Inputs
(Level 2)
35
$
Significant Other
Unobservable
Inputs
(Level 3)
-
$
U.S. large capitalization ..................................................................
U.S. small and mid capitalization ....................................................
International and emerging markets ................................................
Debt securities:
Corporate bonds ............................................................................
Municipal bonds .............................................................................
U.S. treasury and agency securities ...............................................
Asset-backed securities ..................................................................
Other ..............................................................................................
Real estate ..........................................................................................
Private equity .......................................................................................
Derivative assets .................................................................................
Total ....................................................................................................
270
242
114
-
-
179
-
-
-
-
4
$ 810
556
10
264
579
44
30
19
102
-
-
-
$ 1,639
-
-
-
-
-
-
-
1
90
33
-
$ 124
Total
36
$
826
252
378
579
44
209
19
103
90
33
4
$ 2,573(a)(b)
(a)
Includes $77 million of medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue
Code (401(h) accounts) to fund a portion of the postretirement obligation.
(b) Excludes $1 million net payable related to pending security purchases.
The following table summarizes the changes in the fair value of the pension plan assets classified as Level 3 in the
fair value hierarchy for the year ended December 31, 2009:
Other debt securities .........
Real estate .......................
Private equity ....................
Beginning
Balance at
January 1, 2009
$
1
144
39
Actual Return on
Plan Assets Related
to Assets Still Held
at the Reporting Date
$
-
(53 )
(6 )
Actual Return on
Plan Assets Related
to Assets Sold
During the Period
$
-
(2 )
3
Purchases,
Sales, and
Settlements, net
$ -
1
(3 )
Net
Transfers
into (out of)
of Level 3
$ -
-
-
Ending Balance at
December 31, 2009
$
1
90
33
The following table sets forth, utilizing the fair value hierarchy discussed in Note 8 – Fair Value Measurements, the
postretirement benefit plans assets measured at fair value as of December 31, 2009:
Cash and cash equivalents ....................................................................
Equity securities:
U.S. large capitalization ....................................................................
U.S. small and mid capitalization ......................................................
International .....................................................................................
Debt securities:
Corporate bonds ..............................................................................
Municipal bonds ...............................................................................
U.S. treasury and agency securities .................................................
Asset-backed securities ....................................................................
Other ................................................................................................
Derivative assets ...................................................................................
Total ......................................................................................................
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
1
$
Significant Other
Observable Inputs
(Level 2)
$ 26
Significant Other
Unobservable
Inputs
(Level 3)
$
-
193
64
35
3
-
14
-
-
1
$ 311
60
-
45
66
58
35
23
28
-
$ 341
-
-
-
-
-
-
-
-
-
$ -
Total
27
$
253
64
80
69
58
49
23
28
1
$ 652(a)(b)
(a) Excludes $77 million of medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h)
assets are included in the pension plan assets shown above.
(b) Excludes net $3 million of Medicare and interest receivables, offset by payables related to pending security purchases.
150
Net Periodic Benefit Cost
The following table presents the components of the net periodic benefit cost of our pension and postretirement benefit
plans during 2009, 2008, and 2007:
2009:
Service cost ....................................................................................................................................
Interest cost ....................................................................................................................................
Expected return on plan assets .......................................................................................................
Amortization of:
Transition obligation ..................................................................................................................
Prior service cost ......................................................................................................................
Actuarial loss ............................................................................................................................
Net periodic benefit cost ..................................................................................................................
2008:
Service cost ....................................................................................................................................
Interest cost ....................................................................................................................................
Expected return on plan assets .......................................................................................................
Amortization of:
Transition obligation ..................................................................................................................
Prior service cost ......................................................................................................................
Actuarial loss ............................................................................................................................
Net periodic benefit cost ..................................................................................................................
2007:
Service cost ....................................................................................................................................
Interest cost ....................................................................................................................................
Expected return on plan assets .......................................................................................................
Amortization of:
Transition obligation ..................................................................................................................
Prior service cost ......................................................................................................................
Actuarial loss ............................................................................................................................
Net periodic benefit cost ..................................................................................................................
Pension Benefits
Ameren(a)
Postretirement Benefits
Ameren(a)
$
68
186
(206 )
-
9
24
81
60
186
(213 )
-
11
3
47
63
180
(206 )
-
11
22
70
$
$
$
$
$
$ 19
66
(54)
2
(8)
9
$ 34
$ 18
70
(58)
2
(8)
9
$ 33
$ 21
72
(53)
2
(8)
24
$ 58
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The current year expected return on plan assets is primarily determined by adjusting the prior-year market-related
asset value for current year contributions, disbursements, and expected return, plus 25% of the actual return in excess of
(or less than) expected return for the four prior years.
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit
cost in 2010 are as follows:
Regulatory assets:
Accumulated OCI:
Transition obligation ................................................................................................................
Prior service cost (credit) .........................................................................................................
Net actuarial loss .....................................................................................................................
Transition obligation ................................................................................................................
Prior service cost (credit) .........................................................................................................
Net actuarial loss .....................................................................................................................
Total .............................................................................................................................................
Pension Benefits
Ameren(a)
Postretirement Benefits
Ameren(a)
$
-
5
33
$
-
1
-
$ 39
$ 4
(4)
15
$
-
(3)
1
$ 13
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
151
Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting
under the plan. The net actuarial loss subject to amortization is amortized on a straight-line basis over 10 years.
UE, CIPS, Genco, CILCO and IP are responsible for their share of the pension and postretirement benefit costs. The
following table presents the pension costs and the postretirement benefit costs incurred for the years ended
December 31, 2009, 2008 and 2007:
Ameren(a) ..........................................................................................
UE ....................................................................................................
CIPS ..................................................................................................
Genco ................................................................................................
CILCO ...............................................................................................
IP ....................................................................................................
(a)
Pension Costs
2008
$ 47
35
7
5
5
(2 )
2007
$ 70
44
10
7
8
4
2009
$ 81
50
8
7
14
-
Postretirement Costs
2009
$ 34
15
2
3
7
12
2008
$ 33
13
3
2
6
14
$
2007
58
26
6
3
13
13
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The expected pension and postretirement benefit payments from qualified trust and company funds and the federal
subsidy for postretirement benefits related to prescription drug benefits, which reflect expected future service, as of
December 31, 2009, are as follows:
2010 ..........................................................................................................
2011 ..........................................................................................................
2012 ..........................................................................................................
2013 ..........................................................................................................
2014 ..........................................................................................................
2015 – 2019...............................................................................................
Pension Benefits
Paid from
Qualified
Trust
$ 194
201
208
214
222
1,225
Paid from
Company
Funds
$ 3
3
3
2
2
11
Postretirement Benefits
Paid from
Company
Funds
$ 3
3
3
3
3
16
Paid from
Qualified
Trust
$ 78
82
86
89
93
504
Federal
Subsidy
$ 5
5
6
6
6
32
The following table presents the assumptions used to determine net periodic benefit cost for our pension and
postretirement benefit plans for the years ended December 31, 2009, 2008, and 2007:
Pension Benefits
2008
2007
2009
Postretirement Benefits
2008
2009
Ameren, UE, CIPS , Genco, CILCO and IP:
Discount rate at measurement date .........................................
Expected return on plan assets ...............................................
Increase in future compensation .............................................
Medical cost trend rate (initial).................................................
Medical cost trend rate (ultimate) ............................................
Years to ultimate rate ..............................................................
6.05%
8.25
4.00
9.00
5.00
4 years
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
5.75%
8.00
4.00
7.00
5.00
4 years
5.85%
8.50
4.00
-
-
-
6.15%
8.25
4.00
-
-
-
5.75%
8.00
4.00
-
-
-
2007
5.80%
8.50
4.00
9.00
5.00
4 years
0.25% decrease in discount rate ......................................................
0.25% increase in salary scale .........................................................
1.00% increase in annual medical trend ...........................................
1.00% decrease in annual medical trend ..........................................
Other
Ameren sponsors a 401(k) plan for eligible
employees. The Ameren plan covered all eligible
employees of the Ameren Companies at December 31,
2009. The plans allowed employees to contribute a portion
of their base pay in accordance with specific guidelines.
Ameren matched a percentage of the employee
contributions up to certain limits. Ameren’s matching
contributions to the 401(k) plan totaled $24 million, $23
million, and $21 million in 2009, 2008, and 2007,
respectively.
Pension
Postretirement
$
Service Cost and
Interest Cost
-
2
-
-
Projected Benefit
Obligation
$ 93
13
-
-
$
Service Cost and
Interest Cost
-
-
2
(2 )
Postretirement
Benefit Obligation
$ 31
-
32
(29 )
The following table presents the portion of the 401(k)
matching contribution to the Ameren plan attributable to
each of the Ameren Companies for the years ended
December 31, 2009, 2008, and 2007:
2007
Ameren(a) ..................................................................................................
$ 21
UE ............................................................................................................
14
CIPS ..........................................................................................................
1
Genco ........................................................................................................
1
CILCO .......................................................................................................
2
IP ............................................................................................................
3
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
2008
$ 23
14
2
2
2
2
2009
$ 24
14
2
2
4
2
(a)
152
NOTE 12 – Stock-Based Compensation
Ameren’s long-term incentive plan for eligible
employees, called the Long-term Incentive Plan of 1998
(1998 Plan), was replaced prospectively by the 2006
Omnibus Incentive Compensation Plan (2006 Plan)
effective May 2, 2006. The 2006 Plan provides for a
maximum of 4 million common shares to be available for
grant to eligible employees and directors. No new awards
may be granted under the 1998 Plan; however, previously
granted awards continue to vest or to be exercisable in
accordance with their original terms and conditions. The
2006 Plan awards may be stock options, stock
appreciation rights, restricted stock, restricted stock units,
performance shares, performance share units, cash-
based awards, and other stock-based awards.
A summary of nonvested shares as of December 31, 2009, and changes during the year ended December 31, 2009,
under the 1998 Plan and the 2006 Plan are presented below:
Nonvested at January 1, 2009...................................................................
Granted(a) .................................................................................................
Dividends ..................................................................................................
Unearned or forfeited(b) .............................................................................
Earned and vested(c) .................................................................................
Nonvested at December 31, 2009 .............................................................
Performance Share Units
Restricted Shares
Share Units
675,977
741,738
-
(247,065 )
(225,313 )
945,337
Weighted-average
Fair Value per Unit
$ 43.28
15.52
-
57.15
25.66
$ 22.07
Shares
213,683
-
7,934
(3,644 )
(82,277 )
135,696
Weighted-average
Fair Value per Share
$ 47.46
-
25.39
48.30
45.15
$ 48.92
(a)
(b)
(c)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in March 2009 under the
2006 Plan.
Includes share units granted in 2007 that were not earned based on performance provisions of the award grants.
Includes share units granted in 2007 that vested as of December 31, 2009, that were earned pursuant to the provisions of the award grants. Also includes
share units that vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary
depending on actual performance over the three-year measurement period.
Ameren recorded compensation expense of
$15 million, $22 million, and $18 million for the years
ended December 31, 2009, 2008, and 2007, respectively,
and a related tax benefit of $6 million, $8 million, and
$7 million for the years ended December 31, 2009, 2008,
and 2007, respectively. As of December 31, 2009, total
compensation cost of $8 million related to nonvested
awards not yet recognized is expected to be recognized
over a weighted-average period of 16 months.
relative to the designated peer group beginning January 1,
2009. The significant assumptions used to calculate fair
value also included a three-year risk-free rate of 1.24%,
volatility of 21.3% to 33.1% for the peer group, and
Ameren’s attainment of earnings per share of at least
$2.54 during each year of the three-year performance
period.
The fair value of each share unit awarded in February
Performance Share Units
Performance share unit awards were granted under
the 2006 Plan each year since 2006. A share unit will vest
and entitle an employee to receive shares of Ameren
common stock (plus accumulated dividends) if, at the end
of the three-year performance period, certain specified
performance or market conditions have been met and the
individual remains employed by Ameren. The exact
number of shares issued pursuant to a share unit will vary
from 0% to 200% of the target award, depending on actual
company performance relative to the performance goals.
For performance share units granted in 2006, 2007 and
2008, vested performance shares units are held for a 2-
year period before being paid to the employee in shares of
Ameren common stock. During this 2-year hold period, the
employee is paid dividend equivalents on a current basis.
The fair value of each share unit awarded in March
2009 under the 2006 Plan was determined to be $15.52.
That amount was based on Ameren’s closing common
share price of $22.20 at March 2, 2009, and lattice
simulations. Lattice simulations are used to estimate
expected share payout based on Ameren’s total
shareholder return for a three-year performance period
2008 under the 2006 Plan was determined to be $32.35.
That amount was based on Ameren’s closing common
share price of $44.30 at the grant date and lattice
simulations. The significant assumptions used to calculate
fair value also included a three-year risk-free rate of
2.264%, dividend yields of 2.3% to 5.4% for the peer
group, volatility of 14.43% to 21.51% for the peer group,
and Ameren’s attainment of earnings per share of at least
$2.54 during each year of the three-year performance
period.
Restricted Stock
Restricted stock awards of Ameren common stock
were granted under the 1998 Plan from 2001 to 2005.
Restricted shares have the potential to vest over a seven-
year period from the date of grant if the company achieves
certain performance levels. An accelerated vesting
provision included in this plan reduces the vesting period
from seven years to three years if the earnings growth rate
exceeds a prescribed level.
Stock Options
Options to purchase Ameren common stock were
granted under the 1998 Plan at a price not less than the
153
fair-market value of the common shares at the date of
grant. Granted options vest over a period of five years,
beginning at the date of grant, and they permit accelerated
exercising upon the occurrence of certain events,
including retirement. There have not been any stock
options granted since December 31, 2000. Outstanding
options of 58,350 at December 31, 2009, expired in
February 2010. There is no expense from stock options
for the years ended December 31, 2009, 2008 and 2007,
as all options granted were fully vested.
NOTE 13 – INCOME TAXES
The following table presents the principal reasons why the effective income tax rate differed from the statutory federal
income tax rate for the years ended December 31, 2009, 2008 and 2007:
Ameren
2009:
Statutory federal income tax rate: ....................................................
Increases (decreases) from:
Permanent items(a) ...............................................................
Depreciation differences ......................................................
Amortization of investment tax credit ....................................
State tax ..............................................................................
Reserve for uncertain tax positions ......................................
Other(b) ................................................................................
Effective income tax rate .................................................................
2008:
Statutory federal income tax rate: ....................................................
Increases (decreases) from:
Permanent items(a) ...............................................................
Depreciation differences ......................................................
Amortization of investment tax credit ....................................
State tax ..............................................................................
Reserve for uncertain tax positions ......................................
Other(c) ................................................................................
Effective income tax rate .................................................................
2007:
Statutory federal income tax rate: ....................................................
Increases (decreases) from:
Permanent items(a) ...............................................................
Depreciation differences ......................................................
Amortization of investment tax credit ....................................
State tax ..............................................................................
Reserve for uncertain tax positions ......................................
Other(d) ................................................................................
Effective income tax rate .................................................................
35%
(1 )
(1 )
(1 )
5
(1 )
(1 )
35%
35%
(1 )
-
(1 )
4
(1 )
(2 )
34%
35%
(2 )
-
(1 )
4
(1 )
(1 )
34%
UE
35%
-
(3)
(1)
3
-
(1)
33%
35%
1
(1)
(1)
3
(1)
-
36%
35%
(2)
-
(1)
4
(1)
(2)
33%
CIPS
Genco
CILCO
35%
-
(1)
(4)
5
1
-
36%
35%
(1)
(2)
(10)
5
(1)
(1)
25%
35%
2
3
(6)
6
-
(4)
36%
35%
(1)
-
-
4
-
-
38%
35%
(2)
-
-
5
(1)
(1)
36%
35%
(1)
-
(1)
5
-
-
38%
35%
(3)
-
-
4
(1)
-
35%
35%
(1)
(1)
(1)
5
-
(1)
36%
35%
(2)
(1)
(1)
3
-
-
34%
IP
35%
-
-
-
5
-
-
40%
35%
7
-
-
5
2
1
50%
35%
1
(3 )
-
5
-
(1 )
37%
(a) Permanent items are treated differently for book and tax purposes and primarily include Internal Revenue Code Section 199 production activity deductions for
Ameren, UE, Genco and CILCO, company-owned life insurance for Ameren and CILCO, impacts of Medicare Part D for Ameren, UE, Genco and CILCO,
employee stock ownership plan dividends for Ameren, and nondeductible expenses for IP.
(b) Primarily includes low-income housing tax credits and research credits for Ameren and UE.
(c) Primarily includes settlements with state taxing authorities for Ameren, state apportionment changes for Ameren, CIPS, Genco, and CILCO, research credits
for Ameren, Genco, and CILCO and low-income housing tax credits for Ameren and CIPS.
(d) Primarily includes low-income housing tax credits for Ameren, UE, CIPS and IP.
154
The following table presents the components of income tax expense (benefit) for the years ended December 31,
2009, 2008, and 2007:
2009:
Current taxes:
Deferred taxes:
Federal...........................................................................
State ..............................................................................
Federal...........................................................................
State ..............................................................................
Deferred investment tax credits, amortization .......................
Total income tax expense ....................................................
2008:
Current taxes:
Federal...........................................................................
State ..............................................................................
Deferred taxes:
Federal...........................................................................
State ..............................................................................
Deferred investment tax credits, amortization .......................
Total income tax expense ....................................................
2007:
Current taxes:
Federal...........................................................................
State ..............................................................................
Deferred taxes:
Ameren (a)
UE
CIPS
Genco
CILCO
IP
$
(73)
3
337
74
(9)
$ 332
$ 165
10
130
31
(9)
$ 327
$ 311
17
$
(117 )
(31 )
239
42
(5 )
$ 128
$
37
5
86
11
(5 )
$ 134
$ 13
8
(1)
(2)
(2)
$ 16
$
$
4
3
2
(2)
(2)
5
$
$
$
30
11
46
10
(1)
96
81
15
5
-
(1)
$ 100
$ 105
8
$ 21
2
$
49
9
$
$
$
$
$
21
11
34
7
(1 )
72
25
5
9
1
(1 )
39
36
5
$
$
$
$
$
(7)
6
45
9
-
53
(11)
(11)
17
10
-
5
3
(2)
Federal...........................................................................
State ..............................................................................
Deferred investment tax credits, amortization .......................
Total income tax expense ....................................................
(10)
(2)
(2)
9
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary
22
10
(5 )
$ 140
7
4
(9)
$ 330
1
(2 )
(1 )
39
17
4
(1)
78
(a)
$
$
$
$
11
3
-
15
differences at December 31, 2009 and 2008:
Ameren (a)
UE
CIPS
Genco
CILCO
IP
$ 2,813
3
52
(313 )
63
5
(43 )
12
$ 2,592
$ 1,717
(3)
54
(98)
-
-
(9)
11
$ 1,672
$ 197
79
(1 )
(3 )
-
-
-
(17 )
$ 255
$
$
324
(77 )
-
(25 )
-
-
(23 )
17
216
$ 282
-
(1 )
(56 )
-
-
(11 )
(10 )
$ 204
$
$
261
-
1
(18)
(24)
-
-
(5)
215
2009:
Accumulated deferred income taxes, net liability (asset):
Plant related ...............................................................
Deferred intercompany tax gain/basis step-up ............
Regulatory assets (liabilities), net ...............................
Deferred benefit costs ................................................
Purchase accounting ..................................................
Leveraged leases .......................................................
ARO ...........................................................................
Other ..........................................................................
Total net accumulated deferred income tax liabilities(b) ....
2008:
Accumulated deferred income taxes, net liability (asset):
Plant related ...............................................................
Deferred intercompany tax gain/basis step-up ............
Regulatory assets (liabilities), net ...............................
Deferred benefit costs ................................................
Purchase accounting ..................................................
Leveraged leases .......................................................
ARO ...........................................................................
Other ..........................................................................
Total net accumulated deferred income tax liabilities(c) .....
$
$ 2,377
4
37
(281 )
38
6
(27 )
(19 )
$ 2,135
$ 182
90
(3 )
(5 )
-
-
-
(10 )
$ 254
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Includes $18 million, $10 million, and $17 million as current assets recorded in the balance sheets for CIPS, CILCO and IP, respectively. Includes $38 million,
$12 million and $26 million as current liabilities recorded in the balance sheets for Ameren, UE and Genco respectively.
Includes $3 million, $5 million, $15 million, and $15 million as current assets recorded in the balance sheets for UE, CIPS, CILCO and IP, respectively.
Includes $4 million and $15 million as current liabilities recorded in the balance sheets for Ameren and Genco, respectively.
Ameren and IP have Illinois net operating loss carryforwards of $3 million and $1 million, respectively. These will
$ 1,427
(3)
44
(92)
-
-
5
(12)
$ 1,369
$ 242
-
(3 )
(59 )
-
-
(11 )
(13 )
$ 156
289
(87 )
-
(32 )
-
-
(21 )
2
151
205
-
-
(1)
(33)
-
-
(10)
161
$
$
$
(a)
(b)
(c)
begin to expire in 2017.
155
Uncertain Tax Positions
On January 1, 2007, the Ameren Companies adopted authoritative accounting guidance, which addressed the
determination of whether tax benefits claimed or expected to be claimed on an income tax return should be recorded in
the financial statements.
A reconciliation of the change in the unrecognized tax benefit balance during the years ended December 31, 2007,
2008 and 2009, is as follows:
Unrecognized tax benefits – January 1, 2007 ...................................................................
Increases based on tax positions prior to 2007 ...........................................................
Decreases based on tax positions prior to 2007 ..........................................................
Increases based on tax positions related to 2007 ........................................................
Changes related to settlements with taxing authorities ................................................
Decreases related to the lapse of statute of limitations ................................................
Unrecognized tax benefits – December 31, 2007 .............................................................
Increases based on tax positions prior to 2008 ...........................................................
Decreases based on tax positions prior to 2008 ..........................................................
Increases based on tax positions related to 2008 ........................................................
Changes related to settlements with taxing authorities ................................................
Decreases related to the lapse of statute of limitations ................................................
Unrecognized tax benefits – December 31, 2008 .............................................................
Increases based on tax positions prior to 2009 ...........................................................
Decreases based on tax positions prior to 2009 ..........................................................
Increases based on tax positions related to 2009 ........................................................
Changes related to settlements with taxing authorities ................................................
Decreases related to the lapse of statute of limitations ................................................
Unrecognized tax benefits – December 31, 2009 .............................................................
Total unrecognized tax benefits that, if recognized,
would impact the effective tax rates as of December 31, 2007 ....................................
Total unrecognized tax benefits (detriments) that, if recognized,
would impact the effective tax rates as of December 31, 2008 ....................................
Total unrecognized tax benefits that, if recognized,
would impact the effective tax rates as of December 31, 2009 ....................................
Ameren
$ 155
31
(21)
17
(60)
(6)
$ 116
16
(46)
31
(7)
-
$ 110
90
(84)
19
-
-
$ 135
$ 26
$ 12
$
6
UE
$ 58
4
(8)
6
(28)
(6)
$ 26
2
(13)
6
(1)
-
$ 20
76
(19)
11
-
-
$ 88
$
$
$
4
1
3
$
CIPS
$ 15
-
(3 )
-
(12 )
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$
$
$
$
$
-
-
-
Genco
$ 36
10
(8)
6
(4)
-
$ 40
4
(9)
13
(1)
-
$ 47
9
(31)
3
-
-
$ 28
$
$
$
-
(2)
-
CILCO
$ 18
3
-
5
(7)
-
$ 19
2
(4)
8
-
-
$ 25
5
(18)
3
-
-
$ 15
$ 1
$
-
$ 1
As of January 1, 2007, the Ameren Companies adopted a policy of recognizing interest charges (income) and
penalties accrued on tax liabilities on a pretax basis as interest charges (income) or miscellaneous expense in the
statements of income.
A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended
December 31, 2007, 2008 and 2009, is as follows:
$
IP
$ 12
-
(2)
-
(10)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$
$
$
$
$
-
-
-
Liability for interest – January 1, 2007 ..................................................................................
Interest charges for 2007 ................................................................................................
Liability for interest – December 31, 2007.............................................................................
Interest income for 2008 .................................................................................................
Liability for interest – December 31, 2008.............................................................................
Interest charges (income) for 2009 .................................................................................
Liability for interest – December 31, 2009.............................................................................
Ameren
$ 12
5
$ 17
(7)
$ 10
(2)
$ 8
UE
$ 5
-
$ 5
(3)
$ 2
2
$ 4
CIPS
$ 1
-
$ 1
(1)
-
-
-
$
$
Genco
$ 4
3
$ 7
(3 )
$ 4
(2 )
$ 2
CILCO
$ 1
1
$ 2
-
$ 2
(1)
$ 1
IP
$ -
-
$ -
-
$ -
-
$ -
As of January 1, 2007, December 31, 2007, December 31, 2008, and December 31, 2009, the Ameren Companies
have accrued no amount for penalties with respect to unrecognized tax benefits.
Ameren’s 2005 and 2006 federal income tax returns are before the Appeals Office of the Internal Revenue Service.
The Internal Revenue Service is currently examining Ameren’s 2007 and 2008 income tax returns.
State income tax returns are generally subject to examination for a period of three years after filing of the return. The
state impact of any federal changes remains subject to examination by various states for a period of up to one year after
formal notification to the states. The Ameren Companies do not currently have material state income tax issues under
examination, administrative appeals, or litigation.
It is reasonably possible that events will occur during the next 12 months that would cause the total amount of
unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not
believe such increases or decreases would be material to their financial condition or results of operations.
156
NOTE 14 – RELATED PARTY TRANSACTIONS
The Ameren Companies have engaged in, and may in
the future engage in, affiliate transactions in the normal
course of business. These transactions primarily consist of
gas and power purchases and sales, services received or
rendered, and borrowings and lendings. Transactions
between affiliates are reported as intercompany
transactions on their financial statements, but are
eliminated in consolidation for Ameren’s financial
statements. Below are the material related party
agreements.
2007 Illinois Electric Settlement Agreement
As part of the 2007 Illinois Electric Settlement
Agreement, the Ameren Illinois Utilities, Genco, and
AERG agreed to make aggregate contributions of $150
million over four years as part of a comprehensive
program to provide $1 billion of funding for rate relief to
certain Illinois electric customers, including customers of
the Ameren Illinois Utilities.
At December 31, 2009, CIPS, CILCO and IP had
receivable balances from Genco for reimbursement of
customer rate relief of less than $1 million each. Also at
December 31, 2009, CIPS, CILCO and IP had receivable
balances from AERG for reimbursement of customer rate
relief of less than $1 million each. During the year ended
December 31, 2009, Genco incurred charges to earnings
of $10 million for customer rate relief contributions and
program funding reimbursements to the Ameren Illinois
Utilities (CIPS – $3 million, CILCO – $2 million, IP –
$5 million), and AERG incurred charges to earnings of
$5 million (CIPS – $2 million, CILCO – $1 million, and IP –
$2 million). The Ameren Illinois Utilities recorded most of
the reimbursements received from Genco and AERG as
electric revenue. An immaterial amount was recorded as
miscellaneous revenue.
Electric Power Supply Agreements
The following table presents the amount of physical
gigawatthour sales under related party electric power
supply agreements for the years ended December 31,
2009, 2008, and 2007:
2009
Genco sales to
AERG sales to
Marketing Company
Marketing Company(a) .................... 13,372
Marketing Company(a) .................... 6,817
sales to CIPS(b) .............................. 1,283
sales to CILCO(b) ............................
sales to IP(b) ................................... 1,690
556
Marketing Company
Marketing Company
December 31,
2008
2007
16,551 17,425
6,677 5,316
2,050 2,396
909 1,167
2,870 3,493
(a) Both Genco and AERG have a power supply agreement with Marketing
Company whereby Genco and AERG sell and Marketing Company
purchases all the capacity and energy available from Genco’s and
AERG’s generation fleets.
power based on the results of the September 2006
Illinois power procurement auction. The values in this table reflect the
physical sales volumes provided in that agreement.
(b) Marketing Company contracted with CIPS, CILCO, and IP to provide
In December 2006, Genco and AERG entered into
two separate power supply agreements (PSA) with
Marketing Company, whereby Genco and AERG agreed
to sell and Marketing Company agreed to purchase all of
the capacity available from Genco’s and AERG’s
generation fleets and all of the associated energy. In
March 2008, Genco and AERG entered into an
amendment to their respective PSAs with Marketing
Company. Under the amendment, Genco and AERG are
liable to Marketing Company in the event of an unplanned
outage or derate (reduction in rated capacity) due to
sudden, unanticipated failure or accident within
the generating plant site of one or more of its generating
units. Genco’s and AERG’s liability in such cases will be
for the positive difference, if any, between the market price
of capacity or energy Genco and AERG do not deliver and
the contract price under the PSA for that capacity or
energy. An unplanned outage or derate that continues for
one year or more is an event of default under the PSA. In
the event of Marketing Company’s unexcused failure to
receive energy under the PSA, Marketing Company would
be required to pay Genco and AERG the positive
difference, if any, between the contract price and the price
that Genco and AERG, acting in a commercially
reasonable manner, actually receives when it resells the
unreceived energy, less any reasonable related
transmission, ancillary service, or brokerage costs. In
January 2010, Genco and AERG entered into an
amendment to their respective PSAs with Marketing
Company primarily because of the EEI ownership transfer
to Genco.
Both of the PSAs will continue through December 31,
2022, and from year to year thereafter unless either party
elects to terminate the agreement by providing the other
party with no less than six months advance written notice.
In accordance with a January 2006 ICC order, an
auction was held in September 2006 to procure power for
CIPS, CILCO and IP beginning January 1, 2007. Through
the auction, Marketing Company contracted with CIPS,
CILCO and IP to provide power for residential and small
commercial customers (less than one megawatt of
demand) as follows:
Term
Megawatts(a) .................
Cost per
megawatthour .........
May 31, 2008
17 Months
300
Term Ending
May 31, 2009
29 Months
750
May 31, 2010
41 Months
750
$ 64.77
$ 64.75
$ 66.05
(a) Before impact to Ameren Illinois Utilities’ load due to customer
switching.
Capacity Supply Agreements
To replace the power supply contracts that expired on
May 31, 2008, the Ameren Illinois Utilities used RFP
processes in early 2008, pursuant to the 2007 Illinois
Electric Settlement Agreement, to contract for the
necessary capacity requirements for the period from
June 1, 2008,
157
through May 31, 2009. Marketing Company and UE were two
of the winning suppliers in the Ameren Illinois Utilities’
capacity RFPs. Marketing Company contracted to supply a
portion of the Ameren Illinois Utilities’ capacity for $6 million.
In addition, UE contracted to supply a portion of the Ameren
Illinois Utilities’ capacity for $1 million.
CIPS, CILCO and IP, as electric load serving entities,
must acquire capacity sufficient to meet their obligations to
customers. In 2009, the Ameren Illinois Utilities used an RFP
process, administered by the IPA, to contract the necessary
capacity for the period from June 1, 2009, through May 31,
2012. Both Marketing Company and UE were winning
suppliers in the Ameren Illinois Utilities’ capacity RFP
process. In April 2009, Marketing Company contracted to
supply capacity to the Ameren Illinois Utilities for $4 million,
$9 million, and $8 million for the twelve months ending
May 31, 2010, 2011, and 2012, respectively. In April 2009,
UE contracted to supply capacity to the Ameren Illinois
Utilities for $2 million, $2 million, and $1 million for the twelve
months ending May 31, 2010, 2011, and 2012, respectively.
Energy Swaps
As part of the 2007 Illinois Electric Settlement
Agreement, the Ameren Illinois Utilities entered into financial
contracts with Marketing Company (for the benefit of Genco
and AERG), to lock in energy prices for 400 to 1,000
megawatts annually of their round-the-clock power
requirements during the period June 1, 2008, to
December 31, 2012, at then-relevant market prices. These
financial contracts do not include capacity, are not load-
following products, and do not involve the physical delivery of
energy. These financial contracts are derivative instruments.
They are accounted for as cash flow hedges by Marketing
Company and as derivatives subject to regulatory deferral by
Ameren Illinois Utilities. Consequently, the Ameren Illinois
Utilities and Marketing Company record the fair value of the
contracts on their respective balance sheets and the changes
to the fair value in regulatory assets or liabilities for the
Ameren Illinois Utilities and OCI at Marketing Company. See
Note 7 – Derivative Financial Instruments for additional
information on these derivatives. Below are the remaining
contracted volumes and prices per megawatthour as of
December 31, 2009:
Period
January 1, 2010 – May 31, 2010 .................. 800 MW
June 1, 2010 – December 31, 2010 ............. 1,000 MW
January 1, 2011 – December 31, 2011 ......... 1,000 MW
January 1, 2012 – December 31, 2012 ......... 1,000 MW
Volume
Price per
Megawatthour
$ 51.09
51.09
52.06
53.08
To replace the supply contracts that expired on May 31,
2008, the Ameren Illinois Utilities used RFP processes in
early 2008, pursuant to the 2007 Illinois Electric Settlement
Agreement, to contract for the necessary financial energy
swaps requirement for the period from June 1, 2008, through
May 31, 2009. Marketing Company was one of the winning
suppliers in the Ameren Illinois Utilities’ energy swap RFP
process. Marketing Company entered into financial
instruments that fixed the price that the Ameren Illinois
Utilities paid for about two million megawatthours at
approximately $60 per megawatthour.
CIPS, CILCO and IP, as electric load serving entities,
must acquire energy sufficient to meet their obligations to
customers. In 2009, the Ameren Illinois Utilities used an RFP
process, administered by the IPA, to procure financial energy
swaps from June 1, 2009, through May 31, 2011. Marketing
Company was a winning supplier in the Ameren Illinois
Utilities’ energy swap RFP process. In May 2009, Marketing
Company entered into financial instruments that fixed the
price that the Ameren Illinois Utilities will pay for
approximately 80,000 megawatthours at approximately
$48 per megawatthour during the twelve months ending
May 31, 2010 and for approximately 89,000 megawatthours
at approximately $48 per megawatthour during the twelve
months ending May 31, 2011.
Electric Resource Sharing Agreement
On June 1, 2008, FERC accepted an electric resource
sharing agreement among the Ameren Illinois Utilities for
various joint costs of the Ameren Illinois Utilities, including
capacity, renewable energy credits, and rate swaps. The
purpose of the agreement is to allocate these costs among
the Ameren Illinois Utilities in an equitable manner, based on
their respective retail loads.
Interconnection and Transmission Agreements
UE, CIPS and IP are parties to an interconnection
agreement for the use of their respective transmission lines
and other facilities for the distribution of power. In addition,
CILCO and IP, and CILCO and CIPS, are parties to similar
interconnection agreements. These agreements have no
contractual expiration date, but may be terminated by any
party with three years’ notice.
Generator Interconnection Agreement
In 2008, Genco and CIPS signed an agreement requiring
Genco to fund the construction costs of upgrades to CIPS’
transmission system. The transmission upgrades were
required to support the additional electric power upgrades
made at Genco’s Coffeen power plant. Under the agreement,
Genco paid CIPS for the costs of the transmission upgrades.
When the transmission assets were placed in service, CIPS
paid Genco, with interest, for the costs of the transmission
upgrades. In 2009, CIPS paid Genco $2 million when the
transmission assets were placed in service. These
transactions were eliminated in consolidation on Ameren’s
financial statements.
In September 2009, Marketing Company and CIPS
signed an agreement requiring Marketing Company to fund
the cost of certain upgrades to CIPS’ electric transmission
system. Under the agreement, Marketing Company paid
CIPS $5 million for the costs of the transmission upgrades.
These amounts were a contribution in aid of construction and
will not be refunded to Marketing Company. These
transactions were eliminated in consolidation on Ameren’s
financial statements.
158
Joint Ownership Agreement
In 2006, IP and AITC entered into a joint ownership
agreement to construct, own, operate, and maintain certain
electric transmission systems in Illinois. Under the terms of
this agreement, IP and AITC are responsible for their
applicable share of all costs related to the construction,
operation, and maintenance of electric transmission systems.
This agreement will terminate when either IP or AITC is the
sole owner of the transmission systems or when the
transmission systems are decommissioned.
Support Services Agreements
Ameren Services and AFS provide support services to
their affiliates. Ameren Energy, Inc. provided support services
until December 31, 2007. The cost of support services,
including wages, employee benefits, professional services,
and other expenses, are based on, or are an allocation of,
actual costs incurred.
CILCO Support Services
On January 1, 2009, approximately 570 Ameren
Services employees who provided support services to the
Ameren Illinois Utilities were transferred to CILCO (Illinois
Regulated). As CILCO employees, they provide services to
CIPS and IP as well as to CILCO. The cost of support
services provided by CILCO to CIPS and IP, including
wages, employee benefits, professional services, and other
expenses, are based on, or are an allocation of, actual costs
incurred.
Executory Tolling, Gas Sales, and Transportation
Agreements
Prior to 2009, under an executory tolling agreement,
CILCO purchased steam, chilled water, and electricity from
Medina Valley. In January 2009, CILCO transferred the
tolling agreement to Marketing Company. In connection with
the tolling agreement, Medina Valley purchases gas to fuel its
generating facility from AFS under a fuel supply and services
agreement.
Under a gas transportation agreement, Genco acquires
gas transportation service from UE for its Columbia, Missouri,
CTs. This agreement expires in February 2016.
Money Pools
See Note 5 – Long-term Debt and Equity Financings for
discussion of affiliate borrowing arrangements.
Intercompany Borrowings
On May 1, 2005, Genco issued to CIPS an amended and
restated subordinated promissory note in the principal
amount of $249 million with an interest rate of 7.125% per
year. Interest income and charges for this note recorded by
CIPS and Genco, respectively, were $4 million, $7 million,
and $10 million for the years ended December 31, 2009,
2008, and 2007, respectively. Genco’s subordinated note
payable to CIPS associated with the transfer in 2000 of CIPS’
electric generating assets and related liabilities to Genco
matures on May 1, 2010.
CILCO (AERG) had outstanding borrowings from
Ameren of $288 million at December 31, 2009, and had no
outstanding borrowings directly from Ameren at
December 31, 2008. The average interest rate on these
borrowings was 6.1% for the year ended December 31, 2009.
CILCO (AERG) recorded interest charges of $13 million for
Ameren borrowings for the year ended December 31, 2009.
UE had no outstanding borrowings directly from Ameren
at December 31, 2009, and had outstanding borrowings
directly from Ameren of $92 million at December 31, 2008.
The average interest rate on these borrowings was 1.2% for
the year ended December 31, 2009 (2008 – 3.6%). UE
recorded interest charges of less than $1 million, $1 million,
and $4 million for Ameren borrowings for the years ended
December 31, 2009, 2008, and 2007, respectively.
Collateral Postings
Under the terms of the power supply agreements
between Marketing Company and the Ameren Illinois Utilities,
which were entered into as part of the September 2006
Illinois power procurement auction, collateral must be posted
by Marketing Company under certain market conditions to
protect the Ameren Illinois Utilities in the event of
nonperformance by Marketing Company. The collateral
postings are unilateral, which means that Marketing
Company as the supplier is the only counterparty required to
post collateral. At December 31, 2009 and 2008, there were
no collateral postings necessary by Marketing Company
related to the 2006 auction power supply agreements.
Under the terms of the 2008 Illinois power procurement
RFPs, collateral had to be posted by Marketing Company
and the Ameren Illinois Utilities under certain market
conditions. The collateral postings were bilateral, which
means that either counterparty could be required to post
collateral. As of December 31, 2008, the Ameren Illinois
Utilities had cash collateral postings as follows with Marketing
Company: CIPS – $7 million, CILCO – $4 million, and IP –
$11 million. These bilateral collateral postings were
eliminated in consolidation on Ameren’s financial statements.
Under the terms of the 2009 Illinois power procurement
agreements entered into through an RFP process
administered by the IPA, suppliers must post collateral under
certain market conditions to protect the Ameren Illinois
Utilities in the event of nonperformance. The collateral
postings are unilateral, which means only the suppliers are
required to post collateral. Therefore, UE, as a winning
supplier of capacity, and Marketing Company, as a winning
supplier of capacity and financial energy swaps, may be
required to post collateral. As of December 31, 2009, there
were no collateral postings necessary between UE and the
Ameren Illinois Utilities or between Marketing Company and
the Ameren Illinois Utilities related to the 2009 Illinois power
procurement agreements.
159
Operating Leases
Under an operating lease agreement, Genco leased
certain CTs at a Joppa, Illinois, site to its former parent,
Development Company, for an initial term of 15 years,
expiring September 30, 2015. Under an electric power
supply agreement with Marketing Company, Development
Company supplied the capacity and energy from these
leased units to Marketing Company, which in turn supplied
the energy to Genco. By mutual agreement of the parties,
this lease agreement and this power supply agreement
were terminated in February 2008, when an internal
reorganization merged Development Company into
Resources Company. Genco recorded operating revenues
from the lease agreement of $2 million and $11 million for
the years ended December 31, 2008 and 2007,
respectively.
Intercompany Transfers
On January 1, 2008, UE transferred its interest in
Union Electric Development Corporation at book value to
Ameren by means of a $3 million dividend-in-kind. On
March 31, 2008, Union Electric Development Corporation
was merged into Ameren Development Company, with
Ameren Development Company surviving the merger.
On February 29, 2008, UE contributed its 40%
ownership interest in EEI, book value of $39 million, to
Resources Company, in exchange for a 50% interest in
Resources Company, and then immediately transferred its
interest in Resources Company to Ameren by means of a
$39 million dividend-in-kind. Also on February 29, 2008,
Development Company, which formerly held a 40%
ownership interest in EEI, merged into Ameren Energy
Resources Company, which then merged into Resources
Company. As a result, Resources Company had an 80%
ownership interest in EEI.
On January 1, 2010, as part of an internal
reorganization, Resources Company transferred its 80%
ownership interest in EEI to Genco, through a capital
contribution. The transfer of EEI to Genco was accounted
for as a transaction between entities under common
control, whereby Genco recognized the assets and
liabilities of EEI at their book value as of January 1, 2010.
The following table presents the impact on UE, CIPS, Genco, CILCO, and IP of related party transactions for the
years ended December 31, 2009, 2008 and 2007. It is based primarily on the agreements discussed above and the
money pool arrangements discussed in Note 4 – Credit Facility Borrowings and Liquidity.
Agreement
Genco and AERG power supply
agreements with Marketing Company
UE ancillary services and capacity
agreements with CIPS, CILCO and IP
UE and Genco gas transportation
agreement
Genco gas sales to Medina Valley
Genco gas sales to distribution companies
CILCO support services(b)
Total Operating Revenues
UE and Genco gas transportation
agreement
CIPS, CILCO and IP agreements with
Marketing Company
CIPS, CILCO and IP ancillary services and
capacity agreements with UE
Ancillary services agreement with
Marketing Company
Executory tolling agreement with Medina
Valley
Total Purchased Power
Income Statement Line Item
Operating Revenues
Operating Revenues
Operating Revenues
Operating Revenues
Operating Revenues
Operating Revenues
Fuel
Purchased Power
Purchased Power
Purchased Power
Purchased Power
Insurance recoveries
Operating Revenues and
Purchased Power
160
2009
2008
2007
2009
2008
2007
2009
2008
2007
2009
2009
2008
2009
2009
2008
2007
2009
2008
2007
2009
2008
2007
2009
2008
2007
2009
2008
2007
2009
2008
2007
2009
2008
2007
2009
2008
2007
UE
(a)
$
(a)
(a)
3
13
18
1
1
1
(a)
(a)
(a)
(a)
$ 4
14
19
(a)
$
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
-
(c)
(12)
$
$
$
$
$
CIPS
(a )
$
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
$ 140
145
157
1
4
6
(c )
6
3
(a )
(a )
(a )
$ 141
155
166
(a )
$
(a )
(a )
Genco
$ 850
893
831
(a)
(a)
(a)
(a)
(a)
(a)
1
2
7
(a)
$ 853
900
831
1
$
1
1
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
-
(11)
(2)
$
$
$
CILCO
$ 430
344
279
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
(a)
70
$ 500
344
279
(a)
$
(a)
(a)
$ 65
65
76
(c)
2
3
(c)
3
1
(d)
39
38
$ 65
109
118
-
$
(4)
(7)
IP
$
$
$
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
(a )
$ 195
204
227
1
7
9
(c )
8
4
(a )
(a )
(a )
$ 196
219
240
(a )
(a )
(a )
$
Agreement
Income Statement Line Item
UE
CIPS
Genco
CILCO
IP
Gas purchases from Genco
Gas Purchased for Resale
Ameren Services support services
agreement
CILCO support services
Ameren Energy, Inc. support services
agreement(e)
AFS support services agreement
Insurance premiums(f)
Total Other Operations and
Maintenance Expenses
Money pool borrowings (advances)
Other Operations and
Maintenance
Other Operations and
Maintenance
Other Operations and
Maintenance
Other Operations and
Maintenance
Other Operations and
Maintenance
Interest (Charges)
Income
2009
2008
2009
2008
2007
2009
2007
2009
2008
2007
2009
2008
2007
2009
2008
2007
2009
2008
2007
$
(a)
(a)
$ 126
130
137
(a)
$
(a )
(c )
$ 29
50
47
21
8
(a )
$
$
(a)
(a)
27
28
24
(a)
(c)
7
7
6
2
8
19
$ 135
145
170
(c)
$
(c)
(c)
2
2
2
(a )
(a )
(a )
$ 52
52
49
(c )
(c )
(c )
$
3
3
2
1
4
4
31
35
30
(1)
(c)
8
$
$
$
2
6
$ 33
51
49
(a)
(a)
2
2
2
1
3
2
$ 36
56
53
(1)
(c)
(c)
$
$
(c )
(a )
$ 48
76
73
32
(a )
3
2
2
(a )
(a )
(a )
$ 83
78
75
(c )
(c )
1
$
Includes revenues relating to Property and Plant additions during 2009 (CIPS – $6 million and IP – $11 million).
In January 2009, CILCO transferred the tolling agreement to Marketing Company.
(a) Not applicable.
(b)
(c) Amount less than $1 million.
(d)
(e) Ameren Energy, Inc. was eliminated December 31, 2007, through an internal reorganization.
(f) Represents insurance premiums paid to Energy Risk Assurance Company, an affiliate for replacement power, property damage and terrorism coverage.
NOTE 15 – COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and
governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve
substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in
these notes to our financial statements, will not have a material adverse effect on our results of operations, financial
position, or liquidity.
See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 14 –
Related Party Transactions and Note 16 – Callaway Nuclear Plant in this report.
Callaway Nuclear Plant
The following table presents insurance coverage at UE’s Callaway nuclear plant at December 31, 2009. The property
coverage and the nuclear liability coverage must be renewed on October 1 and January 1, respectively, of each year.
Type and Source of Coverage
Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
Maximum Coverages
American Nuclear Insurers ................................................................... $ 300(a)
Pool participation .................................................................................. 12,219(b)
$ 12,519(d)
Nuclear Electric Insurance Ltd. ............................................................. $ 2,750(e)
Nuclear Electric Insurance Ltd. ............................................................. $ 490(f)
Energy Risk Assurance Company ........................................................ $ 64(g)
Property damage:
Replacement power:
$ -
118(c)
$ 118
$ 23
$ 9
$ -
(a) Effective January 1, 2010, limit was increased to $375 million.
(b) Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(c) Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $300 million in the
event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(d) Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed
up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each
reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
for losses in excess of the $500 million primary coverage.
(e) Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion
161
(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear plant. Weekly indemnity of $4.5 million for 52
weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 weeks thereafter.
(g) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear plant. The coverage commences after the first
52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per
week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 14 –
Related Party Transactions for more information on this affiliate transaction.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United
States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and
the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the
Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act
renewal was effective October 29, 2008. Owners of a nuclear reactor cover this exposure through a combination of private
insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.
After the terrorist attacks on September 11, 2001, Nuclear Electric Insurance Ltd. confirmed that losses resulting from
terrorist attacks would be covered under its policies. However, Nuclear Electric Insurance Ltd. imposed an industry-wide
aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.
If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or
if coverage is unavailable, UE is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have
a material adverse effect on Ameren’s and UE’s results of operations, financial position, or liquidity.
Leases
The following table presents our lease obligations at December 31, 2009:
Total
Less than 1 Year
1 - 3 Years
3 - 5 Years
After 5 Years
Ameren:(a)
Capital lease payments(b) ..................................................
Less amount representing interest ....................................
Present value of minimum capital lease payments ............
Operating leases(c) ............................................................
Total lease obligations ......................................................
UE:
Capital lease payments(b) ..................................................
Less amount representing interest ....................................
Present value of minimum capital lease payments ............
Operating leases(c) ............................................................
Total lease obligations ......................................................
CIPS:
Operating leases(c) ............................................................
Genco:
Operating leases(c) ............................................................
CILCO:
Operating leases(c) ............................................................
IP:
Operating leases(c) ............................................................
$ 685
367
318
351
$ 669
$ 685
367
318
157
$ 475
$
2
$ 133
$ 16
$ 32
28
4
37
$ 41
$ 32
28
4
14
$ 18
$
-
$ 9
$ 1
$ 65
55
10
59
$ 69
$ 65
55
10
25
$ 35
$
1
$ 17
$
2
3
$ 65
55
10
52
$ 62
$ 65
55
10
25
$ 35
$
1
$ 17
$
2
$
1
$ 523
229
294
203
$ 497
$ 523
229
294
93
$ 387
$
-
$
90
$
11
$
-
$
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
$ 2
$
6
(a)
(b) See Properties under Part I, Item 2, and Note 3 – Property and Plant, Net of this report for additional information.
(c) Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. Ameren’s $2 million annual obligation for these items is
included in the Less than 1 Year, 1-3 Years, and 3-5 Years columns. Amounts for After 5 Years are not included in the total because that period is indefinite.
162
We lease various facilities, office equipment, plant equipment, and rail cars under operating leases. The following
table presents total rental expense, included in other operations and maintenance expenses, for the years ended
December 31, 2009, 2008 and 2007:
Ameren(a) ...............................................................................................................................................................
UE .........................................................................................................................................................................
CIPS .......................................................................................................................................................................
Genco .....................................................................................................................................................................
CILCO ....................................................................................................................................................................
IP .........................................................................................................................................................................
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
2009
$ 27
19
6
5
6
9
2008
$ 19
20
9
2
7
13
2007
$ 15
19
9
2
7
12
Other Obligations
To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term
commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We also have entered into various
long-term commitments for the purchase of electric capacity and natural gas for distribution. The table below presents our
estimated fuel, electric capacity, and other commitments at December 31, 2009. Ameren’s and UE’s electric capacity
obligations include a 15-year, 102-MW power purchase agreement with a wind farm operator. Included in the Other
column are minimum purchase commitments under contracts for equipment, design and construction, meter reading
services, and an Ameren tax credit obligation at December 31, 2009. Ameren’s tax credit obligation is a $51 million note
payable issued for an investment in a commercial real estate development partnership to acquire tax credits. This note
payable was netted against the related investment in Other Assets at December 31, 2009, as Ameren has a legally
enforceable right to offset under authoritative accounting guidance.
In September 2009, UE announced an agreement with a landfill owner to install CTs at a landfill site in St. Louis
County, Missouri, which would generate approximately 15 MW of electricity by burning methane gas collected from the
landfill. Construction of the CTs is expected to begin in 2010, and the CTs are expected to begin generating power in
2011. UE signed a 20-year supply agreement with the landfill owner to purchase methane gas. The obligation information
presented below includes total estimated methane gas purchase commitments. Related design and construction
commitments associated with this project are included in the Other column in the table below.
Ameren:(a)
2010 .............................................
2011 .............................................
2012 .............................................
2013 .............................................
2014 .............................................
Thereafter .....................................
Total .............................................
UE:
2010 .............................................
2011 .............................................
2012 .............................................
2013 .............................................
2014 .............................................
Thereafter .....................................
Total .............................................
CIPS:
2010 .............................................
2011 .............................................
2012 .............................................
2013 .............................................
2014 .............................................
Thereafter .....................................
Total .............................................
Coal
$
987
874
639
218
120
675
$ 3,513
$
527
447
265
142
106
597
$ 2,084
$
$
-
-
-
-
-
-
-
Natural
Gas
$
580
461
317
205
121
214
$ 1,898
$
$
$
$
83
63
50
39
27
52
314
91
74
64
48
37
10
324
Nuclear
Electric
Capacity
Methane
Gas
Other
Total
$
22
22
22
22
22
207
$ 317
$
22
22
22
22
22
207
$ 317
$
$
(b)
(b)
(b)
-
-
-
(b)
$
-
1
3
3
4
101
$ 112
$
-
1
3
3
4
101
$ 112
$
$
-
-
-
-
-
-
-
$ 70
85
75
58
68
254
$ 610
$ 42
54
43
42
52
154
$ 387
$
2
2
2
2
2
12
$ 22
$
$
$
$
$
$
1,714
1,459
1,099
561
435
1,780
7,048
729
603
426
303
311
1,440
3,812
93
76
66
50
39
22
346
$ 55
16
43
55
100
329
$ 598
$ 55
16
43
55
100
329
$ 598
$
$
-
-
-
-
-
-
-
163
Coal
Natural
Gas
Nuclear
Electric
Capacity
Methane
Gas
Other
Total
$
$
$
$
$
$
$
$
$
$
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
10
10
5
3
3
3
34
-
-
-
-
-
-
-
223
192
167
32
-
-
614
Genco:
2010 .............................................
2011 .............................................
2012 .............................................
2013 .............................................
2014 .............................................
Thereafter .....................................
Total .............................................
CILCO:
2010 .............................................
2011 .............................................
2012 .............................................
2013 .............................................
2014 .............................................
Thereafter .....................................
Total .............................................
IP:
2010 .............................................
2011 .............................................
2012 .............................................
2013 .............................................
2014 .............................................
Thereafter .....................................
Total .............................................
(a)
(b) See Ameren Illinois Utilities’ Purchase Power Agreements below for additional information regarding electric capacity commitments.
$
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
6
10
11
11
11
69
$ 118
1
3
3
3
3
19
$ 32
169
136
96
68
37
94
$ 600
93
103
87
36
14
78
$ 411
(b )
(b )
(b )
-
-
-
(b )
$
-
-
-
-
-
-
$ -
-
-
-
-
-
-
$ -
220
176
100
48
17
54
615
(b )
(b )
(b )
-
-
-
(b )
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
233
202
172
35
3
3
648
$
263
242
186
107
54
191
$ 1,043
$
$
226
186
111
59
28
123
733
Ameren Illinois Utilities’ Power Purchase Agreements
Beginning on January 1, 2007, CIPS, CILCO and IP
were required to obtain all electric supply requirements for
customers who do not purchase electric supply from third-
party suppliers. The power procurement costs incurred by
CIPS, CILCO and IP are passed directly to their
customers. CIPS, CILCO and IP entered into power
supply contracts with the winning bidders, including their
affiliate, Marketing Company, in the Illinois reverse power
procurement auction held in September 2006. Under
these contracts, the electric suppliers are responsible for
providing to CIPS, CILCO and IP energy, capacity, certain
transmission, volumetric risk management, and other
services necessary for the Ameren Illinois Utilities to serve
the electric load needs of residential and small commercial
customers (with less than one megawatt of demand) at an
all-inclusive fixed price. These contracts commenced on
January 1, 2007 with one-third of the supply contracts
expiring in each of May 2008, 2009 and 2010.
Existing supply contracts from the September 2006
auction remain in place. Through the Illinois procurement
auction held in September 2006, CIPS, CILCO and IP
contracted for their anticipated fixed-price loads for
residential and small commercial customers (less than
one megawatt of demand) as follows:
Term
CIPS’ load in megawatts(a) .................................
CILCO’s load in megawatts(a) .............................
IP’s load in megawatts(a) ....................................
Total load in megawatts(a) ..................................
Cost per megawatthour ......................................
(a) Represents peak forecast load for CIPS, CILCO and IP. Actual load
41 Months Ending
May 31, 2010
639
328
928
1,895
$ 66.05
could be different if customers elect not to purchase power pursuant to
the power procurement auction but instead to receive power from a
different supplier. Load could also be affected by weather, among other
things.
In January 2009, the ICC approved the electric
power procurement plan filed by the IPA for both the
Ameren Illinois Utilities and Commonwealth Edison
Company. As a result, in the second quarter of 2009, the
IPA procured electric capacity, financial energy swaps,
and renewable energy credits through an RFP process
on behalf of the Ameren Illinois Utilities. Electric capacity
was procured in April 2009 for the period June 1, 2009,
through May 31, 2012. The Ameren Illinois Utilities
contracted to purchase between 800 and 3,500 MW of
capacity per month at an average price of approximately
$41 per MW-day over the three-year period. Financial
energy swaps were procured in
164
May 2009 for the period June 1, 2009, through May 31,
2011. The Ameren Illinois Utilities contracted to purchase
approximately ten million megawatthours of financial
energy swaps at an average price of approximately $36
per megawatthour. Renewable energy credits were
procured in May 2009 for the period June 1, 2009, through
May 31, 2010. The Ameren Illinois Utilities contracted to
purchase 720,000 renewable energy credits at an average
price of approximately $16 per credit. For additional
information regarding electric capacity and financial
energy swaps entered into with UE and Marketing
Company, see Note 14 – Related Party Transactions. The
following table presents the Ameren Illinois Utilities’
commitments for these contracts at December 31, 2009:
Electric capacity .................................. $ 26
Financial energy swaps .......................
183
Renewable energy credits ...................
6
2010
2011
$ 26
56
-
2012
$ 1
-
-
2007 Illinois Electric Settlement Agreement
The 2007 Illinois Electric Settlement Agreement
provided $1 billion of funding over a four-year period
beginning in 2007 for rate relief for certain electric
customers in Illinois. Funding for the settlement is
provided by electric generators in Illinois and certain
Illinois electric utilities. The Ameren Illinois Utilities,
Genco, and AERG agreed to fund an aggregate of $150
million, of which the following contributions remain to be
made at December 31, 2009:
Ameren CIPS
$ 0.3
2010(a) ........ $ 3.0
(a) Estimated.
CILCO
(Illinois
Regulated)
$ 0.2
CILCO
(AERG)
$ 0.5 $ 1.4 $ 0.6
IP Genco
Also as part of the 2007 Illinois Electric Settlement
Agreement, the Ameren Illinois Utilities entered into
financial contracts with Marketing Company to lock in
energy prices for 400 to 1,000 megawatts annually of their
round-the-clock power requirements from 2008 to 2012.
See Note 7 – Derivative Financial Instruments and Note
14 – Related Party Transactions for additional information.
Environmental Matters
We are subject to various environmental laws and
regulations enforced by federal, state and local authorities.
From the beginning phases of siting and development to
the ongoing operation of existing or new electric
generating, transmission and distribution facilities, natural
gas storage facilities, and natural gas transmission and
distribution facilities, our activities involve compliance with
diverse laws and regulations. These laws and regulations
address noise, emissions, impacts to air, land and water,
protected and cultural resources (such as wetlands,
endangered species, and archeological and historical
resources), and chemical and waste handling. Complex
and lengthy processes are required to obtain approvals,
permits, or licenses for new, existing, or modified facilities.
Additionally, the use and handling of various chemicals or
hazardous materials (including wastes) requires release
prevention plans and emergency response procedures. As
new laws or regulations are promulgated, we assess their
applicability and implement the necessary modifications to
our facilities or our operations. The more significant
matters are discussed below.
Clean Air Act
Both federal and state laws require significant
reductions in SO2 and NOx emissions that result from
burning fossil fuels. In May 2005, the EPA issued
regulations with respect to SO2 and NOx emissions (the
Clean Air Interstate Rule) and mercury emissions (the
Clean Air Mercury Rule). The federal Clean Air Interstate
Rule requires generating facilities in 28 eastern states,
which include Missouri and Illinois, where our generating
facilities are located, and the District of Columbia to
participate in cap-and-trade programs to reduce annual
SO2 emissions, annual NOx emissions, and ozone season
NOx emissions. The cap-and-trade program for both
annual and ozone season NOx emissions went into effect
on January 1, 2009. The SO2 emissions cap-and-trade
program is scheduled to take effect in 2010.
In February 2008, the U.S. Court of Appeals for the
District of Columbia issued a decision that vacated the
federal Clean Air Mercury Rule. The court ruled that the
EPA erred in the method it used to remove electric
generating units from the list of sources subject to the
MACT requirements under the Clean Air Act. In February
2009, the U.S. Supreme Court denied a petition for review
filed by a group representing the electric utility industry.
The impact of this decision is that the EPA will move
forward with a MACT standard for mercury emissions and
other hazardous air pollutants, such as acid gases. In a
consent order, the EPA agreed to propose the regulation
by March 2011 and finalize the regulation by November
2011. Compliance is expected to be required in 2015. We
cannot predict at this time the estimated capital or
operating costs for compliance with such future
environmental rules.
In July 2008, the U.S. Court of Appeals for the District
of Columbia issued a decision that vacated the federal
Clean Air Interstate Rule. The court ruled that the
regulation contained several fatal flaws, including a
regional cap-and-trade program that cannot be used to
facilitate the attainment of ambient air quality standards for
ozone and fine particulate matter. In September 2008, the
EPA, as well as several environmental groups, a group
representing the electric utility industry, and the National
Mining Association, all filed petitions for rehearing with the
U.S. Court of Appeals. In December 2008, the U.S. Court
of Appeals essentially reversed its July 2008 decision to
vacate the federal Clean Air Interstate Rule. The U.S.
Court of Appeals granted the EPA petition for
reconsideration and remanded the rule to the EPA for
further action to remedy the rule’s flaws in accordance
with the U.S. Court of Appeals’ July 2008 opinion in the
case. The impact of the decision is that the existing Illinois
and Missouri rules to implement the
165
federal Clean Air Interstate Rule will remain in effect until
the federal Clean Air Interstate Rule is revised by the
EPA, at which point the Illinois and Missouri rules may be
subject to change. The EPA has stated that it expects to
issue a new proposed version of the Clean Air Interstate
Rule in 2010 and a final version in 2011.
The state of Missouri has adopted rules to implement
the federal Clean Air Interstate Rule for regulating SO2
and NOx emissions from electric generating units. The
rules are a significant part of Missouri’s plan to attain
existing ambient standards for ozone and fine particulates,
as well as meeting the federal Clean Air Visibility Rule.
The rules are expected to reduce NOx emissions by 30%
and SO2 emissions by 75% by 2015. As a result of the
Missouri rules, UE will use allowances and install pollution
control equipment. UE’s costs to comply with SO2
emission reductions required by the Clean Air Interstate
Rule could increase materially if the EPA determines that
existing allowances granted to sources under the Acid
Rain Program cannot be used for compliance with the
Clean Air Interstate Rule or if a new allowance program is
mandated by revisions to the Clean Air Interstate Rule.
Missouri also adopted rules to implement the federal
Clean Air Mercury Rule. However, these rules are not
enforceable as a result of the U.S. Court of Appeals
decision to vacate the federal Clean Air Mercury Rule.
We do not believe that the court decision that vacated
the federal Clean Air Mercury Rule will significantly affect
pollution control obligations in Illinois in the near term.
Under the MPS, as amended, Illinois generators may
defer until 2015 the requirement to reduce mercury
emissions by 90%, in exchange for accelerated installation
of NOx and SO2 controls. This rule, when fully
implemented, is expected to reduce mercury emissions by
90%, NOx emissions by 50%, and SO2 emissions by 70%
by 2015 in Illinois. To comply with the rule, Genco, CILCO
(AERG) and EEI have begun putting into service
equipment designed to reduce mercury emissions. Genco,
CILCO (AERG) and EEI will also need to install additional
pollution control equipment. Current plans include
installing scrubbers for SO2 reduction as well as optimizing
operations of selective catalytic reduction (SCR) systems
for NOx reduction at certain coal-fired plants in Illinois. The
Illinois Joint Committee on Administrative Rules approved
a rule amendment in June 2009 that revised certain
requirements of the MPS. As a result, Genco and CILCO
(AERG) collectively were able to defer to subsequent
years an estimated $300 million of environmental capital
expenditures originally scheduled for 2009 through 2011.
In March 2008, the EPA finalized regulations that will
lower the ambient standard for ozone. Illinois and Missouri
have each submitted their recommendations to the EPA
for designating nonattainment areas. A final action by the
EPA to designate nonattainment areas is expected in
March 2010. State implementation plans will need to be
submitted in 2013 unless Illinois and Missouri seek
extensions for various requirement dates. Additional
emission reductions may be required as a result of future
state implementation plans. In January 2010, the EPA
announced its plans to revise the ozone standard to a
level lower than the level set in 2008. At this time, we are
unable to determine the impact state implementation plans
for such regulations would have on our results of
operations, financial position, and liquidity.
The table below presents estimated capital costs that
are based on current technology to comply with state air
quality implementation plans, the MPS, federal ambient air
quality standards including ozone and fine particulates,
and the federal Clean Air Visibility rule. The estimates
shown in the table below could change depending upon
additional federal or state requirements, the requirements
under a MACT standard, new technology, variations in
costs of material or labor, or alternative compliance
strategies, among other factors. The timing of estimated
capital costs may also be influenced by whether emission
allowances are used to comply with any future rules,
thereby deferring capital investment. During 2009, Ameren
identified significant opportunities to defer or reduce
planned capital spending, which are reflected in the
estimates provided in the table. The capital cost estimates
are lower than previously anticipated, in part because of
Ameren’s ability to manage its generating fleet to minimize
emissions while complying with emission limits and air
permit requirements. Furthermore, previous estimates
included assumptions about potential and developing air
regulations, including rules that were subsequently
vacated by the courts. These estimates include capital
spending to comply primarily with existing and known
regulations as of December 31, 2009.
Total
2011 - 2014
2015 - 2017
2010
UE(a) .................. $ 160
$ 170 –
$ 215
650 –
95
Genco ................
785
120 –
5
CILCO(AERG).............
150
5
EEI ....................
275 –
335
Ameren .............. $ 265
$ 1,215 –
$ 1,485
(a) UE’s expenditures are expected to be recoverable from ratepayers.
Emission Allowances
$ 35 $ 355 –
775 –
190 –
280 –
$ 150 $ 1,600 –
$ 25 –
30 –
65 –
0 –
$ 120 –
35
75
5
$ 410
915
230
345
$ 1,900
Both federal and state laws require significant
reductions in SO2 and NOx emissions that result from
burning fossil fuels. The Clean Air Act created marketable
commodities called allowances under the Acid Rain
Program, the NOx Budget Trading Program, and the
federal Clean Air Interstate Rule. All existing generating
facilities have been allocated allowances based on past
production and the statutory emission reduction goals.
NOx allowances allocated under the NOx Budget Trading
Program can be used for the seasonal NOx program under
the federal Clean Air Interstate Rule. Our generating
facilities comply with the SO2 limits through the use and
purchase of allowances, through the use of low-sulfur
fuels, and through the application of pollution control
technology. Our generating
166
facilities are expected to comply with the NOx limits
through the use and purchase of allowances or through
the application of pollution control technology, including
low-NOx burners, over-fire air systems, combustion
optimization, rich-reagent injection, selective noncatalytic
reduction, and selective catalytic reduction systems.
See Note 1 – Summary of Significant Accounting
Policies for the SO2 and NOx emission allowances held
and the related SO2 and NOx emission allowance book
values that were classified as intangible assets as of
December 31, 2009.
UE, Genco, CILCO (AERG) and EEI expect to use a
substantial portion of their SO2 and NOx allowances for
ongoing operations. Environmental regulations, including
the Clean Air Interstate Rule, the timing of the installation
of pollution control equipment, and the level of operations,
will have a significant impact on the number of allowances
actually required for ongoing operations. The Clean Air
Interstate Rule requires a reduction in SO2 emissions by
increasing the ratio of Acid Rain Program allowances
surrendered. The current Acid Rain Program requires the
surrender of one SO2 allowance for every ton of SO2
emitted. Unless revised by the EPA as a result of the U.S.
Court of Appeals’ remand, the Clean Air Interstate Rule
program will require that SO2 allowances of vintages 2010
through 2014 be surrendered at a ratio of two allowances
for every ton of emission. SO2 allowances with vintages of
2015 and beyond will be required to be surrendered at a
ratio of 2.86 allowances for every ton of emission. In order
to accommodate this change in surrender ratio and to
comply with the federal and state regulations, UE, Genco,
CILCO (AERG), and EEI expect to install control
technology designed to further reduce SO2 emissions, as
discussed above.
The Clean Air Interstate Rule has both an ozone
season program and an annual program for regulating
NOx emissions, with separate allowances issued for each
program. The Clean Air Interstate Rule ozone season
program replaced the NOx Budget Trading Program
beginning in 2009. Allocations for UE’s Missouri
generating facilities for the years 2009 through 2014 were
11,665 tons per ozone season and 26,842 tons annually.
Allocations for Genco’s generating facility in Missouri were
one ton for the ozone season and three tons annually.
Allocations for UE’s, Genco’s, CILCO’s (AERG), and EEI’s
Illinois generating facilities for the years 2010 and 2011
were 90, 3,442, 1,368, and 1,758 tons per ozone season,
respectively, and 93, 8,302, 3,419, and 4,565 tons
annually, respectively.
Global Climate Change
In June 2009, the U.S. House of Representatives
passed energy legislation entitled “The American Clean
Energy and Security Act of 2009” that, if enacted, would
establish an economy-wide cap-and-trade program. The
overarching goal of this proposed cap-and-trade program
is to reduce greenhouse gas emissions from capped
sources, including coal-fired electric generation units, to
3% below
2005 levels by 2012, 17% below 2005 levels by 2020,
42% below 2005 levels by 2030, and 83% below 2005
levels by the year 2050. The proposed legislation provides
an allocation of free emission allowances and greenhouse
gas offsets to utilities, as well as certain merchant coal-
fired electric generators in competitive markets. This
aspect of the proposed legislation would mitigate some of
the cost of compliance for the Ameren Companies.
However, the amount of free allowances decline over time
and are ultimately phased out. The proposed legislation
also contains, among other things, a federal renewable
energy standard of 6% by 2012 that increases gradually to
20% by 2020, of which up to 25% of the goal can be met
by energy efficiency. The proposed legislation also
establishes performance standards for new coal plants,
requires electric utilities to develop plans to support plug-
in hybrid vehicles, and requires load-serving entities to
reduce peak electric demand through energy efficiency
and Smart Grid technologies. In September 2009, climate
change legislation entitled “The Clean Energy Jobs and
American Power Act” was introduced in the U.S. Senate
that was similar to that passed by the U.S. House of
Representatives in June 2009, although it proposes a
slightly greater reduction in greenhouse gas emissions in
the year 2020 and grants fewer emission allowances to
the electricity sector. Under both proposed pieces of
legislation, large sources of CO2 emissions will be required
to obtain and retire an allowance for each ton of CO2
emitted. The allowances may be allocated to the sources
without cost, sold to the sources through auctions or other
mechanisms, or traded among parties. “The Clean Energy
Jobs and American Power Act” was voted out of
committee in November 2009. In December 2009,
Senators Kerry, Graham and Lieberman introduced a
framework for Senate legislation in 2010. The framework
lacks specifics, but it is consistent with the House-passed
legislation except that it emphasizes the need for greater
support for nuclear power and energy independence
through support for clean energy and drilling for oil and
natural gas. Senate leadership has stated that
consideration of climate legislation will be postponed until
spring 2010. In addition, the reduction of greenhouse gas
emissions has been identified as a high priority by
President Obama’s administration. Although we cannot
predict the date of enactment or the requirements of any
future climate change legislation or regulations, we believe
it is possible that some form of federal legislation or
regulations to control emissions of greenhouse gases will
become law during the current administration.
Potential impacts from climate change legislation
could vary, depending upon proposed CO2 emission limits,
the timing of implementation of those limits, the method of
distributing allowances, the degree to which offsets are
allowed and available, and provisions for cost containment
measures, such as a “safety valve” provision that provides
a maximum price for emission allowances. As a result of
our diverse fuel portfolio, our emissions of greenhouse
gases vary among our generating facilities, but coal-fired
power plants are significant sources of CO2 , a principal
greenhouse gas. Ameren’s analysis shows that if either
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“The American Clean Energy and Security Act of 2009” or
“The Clean Energy Jobs and American Power Act” were
enacted into law in its current form, household costs and
rates for electricity could rise significantly. The burden could
fall particularly hard on electricity consumers and upon the
economy in the Midwest because of the region’s reliance on
electricity generated by coal-fired power plants. Natural gas
emits about half the amount of CO2 that coal emits when
burned to produce electricity. As a result, economy-wide
shifts favoring natural gas as a fuel source for electricity
generation also could affect the cost of heating for our utility
customers and many industrial processes. Ameren believes
that wholesale natural gas costs could rise significantly as
well. Higher costs for energy could contribute to reduced
demand for electricity and natural gas.
In early December of 2009, representatives from
countries around the globe met in Copenhagen, Denmark, to
attempt to develop an international treaty to supersede the
Kyoto Protocol, which set mandatory greenhouse gas
reduction requirements for participating countries. The parties
were unable to reach agreement regarding mandatory
greenhouse gas emissions reductions. However, certain
countries, including the United States, entered into an
agreement called the “Copenhagen Accord.” The
Copenhagen Accord provides a mechanism for countries to
make economy-wide greenhouse gas emission mitigation
commitments for reducing emissions of greenhouse gases by
2020 and provides for developed countries to fund
greenhouse gas emissions mitigation projects in developing
countries. Any commitment under the Copenhagen Accord is
subject to congressional action on climate change.
Additional requirements to control greenhouse gas
emissions and address global climate change may also arise
pursuant to the Midwest Greenhouse Gas Reduction Accord,
an agreement signed by the governors of Illinois, Iowa,
Kansas, Michigan, Wisconsin and Minnesota to develop a
strategy to achieve energy security and to reduce
greenhouse gas emissions through a cap-and-trade
mechanism. The advisory group to the Midwest governors
provided draft final recommendations on the design of a
greenhouse gas reduction program in June 2009. In October
2009, the Midwestern Governors Association held a forum to
review some of the advisory group’s recommendations. The
October 2009 forum did not yield any significant updates to
the Midwest Greenhouse Gas Reduction Accord’s work
toward a cap-and-trade mechanism. The recommendations
have not been endorsed or approved by the individual state
governors. It is uncertain whether legislation to implement the
recommendations will be implemented or passed by any of
the states, including Illinois.
With regard to the control of greenhouse gas emissions
under federal regulation, in 2007, the U.S. Supreme Court
issued a decision finding that the EPA has the authority to
regulate CO2 and other greenhouse gases from automobiles
as “air pollutants” under the Clean Air Act. This decision
required the EPA to determine whether greenhouse gas
emissions may reasonably be anticipated to endanger public
health or welfare, or, in the alternative, to provide a
reasonable explanation as to why greenhouse gas emissions
should not be regulated. In December 2009, in response to
the decision of the U.S. Supreme Court, the EPA issued its
“endangerment finding” determining that greenhouse gas
emissions, including CO2 , endanger human health and
welfare and that emissions of greenhouse gases from motor
vehicles contribute to that endangerment. It is expected that
the EPA will issue a rule by the end of March 2010 to control
greenhouse gas emissions from light-duty vehicles such as
automobiles. Once this rule is effective, greenhouse gases
will, for the first time, be a regulated air pollutant under the
Clean Air Act. The EPA has taken the position that the
regulation of greenhouse gas emissions from new motor
vehicles under the Clean Air Act will trigger the applicability of
other Clean Air Act provisions, such as the Title V Operating
Permit Program and the NSR provisions, which apply to
greenhouse gas emissions from stationary sources. This
would include fossil-fuel-fired electricity generating plants.
Recognizing the difficulties presented by regulating at
once virtually all emitters of greenhouse gases, the EPA
announced in September 2009 a proposed rule, known as
the “tailoring rule,” that would establish new higher thresholds
for regulating greenhouse gas emissions from stationary
sources, such as power plants. The rule would require any
source that emits at least 25,000 tons per year of greenhouse
gases measured as CO2 equivalents (CO2 e) to have an
operating permit under Title V Operating Permit Program of
the Clean Air Act. Sources that already have an operating
permit would have greenhouse gas-specific provisions added
to their permits upon renewal. Currently, all Ameren power
plants have operating permits that, depending on the final
rule, may be modified when they are renewed to address
greenhouse gas emissions. The proposed tailoring rule also
provides that if physical changes or changes in operation at
major sources result in an increase in emissions of
greenhouse gases over a threshold ranging from 10,000 tons
to 25,000 tons of CO2 e, the emitters would be required to
obtain a permit under the NSR/Prevention of Significant
Deterioration program and to install the best available
technology to control greenhouse gas emissions. New major
sources also would be required to obtain such a permit and
to install the best available control technology. The EPA has
committed to provide guidance about the best available
control technology for new and modified major sources of
greenhouse gas emissions. The tailoring rule is expected to
be finalized in March 2010, but any federal climate change
legislation that is enacted may preempt the proposed rule,
particularly as it relates to power plant greenhouse gas
emissions. This proposed rule has no immediate impact on
Ameren’s, UE’s, Genco’s or CILCO’s (AERG) generating
facilities. The extent to which this proposed rule could have a
material impact on our generating facilities depends upon
future EPA guidelines as to what constitutes the best
available control technology for greenhouse gas emissions
from power plants, whether physical changes or change in
operation subject to the rule
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would occur at our power plants, and whether federal
legislation that preempts the proposed rule is passed.
The EPA also finalized regulations in September 2009
that would require certain categories of businesses, including
fossil-fuel-fired power plants, to monitor and report their
annual greenhouse gas emissions, beginning in January
2011 for 2010 emissions. CO2 emissions from fossil-fuel-fired
power plants subject to the Clean Air Act’s acid rain program
have been monitored and reported for over fifteen years.
Thus, this new rule covering greenhouse gas emissions is
not expected to have a material effect on our operations. It
will require additional reporting of greenhouse gas emissions
from various gas operations and possibly other minor
sources within our system.
Recent federal appellate court decisions have ruled that
common law causes of action, such as nuisance, can be
used to redress damages resulting from global climate
change. In State of Connecticut v. American Electric Power
(“AEP”), the U.S. Court of Appeals for the Second Circuit
ruled in September 2009 that public nuisance claims brought
by states, New York City and public land trusts could proceed
and were not beyond the scope of judicial relief. Ameren’s
generating plants were not named in the AEP litigation. In
Comer v. Murphy Oil (“Comer”), a Mississippi property owner
sued several industrial companies, alleging that CO2
emissions created the atmospheric conditions, that resulted
in Hurricane Katrina. The U.S. Court of Appeals for the Fifth
Circuit issued a ruling in Comer in October 2009 that permits
this cause of action to proceed. Comer is seeking class
action certification on behalf of similarly situated property
owners. Additional legal challenges and appeals are
expected in both the Comer and AEP cases. The rulings in
these cases may spur other claimants to file suit against
greenhouse gas emitters, including Ameren. The courts did
not rule on the merits of the lawsuits, only that plaintiffs had
standing to pursue their claims. Under some of the versions
of greenhouse gas legislation currently pending in Congress,
nuisance claims could be rendered moot. We are unable to
predict the outcome of lawsuits seeking damages that
litigants claim are attributable to climate change and their
impact on our results of operations, financial position, and
liquidity.
Future federal and state legislation or regulations that
mandate limits on the emission of greenhouse gases would
result in significant increases in capital expenditures and
operating costs, which, in turn, could lead to increased
liquidity needs and higher financing costs. Moreover, to the
extent we request recovery of these costs through rates, our
regulators might deny some or all of, or defer timely recovery
of, these costs. Excessive costs to comply with future
legislation or regulations might force UE, Genco, CILCO
(through AERG) and EEI as well as other similarly situated
electric power generators to close some coal-fired facilities
and could lead to possible impairment of assets and reduced
revenues. As a result, mandatory limits could have a material
adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and
EEI’s results of operations, financial position, and liquidity.
The impact on us of future initiatives related to
greenhouse gas emissions and global climate change is
unknown. Although compliance costs are unlikely in the near
future, federal legislative, federal regulatory and state-
sponsored initiatives to control greenhouse gases continue to
progress, making it more likely that some form of greenhouse
gas emissions control will eventually be required. Since these
initiatives continue to evolve, the impact on our coal-fired
generation plants and our customers’ costs is unknown, but
any impact would likely be negative. Our costs of complying
with any mandated federal or state greenhouse gas program
could have a material impact on our future results of
operations, financial position, and liquidity.
NSR and Notice of Violation
The EPA is engaged in an enforcement initiative targeted
at coal-fired power plants in the United States to determine
whether those power plants failed to comply with the
requirements of the NSR and New Source Performance
Standards (NSPS) provisions under the Clean Air Act when
the plants implemented modifications. The EPA’s inquiries
focus on whether projects performed at power plants should
have triggered various permitting requirements and the
installation of pollution control equipment.
In April 2005, Genco received a request from the EPA for
information pursuant to Section 114(a) of the Clean Air Act. It
sought detailed operating and maintenance history data with
respect to Genco’s Coffeen, Hutsonville, Meredosia and
Newton facilities, EEI’s Joppa facility, and AERG’s E.D.
Edwards and Duck Creek facilities. In 2006, the EPA issued
a second Section 114(a) request to Genco regarding projects
at the Newton facility. All of these facilities are coal-fired
power plants. In September 2008, the EPA issued a third
Section 114(a) request regarding projects at all of Ameren’s
Illinois coal-fired power plants. In May 2009, we completed
our response to the most recent information request, but we
are unable to predict the outcome of this matter.
In January 2010, UE received a Notice of Violation from
the EPA alleging violations of the Clean Air Act’s NSR and
Title V programs. In the Notice of Violation, the EPA
contends that various maintenance, repair and replacement
projects at UE’s Labadie, Meramec, Rush Island, and Sioux
coal-fired power plant facilities, dating back to the mid-1990s,
triggered NSR requirements. The EPA alleges that UE
violated the Title V operating permit program by failing to
include such NSR requirements in its operating permits or
applications for those permits. If litigation regarding this
matter occurs, it could take many years to resolve the
underlying issues alleged in the Notice of Violation. UE
believes its defenses to the allegations described in the
Notice of Violation are meritorious and will defend itself
vigorously; however, there can be no assurances that it will
be successful in its efforts.
Resolution of these matters could have a material
adverse impact on the future results of operations, financial
position, and liquidity of Ameren, UE, Genco, AERG and
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EEI. A resolution could result in increased capital
expenditures for the installation of control technology,
increased operations and maintenance expenses, and fines
or penalties.
Clean Water Act
In July 2004, the EPA issued rules under the Clean
Water Act that require cooling-water intake structures to have
the best technology available for minimizing adverse
environmental impacts on aquatic species. These rules
pertain to all existing generating facilities that currently
employ a cooling-water intake structure whose flow exceeds
50 million gallons per day. The rules may require facilities to
install additional technology on their cooling water intakes or
take other protective measures and to do extensive site-
specific study and monitoring. There is also the possibility
that the rules may lead to the installation of cooling towers on
some of our generating facilities. On April 1, 2009, the U.S.
Supreme Court ruled that the EPA can compare the costs of
technology for protecting aquatic species to the benefits of
that technology in order to establish the “best technology
available” standards applicable to the cooling water intake
structure at existing power plants under the Clean Water Act.
The EPA is expected to propose revised rules in 2010. Until
the EPA reissues the rules and such rules are adopted, and
until the studies on the aquatic impacts of the power plants
are completed, we are unable to estimate the costs of
complying with these rules. Such costs are not expected to
be incurred prior to 2012. All major generation facilities at UE,
Genco, AERG and EEI with cooling water systems could be
subject to these new regulations.
Remediation
We are involved in a number of remediation actions to
clean up hazardous waste sites as required by federal and
state law. Such statutes require that responsible parties fund
remediation actions regardless of their degree of fault, the
legality of original disposal, or the ownership of a disposal
site. UE, CIPS, CILCO and IP have each been identified by
the federal or state governments as a potentially responsible
party (PRP) at several contaminated sites. Several of these
sites involve facilities that were transferred by CIPS to Genco
in May 2000 and facilities transferred by CILCO to AERG in
October 2003. As part of each transfer, CIPS and CILCO
have contractually agreed to indemnify Genco and AERG,
respectively, for remediation costs associated with
preexisting environmental contamination at the transferred
sites.
As of December 31, 2009, CIPS, CILCO and IP owned
or were otherwise responsible for several former MGP sites
in Illinois. CIPS has 15, CILCO has 4, and IP has 25 sites. All
of these sites are in various stages of investigation,
evaluation, and remediation. Ameren currently anticipates
completion of remediation at these sites by 2015, except for a
CIPS site that is expected to be completed by 2017. The ICC
permits each company to recover remediation and litigation
costs associated with its former MGP sites from its Illinois
electric and natural gas utility customers through
environmental adjustment rate riders. To be recoverable,
such costs must be prudently and properly incurred. Costs
are subject to annual review by the ICC. As of December 31,
2009, estimated obligations were: CIPS – $47 million to $62
million, CILCO – less than $1 million, and IP – $112 million to
$175 million. CIPS, CILCO and IP have liabilities of $47
million, less than $1 million, and $112 million, respectively,
recorded to represent estimated minimum obligations, as no
other amount within the range was a better estimate. In 2009,
after the completion of site investigations and the selection of
remediated actions, CIPS and IP increased their remediation
liabilities.
CIPS is also responsible for the cleanup of a former coal
ash landfill in Coffeen, Illinois. As of December 31, 2009,
CIPS estimated that obligation at $0.5 million to $6 million.
CIPS recorded a liability of $0.5 million to represent its
estimated minimum obligation for this site, as no other
amount within the range was a better estimate. IP is also
responsible for the cleanup of a landfill, underground storage
tanks, and a water treatment plant in Illinois. As of
December 31, 2009, IP recorded a liability of $0.8 million to
represent its best estimate of the obligation for these sites.
In addition, UE owns or is otherwise responsible for 10
MGP sites in Missouri and one site in Iowa. UE does not
currently have in effect in Missouri a rate rider mechanism
that permits recovery of remediation costs associated with
MGP sites from utility customers. UE does not have any retail
utility operations in Iowa that would provide a source of
recovery of these remediation costs. As of December 31,
2009, UE estimated its obligation at $3 million to $5 million.
UE has a liability of $3 million recorded to represent its
estimated minimum obligation for its MGP sites, as no other
amount within the range was a better estimate.
UE also is responsible for four waste sites in Missouri
that have corporate cleanup liability as a result of federal
agency mandates. UE concluded cleanups at two of these
sites, and no further remediation actions are anticipated at
those two sites. One of the remaining waste sites for which
UE has corporate cleanup responsibility is a former coal tar
distillery located in St. Louis, Missouri. In July 2008, the EPA
issued an administrative order to UE pertaining to this
distillery operated by Koppers Company or its predecessor
and successor companies. UE is the current owner of the
site, but UE did not conduct any of the manufacturing
operations involving coal tar or its byproducts. UE along with
two other PRPs have reached an agreement with the EPA
about the scope of the site investigation. The investigation
will occur later this year. As of December 31, 2009, UE
estimated this obligation at $2 million to $5 million. UE has a
liability of $2 million recorded to represent its estimated
minimum obligation, as no other amount within the range was
a better estimate.
In June 2000, the EPA notified UE and numerous other
companies, including Solutia, that former landfills and
lagoons in Sauget, Illinois, may contain soil and groundwater
contamination. These sites are known as Sauget Area 2.
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From about 1926 until 1976, UE operated a power
generating facility adjacent to Sauget Area 2. UE currently
owns a parcel of property that was once used as a landfill.
Under the terms of an Administrative Order and Consent,
UE has joined with other PRPs to evaluate the extent of
potential contamination with respect to Sauget Area 2.
The Sauget Area 2 investigations overseen by the
EPA have been completed. The results have been
submitted to the EPA and a record of decision is expected
in 2010. Once the EPA has selected a remedy, it will
begin negotiations with various PRPs to implement it.
Over the last several years, numerous other parties have
joined the PRP group and all presumably will participate in
the funding of any required remediation. In addition,
Pharmacia Corporation and Monsanto Company have
agreed to assume the liabilities related to Solutia’s former
chemical waste landfill in the Sauget Area 2,
notwithstanding Solutia’s filing for bankruptcy protection.
As of December 31, 2009, UE estimated its obligation at
$0.4 million to $10 million. UE has a liability of $0.4 million
recorded to represent its estimated minimum obligation,
as no other amount within the range was a better
estimate.
In December 2004, AERG submitted a plan to the
Illinois EPA to address groundwater and surface water
issues associated with the recycle pond, ash ponds, and
reservoir at the Duck Creek power plant facility.
Information submitted by AERG is currently under review
by the Illinois EPA. CILCO (AERG) has a liability of $3
million at December 31, 2009, for the estimated cost of the
remediation effort, which involves discharging recycle-
system water into the Duck Creek reservoir and the
eventual closure of ash ponds in order to address these
groundwater and surface water issues.
Our operations or those of our predecessor
companies involve the use, disposal of, and in appropriate
circumstances, the cleanup of substances regulated under
environmental protection laws. We are unable to
determine whether such practices will result in future
environmental commitments or impact our results of
operations, financial position, or liquidity.
Ash Management
There has been increased activity at both state and
federal levels to examine the need for additional regulation
of ash pond facilities and coal combustion byproducts
(CCB) and wastes. The EPA is considering regulating
CCB under the hazardous waste regulations, which could
impact future disposal and handling costs at our power
plant facilities. We believe it is likely that the EPA will
continue to allow some beneficial use, such as recycling,
of CCB without classifying them as hazardous wastes. As
part of its proposed regulations, the EPA is considering
requirements that coal-fired power plants engage in the
mandatory closure of active surface impoundments used
for the management of CCB. In September 2009, the EPA
announced that it expects to revise federal rules governing
wastewater discharges from coal-fired power plants.
Some form of additional regulation concerning ash ponds,
and the handling and disposal of CCB and waste, is
expected to be proposed in early 2010. Depending upon
the scope and timing of these rules, Ameren may be
required to alter the management of CCB waste, including
beneficial reuse, and to discontinue or phase out the use
of the ash ponds. Ameren’s CCB impoundments were not
identified in the EPA’s 2009 list of 44 high-hazard potential
impoundments containing CCB.
In addition, the Illinois EPA has requested that UE,
Genco, CILCO (AERG) and EEI establish groundwater
monitoring plans for their active and inactive ash
impoundments in Illinois. Genco is currently petitioning the
Illinois Pollution Control Board to issue a site specific rule
approving the closure of an ash pond at its Hutsonville
power plant. Ameren has entered into discussions with the
Illinois EPA about a framework for closure of additional
ash ponds in Illinois, including the ash ponds at Venice
and Duck Creek, when such facilities are ultimately taken
out of service. The permits for the Venice and Duck Creek
ash ponds both expire in 2010. UE, Genco and CILCO
(AERG) have recorded AROs, based on current laws, for
the estimated costs of the retirement of their ash ponds.
At this time, we are unable to predict the effects any
such state and federal regulations might have on our
results of operations, financial position, and liquidity.
Pumped-storage Hydroelectric Facility Breach
In December 2005, there was a breach of the upper
reservoir at UE’s Taum Sauk pumped-storage
hydroelectric facility. This resulted in significant flooding in
the local area, which damaged a state park. UE settled
with FERC and the state of Missouri all issues associated
with the December 2005 Taum Sauk incident.
UE has property and liability insurance coverage for
the Taum Sauk incident, subject to certain limits and
deductibles. Insurance does not cover lost electric
margins and penalties paid to FERC. UE expects that the
total cost for cleanup, damage and liabilities, excluding
costs to rebuild the upper reservoir, will be approximately
$205 million. As of December 31, 2009, UE had paid
$205 million, including costs resulting from the FERC-
approved stipulation and consent agreement. As of
December 31, 2009, UE had recorded expenses of
$35 million, primarily in prior years, for items not covered
by insurance and had recorded a $170 million receivable
for amounts recoverable from insurance companies under
liability coverage. As of December 31, 2009, UE had
received $100 million from insurance companies, which
reduced the insurance receivable balance subject to
liability coverage to $70 million.
UE received approval from FERC to rebuild the upper
reservoir at its Taum Sauk plant and is in the process of
testing the rebuilt facility. UE expects the Taum Sauk plant
to become operational in the second quarter of 2010. The
estimated cost to rebuild the upper reservoir is in the
range of $490 million. As of December 31, 2009, UE had
recorded
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a $420 million receivable due from insurance companies
under property insurance coverage related to the
rebuilding of the facility and the reimbursement of
replacement power costs. As of December 31, 2009, UE
had received $362 million from insurance companies,
which reduced the property insurance receivable balance
as of December 31, 2009, to $58 million.
Under UE’s insurance policies, all claims by or against
UE are subject to review by its insurance carriers. In July
2009, three insurance carriers filed a petition against
Ameren in the Circuit Court of St. Louis County, Missouri,
seeking a declaratory judgment that the property
insurance policy does not require these three insurers to
indemnify Ameren for their share of the entire cost of
construction associated with the facility rebuild design
being utilized. The three insurers allege that they, along
with the other policy participants, presented a rebuild
design that was consistent with their insurance coverage
obligations and that the insurance policies do not require
these insurers to pay their share of the costs of
construction associated with the design being used. These
insurers have estimated a cost of approximately $214
million for their rebuild design compared to the estimated
$490 million cost of the design approved by FERC and
implemented by Ameren. Ameren has filed an answer and
counterclaim in the Circuit Court of St. Louis County,
Missouri, against these insurers. The counterclaim asserts
that the three insurance carriers have breached their
obligations under the property insurance policies issued to
Ameren and UE. Ameren seeks payment of a sum to-be-
determined for all amounts covered by these policies
incurred in the facility rebuild, including power
replacement costs, interest, and attorneys’ fees. The
insurers that are parties to the litigation represent
approximately 40%, on a weighted average basis, of the
property insurance policy coverage between the disputed
amounts of $214 million and $490 million.
On August 31, 2009, Ameren and the property
insurance carriers that are not parties to the above
litigation (the “Settling Insurance Companies”) reached a
settlement of any and all claims, liabilities, and obligations
arising out of, or relating to, coverage under its property
insurance policy, including those related to the rebuilding
of the facility and the reimbursement of replacement
power costs. All payments from the Settling Insurance
Companies were received by UE in September 2009.
Until Ameren’s remaining insurance claims and the
related litigation are resolved, among other things, we are
unable to determine the total impact the breach could
have on Ameren’s and UE’s results of operations, financial
position, and liquidity beyond those amounts already
recognized. Ameren and UE expect to recover, through
insurance, 80% to 90% of the total property insurance
claim for the Taum Sauk incident. Beyond insurance, the
recoverability of any Taum Sauk facility rebuild costs from
customers is subject to the terms and conditions set forth
in UE’s November 2007 State of Missouri settlement
agreement. In that settlement, UE agreed that it would not
attempt to recover from rate payers costs incurred in the
reconstruction expressly excluding, however,
enhancements, costs incurred due to circumstances or
conditions that were not at that time reasonably
foreseeable and costs that would have been incurred
absent the Taum Sauk incident. Certain costs associated
with the Taum Sauk facility not recovered from property
insurers may be recoverable from UE’s electric customers
through rates established in rate cases filed subsequent to
the in-service date of the rebuilt facility. As of
December 31, 2009, UE had capitalized in property and
plant qualifying Taum Sauk- related costs of $99 million
that UE believes qualify for potential recovery in electric
rates under the terms of the November 2007 State of
Missouri Settlement. The inclusion of such costs in UE’s
electric rates is subject to review and approval by the
MoPSC in a future rate case. Any amounts not recovered
through insurance, in electric rates, or otherwise, could
result in charges to earnings, which could be material.
Asbestos-related Litigation
Ameren, UE, CIPS, Genco, CILCO and IP have been
named, along with numerous other parties, in a number of
lawsuits filed by plaintiffs claiming varying degrees of
injury from asbestos exposure. Most have been filed in the
Circuit Court of Madison County, Illinois. The total number
of defendants named in each case is significant; as many
as 192 parties are named in some pending cases and as
few as six in others. However, in the cases that were
pending as of December 31, 2009, the average number of
parties was 71.
The claims filed against Ameren, UE, CIPS, Genco,
CILCO and IP allege injury from asbestos exposure during
the plaintiffs’ activities at our present or former electric
generating plants. Former CIPS plants are now owned by
Genco, and former CILCO plants are now owned by
AERG. Most of IP’s plants were transferred to a former
parent subsidiary prior to Ameren’s acquisition of IP. As a
part of the transfer of ownership of the CIPS and CILCO
generating plants, CIPS and CILCO have contractually
agreed to indemnify Genco and AERG, respectively, for
liabilities associated with asbestos-related claims arising
from activities prior to the transfer. Each lawsuit seeks
unspecified damages that, if awarded at trial, typically
would be shared among the various defendants.
The following table presents the pending asbestos-
related lawsuits filed against the Ameren Companies as of
December 31, 2009:
Specifically Named as Defendant
Ameren
1
UE CIPS Genco CILCO
26
15
32
-
IP
40
Total(a)
75
(a) Total does not equal the sum of the subsidiary unit lawsuits because
some of the lawsuits name multiple Ameren entities as defendants.
As of December 31, 2009, nine asbestos-related
lawsuits were pending against EEI. The general liability
insurance maintained by EEI provides coverage with
respect to liabilities arising from asbestos-related claims.
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At December 31, 2009, Ameren, UE, CIPS, CILCO
and IP had liabilities of $14 million, $4 million, $3 million,
$2 million and $5 million, respectively, recorded to
represent their best estimate of their obligations related to
asbestos claims.
IP has a tariff rider to recover the costs of asbestos-
related litigation claims, subject to the following terms:
90% of cash expenditures in excess of the amount
included in base electric rates are recovered by IP from a
trust fund established by IP. At December 31, 2009, the
trust fund balance was approximately $23 million,
including accumulated interest. If cash expenditures are
less than the amount in base rates, IP will contribute 90%
of the difference to the fund. Once the trust fund is
depleted, 90% of allowed cash expenditures in excess of
base rates will be recovered through charges assessed to
customers under the tariff rider.
The Ameren Companies believe that the final
disposition of these proceedings will not have a material
adverse effect on their results of operations, financial
position, or liquidity.
NOTE 16 – CALLAWAY NUCLEAR PLANT
Under the Nuclear Waste Policy Act of 1982, the DOE
is responsible for the permanent storage and disposal of
spent nuclear fuel. The DOE currently charges one mill, or
1/10 of one cent, per nuclear-generated kilowatthour sold
for future disposal of spent fuel. Pursuant to this act, UE
collects one mill from its electric customers for each
kilowatthour of electricity that it generates and sells from
its Callaway nuclear plant. Electric utility rates charged to
customers provide for recovery of such costs. The DOE’s
last announced date of when it expects a permanent
storage facility for spent fuel to be available was 2020,
and the DOE continues to evaluate permanent storage
alternatives. UE has sufficient installed storage capacity at
its Callaway nuclear plant until 2020. It has the capability
for additional storage capacity through the licensed life of
the plant. The delayed availability of the DOE’s disposal
facility is not expected to adversely affect the continued
operation of the Callaway nuclear plant through its
currently licensed life.
UE intends to submit a license extension application
with the NRC to extend its Callaway nuclear plant’s
operating license from 2024 to 2044. If the Callaway
nuclear plant’s license is extended, additional spent fuel
storage will be required. UE is evaluating the installation of
a dry spent fuel storage facility at its Callaway nuclear plant.
Electric utility rates charged to customers provide for
the recovery of the Callaway nuclear plant’s
decommissioning costs, which include decontamination,
dismantling, and site restoration costs, over an assumed
40-year life of the plant, ending with the expiration of the
plant’s operating license in 2024. It is assumed that the
Callaway nuclear plant site will be decommissioned based
on the immediate dismantlement method and removed
from service. Ameren and UE have recorded an ARO for
the Callaway nuclear plant decommissioning costs at fair
value, which represents the present value of estimated
future cash outflows. Decommissioning costs are included
in the costs of service used to establish electric rates for
UE’s customers. These costs amounted to $7 million in
each of the years 2009, 2008, and 2007. Every three
years, the MoPSC requires UE to file an updated cost
study for decommissioning its Callaway nuclear plant.
Electric rates may be adjusted at such times to reflect
changed estimates. The latest cost study, filed in
September 2008, included minor tritium contamination
discovered on the Callaway nuclear plant site, which did
not result in a significant increase in the decommissioning
cost estimate. Costs collected from customers are
deposited in an external trust fund to provide for the
Callaway nuclear plant’s decommissioning. If the assumed
return on trust assets is not earned, we believe that it is
probable that any such earnings deficiency will be
recovered in rates. The fair value of the nuclear
decommissioning trust fund for UE’s Callaway nuclear
plant is reported as Nuclear Decommissioning Trust Fund
in Ameren’s Consolidated Balance Sheet and UE’s
Balance Sheet. This amount is legally restricted and may
be used only to fund the costs of nuclear
decommissioning. Changes in the fair value of the trust
fund are recorded as an increase or decrease to the
nuclear decommissioning trust fund, with an offsetting
adjustment to the related regulatory asset. See Note 9 –
Nuclear Decommissioning Trust Fund Investments for
additional information.
NOTE 17 – GOODWILL
We evaluate goodwill for impairment as of October 31
of each year, or more frequently if events and
circumstances indicate that the asset might be impaired.
Goodwill impairment testing is a two-step process. The
first step involves a comparison of the estimated fair value
of a reporting unit with its carrying amount. If the
estimated fair value of the reporting unit exceeds the
carrying value, goodwill of the reporting unit is considered
unimpaired. If the carrying amount of the reporting unit
exceeds its estimated fair value, a second step is
performed to measure the amount of impairment, if any.
The second step of the goodwill impairment test compares
the implied fair value of the reporting unit’s goodwill with
the carrying amount of that goodwill. The implied fair value
of goodwill is determined by allocating the estimated fair
value of the reporting unit to the estimated fair value of its
existing assets and liabilities in a manner similar to a
purchase price allocation. The unallocated portion of the
estimated fair value of the reporting unit is the implied fair
value of goodwill. If the implied fair value of goodwill is
less than the carrying amount, an impairment loss
equivalent to the difference is recorded as a reduction of
goodwill and a charge to operating expense.
During the first quarter of 2009, we concluded that
events had occurred and circumstances had changed
which
173
required us to perform an interim goodwill impairment test.
The following events triggered this impairment test:
A significant decline in Ameren’s market capitalization.
The continuing decline in market prices for electricity.
A decrease in observable industry market multiples.
The fair value of Ameren’s and IP’s reporting units
was estimated based on a risk-adjusted, probability-
weighted discounted cash flow model that considered
multiple operating scenarios. Key assumptions in the
determination of fair value included the use of an
appropriate discount rate, estimated five-year cash flows,
and an exit value based on observable industry market
multiples. We use our best estimates in making these
evaluations. We consider various factors, including
forward price curves for energy and fuel costs, the
regulatory environment, and operating costs. For the
interim test conducted as of March 31, 2009, the discount
rate used was 3.8%, based on the 20-year treasury yield.
To assess the reasonableness of the estimated reporting
unit fair values, the sum of the estimated fair values of the
Ameren reporting units is reconciled to our current market
capitalization plus an estimated control premium.
Ameren’s reporting units and IP’s reporting unit did not
require a second step assessment; the results of the step
one tests indicated no impairment of goodwill as of
March 31, 2009.
The annual impairment test, conducted as of
October 31, 2009, did not result in a second step
assessment; the test indicated no impairment of Ameren’s
or IP’s goodwill. The annual test was conducted in a
manner similar to the interim test described above.
Ameren’s market capitalization was less than the book
value of its equity as of the October 31, 2009, testing date
and during the remainder of 2009. However, the sum of
the estimated fair values of Ameren reporting units
exceeded the combined Ameren reporting unit carrying
value as of October 31, 2009. We believe the difference
between Ameren’s market capitalization and the sum of
the estimated fair values of the Ameren reporting units as
of October 31, 2009, can be explained by the application
of a reasonable control premium to our share price. The
discount rate used was 4.2%, based on the 20-year
treasury yield. At Ameren’s Illinois Regulated reporting
unit and IP’s Illinois Regulated reporting unit, either (1) a
decrease in the forecasted cash flows of ten percent,
(2) an increase in the discount rate of one percentage
point, or (3) a decrease of the market multiple by one
would not have resulted in the carrying value of the
reporting unit exceeding their fair values. However, the
estimated fair value of Ameren’s Merchant Generation
reporting unit exceeded its carrying value by a nominal
amount as of October 31, 2009. The estimated fair value
of Ameren’s Merchant Generation reporting unit exceeded
its carrying value by approximately $95 million, or 3%. The
failure in the future of any reporting unit to achieve
forecasted operating results and cash flows or a decline of
observable industry market multiples may further reduce
its estimated fair value below its carrying value, which
would likely result in the recognition of a goodwill
impairment charge.
Ameren and IP will continue to monitor the actual and
forecasted operating results, cash flows, market
capitalization, market prices for electricity, and observable
industry market multiples of their reporting units for signs
of possible declines in estimated fair value and potential
goodwill impairment.
Ameren has identified three reporting units, which also represent Ameren’s reportable segments. The Ameren
reporting units are Missouri Regulated, Illinois Regulated, and Merchant Generation. IP has one reporting unit, Illinois
Regulated. Ameren’s reporting units have been defined and goodwill has been evaluated at the operating segment level
in accordance with authoritative accounting guidance. The following tables provide a reconciliation of the beginning and
ending carrying amounts of goodwill by reporting unit, for Ameren and IP, for the years 2009 and 2008:
Ameren
2009
2008
Gross goodwill at January 1 .........................................
Accumulated impairment losses ...................................
Goodwill, net of accumulated impairment losses ..........
Changes during the year ..............................................
Goodwill, net of impairment losses at December 31 .....
Illinois
Regulated
$ 411
-
$ 411
-
$ 411
Includes amounts for Ameren registrants and nonregistrant subsidiaries.
Missouri
Regulated
$ -
-
$ -
-
$ -
(a)
IP
Merchant
Generation Total(a)
$ 831
$ 420
-
-
$ 831
$ 420
-
-
$ 831
$ 420
Missouri
Regulated
$ -
-
$ -
-
$ -
Illinois
Regulated
$ 411
-
$ 411
-
$ 411
Merchant
Generation
$ 420
-
$ 420
-
$ 420
Total(a)
$ 831
-
$ 831
-
$ 831
2009
2008
Gross goodwill at January 1 ........................................
Accumulated impairment losses ..................................
Goodwill, net of accumulated impairment losses .........
Changes during the year .............................................
Goodwill, net of impairment losses at December 31 ....
Missouri
Regulated
$ -
-
$ -
-
$ -
Illinois
Regulated
$ 214
-
$ 214
-
$ 214
Merchant
Generation Total
$ -
-
$ -
-
$ -
$ 214
-
$ 214
-
$ 214
Missouri
Regulated
$ -
-
$ -
-
$ -
Illinois
Regulated
$ 214
-
$ 214
-
$ 214
Merchant
Generation
$ -
-
$ -
-
$ -
Total
$ 214
-
$ 214
-
$ 214
174
NOTE 18 – SEGMENT INFORMATION
Ameren has three reportable segments: Missouri
Regulated, Illinois Regulated, and Merchant Generation.
The Missouri Regulated segment for Ameren includes all
the operations of UE’s business as described in Note 1 –
Summary of Significant Accounting Policies, except for
UE’s 40% interest in EEI (which in February 2008 was
transferred to Resources Company through an internal
reorganization). The Illinois Regulated segment for
Ameren consists of the regulated electric and gas
transmission and distribution businesses of CIPS, CILCO,
and IP, as described in Note 1 – Summary of Significant
Accounting Policies, and AITC. The Merchant Generation
segment for Ameren consists primarily of the operations or
activities of Genco, the CILCORP parent company,
AERG, EEI, Medina Valley and Marketing Company. The
category called Other primarily includes Ameren parent
company activities.
UE has one reportable segment: Missouri Regulated.
The Missouri Regulated segment for UE includes all the
operations of UE’s business as described in Note 1 –
Summary of Significant Accounting Policies, except for
UE’s former 40% interest in EEI.
CILCO has two reportable segments: Illinois
Regulated and Merchant Generation. The Illinois
Regulated segment for CILCO consists of the regulated
electric and gas transmission and distribution businesses
of CILCO. The Merchant Generation segment for CILCO
consists of the generation business of AERG. Other
comprises minor activities not reported in the Illinois
Regulated or Merchant Generation segments.
The following tables present information about the reported revenues and specified items included in net income of
Ameren, UE, and CILCO for the years ended December 31, 2009, 2008 and 2007, and total assets as of December 31,
2009, 2008 and 2007.
Ameren
Missouri
Regulated
Illinois
Regulated
Merchant
Generation
Other
Intersegment
Eliminations
Consolidated
$
$
-
(463)
-
(37)
(41)
-
-
-
(2,433)
$ 2,912
27
216
5
153
77
124
415
7,344
$ 2,847
27
357
29
229
128
259
872
12,301
$ 1,322
390
126
-
119
151
247
408
4,921
$ 7,090
-
725
30
508
332
612
1,704
23,790
9
19
26
33
48
(24 )
(18 )
9
1,657
2009
External revenues ..............................................................
Intersegment revenues ......................................................
Depreciation and amortization ............................................
Interest and dividend income .............................................
Interest charges .................................................................
Income taxes (benefit)........................................................
Net income (loss) attributable to Ameren Corporation(a) ......
Capital expenditures ..........................................................
Total assets .......................................................................
2008
External revenues ..............................................................
Intersegment revenues ......................................................
Depreciation and amortization ............................................
Interest and dividend income .............................................
Interest charges .................................................................
Income taxes (benefit)........................................................
Net income (loss) attributable to Ameren Corporation(a) ......
Capital expenditures ..........................................................
Total assets .......................................................................
2007
External revenues ..............................................................
Intersegment revenues ......................................................
Depreciation and amortization ............................................
Interest and dividend income .............................................
Interest charges .................................................................
Income taxes (benefit)........................................................
Net income attributable to Ameren Corporation(a) ...............
Capital expenditures ..........................................................
Total assets .......................................................................
(a) Represents net income (loss) available to common stockholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.
2
18
28
30
44
(40 )
(13 )
52
1,227
$ 7,562
-
681
55
423
330
618
1,381
20,752
$ 7,839
-
685
43
440
327
605
1,896
22,671
$ 1,315
497
105
2
107
182
281
395
3,784
$ 1,482
455
109
3
99
217
352
611
4,568
$ 2,915
46
333
34
194
143
281
625
10,852
$ 2,922
38
329
33
193
134
234
874
11,529
$ 3,318
62
217
26
132
25
47
321
6,409
$ 3,433
45
219
15
144
16
32
359
7,088
-
(645)
-
(59)
(39)
-
-
-
(1,258)
-
(556)
-
(38)
(40)
-
-
-
(1,741)
14
40
26
52
29
(20 )
9
40
965
$
$
$
$
175
Missouri Regulated
Other (a)
Consolidated UE
UE
2009
Revenues .....................................................................................................................
Depreciation and amortization .......................................................................................
Interest charges ............................................................................................................
Income taxes ................................................................................................................
Net income(b) ................................................................................................................
Capital expenditures .....................................................................................................
Total assets ..................................................................................................................
2008
Revenues .....................................................................................................................
Depreciation and amortization .......................................................................................
Interest charges ............................................................................................................
Income taxes ................................................................................................................
Net income(b) ................................................................................................................
Capital expenditures .....................................................................................................
Total assets ..................................................................................................................
2007
Revenues .....................................................................................................................
Depreciation and amortization .......................................................................................
Interest charges ............................................................................................................
Income taxes (benefit)...................................................................................................
Net income(b) ................................................................................................................
Capital expenditures .....................................................................................................
Total assets ..................................................................................................................
Included 40% interest in EEI through February 29, 2008.
(a)
(b) Represents net income available to the common stockholder (Ameren).
CILCO
2009
External revenues ............................................................
Intersegment revenues ....................................................
Depreciation and amortization ..........................................
Interest charges ...............................................................
Income taxes ...................................................................
Net income(a) ...................................................................
Capital expenditures ........................................................
Total assets .....................................................................
2008
External revenues ............................................................
Intersegment revenues ....................................................
Depreciation and amortization ..........................................
Interest charges ...............................................................
Income taxes ...................................................................
Net income(a) ...................................................................
Capital expenditures ........................................................
Total assets .....................................................................
2007
External revenues ............................................................
Intersegment revenues ....................................................
Depreciation and amortization ..........................................
Interest charges ...............................................................
Income taxes ...................................................................
Net income(a) ...................................................................
Capital expenditures ........................................................
Total assets .....................................................................
Illinois
Regulated
Merchant
Generation
$ 655
1
32
25
8
20
63
1,264
$ 805
3
50
16
5
16
61
1,214
$ 732
-
54
18
-
9
64
1,017
$ 427
-
38
16
64
114
91
1,119
$ 342
-
27
5
34
52
258
1,081
$ 279
4
19
8
39
65
190
859
$ 2,874
357
229
128
259
872
12,301
$ 2,960
329
193
134
234
874
11,529
$ 2,961
333
194
143
281
625
10,852
Other
$ -
-
-
-
-
-
-
$
-
-
-
-
-
-
-
-
$
-
-
-
1
-
-
-
-
$
$
$
-
-
-
-
-
-
-
-
-
-
-
11
-
-
-
-
-
(3 )
55
-
51
$
$
$
2,874
357
229
128
259
872
12,301
2,960
329
193
134
245
874
11,529
2,961
333
194
140
336
625
10,903
Intersegment
Eliminations
Consolidated
CILCO
$ -
(1 )
-
-
-
-
-
(1 )
$
$
-
(3 )
-
-
-
-
-
1
-
(4 )
-
-
-
-
-
(9 )
$ 1,082
-
70
41
72
134
154
2,382
$ 1,147
-
77
21
39
68
319
2,296
$ 1,011
-
73
27
39
74
254
1,867
(a) Represents net income available to the common stockholder (CILCORP); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated
segment.
176
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
Quarter Ended(a)
Ameren
March 31, 2009 ...........................................................
March 31, 2008 ...........................................................
June 30, 2009 .............................................................
June 30, 2008 .............................................................
September 30, 2009 ...................................................
September 30, 2008 ...................................................
December 31, 2009 ....................................................
December 31, 2008 ....................................................
Operating
Revenues
Operating
Income
Net Income
Attributable to
Ameren Corporation
Earnings per Common
Share - Basic and
Diluted
$ 1,916
2,081
1,684
1,790
1,815
2,060
1,675
1,908
$ 321
321
365
444
485
428
245
169
$ 141
138
165
206
227
204
79
57
$ 0.66
0.66
0.77
0.98
1.04
0.97
0.34
0.27
(a) The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is due to the effects of rounding
and changes in the number of weighted-average shares outstanding each period.
Quarter Ended
UE
March 31, 2009 ...........................................................
March 31, 2008 ...........................................................
June 30, 2009 .............................................................
June 30, 2008 .............................................................
September 30, 2009 ...................................................
September 30, 2008 ...................................................
December 31, 2009 ....................................................
December 31, 2008 ....................................................
CIPS
March 31, 2009 ...........................................................
March 31, 2008 ...........................................................
June 30, 2009 .............................................................
June 30, 2008 .............................................................
September 30, 2009 ...................................................
September 30, 2008 ...................................................
December 31, 2009 ....................................................
December 31, 2008 ....................................................
Genco(a)
March 31, 2009 ...........................................................
March 31, 2008 ...........................................................
June 30, 2009 .............................................................
June 30, 2008 .............................................................
September 30, 2009 ...................................................
September 30, 2008 ...................................................
December 31, 2009 ....................................................
December 31, 2008 ....................................................
CILCO
March 31, 2009 ...........................................................
March 31, 2008 ...........................................................
June 30, 2009 .............................................................
June 30, 2008 .............................................................
September 30, 2009 ...................................................
September 30, 2008 ...................................................
December 31, 2009 ....................................................
December 31, 2008 ....................................................
Operating
Revenues
Operating
Income (Loss)
Net Income (Loss)
Net Income (Loss)
Available to Common
Stockholder
$ 22
64
84
124
142
99
17
(36 )
$
7
3
1
(3 )
18
7
3
8
$ 47
46
46
74
27
20
35
35
$ 33
26
31
12
37
24
34
7
$
21
63
82
122
141
98
15
(38 )
$
$
$
6
2
1
(3 )
17
6
2
7
47
46
46
74
27
20
35
35
33
26
31
11
36
24
34
7
$ 655
724
752
771
836
875
631
590
$
$
$
265
290
196
207
208
217
200
268
225
233
218
196
212
238
195
241
311
345
232
232
251
264
288
306
$ 75
111
173
232
257
195
61
(24 )
$ 16
8
6
3
35
14
11
17
$ 90
83
84
133
63
46
73
68
$ 59
48
59
22
69
43
65
19
177
Quarter Ended
IP
March 31, 2009 ...........................................................
March 31, 2008 ...........................................................
June 30, 2009 .............................................................
June 30, 2008 .............................................................
September 30, 2009 ...................................................
September 30, 2008 ...................................................
December 31, 2009 ....................................................
December 31, 2008 ....................................................
(a) Genco had no preferred stock outstanding.
Operating
Revenues
Operating
Income (Loss)
Net Income (Loss)
Net Income (Loss)
Available to Common
Stockholder
$ 472
503
325
360
329
353
378
480
$ 49
27
47
8
83
29
51
39
$ 14
3
13
(10 )
35
5
17
7
$
13
2
13
(10 )
34
4
17
7
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE.
None.
ITEM 9A and ITEM 9A(T). CONTROLS AND PROCEDURES.
Each of the Ameren Companies was required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and
related SEC regulations as to management’s assessment of internal control over financial reporting for the 2009 fiscal
year.
(a) Evaluation of Disclosure Controls and Procedures
As of December 31, 2009, evaluations were performed under the supervision and with the participation of
management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of
the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules
13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, the principal executive officer and principal
financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to
provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the
Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and
forms and such information is accumulated and communicated to its management, including its principal executive and
principal financial officers, to allow timely decisions regarding required disclosure.
(b) Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as
such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of
management, including the principal executive officer and principal financial officer, an evaluation was conducted of the
effectiveness of each of the Ameren Companies’ internal control over financial reporting based on the framework in
Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). After making that evaluation, management concluded that each of the Ameren Companies’ internal
control over financial reporting was effective as of December 31, 2009. The effectiveness of Ameren’s internal control
over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent
registered public accounting firm, as stated in its report herein under Part II, Item 8. This annual report does not include an
attestation report of UE’s, Genco’s, CIPS’, CILCO’s, or IP’s (the Subsidiary Registrants) independent registered public
accounting firm regarding internal control over financial reporting. Management’s report for the Subsidiary Registrants was
not subject to attestation by the independent registered public accounting firm because temporary rules of the SEC permit
the company to provide only management’s report in this annual report.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness into future periods are subject to the risk that controls might become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures might
deteriorate.
(c) Change in Internal Control
There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent
fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial
reporting.
ITEM 9B. OTHER INFORMATION.
The Ameren Companies have no information reportable under this item that was required to be disclosed in a report
on SEC Form 8-K during the fourth quarter of 2009 that has not previously been reported on an SEC Form 8-K.
178
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
PART III
Information required by Items 401, 405, 406 and
407(c)(3),(d)(4) and (d)(5) of SEC Regulation S-K for
Ameren will be included in its definitive proxy statement for
its 2010 annual meeting of shareholders filed pursuant to
SEC Regulation 14A; it is incorporated herein by reference.
Information required by these SEC Regulation S-K items for
UE, CIPS and CILCO will be included in each company’s
definitive information statement for its 2010 annual meeting
of shareholders filed pursuant to SEC Regulation 14C; it is
incorporated herein by reference. Information required by
these SEC Regulation S-K items for IP is identical to the
information that will be contained in CIPS’ definitive
information statement for CIPS’ 2010 annual meeting of
shareholders filed pursuant to SEC Regulation 14C; it is
incorporated herein by reference. With respect to Genco
this information is omitted in reliance on General Instruction
I(2) of Form 10-K.
Information concerning executive officers of the
Ameren Companies required by Item 401 of SEC
Regulation S-K is reported under a separate caption
entitled “Executive Officers of the Registrants” in Part I of
this report.
UE, CIPS, Genco, CILCO and IP do not have
separately designated standing audit committees, but
instead use Ameren’s audit and risk committee to perform
such committee functions for their boards of directors.
These companies have no securities listed on the NYSE
and therefore are not subject to the NYSE listing
standards. Douglas R. Oberhelman serves as chairman of
Ameren’s audit and risk committee, and Stephen F.
Brauer, Susan S. Elliott, Ellen M. Fitzsimmons and
Stephen R. Wilson serve as members. The board of
ITEM 11. EXECUTIVE COMPENSATION.
directors of Ameren has determined that Douglas R.
Oberhelman qualifies as an audit committee financial
expert and that he is “independent” as that term is used in
SEC Regulation 14A.
Also, on the same basis as reported above, the
boards of directors of UE, CIPS, Genco, CILCO and IP
use the nominating and corporate governance committee
of Ameren’s board of directors to perform such committee
functions. This committee is responsible for the
nomination of directors and corporate governance
practices. Ameren’s nominating and corporate governance
committee will consider director nominations from
shareholders in accordance with its Policy Regarding
Nominations of Directors, which can be found on
Ameren’s Web site: www.ameren.com.
To encourage ethical conduct in its financial
management and reporting, Ameren has adopted a Code
of Ethics that applies to the principal executive officer, the
principal financial officer, the principal accounting officer,
the controllers, and the treasurer of the Ameren
Companies. Ameren has also adopted a Code of
Business Conduct that applies to the directors, officers,
and employees of the Ameren Companies. It is referred to
as the Corporate Compliance Policy. The Ameren
Companies make available free of charge through
Ameren’s Web site (www.ameren.com) the Code of Ethics
and Corporate Compliance Policy. Any amendment to, or
waiver of, the Code of Ethics and Corporate Compliance
Policy will be posted on Ameren’s Web site within four
business days following the date of the amendment or
waiver.
Information required by Items 402 and 407(e)(4) and (e)(5) of SEC Regulation S-K for Ameren will be included in its
definitive proxy statement for its 2010 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is
incorporated herein by reference. Information required by these SEC Regulation S-K items for UE, CIPS and CILCO will
be included in each company’s definitive information statement for its 2010 annual meeting of shareholders filed pursuant
to SEC Regulation 14C; it is incorporated herein by reference. Information required by these SEC Regulation S-K items
for IP is identical to the information that will be included in CIPS’ definitive information statement for CIPS’ 2010 annual
meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. With respect to
Genco, this information is omitted in reliance on General Instruction I(2) of Form 10-K.
179
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS.
Equity Compensation Plan Information
The following table presents information as of December 31, 2009, with respect to the shares of Ameren’s common
stock that may be issued under its existing equity compensation plans.
Plan Category
Equity compensation plans approved by security
holders(a) .......................................................................
Equity compensation plans not approved by security
holders ..........................................................................
Total ...................................................................................
Number of Securities to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights
(a)
Weighted-Average
Exercise Price of
Outstanding Options,
Warrants and Rights
(b)
Number of Securities Remaining
Available for Future Issuance Under
Equity Compensation
Plans (excluding
securities reflected in column (a))
(c)
1,510,657
-
1,510,657
$ 31.00(b)
-
$ 31.00 (b)
2,482,059
-
2,482,059
(a) Consists of the Ameren Corporation Long-term Incentive Plan of 1998, which was approved by shareholders in April 1998 and expired on April 1, 2008, and
the Ameren Corporation 2006 Omnibus Incentive Compensation Plan, which was approved by shareholders in May 2006 and expires on May 2, 2016.
Pursuant to grants of performance share units (PSUs) under the Long-term Incentive Plan of 1998 and the 2006 Omnibus Incentive Compensation Plan,
124,953 of the securities represent PSUs that vested at December 31, 2009 (including accrued and reinvested dividends), and 1,327,354 of the securities
represent PSUs granted but not vested (including accrued and reinvested dividends). The actual number of shares issued in respect of the PSUs will vary
from 0% to 200% of the target level based on the achievement of total shareholder return objectives established for such awards.
calculating the weighted-average exercise price.
UE, CIPS, Genco, CILCO and IP do not have separate equity compensation plans.
(b) PSUs are awarded when earned in shares of Ameren common stock on a one-for-one basis. Accordingly, the PSUs have been excluded for purposes of
Security Ownership of Certain Beneficial Owners and Management
The information required by Item 403 of SEC Regulation S-K for Ameren will be included in its definitive proxy
statement for its 2010 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by
reference. Information required by this SEC Regulation S-K item for UE, CIPS and CILCO will be included in each
company’s definitive information statement for its 2010 annual meeting of shareholders filed pursuant to SEC Regulation
14C; it is incorporated herein by reference. With respect to Genco, this information is omitted in reliance on General
Instruction I(2) of Form 10-K. Information required by SEC Regulation S-K Item 403 for IP is as follows.
Securities of IP
All 23 million outstanding shares of IP’s common stock and 662,924 shares, or about 73%, of IP’s preferred stock are
owned by Ameren. None of IP’s outstanding shares of preferred stock were owned by directors, nominees for director, or
executive officers of IP as of February 1, 2010. To our knowledge, other than Ameren, there are no beneficial owners of
5% or more of IP’s outstanding shares of preferred stock as of February 1, 2010, but no independent inquiry has been
made to determine whether any shareholder is the beneficial owner of shares not registered in the name of such
shareholder or whether any shareholder is a member of a shareholder group.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.
Information required by Item 404 and Item 407(a) of SEC Regulation S-K for Ameren will be included in its definitive
proxy statement for its 2010 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated
herein by reference. Information required by Item 404 of SEC Regulation S-K item for UE, CIPS and CILCO will be
included in each company’s definitive information statement for its 2010 annual meeting of shareholders filed pursuant to
SEC Regulation 14C; it is incorporated herein by reference. Information required by Item 404 of SEC Regulation S-K item
for IP is identical to the information that will be contained in CIPS’ definitive information statement for CIPS’ 2010 annual
meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. With respect to
Genco, this information is omitted in reliance on General Instruction I(2) of Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies will be included in the definitive
proxy statement of Ameren and the definitive information statements of UE, CIPS and CILCO for their 2010 annual
meetings of shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by
reference.
180
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
PART IV
(a)(1) Financial Statements
Ameren
Report of Independent Registered Public Accounting Firm .............................................................................................................................
Consolidated Statement of Income - Years Ended December 31, 2009, 2008 and 2007 .................................................................................
Consolidated Balance Sheet - December 31, 2009 and 2008 ........................................................................................................................
Consolidated Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007 ..........................................................................
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2009, 2008 and 2007 ..............................................
UE
Report of Independent Registered Public Accounting Firm .............................................................................................................................
Consolidated Statement of Income - Years Ended December 31, 2009, 2008 and 2007 .................................................................................
Balance Sheet - December 31, 2009 and 2008 ..............................................................................................................................................
Consolidated Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007 ..........................................................................
Consolidated Statement of Common Stockholders’ Equity ............................................................................................................................
CIPS
Report of Independent Registered Public Accounting Firm .............................................................................................................................
Statement of Income - Years Ended December 31, 2009, 2008 and 2007 ......................................................................................................
Balance Sheet - December 31, 2009 and 2008 ..............................................................................................................................................
Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007 ...............................................................................................
Statement of Common Stockholders’ Equity ..................................................................................................................................................
Genco
Report of Independent Registered Public Accounting Firm .............................................................................................................................
Consolidated Statement of Income - Years Ended December 31, 2009, 2008 and 2007 .................................................................................
Consolidated Balance Sheet - December 31, 2009 and 2008 .........................................................................................................................
Consolidated Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007 ..........................................................................
Consolidated Statement of Common Stockholder’s Equity - Years Ended December 31, 2009, 2008 and 2007 ..............................................
CILCO
Report of Independent Registered Public Accounting Firm .............................................................................................................................
Consolidated Statement of Income - Years Ended December 31, 2009, 2008 and 2007 .................................................................................
Consolidated Balance Sheet - December 31, 2009 and 2008 .........................................................................................................................
Consolidated Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007 ..........................................................................
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2009, 2008 and 2007 ..............................................
IP
Report of Independent Registered Public Accounting Firm .............................................................................................................................
Consolidated Statement of Income - Years Ended December 31, 2009, 2008 and 2007 .................................................................................
Balance Sheet -December 31, 2009 and 2008 ...............................................................................................................................................
Consolidated Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007 ..........................................................................
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2009, 2008 and 2007 ..............................................
(a)(2) Financial Statement Schedules
Schedule I - Condensed Financial Information of Parent - Ameren:
Condensed Statement of Income - Years Ended December 31, 2009, 2008 and 2007 ........................................................................
Condensed Balance Sheet - December 31, 2009 and 2008 ................................................................................................................
Condensed Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007 .................................................................
Schedule I - Condensed Financial Information of Parent - CILCO:
Condensed Statement of Income - Years Ended December 31, 2009, 2008 and 2007 ........................................................................
Condensed Balance Sheet - December 31, 2009 and 2008 ................................................................................................................
Condensed Statement of Cash Flows - Years Ended December 31, 2009, 2008 and 2007 .................................................................
Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2009, 2008 and 2007 .....................................................
Page No.
78
81
82
83
84
79
85
86
87
88
79
89
90
91
92
79
93
94
95
96
80
97
98
99
100
80
101
102
103
104
182
182
182
183
183
183
184
Schedule I and II should be read in conjunction with the aforementioned financial statements. Certain schedules have been omitted because they are not
applicable or because the required data is shown in the aforementioned financial statements.
(a)(3) Exhibits.
Reference is made to the Exhibit Index commencing on page 191.
Exhibits are listed in the Exhibit Index commencing on page 191.
(b)
181
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME
For the Years Ended December 31, 2009, 2008 and 2007
(In millions)
Operating revenue ......................................................................................................................................
Operating expenses ....................................................................................................................................
Operating loss ............................................................................................................................................
Equity in earnings of subsidiaries ................................................................................................................
Miscellaneous income .................................................................................................................................
Interest and other charges ..........................................................................................................................
Income tax expense ....................................................................................................................................
Net income .................................................................................................................................................
$
2009
-
20
(20 )
625
32
37
(12 )
$ 612
2008
$
-
22
(22 )
610
16
22
(23 )
$ 605
2007
-
$
18
(18 )
614
30
25
(17 )
$ 618
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET
December 31, 2009
December 31, 2008
(In millions)
Assets:
Cash and equivalents ................................................................................................................................
Accounts and notes receivable .................................................................................................................
Total current assets ........................................................................................................................
Investments in subsidiaries ........................................................................................................................
Other .........................................................................................................................................................
Total assets ..........................................................................................................................................................
Liabilities and Stockholders’ Equity:
Accounts payable ......................................................................................................................................
Other current liabilities ...............................................................................................................................
Total current liabilities .....................................................................................................................
Long-term debt ..........................................................................................................................................
Other deferred credits and other noncurrent liabilities .................................................................................
Stockholders’ equity ...................................................................................................................................
Total liabilities and stockholders’ equity .................................................................................................................
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2009, 2008 and 2007
(In millions)
Net cash flows from operating activities .............................................................................................
Cash flows from investing activities:
Money pool advances, net .....................................................................................................
Investments in subsidiaries ....................................................................................................
Net cash flows from investing activities .............................................................................................
Cash flows from financing activities:
Dividends on common stock ..................................................................................................
Short-term and credit facility borrowings, net ..........................................................................
Redemptions, repurchases, and maturities of long-term debt .................................................
Issuances of:
Long-term debt ...........................................................................................................
Common stock ...........................................................................................................
Other .....................................................................................................................................
Net cash flows from financing activities .............................................................................................
Net change in cash and equivalents ..................................................................................................
Cash and equivalents at beginning of year ........................................................................................
Cash and equivalents at the end of year ...........................................................................................
Cash dividends received from consolidated subsidiaries ...................................................................
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2009
NOTE 1 – BASIS OF PRESENTATION
$
24
1,211
1,235
7,882
229
$ 9,346
$
66
915
981
423
73
7,869
$ 9,346
$
22
804
826
6,764
133
$ 7,723
$
50
632
682
-
78
6,963
$ 7,723
2008
$ 338
2007
$ 682
2009
$ ( 442)
300
(831)
( 531)
(338)
275
-
423
634
(19)
97 5
2
22
24
338
(129)
67
(62)
(534)
25
-
-
154
(6)
(361)
(85)
107
22
534
131
(523)
(392)
(527)
500
(350)
-
91
-
(286)
4
103
107
527
Ameren Corporation (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented
on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the combined notes under Part II, Item 8, of
this report.
182
NOTE 2 – LONG-TERM OBLIGATIONS
See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a description and details of long-term obligations of Ameren
Corporation (parent company only).
NOTE 3 – COMMITMENTS AND CONTINGENCIES
See Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for a description of all material contingencies and guarantees outstanding
of Ameren Corporation (parent company only).
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CENTRAL ILLINOIS LIGHT COMPANY
CONDENSED STATEMENT OF INCOME
For the Years Ended December 31, 2009, 2008 and 2007
(In millions)
Operating revenue .....................................................................................................................................
Operating expenses ...................................................................................................................................
Operating income ......................................................................................................................................
Equity in earnings of subsidiaries ...............................................................................................................
Miscellaneous income (expense) ...............................................................................................................
Interest and other charges .........................................................................................................................
Income tax expense ...................................................................................................................................
Net income ................................................................................................................................................
2009
$ 656
598
58
114
(4)
26
8
$ 134
2008
$ 808
767
41
52
(3 )
17
5
68
$
2007
$ 732
704
28
65
1
20
-
$ 74
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CENTRAL ILLINOIS LIGHT COMPANY
CONDENSED BALANCE SHEET
December 31, 2009
December 31, 2008
(In millions)
Assets:
Cash and equivalents .............................................................................................................
Other current assets ...............................................................................................................
Total current assets .....................................................................................................
Investments in subsidiaries .....................................................................................................
Property and plant, net ............................................................................................................
Other ......................................................................................................................................
Total assets .......................................................................................................................................
Liabilities and Stockholders’ Equity:
Accounts payable ...................................................................................................................
Other current liabilities ............................................................................................................
Total current liabilities ..................................................................................................
Long-term debt .......................................................................................................................
Other deferred credits and other noncurrent liabilities ..............................................................
Stockholders’ equity ................................................................................................................
Total liabilities and stockholders’ equity ..............................................................................................
$
88
207
295
552
792
177
$ 1,816
$
76
96
172
279
512
853
$ 1,816
$
-
248
248
438
754
209
$ 1,649
$
86
95
181
279
501
688
$ 1,649
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CENTRAL ILLINOIS LIGHT COMPANY
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2009, 2008 and 2007
(In millions)
Net cash flows from operating activities ...............................................................................................
Cash flows from investing activities: ....................................................................................................
Capital expenditures ................................................................................................................
Net cash flows from investing activities ...............................................................................................
Cash flows from financing activities:
Dividends on common stock ....................................................................................................
Short-term debt, net .................................................................................................................
Redemptions, repurchases, and maturities of long term debt ...................................................
Issuances of long-term debt .....................................................................................................
Capital contribution from parent ...............................................................................................
Other .......................................................................................................................................
Net cash flows from financing activities ...............................................................................................
Net change in cash and equivalents ....................................................................................................
Cash and equivalents at beginning of year ..........................................................................................
Cash and equivalents at the end of year .............................................................................................
Cash dividends received from consolidated subsidiaries .....................................................................
2009
$ 124
2008
$ 42
2007
$ 38
(63)
(63)
(20)
-
-
-
51
(4)
27
88
-
88
-
(61)
(61)
-
(115)
(19)
150
-
(1)
15
(4)
4
-
-
(64 )
(64 )
-
65
(50 )
-
15
-
30
4
-
4
10
183
CENTRAL ILLINOIS LIGHT COMPANY (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2009
NOTE 1 – BASIS OF PRESENTATION
Central Illinois Light Company (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are
presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the combined notes under Part II,
Item 8, of this report.
NOTE 2 – LONG-TERM OBLIGATIONS
See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a description and details of long-term obligations of Central Illinois
Light Company (parent company only).
NOTE 3 – COMMITMENTS AND CONTINGENCIES
See Note 15 – Commitments and Contingencies under Part II, Item 8, of this report for a description of all material contingencies and guarantees outstanding
of Central Illinois Light Company (parent company only).
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007
(In millions)
Column A
Description
Ameren:
Deducted from assets - allowance for doubtful accounts:
2009 ...................................................................................
2008 ...................................................................................
2007 ...................................................................................
UE:
Deducted from assets - allowance for doubtful accounts:
2009 ...................................................................................
2008 ...................................................................................
2007 ...................................................................................
CIPS:
Deducted from assets - allowance for doubtful accounts:
2009 ...................................................................................
2008 ...................................................................................
2007 ...................................................................................
CILCO:
Deducted from assets - allowance for doubtful accounts:
2009 ...................................................................................
2008 ...................................................................................
2007 ...................................................................................
IP:
Deducted from assets - allowance for doubtful accounts:
2009 ...................................................................................
2008 ...................................................................................
2007 ...................................................................................
Column B
Balance at
Beginning
of Period
Column C
Column D
Column E
(1)
Charged to Costs
and Expenses
(2)
Charged to Other
Accounts
Deductions(a)
Balance at End
of Period
$ 28
22
11
$ 8
6
6
$ 6
5
2
$ 3
2
1
$ 12
9
3
$ 37
63
53
$
$
$
8
14
14
7
13
10
6
9
7
$ 14
27
21
$ -
-
-
$
$
$
$
-
-
-
-
-
-
-
-
-
-
-
-
$ 41
57
42
$ 10
12
14
$
$
8
12
7
6
8
6
$ 17
24
15
$ 24
28
22
$ 6
8
6
$ 5
6
5
$ 3
3
2
$ 9
12
9
(a) Uncollectible accounts charged off, less recoveries.
184
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for each
undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
SIGNATURES
Date: February 26, 2010
AMEREN CORPORATION (registrant)
By /s/ Thomas R. Voss
Thomas R. Voss
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Thomas R. Voss
Thomas R. Voss
President, Chief Executive Officer
and Director
(Principal Executive Officer)
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and
Chief Financial Officer
(Principal Financial and Accounting Officer)
Stephen F. Brauer
Susan S. Elliott
Ellen M. Fitzsimmons
Walter J. Galvin
Gayle P.W. Jackson
James C. Johnson
*
*
*
*
*
*
*
Charles W. Mueller
*
Douglas R. Oberhelman
Gary L. Rainwater
Harvey Saligman
Patrick T. Stokes
Stephen R. Wilson
Jack D. Woodard
*
*
*
*
*
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
185
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
Date: February 26, 2010
UNION ELECTRIC COMPANY (registrant)
By /s/ Warner L. Baxter
Warner L. Baxter
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Daniel F. Cole
Adam C. Heflin
Richard J. Mark
Steven R. Sullivan
*
*
*
*
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
Senior Vice President,
Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
Director
Director
Director
Director
186
Date: February 26, 2010
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY (registrant)
By /s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Scott A. Cisel
Scott A. Cisel
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Daniel F. Cole
Steven R. Sullivan
*
*
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
February 26, 2010
Senior Vice President,
Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
Director
Director
187
AMEREN ENERGY GENERATING COMPANY (registrant)
Date: February 26, 2010
By /s/ Charles D. Naslund
Charles D. Naslund
Chairman and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Charles D. Naslund
Charles D. Naslund
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Daniel F. Cole
Steven R. Sullivan
*
*
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
Chairman, President and Director
(Principal Executive Officer)
February 26, 2010
Senior Vice President,
Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
Director
Director
188
Date: February 26, 2010
CENTRAL ILLINOIS LIGHT COMPANY (registrant)
By /s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Scott A. Cisel
Scott A. Cisel
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Daniel F. Cole
Steven R. Sullivan
*
*
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
February 26, 2010
Senior Vice President,
Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
Director
Director
189
Date: February 26, 2010
ILLINOIS POWER COMPANY (registrant)
By /s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ Scott A. Cisel
Scott A. Cisel
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Daniel F. Cole
Steven R. Sullivan
*
*
*By /s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Attorney-in-Fact
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
February 26, 2010
Senior Vice President,
Chief Financial Officer and Director
(Principal Financial and Accounting Officer)
February 26, 2010
February 26, 2010
February 26, 2010
February 26, 2010
Director
Director
190
The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from
the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith:
EXHIBIT INDEX
Nature of Exhibit
Previously Filed as Exhibit to:
File No. 33-64165, Annex F
1998 Form 10-K, Exhibit 3(i), File No. 1-
14756
1993 Form 10-K, Exhibit 3(i), File No. 1-2967
March 31, 1994 Form 10-Q, Exhibit 3(b), File
No. 1-3672
Exhibit 3.1, Form S-4, File No. 333-56594
Exhibit 3.2, Form S-4, File No. 333-56594
1998 Form 10-K, Exhibit 3, File No. 1-2732
September 7, 1994 Form 8-K, Exhibit 3(a),
File No. 1-3004
Exhibit 4.1(ii), File No. 333-84008
October 14, 2008 Form 8-K, Exhibit 3.1(ii),
File No. 1-14756
July 29, 2008 Form 8-K, Exhibit 3.1(ii), File
No. 1-2967
July 29, 2008 Form 8-K, Exhibit 3.2(ii), File
No. 1-3672
September 30, 2004 Form 10-Q, Exhibit 3.1,
File No. 333-56594
July 29, 2008 Form 8-K, Exhibit 3.3(ii), File
No. 1-2732
July 29, 2008 Form 8-K, Exhibit 3.4(ii), File
No. 1-3004
Exhibit 4.5, File No. 333-81774
June 30, 2008 Form 10-Q, Exhibit 4.1, File
No. 1-14756
May 15, 2009 Form 8-K, Exhibits 4.3 and 4.4,
File No. 1-14756
Exhibit B-1, File No. 2-4940
Exhibit Designation
Articles of Incorporation/ By-Laws
Ameren
Ameren
3.1(i)
3.2(i)
Registrant(s)
3.3(i)
3.4(i)
3.5(i)
3.6(i)
3.7(i)
3.8(i)
3.9(i)
3.10(ii)
3.11(ii)
3.12(ii)
3.13(ii)
3.14(ii)
3.15(ii)
UE
CIPS
Genco
Genco
CILCO
IP
IP
Ameren
UE
CIPS
Genco
CILCO
IP
4.2
4.3
4.4
Ameren
Ameren
Ameren
UE
Instruments Defining Rights of Security Holders, Including Indentures
4.1
Ameren
Restated Articles of Incorporation of Ameren
Certificate of Amendment to Ameren’s Restated
Articles of Incorporation filed December 14, 1997
Restated Articles of Incorporation of UE
Restated Articles of Incorporation of CIPS
Articles of Incorporation of Genco
Amendment to Articles of Incorporation of Genco
filed April 19, 2000
Articles of Incorporation of CILCO as amended
May 29, 1998
Amended and Restated Articles of Incorporation of
IP, dated September 7, 1994
Articles of Amendment to IP’s Amended and
Restated Articles of Incorporation filed March 28,
2002
By-Laws of Ameren as amended effective October
10, 2008
By-Laws of UE as amended July 28, 2008
By-Laws of CIPS as amended July 28, 2008
By-Laws of Genco as amended to October 8,
2004
By-Laws of CILCO as amended effective July 28,
2008
By-Laws of IP as amended July 28, 2008
Indenture of Ameren with The Bank of New York
Mellon Trust Company, N.A., as successor
trustee, relating to senior debt securities dated as
of December 1, 2001 (Ameren’s Senior Indenture)
First Supplemental Indenture to Ameren’s Senior
Indenture dated as of May 19, 2008
Ameren Company Order dated May 15, 2009,
establishing 8.875% Senior Notes, due 2014
(including the global note)
Indenture of Mortgage and Deed of Trust dated
June 15, 1937 (UE Mortgage), from UE to The
Bank of New York Mellon, as successor trustee,
as amended May 1, 1941, and Second
Supplemental Indenture dated May 1, 1941
191
Exhibit Designation
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
Registrant(s)
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Nature of Exhibit
Supplemental Indenture to the UE Mortgage dated
as of April 1, 1971
Supplemental Indenture to the UE Mortgage dated
as of February 1, 1974
Supplemental Indenture to the UE Mortgage dated
as of July 7, 1980
Supplemental Indenture to the UE Mortgage dated
as of May 1, 1993
Supplemental Indenture to the UE Mortgage dated
as of October 1, 1993
Supplemental Indenture to the UE Mortgage dated
as of February 1, 2000
Supplemental Indenture to the UE Mortgage dated
August 15, 2002
Supplemental Indenture to the UE Mortgage dated
March 5, 2003
Supplemental Indenture to the UE Mortgage dated
April 1, 2003
Supplemental Indenture to the UE Mortgage dated
July 15, 2003
Supplemental Indenture to the UE Mortgage dated
October 1, 2003
Supplemental Indenture to the UE Mortgage dated
February 1, 2004, relative to Series 2004A
(1998A) Bonds
Supplemental Indenture to the UE Mortgage dated
February 1, 2004, relative to Series 2004B
(1998B) Bonds
Supplemental Indenture to the UE Mortgage dated
February 1, 2004, relative to Series 2004C
(1998C) Bonds
Supplemental Indenture to the UE Mortgage dated
February 1, 2004, relative to Series 2004D
(2000B) Bonds
Supplemental Indenture to the UE Mortgage dated
February 1, 2004, relative to Series 2004E
(2000A) Bonds
Supplemental Indenture to the UE Mortgage dated
February 1, 2004, relative to Series 2004F
(2000C) Bonds
Supplemental Indenture to the UE Mortgage dated
February 1, 2004, relative to Series 2004G (1991)
Bonds
Supplemental Indenture to the UE Mortgage dated
February 1, 2004, relative to Series 2004H (1992)
Bonds
Supplemental Indenture to the UE Mortgage dated
May 1, 2004
Supplemental Indenture to the UE Mortgage dated
September 1, 2004
Supplemental Indenture to the UE Mortgage dated
January 1, 2005
Previously Filed as Exhibit to:
April 1971 Form 8-K, Exhibit 6, File No. 1-
2967
February 1974 Form 8-K, Exhibit 3, File
No. 1-2967
Exhibit 4.6, File No. 2-69821
1993 Form 10-K, Exhibit 4.6, File No. 1-2967
1993 Form 10-K, Exhibit 4.8, File No. 1-2967
2000 Form 10-K, Exhibit 4.1, File No. 1-2967
August 23, 2002 Form 8-K, Exhibit 4.3, File
No. 1-2967
March 11, 2003 Form 8-K, Exhibit 4.4, File
No. 1-2967
April 10, 2003 Form 8-K, Exhibit 4.4, File
No. 1-2967
August 4, 2003 Form 8-K, Exhibit 4.4, File
No. 1-2967
October 8, 2003 Form 8-K, Exhibit 4.4, File
No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.1, File
No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.2, File
No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.3, File
No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.4, File
No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.5, File
No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.6, File
No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.7, File
No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.8, File
No. 1-2967
May 18, 2004 Form 8-K, Exhibit 4.4, File
No. 1-2967
September 23, 2004 Form 8-K, Exhibit 4.4,
File No. 1-2967
January 27, 2005 Form 8-K, Exhibit 4.4, File
No. 1-2967
192
Exhibit Designation
4.27
4.28
4.29
4.30
4.31
4.32
4.33
4.34
4.35
4.36
4.37
4.38
4.39
4.40
4.41
4.42
4.43
Registrant(s)
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Nature of Exhibit
Supplemental Indenture to the UE Mortgage dated
July 1, 2005
Supplemental Indenture to the UE Mortgage dated
December 1, 2005
Supplemental Indenture to the UE Mortgage dated
June 1, 2007
Supplemental Indenture to the UE Mortgage dated
April 1, 2008
Supplemental Indenture to the UE Mortgage dated
June 1, 2008
Supplemental Indenture to the UE Mortgage dated
March 1, 2009
Loan Agreement dated as of December 1, 1992,
between the Missouri Environmental Authority and
UE, together with Indenture of Trust dated as of
December 1, 1992, between the Missouri
Environmental Authority and UMB Bank, N.A. as
successor trustee to Mercantile Bank of St. Louis,
N.A.
First Amendment dated as of February 1, 2004, to
Loan Agreement dated as of December 1, 1992,
between the Missouri Environmental Authority and
UE
Series 1998A Loan Agreement dated as of
September 1, 1998, between the Missouri
Environmental Authority and UE
First Amendment dated as of February 1, 2004, to
Series 1998A Loan Agreement dated as of
September 1, 1998, between the Missouri
Environmental Authority and UE
Series 1998B Loan Agreement dated as of
September 1, 1998, between the Missouri
Environmental Authority and UE
First Amendment dated as of February 1, 2004, to
Series 1998B Loan Agreement dated as of
September 1, 1998, between the Missouri
Environmental Authority and UE
Series 1998C Loan Agreement dated as of
September 1, 1998, between the Missouri
Environmental Authority and UE
First Amendment dated as of February 1, 2004, to
Series 1998C Loan Agreement dated as of
September 1, 1998, between the Missouri
Environmental Authority and UE
Indenture dated as of August 15, 2002, from UE to
The Bank of New York Mellon, as successor
trustee (relating to senior secured debt securities)
UE Company Order dated August 22, 2002,
establishing the 5.25% Senior Secured Notes due
2012 (including the global note)
UE Company Order dated March 10, 2003,
establishing the 5.50% Senior Secured Notes due
2034 (including the global note)
Previously Filed as Exhibit to:
July 21, 2005 Form 8-K, Exhibit 4.4, File
No. 1-2967
December 9, 2005 Form 8-K, Exhibit 4.4, File
No. 1-2967
June 15, 2007 Form 8-K, Exhibit 4.5, File
No. 1-2967
April 8, 2008 Form 8-K, Exhibit 4.7, File
No. 1-2967
June 19, 2008 Form 8-K, Exhibit 4.5, File
No. 1-2967
March 23, 2009 Form 8-K, Exhibit 4.5, File
No. 1-2967
1992 Form 10-K, Exhibit 4.38, File No. 1-
2967
March 31, 2004 Form 10-Q, Exhibit 4.10, File
No. 1-2967
September 30, 1998 Form 10-Q, Exhibit
4.28, File No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.11, File
No. 1-2967
September 30, 1998 Form 10-Q, Exhibit
4.29, File No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.12, File
No. 1-2967
September 30, 1998 Form 10-Q, Exhibit
4.30, File No. 1-2967
March 31, 2004 Form 10-Q, Exhibit 4.13, File
No. 1-2967
August 23, 2002 Form 8-K, Exhibit 4.1, File
No. 1-2967
August 23, 2002 Form 8-K, Exhibit 4.2, File
No. 1-2967
March 11, 2003 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
193
Exhibit Designation
4.44
4.45
4.46
4.47
4.48
4.49
4.50
4.51
4.52
4.53
4.54
4.55
4.56
4.57
4.58
4.59
4.60
4.61
4.62
4.63
Registrant(s)
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Nature of Exhibit
UE Company Order dated April 9, 2003,
establishing the 4.75% Senior Secured Notes due
2015 (including the global note)
UE Company Order dated July 28, 2003,
establishing the 5.10% Senior Secured Notes due
2018 (including the global note)
UE Company Order dated October 7, 2003,
establishing the 4.65% Senior Secured Notes due
2013 (including the global note)
UE Company Order dated May 13, 2004,
establishing the 5.50% Senior Secured Notes due
2014 (including the global note)
UE Company Order dated September 1, 2004,
establishing the 5.10% Senior Secured Notes due
2019 (including the global note)
UE Company Order dated January 27, 2005,
establishing the 5.00% Senior Secured Notes due
2020 (including the global note)
UE Company Order dated July 21, 2005,
establishing the 5.30% Senior Secured Notes due
2037 (including the global note)
UE Company Order dated December 8, 2005,
establishing the 5.40% Senior Secured Notes due
2016 (including the global note)
UE Company Order dated June 15, 2007,
establishing the 6.40% Senior Secured Notes due
2017 (including the global note)
UE Company Order dated April 8, 2008,
establishing the 6.00% Senior Secured Notes due
2018 (including the global note)
UE Company Order dated June 19, 2008,
establishing the 6.70% Senior Secured Notes due
2019 (including the global note)
UE Company Order dated March 20, 2009,
establishing 8.45% Senior Secured Notes due
2039 (including the global note)
Indenture of Mortgage or Deed of Trust dated
October 1, 1941, from CIPS to U.S. Bank National
Association and Richard Prokosch, as successor
trustees (CIPS Mortgage)
Supplemental Indenture to the CIPS Mortgage,
dated September 1, 1947
Supplemental Indenture to the CIPS Mortgage,
dated January 1, 1949
Supplemental Indenture to the CIPS Mortgage,
dated June 1, 1965
Supplemental Indenture to the CIPS Mortgage,
dated April 1, 1971
Supplemental Indenture to the CIPS Mortgage,
dated December 1, 1973
Supplemental Indenture to the CIPS Mortgage,
dated February 1, 1980
Supplemental Indenture to the CIPS Mortgage,
dated May 15, 1992
Previously Filed as Exhibit to:
April 10, 2003 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
August 4, 2003 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
October 8, 2003 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
May 18, 2004 Form 8-K, Exhibits 4.2 and 4.3,
No. 1-2967
September 23, 2004 Form 8-K, Exhibits 4.2
and 4.3, No. 1-2967
January 27, 2005 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3,
File No. 1-2967
December 9, 2005 Form 8-K, Exhibits 4.2
and 4.3, File No. 1-2967
June 15, 2007 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
April 8, 2008 Form 8-K, Exhibits 4.3 and 4.5,
File No. 1-2967
June 19, 2008 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
March 23, 2009 Form 8-K, Exhibits 4.2 and
4.3, File No. 1-2967
Exhibit 2.01, File No. 2-60232
Amended Exhibit 7(b), File No. 2-7341
Second Amended Exhibit 7.03, File No. 2-
7795
Amended Exhibit 2.02, File No. 2-23569
Amended Exhibit 2.02, File No. 2-39587
Exhibit 2.03, File No. 2-60232
Exhibit 2.02(a), File No. 2-66380
May 15, 1992 Form 8-K, Exhibit 4.02, File
No. 1-3672
194
Exhibit Designation
4.64
4.65
4.66
4.67
4.68
4.69
4.70
4.71
4.72
4.73
4.74
4.75
4.76
4.77
4.78
4.79
4.80
4.81
Registrant(s)
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
Genco
Nature of Exhibit
Supplemental Indenture to the CIPS Mortgage,
dated June 1, 1997
Supplemental Indenture to the CIPS Mortgage,
dated December 1, 1998
Supplemental Indenture to the CIPS Mortgage,
dated June 1, 2001
Supplemental Indenture to the CIPS Mortgage,
dated October 1, 2004
Supplemental Indenture to the CIPS Mortgage,
dated June 1, 2006
Supplemental Indenture to the CIPS Mortgage,
dated June 15, 2009
Indenture dated as of December 1, 1998, from
CIPS to The Bank of New York Mellon Trust
Company, N.A., as successor trustee (CIPS
Indenture)
CIPS Global Note, dated December 22, 1998,
representing Senior Secured Notes, 5.375% due
2008
CIPS Global Note, dated December 22, 1998,
representing Senior Secured Notes, 6.125% due
2028
First Supplemental Indenture to the CIPS
Indenture, dated as of June 14, 2006
CIPS Company Order, dated June 14, 2006,
establishing 6.70% Series Secured Notes due
2036
Indenture dated as of November 1, 2000, from
Genco to The Bank of New York Mellon Trust
Company, N.A., as successor trustee (Genco
Indenture)
First Supplemental Indenture dated as of
November 1, 2000, to Genco Indenture, relating to
Genco’s 8.35% Senior Notes, Series B due 2010
Second Supplemental Indenture dated as of June
12, 2001, to Genco Indenture, relating to Genco’s
8.35% Senior Note, Series D due 2010
Third Supplemental Indenture dated as of June 1,
2002, to Genco Indenture, relating to Genco’s
7.95% Senior Notes, Series E due 2032
Fourth Supplemental Indenture dated as of
January 15, 2003, to Genco Indenture, relating to
Genco 7.95% Senior Notes, Series F due 2032
Fifth Supplemental Indenture dated as of April 1,
2008, to Genco Indenture, relating to Genco
7.00% Senior Notes, Series G due 2018
Sixth Supplemental Indenture, dated as of July 7,
2008, to Genco Indenture, relating to Genco
7.00% Senior Notes, Series H due 2018
Previously Filed as Exhibit to:
June 6, 1997 Form 8-K, Exhibit 4.03, File
No. 1-3672
Exhibit 4.2, File No. 333-59438
June 30, 2001 Form 10-Q, Exhibit 4.1, File
No. 1-3672
2004 Form 10-K, Exhibit 4.91, File No. 1-
3672
June 19, 2006 Form 8-K, Exhibit 4.9, File
No. 1-3672
June 30, 2009 Form 10-Q, Exhibit 4.1, File
No. 1-3672
Exhibit 4.4, File No. 333-59438
Exhibit 4.5, File No. 333-59438
Exhibit 4.6, File No. 333-59438
June 19, 2006 Form 8-K, Exhibit 4.2, File
No. 1-3672
June 19, 2006 Form 8-K, Exhibit 4.5, File
No. 1-3672
Exhibit 4.1, File No. 333-56594
Exhibit 4.2, File No. 333-56594
Exhibit 4.3, File No. 333-56594
June 30, 2002 Form 10-Q, Exhibit 4.1, File
No. 333-56594
2002 Form 10-K, Exhibit 4.5, File No. 333-
56594
April 9, 2008 Form 8-K, Exhibit 4.2, File
No. 333-56594
Exhibit No. 4.55, File No. 333-155416
195
Exhibit Designation
4.82
4.83
Registrant(s)
Ameren
Genco
Ameren
CILCO
4.84
4.85
4.86
4.87
4.88
4.89
4.90
4.91
4.92
4.93
4.94
4.95
4.96
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
IP
Ameren
IP
Nature of Exhibit
Seventh Supplemental Indenture, dated as of
November 1, 2009, to Genco Indenture, relating to
Genco 6.30% Senior Notes, Series l due 2020
Indenture of Mortgage and Deed of Trust between
Illinois Power Company (predecessor in interest to
CILCO) and Deutsche Bank Trust Company
Americas (formerly known as Bankers Trust
Company), as trustee, dated as of April 1, 1933
(CILCO Mortgage), Supplemental Indenture
between the same parties dated as of June 30,
1933, Supplemental Indenture between CILCO
and the trustee, dated as of July 1, 1933,
Supplemental Indenture between the same parties
dated as of January 1, 1935, and Supplemental
Indenture between the same parties dated as of
April 1, 1940
Supplemental Indenture to the CILCO Mortgage,
dated December 1, 1949
Supplemental Indenture to the CILCO Mortgage,
dated July 1, 1957
Supplemental Indenture to the CILCO Mortgage,
dated February 1, 1966
Supplemental Indenture to the CILCO Mortgage,
dated January 15, 1992
Supplemental Indenture to the CILCO Mortgage,
dated October 1, 2004
Supplemental Indenture to the CILCO Mortgage,
dated June 1, 2006
Supplemental Indenture to the CILCO Mortgage,
dated December 1, 2008
Supplemental Indenture to the CILCO Mortgage,
dated June 15, 2009
Indenture dated as of June 1, 2006, from CILCO
to The Bank of New York Mellon Trust Company,
N.A., as successor trustee
CILCO Company Order, dated June 14, 2006,
establishing the 6.20% Senior Secured Notes due
2016 (including the global note) and the 6.70%
Senior Secured Notes due 2036 (including the
global note)
CILCO Company Order, dated December 9, 2008,
establishing the 8.875% Senior Secured Notes
due 2013 (including the global note)
General Mortgage Indenture and Deed of Trust
dated as of November 1, 1992 between IP and
The Bank of New York Mellon Trust Company,
N.A., as successor trustee (IP Mortgage)
Supplemental Indenture dated as of April 1, 1997,
to IP Mortgage for the series P, Q and R bonds
Previously Filed as Exhibit to:
November 17, 2009 Form 8-K, Exhibit 4.8,
File No. 333-56594
Exhibit B-1, Registration No. 2-1937; Exhibit
B-1(a), Registration No. 2-2093; and
Exhibit A, April 1940 Form 8-K, File No. 1-
2732
December 1949 Form 8-K, Exhibit A, File
No. 1-2732
July 1957 Form 8-K, Exhibit A, File No. 1-
2732
February 1966 Form 8-K, Exhibit A, File
No. 1-2732
January 30, 1992 Form 8-K, Exhibit 4(b), File
No. 1-2732
2004 Form 10-K, Exhibit 4.121, File No. 1-
2732
June 19, 2006 Form 8-K, Exhibit 4.11, File
No. 1-2732
December 9, 2008 Form 8-K, Exhibit 4.5, File
No. 1-2732
June 30, 2009 Form 10-Q, Exhibit 4.2, File
No. 1-2732
June 19, 2006 Form 8-K, Exhibit 4.3, File
No. 1-2732
June 19, 2006 Form 8-K, Exhibit 4.6, File
No. 1-2732
December 9, 2008 Form 8-K, Exhibits 4.2
and 4.3, File No. 1-2732
1992 Form 10-K, Exhibit 4(cc), File No. 1-
3004
March 31, 1997 Form 10-Q, Exhibit 4(b), File
No. 1-3004
196
Exhibit Designation
4.97
4.98
4.99
4.100
4.101
4.102
4.103
4.104
4.105
4.106
4.107
4.108
4.109
4.110
4.111
4.112
4.113
4.114
Material Contracts
10.1
Registrant(s)
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
CIPS
Genco
Nature of Exhibit
Supplemental Indenture dated as of March 1,
1998, to IP Mortgage for the series S bonds
Supplemental Indenture dated as of March 1,
1998, to IP Mortgage for the series T bonds
Supplemental Indenture dated as of June 15,
1999, to IP Mortgage for the 7.50% bonds due
2009
Supplemental Indenture dated as of July 15, 1999,
to IP Mortgage for the series U bonds
Supplemental Indenture dated as of May 1, 2001
to IP Mortgage for the series W bonds
Supplemental Indenture dated as of May 1, 2001,
to IP Mortgage for the series X bonds
Supplemental Indenture dated as of December 15,
2002, to IP Mortgage for the 11.50% bonds due
2010
Supplemental Indenture dated as of June 1, 2006,
to IP Mortgage for the series AA bonds
Supplemental Indenture dated as of November 15,
2007, to IP Mortgage for the series BB bonds
Supplemental Indenture dated as of April 1, 2008,
to IP Mortgage for the series CC bonds
Supplemental Indenture dated as of October 1,
2008, to IP Mortgage for the series DD bonds
Supplemental Indenture dated as of June 15,
2009, to IP Mortgage for the 2009 Credit
Agreement series bonds
Indenture, dated as of June 1, 2006 from IP to The
Bank of New York Mellon Trust Company, N.A., as
successor trustee
IP Company Order, dated June 14, 2006,
establishing the 6.25% Senior Secured Notes due
2016 (including the global note)
IP Company Order, dated November 15, 2007,
establishing the 6.125% Senior Secured Notes
due 2017 (including the global note)
IP Company Order, dated April 8, 2008,
establishing the 6.25% Senior Secured Notes due
2018 (including the global note)
IP Company Order dated October 23, 2008,
establishing the 9.75% Senior Secured Notes due
2018 (including the global note)
Amended and Restated Genco Subordinated
Promissory Note dated as of May 1, 2005
Previously Filed as Exhibit to:
Exhibit 4.41, File No. 333-71061
Exhibit 4.42, File No. 333-71061
June 30, 1999 Form 10-Q, Exhibit 4.2, File
No. 1-3004
June 30, 1999 Form 10-Q, Exhibit 4.4, File
No. 1-3004
2001 Form 10-K, Exhibit 4.19, File No. 1-
3004
2001 Form 10-K, Exhibit 4.20, File No. 1-
3004
December 23, 2002 Form 8-K, Exhibit 4.1,
File No. 1-3004
June 19, 2006 Form 8-K, Exhibit 4.13, File
No. 1-3004
November 20, 2007 Form 8-K, Exhibit 4.4,
File No. 1-3004
April 8, 2008 Form 8-K, Exhibit 4.9, File
No. 1-3004
October 23, 2008 Form 8-K, Exhibit 4.4, File
No. 1-3004
June 30, 2009 Form 10-Q, Exhibit 4.3, File
No. 1-3004
June 19, 2006 Form 8-K, Exhibit 4.4, File
No. 1-3004
June 19, 2006 Form 8-K, Exhibit 4.7, File
No. 1-3004
November 20, 2007 Form 8-K, Exhibit 4.2,
File No. 1-3004
April 8, 2008 Form 8-K, Exhibit 4.4, File
No. 1-3004
October 23, 2008 Form 8-K, Exhibit 4.2, File
No. 1-3004
May 2, 2005 Form 8-K, Exhibit 4.1, File
No. 1-14756
Ameren
Genco
Amended and Restated Power Supply Agreement,
dated March 28, 2008, between Marketing
Company and Genco
March 28, 2008 Form 8-K, Exhibit 10.3, File
No. 1-14756
197
Exhibit Designation
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
Registrant(s)
Ameren
Genco
Ameren
IP
Ameren Companies
Ameren
Genco
Ameren
UE
Genco
Ameren
UE
Genco
Ameren
UE
Genco
Ameren
CIPS
CILCO
IP
Ameren
Ameren Companies
Ameren Companies
Ameren Companies
Ameren
Ameren Companies
Ameren Companies
Ameren Companies
Nature of Exhibit
Previously Filed as Exhibit to:
First Amendment dated January 1, 2010, to
Amended and Restated Power Supply Agreement,
dated March 28, 2008, between Marketing
Company and Genco
Unilateral Borrowing Agreement by and among
Ameren, IP and Ameren Services, dated as of
September 30, 2004
Third Amended Ameren Corporation System Utility
Money Pool Agreement, as amended September
30, 2004
Ameren Corporation System Amended and
Restated Non-Regulated Subsidiary Money Pool
Agreement, dated March 1, 2008
Amended and Restated Credit Agreement dated
as of July 14, 2006, among Ameren, UE, Genco
and JPMorgan Chase Bank, N.A., as agent
Amendment Agreement dated as of June 30,
2009, among Ameren, UE, Genco and JPMorgan
Chase Bank, N.A., as administrative agent, in
respect of the Amended and Restated Credit
Agreement dated as of July 14, 2006, among
Ameren, UE, Genco and JPMorgan Chase Bank,
N.A., as agent
Supplemental Credit Agreement dated as of June
30, 2009, among Ameren, UE, Genco and
JPMorgan Chase Bank, N.A., as agent
Credit Agreement dated as of June 30, 2009,
among Ameren, CIPS, CILCO, IP and JPMorgan
Chase Bank, N.A., as agent
*Summary Sheet of Ameren Corporation Non-
Management Director Compensation revised on
August 8, 2008
*Ameren’s Long-Term Incentive Plan of 1998
*First Amendment to Ameren’s Long-Term
Incentive Plan of 1998
*Form of Restricted Stock Award under Ameren’s
Long-Term Incentive Plan of 1998
*Ameren’s Deferred Compensation Plan for
Members of the Board of Directors amended and
restated effective January 1, 2009, dated June 13,
2008
*Amendment dated October 12, 2009, to Ameren’s
Deferred Compensation Plan for Members of the
Board of Directors, effective January 1, 2010
*Ameren’s Deferred Compensation Plan for
Members of the Ameren Leadership Team as
amended and restated effective January 1, 2001
*Ameren’s Executive Incentive Compensation
Program Elective Deferral Provisions for Members
of the Ameren Leadership Team as amended and
restated effective January 1, 2001
October 1, 2004 Form 8-K, Exhibit 10.3, File
No. 1-3004
October 1, 2004 Form 8-K, Exhibit 10.2, File
No. 1-14756
March 31, 2008 Form 10-Q, Exhibit 10.1, File
No. 1-14756
July 18, 2006 Form 8-K, Exhibit 10.1, File
No. 1-14756
June 30, 2009 Form 10-Q, Exhibit 10.3, File
No. 1-14756
June 30, 2009 Form 10-Q, Exhibit 10.4, File
No. 1-14756
June 30, 2009 Form 10-Q, Exhibit 10.2, File
No. 1-14756
September 30, 2008 Form 10-Q, Exhibit
10.1, File No. 1-14756
1998 Form 10-K, Exhibit 10.1, File No. 1-
14756
February 16, 2006 Form 8-K, Exhibit 10.6,
File No. 1-14756
February 14, 2005 Form 8-K, Exhibit 10.1,
File No. 1-14756
June 30, 2008 Form 10-Q, Exhibit 10.3, File
No. 1-14756
2000 Form 10-K, Exhibit 10.1, File No. 1-
14756
2000 Form 10-K, Exhibit 10.2, File No. 1-
14756
198
Exhibit Designation
10.18
Registrant(s)
Ameren Companies
Nature of Exhibit
*Ameren 2007 Deferred Compensation Plan
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
10.37
10.38
10.39
Ameren Companies
*Ameren 2008 Deferred Compensation Plan
Ameren Companies
Ameren Companies
*Ameren’s Deferred Compensation Plan as
amended and restated effective January 1, 2010
*2006 Ameren Executive Incentive Plan
Ameren Companies
*2007 Ameren Executive Incentive Plan
Ameren Companies
*2008 Ameren Executive Incentive Plan
Ameren Companies
*2009 Ameren Executive Incentive Plan
Ameren Companies
*2010 Ameren Executive Incentive Plan
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
Ameren Companies
*2007 Base Salary Table for Named Executive
Officers
*2008 Base Salary Table for Named Executive
Officers
*2009 Base Salary Table for Named Executive
Officers
*2010 Base Salary Table for Named Executive
Officers
*Second Amended and Restated Ameren
Corporation Change of Control Severance Plan
*First Amendment dated October 12, 2009, to the
Second Amended and Restated Ameren Change
of Control Severance Plan
*Revised Schedule I to Second Amended and
Restated Ameren Change of Control Severance
Plan, as amended
*Table of 2005 Cash Bonus Awards and 2006
Performance Share Unit Awards Issued to Named
Executive Officers
*Table of 2007 Target Performance Share Unit
Awards Issued to Named Executive Officers
*Table of 2008 Target Performance Share Unit
Awards Issued to Named Executive Officers
*Table of 2009 Target Performance Share Unit
Awards Issued to Executive Officers
*Formula for Determining 2010 Target
Performance Share Unit Awards to be Issued to
Named Executive Officers
*Ameren Corporation 2006 Omnibus Incentive
Compensation Plan
*Form of Performance Share Unit Award Issued in
2006-2008 Pursuant to 2006 Omnibus Incentive
Compensation Plan
Previously Filed as Exhibit to:
December 5, 2006 Form 8-K, Exhibit 10.1,
File No. 1-14756
June 30, 2008 Form 10-Q, Exhibit 10.2, File
No. 1-14756
October 14, 2009 Form 8-K, Exhibit 10.1, File
No. 1-14756
February 16, 2006 Form 8-K, Exhibit 10.2,
File No. 1-14756
February 15, 2007 Form 8-K, Exhibit 99.3,
File No. 1-14756
December 18, 2007 Form 8-K, Exhibit 99.1,
File No. 1-14756
February 19, 2009 Form 8-K, Exhibit 10.1,
File No. 1-14756
December 17, 2009 Form 8-K, Exhibit 10.1,
File No. 1-14756
March 31, 2007 Form 10-Q, Exhibit 10.2, File
No. 1-14756
2008 Form 10-K, Exhibit 10.31, File No. 1-
14756
2008 Form 10-K, Exhibit 10.36, File No. 1-
14756
2008 Form 10-K, Exhibit 10.37, File No. 1-
14756
October 14, 2009 Form 8-K, Exhibit 10.2, File
No. 1-14756
February 16, 2006 Form 8-K, Exhibit 10.1,
File No. 1-14756
February 15, 2007 Form 8-K, Exhibit 99.4,
File No. 1-14756
February 14, 2008 Form 8-K, Exhibit 99.1,
File No. 1-14756
March 2, 2009 Form 8-K, Exhibit 99.1, File
No. 1-14756
December 17, 2009 Form 8-K, Exhibit 99.1,
File No. 1-14756
February 16, 2006 Form 8-K, Exhibit 10.3,
File No. 1-14756
February 16, 2006 Form 8-K, Exhibit 10.4,
File No. 1-14756
199
Exhibit Designation
10.40
Registrant(s)
Ameren Companies
10.41
10.42
10.43
10.44
10.45
10.46
12.1
Ameren Companies
Ameren Companies
Ameren Companies
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
Statement re: Computation of Ratios
12.2
12.3
12.4
12.5
12.6
UE
CIPS
Genco
CILCO
IP
Nature of Exhibit
*Form of Performance Share Unit for Award
Issued in 2009 pursuant to 2006 Omnibus
Incentive Compensation Plan
*Form of Performance Share Unit for Award to be
Issued in 2010 pursuant to 2006 Omnibus
Incentive Compensation Plan
*Ameren Supplemental Retirement Plan amended
and restated effective January 1, 2008, dated
June 13, 2008
*First Amendment to amended and restated
Ameren Supplemental Retirement Plan dated
October 24, 2008
*CILCO Executive Deferral Plan as amended
effective August 15, 1999
*CILCO Executive Deferral Plan II as amended
effective April 1, 1999
*CILCO Restructured Executive Deferral Plan
(approved August 15, 1999)
Ameren’s Statement of Computation of Ratio of
Earnings to Fixed Charges
UE’s Statement of Computation of Ratio of
Earnings to Fixed Charges and Combined Fixed
Charges and Preferred Stock Dividend
Requirements
CIPS’ Statement of Computation of Ratio of
Earnings to Fixed Charges and Combined Fixed
Charges and Preferred Stock Dividend
Requirements
Genco’s Statement of Computation of Ratio of
Earnings to Fixed Charges
CILCO’s Statement of Computation of Ratio of
Earnings to Fixed Charges and Combined Fixed
Charges and Preferred Stock Dividend
Requirements
IP’s Statement of Computation of Ratio of
Earnings to Fixed Charges and Combined Fixed
Charges and Preferred Stock Dividend
Requirements
Previously Filed as Exhibit to:
March 2, 2009 Form 8-K, Exhibit 10.1, File
No. 1-14756
December 17, 2009 Form 8-K, Exhibit 10.2,
File No. 1-14756
June 30, 2008 Form 10-Q, Exhibit 10.1, File
No. 1-14756
2008 Form 10-K, Exhibit 10.44, File
No. 1-14756
1999 Form 10-K, Exhibit 10, File
No. 1-2732
1999 Form 10-K, Exhibit 10(a), File
No. 1-2732
1999 Form 10-K, Exhibit 10(e), File
No. 1-2732
June 30, 2004 Form 10-Q, Exhibit 14.1, File
No. 1-14756
Code of Ethics
14.1
Ameren Companies
Code of Ethics amended as of June 11, 2004
Subsidiaries of the Registrant
21.1
Ameren Companies
Consent of Experts and Counsel
Ameren
23.1
23.2
23.3
23.4
23.5
UE
CIPS
Genco
CILCO
Subsidiaries of Ameren
Consent of Independent Registered Public
Accounting Firm with respect to Ameren
Consent of Independent Registered Public
Accounting Firm with respect to UE
Consent of Independent Registered Public
Accounting Firm with respect to CIPS
Consent of Independent Registered Public
Accounting Firm with respect to Genco
Consent of Independent Registered Public
Accounting Firm with respect to CILCO
200
Exhibit Designation
23.6
IP
Registrant(s)
Power of Attorney
24.1
24.2
24.3
24.4
24.5
24.6
Ameren
UE
CIPS
Genco
CILCO
IP
Rule 13a-14(a)/15d-14(a) Certifications
31.1
Ameren
31.2
31.3
31.4
31.5
31.6
31.7
31.8
31.9
31.10
31.11
31.12
Ameren
UE
UE
CIPS
CIPS
Genco
Genco
CILCO
CILCO
IP
IP
Section 1350 Certifications
32.1
Ameren
32.2
32.3
32.4
32.5
32.6
UE
CIPS
Genco
CILCO
IP
Nature of Exhibit
Previously Filed as Exhibit to:
Consent of Independent Registered Public
Accounting Firm with respect to IP
Power of Attorney with respect to Ameren
Power of Attorney with respect to UE
Power of Attorney with respect to CIPS
Power of Attorney with respect to Genco
Power of Attorney with respect to CILCO
Power of Attorney with respect to IP
Rule 13a-14(a)/15d-14(a) Certification of Principal
Executive Officer of Ameren
Rule 13a-14(a)/15d-14(a) Certification of Principal
Financial Officer of Ameren
Rule 13a-14(a)/15d-14(a) Certification of Principal
Executive Officer of UE
Rule 13a-14(a)/15d-14(a) Certification of Principal
Financial Officer of UE
Rule 13a-14(a)/15d-14(a) Certification of Principal
Executive Officer of CIPS
Rule 13a-14(a)/15d-14(a) Certification of Principal
Financial Officer of CIPS
Rule 13a-14(a)/15d-14(a) Certification of Principal
Executive Officer of Genco
Rule 13a-14(a)/15d-14(a) Certification of Principal
Financial Officer of Genco
Rule 13a-14(a)/15d-14(a) Certification of Principal
Executive Officer of CILCO
Rule 13a-14(a)/15d-14(a) Certification of Principal
Financial Officer of CILCO
Rule 13a-14(a)/15d-14(a) Certification of Principal
Executive Officer of IP
Rule 13a-14(a)/15d-14(a) Certification of Principal
Financial Officer of IP
Section 1350 Certification of Principal Executive
Officer and Principal Financial Officer of Ameren
Section 1350 Certification of Principal Executive
Officer and Principal Financial Officer of UE
Section 1350 Certification of Principal Executive
Officer and Principal Financial Officer of CIPS
Section 1350 Certification of Principal Executive
Officer and Principal Financial Officer of Genco
Section 1350 Certification of Principal Executive
Officer and Principal Financial Officer of CILCO
Section 1350 Certification of Principal Executive
Officer and Principal Financial Officer of IP
201
Exhibit Designation
Additional Exhibits
99.1
99.2
Ameren
CILCO
Ameren
CILCO
Ameren
Ameren
Ameren
XBRL - Related Documents
101.INS**
101.SCH**
101.CAL**
101.LAB**
101.PRE**
Ameren
Ameren
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
March 28, 2008 Form 8-K, Exhibit 99.1, File
No. 1-14756
Amended and Restated Power Supply Agreement,
dated March 28, 2008, between Marketing
Company and AERG
First Amendment dated January 1, 2010, to
Amended and Restated Power Supply Agreement,
dated March 28, 2008, between Marketing
Company and AERG
XBRL Instance Document
XBRL Taxonomy Extension Schema Document
XBRL Taxonomy Extension Calculation Linkbase
Document
XBRL Taxonomy Extension Label Linkbase
Document
XBRL Taxonomy Extension Presentation Linkbase
Document
The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; UE, 1-2967; CIPS, 1-3672; Genco, 333-56594; CILCO,
1-2732; and IP, 1-3004.
*Compensatory plan or arrangement.
**Attached as Exhibit 101 to this report is the following financial information from Ameren’s Annual Report on Form 10-K for the year ended December 31,
2009, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Statement of Income for the years ended December 31, 2009, 2008 and
2007, (ii) the Consolidated Balance Sheet at December 31, 2009, and December 31, 2008, (iii) the Consolidated Statement of Cash Flows for the years ended
December 31, 2009, 2008 and 2007 and (iv) the Combined Notes to the Financial Statements for the year ended December 31, 2009, tagged as blocks of text.
These Exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.
Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that such registrant has not
filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.
202
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL FINANCIAL OFFICER OF AMEREN CORPORATION
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
Exhibit 31.2
I, Martin J. Lyons, Jr., certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Ameren Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Exhibit 31.3
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL EXECUTIVE OFFICER OF UNION ELECTRIC COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
I, Warner L. Baxter, certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Union Electric
Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Warner L. Baxter
Warner L. Baxter
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
Exhibit 31.4
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL FINANCIAL OFFICER OF UNION ELECTRIC COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
I, Martin J. Lyons, Jr., certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Union Electric
Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Exhibit 31.5
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL EXECUTIVE OFFICER OF CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
I, Scott A. Cisel, certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Central Illinois Public
Service Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
Exhibit 31.6
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL FINANCIAL OFFICER OF CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
I, Martin J. Lyons, Jr., certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Central Illinois Public
Service Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL EXECUTIVE OFFICER OF
AMEREN ENERGY GENERATING COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
Exhibit 31.7
I, Charles D. Naslund, certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Ameren Energy
Generating Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Charles D. Naslund
Charles D. Naslund
Chairman and President
(Principal Executive Officer)
Exhibit 31.8
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL FINANCIAL OFFICER OF AMEREN ENERGY GENERATING COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
I, Martin J. Lyons, Jr., certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Ameren Energy
Generating Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Exhibit 31.9
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL EXECUTIVE OFFICER OF CENTRAL ILLINOIS LIGHT COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
I, Scott A. Cisel, certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Central Illinois Light
Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
Exhibit 31.10
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL FINANCIAL OFFICER OF CENTRAL ILLINOIS LIGHT COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
I, Martin J. Lyons, Jr., certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Central Illinois Light
Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Exhibit 31.11
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL EXECUTIVE OFFICER OF ILLINOIS POWER COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
I, Scott A. Cisel, certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Illinois Power
Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
Exhibit 31.12
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL FINANCIAL OFFICER OF ILLINOIS POWER COMPANY
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
I, Martin J. Lyons, Jr., certify that:
1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2009 of Illinois Power
Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such statements were
made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for,
the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period
in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual
report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control
over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role
in the registrant’s internal control over financial reporting.
Date: February 26, 2010
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
SECTION 1350 CERTIFICATION OF
AMEREN CORPORATION
(required by Section 906 of the
Sarbanes-Oxley Act of 2002)
Exhibit 32.1
In connection with the report on Form 10-K for the fiscal year ended December 31, 2009 of Ameren Corporation
(the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form
10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant
to §906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and
results of operations of the Registrant.
Date: February 26, 2010
/s/ Thomas R. Voss
Thomas R. Voss
President and Chief Executive Officer
(Principal Executive Officer)
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and Chief Financial
Officer
(Principal Financial Officer)
SECTION 1350 CERTIFICATION OF
UNION ELECTRIC COMPANY
(required by Section 906 of the
Sarbanes-Oxley Act of 2002)
Exhibit 32.2
In connection with the report on Form 10-K for the fiscal year ended December 31, 2009 of Union Electric Company
(the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form
10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant
to §906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and
results of operations of the Registrant.
Date: February 26, 2010
/s/ Warner L. Baxter
Warner L. Baxter
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and Chief Financial
Officer
(Principal Financial Officer)
SECTION 1350 CERTIFICATION OF
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
(required by Section 906 of the
Sarbanes-Oxley Act of 2002)
Exhibit 32.3
In connection with the report on Form 10-K for the fiscal year ended December 31, 2009 of Central Illinois Public
Service Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date
hereof (the “Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as
adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and
results of operations of the Registrant.
Date: February 26, 2010
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and Chief Financial
Officer
(Principal Financial Officer)
SECTION 1350 CERTIFICATION OF
AMEREN ENERGY GENERATING COMPANY
(required by Section 906 of the
Sarbanes-Oxley Act of 2002)
Exhibit 32.4
In connection with the report on Form 10-K for the fiscal year ended December 31, 2009 of Ameren Energy
Generating Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the
date hereof (the “Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C.
§1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and
results of operations of the Registrant.
Date: February 26, 2010
/s/ Charles D. Naslund
Charles D. Naslund
Chairman and President
(Principal Executive Officer)
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and Chief Financial
Officer
(Principal Financial Officer)
SECTION 1350 CERTIFICATION OF
CENTRAL ILLINOIS LIGHT COMPANY
(required by Section 906 of the
Sarbanes-Oxley Act of 2002)
Exhibit 32.5
In connection with the report on Form 10-K for the fiscal year ended December 31, 2009 of Central Illinois Light
Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof
(the “Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as
adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and
results of operations of the Registrant.
Date: February 26, 2010
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and Chief Financial
Officer
(Principal Financial Officer)
SECTION 1350 CERTIFICATION OF
ILLINOIS POWER COMPANY
(required by Section 906 of the
Sarbanes-Oxley Act of 2002)
Exhibit 32.6
In connection with the report on Form 10-K for the fiscal year ended December 31, 2009 of Illinois Power Company
(the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form
10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant
to §906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934
(15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and
results of operations of the Registrant.
Date: February 26, 2010
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
/s/ Martin J. Lyons, Jr.
Martin J. Lyons, Jr.
Senior Vice President and Chief Financial
Officer
(Principal Financial Officer)
Investor Information
COMMON STOCK AND DIVIDEND INFORMATION
Ameren’s common stock is listed on the New York Stock
Exchange (ticker symbol: AEE). Ameren began trading on
January 2, 1998, following the merger of Union Electric Company
and CIPSCO Inc. on December 31, 1997. Ameren common
shareholders of record totaled 70,094 on December 31, 2009.
The following table provides the closing price ranges and
dividends paid per Ameren common share for each quarter
during 2009 and 2008.
AEE 2009
Quarter Ended
High
Low Close
Dividends
Paid
March 31
June 30
September 30
December 31
AEE 2008
$35.35 $19.51 $23.19
21.75
23.09
24.89
25.25
25.28
27.66
28.67 23.78
27.95
38 1⁄2 ¢
38 1⁄2
38 1⁄2
38 1⁄2
Quarter Ended
High
Low Close
Dividends
Paid
March 31
June 30
September 30
December 31
48.39
$54.29 $40.92 $44.04
41.34
38.49
63 1⁄2 ¢
63 1⁄2
63 1⁄2
39.15 25.51 33.26 63 1⁄2
43.16
39.03
42.23
ANNUAL MEETING
The annual meeting of Ameren Corporation shareholders will
convene at 9 a.m. (Central Time), Tuesday, April 27, 2010, at Powell
Symphony Hall, 718 North Grand Boulevard, St. Louis, MO. The
annual shareholder meetings of Central Illinois Light Company,
Central Illinois Public Service Company, Illinois Power Company
and Union Electric Company will be held at the same time.
DRPLUS
Any person of legal age or entity, whether or not an Ameren
shareholder, is eligible to participate in DRPlus, Ameren’s dividend
reinvestment and stock purchase plan. Participants can:
• make cash investments by check or automatic direct debit
to their bank accounts to purchase Ameren common stock,
totaling up to $120,000 annually,
• reinvest their dividends in Ameren common stock or receive
Ameren dividends in cash, and
• place Ameren common stock certificates in safekeeping and
receive regular account statements.
For more information about DRPlus, you may obtain a prospectus
from the company’s Investor Services representatives.
DIRECT DEPOSIT OF DIVIDENDS
All registered Ameren common and Central Illinois Light
Company, Central Illinois Public Service Company, Illinois Power
Company and Union Electric Company preferred shareholders
can have their cash dividends automatically deposited to their
bank accounts. This service gives shareholders immediate
access to their dividend on the dividend payment date and
eliminates the possibility of lost or stolen dividend checks.
CORPORATE GOVERNANCE DOCUMENTS
Ameren makes available, free of charge through its Web site
(www.ameren.com), the charters of the board of directors’ audit
and risk committee, human resources committee, nominating and
corporate governance committee, nuclear oversight committee,
finance committee and public policy committee. Also available
on Ameren’s Web site are its corporate governance guidelines,
director nomination policy, communications to the board of
directors policy, policy and procedures with respect to related-
person transactions, Code of Business Conduct (referred to
as the “Corporate Compliance Policy”) and its Code of Ethics
for principal executive and senior financial officers. These
documents are also available in print, free of charge upon written
request, from the Office of the Secretary, Ameren Corporation,
P.O. Box 66149, Mail Code 1370, St. Louis, MO 63166-6149.
Ameren also makes available, free of charge through its Web
site, the company’s annual reports on Securities and Exchange
Commission (SEC) Form 10-K, quarterly reports on SEC Form
10-Q and its current reports on SEC Form 8-K, including any
chief executive officer and chief financial officer certifications
required to be filed with the SEC therewith filed.
ONLINE STOCK ACCOUNT ACCESS
Ameren’s Web site (www.ameren.com) allows registered
shareholders to access their account information online.
Shareholders can securely change their reinvestment options,
view account summaries, receive DRPlus statements and more
through the Web site. This is a free service.
INVESTOR SERVICES
Ameren’s Investor Services representatives are available to
help you each business day from 8:00 a.m. to 4:00 p.m.
(Central Time). Please write or call:
Ameren Services Company, Investor Services, P.O. Box 66887,
St. Louis, MO 63166-6887. Phone: 314-554-3502 or toll-free:
800-255-2237. Email: invest@ameren.com
TRANSFER AGENT, REGISTRAR AND PAYING AGENT
The Transfer Agent, Registrar and Paying Agent for Ameren
common stock and Central Illinois Light Company, Central Illinois
Public Service Company, Illinois Power Company and Union
Electric Company preferred stock is Ameren Services Company.
Ameren Corporation
One Ameren Plaza
1901 Chouteau Avenue
St. Louis, MO 63103
314-621-3222
ExTEND YOUR DIVIDEND TAx RATE REDUCTION
In 2003, Congress passed an important law—the Jobs and
Growth Tax Reconciliation Act of 2003, which, as amended,
expires in 2010 unless extended by Congress. The law
reduced to 15 percent the maximum individual tax rate
on qualified dividends. Prior to enactment of this law, the
maximum tax rate on dividend income was 38.6 percent.
The dividend tax rate reduction is achieving highly favorable
results. The law promotes economic growth and benefits
the millions of Americans who depend on dividend income.
To encourage Congress to extend the dividend tax
reduction, visit www.defendmydividend.org and let your
congressional representative know you are interested in
extending the dividend tax rate reduction to encourage
Americans to continue investing and drive U.S.
economic growth.
P.O. Box 66149
St. Louis, MO 63166-6149
www.ameren.com