n
20 08 an n ua l r eport
On the Job 2
On Your Side 4
On Strategy 6
Financial Highlights 14
Officers and Directors 16
Form 10-K
Letter to Shareholders 9
Investor Information Inside back cover
on your side
on the job
on strategyn
on the job…
throughout 2008, we remained focused on our customers. We made
significant investments in our energy infrastructure and forged
strong partnerships with our customers and communities, improving
overall reliability and customer satisfaction. through amerenue’s
power on reliability program in Missouri, in 2008 we completed
250 undergrounding projects, burying more than 100 miles of electric
line. We trimmed trees along more than 6,500 miles of overhead
line, tested nearly 100,000 wood utility poles and inspected more
than 8,000 miles of electric line – all to improve customer reliability.
this initiative resulted in a much lower number of outages during
2008 weather events.
In Illinois, targeting the worst-performing circuits and aggressively
trimming trees also yielded significant reliability improvements. Illinois
crews’ performance on gas leak calls – with an average response
time of less than 23 minutes – placed ameren’s Illinois utilities among
the leaders in industry rankings.
In both states, ratings in surveys conducted with customers who
had contact with ameren’s utility companies were among the
highest ever experienced, and ratings of general satisfaction
also improved. across Illinois and Missouri in 2008, our utility
companies can be credited with distinguished performance, reducing
the frequency of service interruptions and per-customer outages by
15 percent since 2004 to earn a top-quartile industry ranking.
2 3
n ensuring safe,
reliable service
on your side…
environmental stewardship is a cornerstone of performance
leadership at ameren. over the years, our power plants have been
industry leaders in reducing emissions by piloting new technologies
and investing in research. In 2008, we began installing scrubbers –
sophisticated emissions-reduction equipment – at three plants. these
new, state-of-the-art controls are expected to eliminate almost all
sulfur dioxide emissions at these facilities.
at amerenue, a comprehensive integrated resource planning
process calls for the combination of energy efficiency initiatives and
renewable resources as the best way to delay the need for building
large generating plants. In executing this plan, we are launching
aggressive initiatives to help customers use energy more efficiently.
a range of customer programs are aimed at helping customers
change their approach to using energy, with a goal of saving
540 megawatts of generation by 2025 – the equivalent of a mid-sized
coal-fired plant. amerenue has also committed to add wind power
to its generation portfolio and continues to sponsor and promote a
voluntary renewable energy program for electric customers.
Illinois law has set aggressive annual energy efficiency savings
goals. In 2008, we began offering incentives on electric energy-
efficient systems to our Illinois customers, and ameren’s Illinois
utilities have also created actonenergy.com, a dynamic new Web
site to provide energy-saving advice and program information.
ameren’s purchase of renewable energy credits in Illinois also
demonstrates the company’s commitment.
(Photo at right) Jeremy Dyer, Director of
Operations C-Store Division, Niemann
Foods, right, discusses energy efficiency
with Rusty Tribe, an Ameren Illinois
utilities’ ActOnEnergy™ representative.
With a three-year electric and natural gas
budget of $100 million, ActOnEnergy is
an incentive program for Ameren Illinois
utilities’ electric and natural gas distribu-
tion customers. Niemann Foods received
more than $212,000 for projects that
will make 27 Illinois grocery stores
more energy efficient.
4 5
n providing energy savings options
and protecting the environment
on strategy…
even though the current economic environment has created
challenges for our industry and our company, we have plans in
place to stay on strategy. that strategy calls for investing in our
Illinois and Missouri regulated businesses to deliver safe, reliable
and affordable energy in an environmentally responsible manner.
our strategy also calls for optimizing our existing non-rate-regulated
generation assets. together, these initiatives should deliver solid,
long-term value to our shareholders.
also key to our strategic plan is our concept of the cycle shown
on this page: that cycle begins with prudent investments in
infrastructure. Making these investments helps us improve service,
which, in turn, leads to higher customer satisfaction. Improved
service and satisfaction should translate into fair treatment by our
regulators. Better regulatory treatment should result in improved
returns on investment for our regulated electric and natural
gas operations – bringing returns to levels that are necessary to
cost-effectively fund further infrastructure investment. all this
should lead to a continuation of this cycle and long-term benefits
to our shareholders.
MeanIngFul
InvestMent
In servIng
CustoMers
FaIr
return on
InvestMent
HIgH
QualIty
servICe
HIgH
CustoMer
satIsFaCtIon
6 7
n building long-term
fundamental value
n n
my fellow shareholders
the theme of our 2008 report is simple: We are on the job,
on your side and focused on our strategy.
the evidence of our progress on these initiatives is plentiful,
from improved reliability statistics to higher customer
satisfaction ratings, from strong power plant performance
to much-needed rate increases for our regulated operations
both in Illinois and Missouri.
I will address these later, but one of our most critical 2008
accomplishments is that we acted strategically to respond to
the dramatic economic downturn, volatile commodity markets
and unprecedented strains in capital and credit markets.
We took timely, prudent actions to increase our liquidity and
enhance our financial flexibility, accessing the capital markets
and significantly reducing our 2008 and projected 2009 spending.
We put in place plans to slash projected capital and operating
expenditures by approximately $800 million. We reduced
executive management salaries and incentive compensation
opportunities and established firm controls on headcount. We
have always tightly managed our operations, maintenance and
administrative expenses, but we are taking it to a new level.
Ameren’s Executive Leadership Team: (From left) Adam C. Heflin, Senior Vice President and Chief Nuclear Officer,
AmerenUE; Donna K. Martin, Senior Vice President and Chief Human Resources Officer; Daniel F. Cole, Senior Vice
President, Administration and Technical Services, Ameren Services; Scott A. Cisel, President and Chief Executive Officer,
AmerenCilCO, AmerenCiPS and AmereniP; Gary L. Rainwater, Chairman, President and Chief Executive Officer;
Andrew M. Serri, President, Ameren Energy Marketing; Thomas R. Voss, Executive Vice President and Chief Operating
Officer, President and Chief Executive Officer, AmerenUE; Charles D. Naslund, President and Chief Executive Officer,
Ameren Energy Resources; Warner L. Baxter, Executive Vice President and Chief Financial Officer, President and
Chief Executive Officer, Ameren Services; Richard J. Mark, Senior Vice President, Energy Delivery, AmerenUE;
Martin J. Lyons, Jr., Senior Vice President and Chief Accounting Officer; Steven R. Sullivan, Senior Vice President,
General Counsel and Secretary; and Michael L. Moehn, Senior Vice President, Corporate Planning and Risk Management,
Ameren Services.
8 9
as part of these efforts, ameren’s Board of Directors
companies, as compared to the 88 percent paid out
reduced the common share dividend level by
by ameren in 2008.
39 percent in early 2009. your board did not make
this decision lightly. ameren’s directors realized
that the corporation was faced with the prospect of
abandoning a strategic plan that we firmly believe
will deliver long-term value to you, our investors.
Had we not reduced the dividend, we would have
been forced to turn to high-cost financings to
support the execution of that plan.
By setting a new, more realistic level, we can retain
approximately $215 million a year. this additional
cash will help us enhance reliability, meet our
customers’ expectations and grow our regulated
businesses. It will also reduce our reliance on
dilutive equity financings, enhance our access to
the capital and credit markets and drive solid, long-
term earnings-per-share growth.
n
AmerenUE is installing weather stations on existing AmerenUE poles in
key locations throughout the region to measure temperature and wind
speed, among other variables. AmerenUE joined Saint Louis University’s
Department of Earth & Atmospheric Sciences to create Quantum
Weather™, a highly precise weather monitoring, forecasting and response
system that improves efficiency and speeds up power restoration.
We are FoCuseD on DelIverIng
saFe, relIaBle anD aFForDaBle
energy, WHIle aCHIevIng solID
returns. groWIng our InvestMent
In our regulateD BusInesses WIll
InCrease CustoMer satIsFaCtIon
tHrougH exCellent servICe.
In the end, this action will make ameren stronger
and more nimble – able to access the capital
markets on more favorable terms.
More importantly, we can use these incremental
funds to continue to pursue the following straightfor-
ward, long-term business strategies to deliver solid,
long-term value to you, our shareholders:
some background on the dividend: the previous
level was established at a time when ameren’s
earnings were fully regulated and more predict-
able. In 2008, almost 60 percent of ameren’s
earnings came from its non-rate-regulated genera-
tion business. these earnings are subject to wide
fluctuations based on market-driven power prices.
Continued dependence on this volatile earnings
stream cannot support a large dividend, and our
dividend was sizeable. In recent years, ameren’s
annual dividend payout has totaled over half a
billion dollars – a payout ratio that was among the
highest in the industry and the nation.
our adjusted dividend level provides us with a more
sustainable payout ratio, based upon earnings
primarily from our regulated businesses. It also
puts our new dividend payout ratio squarely in line
with ratios of 50 to 60 percent of earnings for peer
n
• A Commitment To Investing In Our Illinois
In 2008, we also worked to balance the need to
and Missouri Regulated Businesses. We are
invest in regulated delivery and generation infra-
focused on delivering safe, reliable and affordable
structure with the need to provide reasonable rates.
energy, while achieving solid returns. growing
In addition, we aggressively sought recovery of
our investment in our regulated businesses
these prudent investments to improve our returns.
will increase customer satisfaction through
excellent service.
• Building Constructive Regulatory Frame-
works. Being “on” means recognizing the impact
In 2008, we succeeded in doing just that. on the
regulatory decisions have on earnings and credit
delivery side of our business, reliability improved,
ratings that affect our ability to cost effectively raise
and customer satisfaction survey ratings rose.
capital and invest in our businesses. In both Illinois
For generating stations across Ameren’s service
territory, the Performance Monitoring Center
continuously monitors plant equipment performance
through pattern recognition software tools and
real-time support. The center provides early stage
notification of any equipment degradation or pending
equipment failure to avoid extended outages that
could hurt power plant availability.
amerenue’s power on reliability program
and Missouri, we have worked hard to achieve
contributed to a much lower number of outages
constructive regulatory outcomes, given our need
during storms. Both the Illinois and Missouri
to update rates to levels that reflect today’s much
delivery companies earned top-quartile industry
higher costs. our three Illinois electric and natural
rankings by reducing service interruption frequency
gas delivery companies were authorized to raise
– a key reliability measure.
our focus on achieving operational excellence at
our regulated generating plants has also yielded
strong results – with our Callaway nuclear plant
leading the way. In 2008, Callaway completed
rates by $161 million, effective october 1, 2008.
amerenue received a $162 million electric rate
increase in Missouri, which took effect March 1, 2009.
However, even with this recent increase, amerenue
rates remain well below the national average.
a record run of 520 consecutive days – and its
the most recent Missouri rate case also granted
shortest refueling and maintenance outage ever.
approval for recovering fuel and purchased power
our coal-fired plants also performed well, with
costs on a timely basis. By offering greater stability
another year of solid availability. one notable mile-
of earnings and cash flows, this provision bolsters
stone: labadie power plant in Missouri generated
our ability to continue to raise capital and invest in
more than a half-billion-megawatthours – one of
our utility infrastructure.
only a few coal-fired plants in the nation to achieve
that level.
10 11
• Optimizing Our Existing non-Rate-Regulated
Generation Assets. In 2008, core earnings at
our non-rate-regulated generation operations rose
almost 11 percent because the plants stayed
on – improving output and margins.
unfortunately, power and fuel markets have recently
exhibited extreme price volatility. However, our
prudent hedging policies are expected to preserve
value in 2009 and beyond. as we manage our
investment in non-rate-regulated generation
In 2008, Core earnIngs at
our non-rate-regulateD
generatIon operatIons rose
alMost 11 perCent BeCause tHe
plants stayeD On – IMprovIng
output anD MargIns.
For all these reasons, we are focused on this issue.
We have been actively working to frame reasonable
legislation and regulation, while we have acted to
address climate change. our efforts range from
participating in research projects on clean coal and
A new scrubber (left) is being installed at our Duck Creek Power
Plant in Canton, near Peoria, Ill. (above). Slated for completion in
2009, the scrubber operates like a chemical plant and, along with
an existing selective catalytic reduction system, will dramatically
reduce sulfur dioxide and mercury emissions, positioning this non-
rate-regulated generating plant to comply with state and federal
clean air regulations.
operations, we will continue to closely monitor
carbon capture storage technologies to increasing
market movements and the regulatory landscape.
operating efficiencies at our nuclear and hydro-
In 2008, we began to install state-of-the-art environ-
electric plants.
mental controls at some of our non-rate-regulated
coal-fired plants to extend their lives in the face of
increasingly stringent federal and state emissions
reduction regulations.
ameren is also “on” when it comes to encouraging
energy efficiency. In early 2008, amerenue filed
an integrated resource plan with the Missouri public
service Commission detailing how the company
• Demonstrating Environmental Leadership.
expects to supply electricity in coming years. after
We continue to maintain an active presence in
a year-long process involving dozens of meetings
discussions related to the need to address climate
with stakeholders and intensive analysis, the
change by reducing greenhouse gas emissions
company filed a preferred plan that calls for
from our coal-fired plants. our current analysis
increasing efficiency initiatives and renewable
of various policy scenarios now being debated in
energy development. Both in Illinois and Missouri,
Washington shows that, if implemented, they could
we are launching a number of programs aimed at
cause household costs and rates for electricity
helping customers reduce energy use. the ameren
to rise significantly. the Midwest economy is
Illinois utilities have raised customer energy aware-
especially vulnerable to economic dislocation given
ness with an award-winning actonenergy Web site
its reliance on coal-fired power.
(www.actonenergy.com).
In Missouri, amerenue plans to add at least
growth target of at least 5 percent. Coupled with
100 megawatts of wind power by 2010 and antici-
the new common dividend rate, this would provide
pates up to an additional 225 megawatts by 2020.
competitive, long-term total return potential. even-
the company is working to supply electric genera-
tually, our goal would be to grow the dividend level
tion from wind and landfill gas, while participating in
as our earnings from rate-regulated operations
studies on potential biomass fuel sources, looking
increase and our overall cash profile improves.
into hydroelectric generation facilities on local rivers
and investigating development of solar generation.
amerenue has also launched a voluntary renew-
able energy credit customer program, which in
2008, was named the new green power program
We are confident that execution of this plan will
deliver solid, long-term returns for our shareholders
as the economy and energy markets recover. We
understand that you – our owners – depend on us
n
Shown here are the cooling tower and a simulated control room used for
training at AmerenUE’s Callaway Nuclear Plant, where in October 2008,
employees completed a record run of 520 consecutive days, which began
in May 2007. Callaway is one of only 26 of the nation’s 104 nuclear plants
to achieve a record run of more than 500 days.
of the year by the u.s. Department of energy, the
to turn challenges into opportunities for sustained
u.s. environmental protection agency and the
growth. We have the strategies, the people and the
Center for resource solutions. In Illinois, we are
assets to do just that. We are “on” it.
purchasing renewable energy credits.
However, we know this will not be enough.
during this difficult period, and we thank our
amerenue expects to need new generation by
employees for their dedication and for incorporating
the 2018 to 2020 timeframe. that’s why in 2008
our values in everything they do.
We want to thank you for your continued support
amerenue moved to preserve the option for a
possible second nuclear unit at its existing Callaway
plant site. no decision on building a unit has been
made. But by applying for a license to possibly build
a unit, we began the regulatory process and made
the unit eligible for billions of dollars in federal incen-
tives established by the energy policy act of 2005.
ameren is on the path to earnings growth. We
expect execution of our strategy to enable us to
achieve a long-term, annual earnings-per-share
I hope you can attend this year’s annual share-
holders’ Meeting on april 28 at the Chase park
plaza Hotel in st. louis.
gary l. raInWater
CHaIrMan, presIDent anD
CHIeF exeCutIve oFFICer
aMeren CorporatIon
March 2, 2009
12 13
Financial Highlights
aMeren ConsolIDateD
(In millions, except per share amounts and as noted)
2008
2007
2006
Year Ended December 31,
results oF operatIons
operating revenues
operating expenses
operating income
net income
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
$7,839
$6,477
$1,362
$605
$7,562
$6,203
$1,359
$618
$2.88
$2.54
7.6%
$33.26
210.1
$7,062
$32.80
$16,567
$22,657
$6,554
45.9%
1.3%
52.8%
107,754
119,712
80,859
2.4
1.0
$2.98
$2.54
4.7%
$54.21
207.4
$11,294
$32.41
$15,069
$20,728
$5,689
48.2%
1.4%
50.4%
107,486
107,871
81,367
2.4
1.0
$6,895
$5,707
$1,188
$547
$2.66
$2.54
4.7%
$53.73
205.6
$11,099
$31.87
$14,286
$19,635
$5,285
50.6%
1.5%
47.9%
101,015
108,682
81,485
2.4
1.0
6,500
megawatts generating
capacity in Illinois
3,400,000
electric and natural
gas customers
ameren employees, numbering approximately
9,500, serve approximately 2.4 million electric
and nearly one million natural gas customers over
Peoria
64,000 square miles in Illinois and Missouri. the
Springfield
Decatur
St. Louis
10,000
megawatts generating
capacity in Missouri
Company and
Subsidiary Headquarters
Electric Service Territory
Electric and Natural Gas
Service Territory
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 about 10,000 megawatts
of generating capacity. our Illinois operations
include rate-regulated electric and natural gas
transmission and distribution businesses, as well
as a non-rate-regulated generating business
with a capacity of approximately 6,500 megawatts
of generation. today, ameren’s Missouri company,
amerenue, is the largest electric utility in the state,
while the Illinois operations make ameren the
second largest electric distribution company and
one of the largest distributors of natural gas in
that state.
total
eleCtrIC
sales
6
8
4
,
7
0
1
4
5
7
,
7
0
1
5
1
0
,
1
0
1
natIve
natural
gas sales
2
1
7
,
9
1
1
2
8
6
,
8
0
1
1
7
8
,
7
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t
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w
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l
i
k
(
total
generatIon
output
5
8
4
,
1
8
7
6
3
,
1
8
9
5
8
,
0
8
)
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i
m
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s
r
u
o
h
t
t
a
w
o
l
i
k
(
CapItal
InvestMents
6
9
8
,
1
$
1
8
3
,
1
$
4
8
2
,
1
$
)
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06
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08
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08
06
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14 15
Ameren Corporation and Subsidiaries Officers and Directors
exeCutIve leaDersHIp teaM
Gary L. Rainwater
Chairman, President
and Chief Executive Officer
Warner L. Baxter
Executive Vice President
and Chief Financial Officer;
President and Chief Executive
Officer, Ameren Services
Thomas R. Voss
Executive Vice President
and Chief Operating Officer;
President and Chief Executive
Officer, AmerenUE
Scott A. Cisel*
President and Chief
Executive Officer,
AmerenCILCO, AmerenCIPS,
AmerenIP
Donna K. Martin
Senior Vice President
and Chief Human
Resources Officer
Steven R. Sullivan
Senior Vice President,
General Counsel and
Secretary
Daniel F. Cole*
Senior Vice President,
Administration and Technical
Services, Ameren Services
Adam C. Heflin*
Senior Vice President and
Chief Nuclear Officer,
AmerenUE
Martin J. Lyons, Jr.
Senior Vice President
and Chief Accounting Officer
Richard J. Mark*
Senior Vice President,
Energy Delivery, AmerenUE
Michael L. Moehn*
Senior Vice President,
Corporate Planning and Risk
Management,
Ameren Services
Charles D. Naslund*
President and Chief Executive
Officer, Ameren Energy Resources;
President, Ameren Energy
Generating Company
Andrew M. Serri*
President,
Ameren Energy Marketing
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
Charles A. Bremer*
Vice President, Information
Technology and Ameren
Services Center, Ameren Services
Richard C. Cissell*
Vice President, Operations,
Ameren Energy Generating
Kevin DeGraw*
Vice President,
Corporate Project Risk
Management, Ameren Services
Fadi Diya*
Vice President,
Nuclear Operations, AmerenUE
Ronald K. Evans*
Vice President and
Deputy General Counsel,
Ameren Services
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.
Walter J. Galvin 1, 3
Senior Executive Vice
President and Chief
Financial Officer,
Emerson Electric Co.
16
John R. Fey*
Vice President, Human
Resources, Business Services,
Ameren Services
Karen C. Foss*
Vice President, Public Relations,
AmerenUE
Michael J. Getz*
Controller,
AmerenCILCO, AmerenCIPS,
AmerenIP
Scott A. Glaeser*
Vice President, Gas Supply
and System Control,
Ameren Energy Fuels
and Services
Timothy E. Herrmann*
Vice President, Engineering,
Callaway Nuclear Plant,
AmerenUE
Christopher A. Iselin*
Vice President, Generation
Technical Services,
Ameren Energy Resources
Stephen M. Kidwell*
Vice President,
Regulatory Affairs, AmerenUE
Mark C. Lindgren*
Vice President, Corporate
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
Robert K. Neff*
Vice President, Coal Supply
and Transportation,
Ameren Energy Fuels and
Services
Craig D. Nelson*
Vice President, Regulatory Affairs
and Financial Services, Ameren-
CILCO, AmerenCIPS, AmerenIP
Gregory L. Nelson*
Vice President and Tax Counsel,
Ameren Services
Stan E. Ogden*
Vice President, Customer
Service and Public Relations,
AmerenCILCO, AmerenCIPS,
AmerenIP
Ronald D. Pate*
Vice President, Regional
Operations, AmerenCILCO,
AmerenCIPS, AmerenIP
Dr. Gayle P. W. Jackson 5, 6
President, Energy Global, Inc.
James C. Johnson 3, 4
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
Group President, Caterpillar Inc.
Gary L. Rainwater
Chairman, President
and Chief Executive Officer,
Ameren Corporation
Harvey Saligman 3, 4
Partner, Cynwyd Investments
Patrick T. Stokes 3, 4, 7
Former Chairman,
Anheuser-Busch
Companies, Inc.
Jack D. Woodard 5, 6
Retired Executive Vice
President and Chief Nuclear
Officer, Southern Nuclear
Operating Company, Inc.
Joseph M. Power*
Vice President, Federal
Legislative and Regulatory
Affairs, Ameren Services
William J. Prebil*
Vice President,
Regional Operations,
AmerenCILCO, AmerenCIPS,
AmerenIP
David J. Schepers*
Vice President, Energy
Delivery Technical Services,
Ameren Services
Shawn E. Schukar*
Vice President, Strategic
Initiatives, Ameren Services
Jerry L. Simpson*
Vice President, Business
Services, Ameren Energy
Resources
James A. Sobule*
Vice President and
Deputy General Counsel,
Ameren Services
Bruce A. Steinke
Vice President and Controller
Dennis W. Weisenborn*
Vice President,
Supply Services, Ameren
Services
Ronald C. Zdellar*
Vice President, Energy
Delivery Distribution Services,
AmerenUE
1 Member of Finance Committee
2 Member of Audit and Risk Committee
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
As of March 2, 2009
* 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, 2008
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
CILCORP Inc.
(Illinois Corporation)
300 Liberty Street
Peoria, Illinois 61602
(309) 677-5271
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
IRS Employer
Identification No.
43-1723446
43-0559760
37-0211380
37-1395586
37-1169387
37-0211050
37-0344645
Commission
File Number
1-14756
1-2967
1-3672
333-56594
2-95569
1-2732
1-3004
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
Ameren Corporation
Title of each class
Common Stock, $0.01 par value per share
Securities Registered Pursuant to Section 12(g) of the Securities Exchange Act of 1934:
Registrant
Union Electric Company
Title of each class
Preferred Stock, cumulative, no par value,
Central Illinois Public Service Company
Central Illinois Light Company
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 –
4.90% Series
4.25% Series
4.00% Series
6.625% Series
5.16% Series
4.92% 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, CILCORP Inc., 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 check mark 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
CILCORP Inc.
Central Illinois Light Company
Illinois Power Company
Yes
Yes
Yes
Yes
Yes
Yes
Yes
(X)
(X)
( )
( )
( )
( )
( )
No
No
No
No
No
No
No
Indicate by check mark 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
CILCORP Inc.
Central Illinois Light Company
Illinois Power Company
Yes
Yes
Yes
Yes
Yes
Yes
Yes
( )
( )
( )
( )
(X)
( )
( )
No
No
No
No
No
No
No
( )
( )
(X)
(X)
(X)
(X)
(X)
(X)
(X)
(X)
(X)
( )
(X)
(X)
Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
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
(X)
(X)
(X)
(X)
(X)
(X)
No
No
No
No
No
No
( )
( )
( )
( )
( )
( )
CILCORP has voluntarily filed all reports that it would have been required to file if it had been subject to the requirements
of Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of each registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
CILCORP Inc.
Central Illinois Light Company
Illinois Power Company
( )
(X)
(X)
(X)
(X)
(X)
(X)
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer 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.
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
CILCORP Inc.
Central Illinois Light Company
Illinois Power Company
Large
Accelerated
Filer
(X)
( )
( )
( )
( )
( )
( )
Accelerated
Filer
( )
( )
( )
( )
( )
( )
( )
Non-accelerated
Filer
( )
(X)
(X)
(X)
(X)
(X)
(X)
Smaller
Reporting
Company
( )
( )
( )
( )
( )
( )
( )
Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange
Act of 1934).
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
CILCORP Inc.
Central Illinois Light Company
Illinois Power Company
Yes
Yes
Yes
Yes
Yes
Yes
Yes
( )
( )
( )
( )
( )
( )
( )
No
No
No
No
No
No
No
(X)
(X)
(X)
(X)
(X)
(X)
(X)
As of June 30, 2008, Ameren Corporation had 210,050,075 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 $8,870,414,667. The shares of common stock of the other registrants
were held by affiliates as of June 30, 2008.
The number of shares outstanding of each registrant’s classes of common stock as of January 30, 2009, was as follows:
Ameren Corporation
Union Electric Company
Central Illinois Public Service Company
Ameren Energy Generating Company
CILCORP Inc.
Central Illinois Light Company
Illinois Power Company
Common stock, $0.01 par value per share: 212,519,772
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 Ameren
Corporation (parent company of the registrant): 1,000
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 2009 annual
meetings of shareholders are incorporated by reference into Part III of this Form 10-K.
Ameren Energy Generating Company and CILCORP Inc. meet the conditions set forth in General Instruction I(1)(a) and
(b) of Form 10-K and are therefore filing this form with the reduced disclosure format allowed under that General Instruction.
OMISSION OF CERTAIN INFORMATION
This combined Form 10-K is separately filed by Ameren Corporation, Union Electric Company, Central Illinois Public
Service Company, Ameren Energy Generating Company, CILCORP Inc., 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
GLOSSARY OF TERMS AND ABBREVIATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forward-looking Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Segments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rates and Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supply for Electric Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas Supply for Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industry Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Officers of the Registrants (Item 401(b) of Regulation S-K) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A and
Item 9A(T).
Item 9B.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . .
Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Directors, Executive Officers, and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Certain Relationships and Related Transactions and Director Independence . . . . . . . . . . . . . . . . . . . . .
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
Item 15.
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EXHIBIT INDEX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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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 page 3 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.
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.
GLOSSARY OF TERMS AND ABBREVIATIONS
AERG – AmerenEnergy Resources Generating Company, a
CILCO subsidiary that operates a non-rate-regulated 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, a wholly
owned subsidiary of Ameren Corporation 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 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 AERG and Genco.
AMMO – The balancing authority area operated by Ameren,
which includes the load and generating assets of UE.
AMT – Alternative minimum tax.
ARB – Accounting Research Bulletin.
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 non-rate-
regulated 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 a non-rate-regulated subsidiary.
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.
CO2 – Carbon dioxide.
COLA – Combined 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 non-rate-regulated
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.
EITF – Emerging Issues Task Force, an organization
designed to assist the FASB in improving financial reporting
through the identification, discussion and resolution of
financial issues in keeping with existing authoritative
literature.
ELPC – Environmental Law and Policy Center.
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
power costs, net of off-system revenues, including MISO
costs and revenues, above or below the amount set in base
rates.
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.
1
FIN – FASB Interpretation. A FIN statement is an
explanation intended to clarify accounting pronouncements
previously issued by the FASB.
Fitch – Fitch Ratings, a credit rating agency.
FSP – FASB Staff Position, a publication that provides
application guidance on FASB literature.
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 non-rate-regulated
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 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
Illinois electric settlement agreement, 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 addresses the issue of power procurement, and
it includes a comprehensive rate relief and customer
assistance program.
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.
2
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
beginning in June 2009.
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.
JDA – The joint dispatch agreement among UE, CIPS, and
Genco under which UE and Genco jointly dispatched electric
generation prior to its termination on December 31, 2006.
Kilowatthour – A measure of electricity consumption
equivalent to the use of 1,000 watts of power over a period
of one hour.
Lehman – Lehman Brothers Holdings, Inc.
MACT – Maximum Achievable Control Technology.
Marketing Company – Ameren Energy Marketing Company,
a Resources Company subsidiary that markets power for
Genco, AERG and EEI.
Medina Valley – AmerenEnergy Medina Valley Cogen
L.L.C., a Resources Company subsidiary, which owns a
40-megawatt gas-fired electric generation plant.
Megawatthour – One thousand kilowatthours.
MGP – Manufactured gas plant.
MISO – Midwest Independent Transmission System
Operator, Inc.
MISO Day Two Energy Market – A market that uses
market-based pricing, incorporating transmission
congestion and line losses, to compensate market
participants for power.
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.
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 reached in
2006 among Genco, CILCO (AERG), EEI and the Illinois
EPA, which was codified in Illinois environmental
regulations.
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.
NCF&O – National Congress of Firemen and Oilers, a labor
union.
Non-rate-regulated Generation – A financial reporting
segment consisting of the operations or activities of Genco,
the CILCORP parent company, AERG, EEI, Medina Valley,
and Marketing Company.
NOx – Nitrogen oxide.
Noranda – Noranda Aluminum, Inc.
NRC – Nuclear Regulatory Commission, a U.S. government
agency.
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 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.
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.
SFAS – Statement of Financial Accounting Standards, the
accounting and financial reporting rules issued by the
FASB.
SO2 – 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. Since the application of FIN
46R, IP did not consolidate IP SPT. Therefore, the
obligation to IP SPT appears on IP’s balance sheet as of
December 31, 2007. In September 2008, IP redeemed the
remaining TFNs.
TVA – Tennessee Valley Authority, a public power
authority.
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.
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:
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regulatory or legislative actions, including changes in
regulatory policies and ratemaking determinations and
future rate proceedings or future legislative actions that
seek to limit or reverse rate increases;
uncertainty as to the continued effectiveness of 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;
enactment of legislation taxing electric generators, in
Illinois or elsewhere;
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;
3
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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, impossible, more
difficult or costly;
our assessment of our liquidity;
the impact of the adoption of new accounting standards
and the application of appropriate technical accounting
rules and guidance;
actions of credit rating agencies and the effects of such
actions;
weather conditions and other natural phenomena,
including impacts to our customers;
the impact of system outages caused by severe
weather conditions or other events;
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generation plant construction, installation and
performance, including costs associated with UE’s
Taum Sauk pumped-storage hydroelectric plant
incident and the plant’s future operation;
recoverability through insurance of costs associated
with UE’s Taum Sauk pumped-storage hydroelectric
plant incident;
operation of UE’s nuclear power facility, including
planned and unplanned outages, and decommissioning
costs;
the effects of strategic initiatives, including 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, will be introduced
over time, which could have a negative financial effect;
labor disputes, 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.
ITEM 1. BUSINESS.
GENERAL
PART I
Ameren, headquartered in St. Louis, Missouri, is a
The following table presents our total employees at
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, CILCORP and IP.
Ameren’s subsidiaries are separate, independent legal
entities with separate businesses, assets and liabilities.
These subsidiaries operate rate-regulated electric
generation, transmission and distribution businesses, rate-
regulated natural gas transmission and distribution
businesses, and non-rate-regulated electric generation
businesses in Missouri and Illinois. Dividends on Ameren’s
common stock are dependent on distributions made to it by
its subsidiaries.
December 31, 2008:
Ameren(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,524
4,146
679
577
626
1,173
(a) Total for Ameren includes Ameren registrant and nonregistrant
subsidiaries.
As of January 1, 2009, the IBEW, the IUOE, the NCF&O
and the Laborers and Gas Fitters labor unions collectively
represent about 58% of Ameren’s total employees. They
represent 63% of the employees at UE, 82% at CIPS, 70%
at Genco, 38% at CILCORP, 38% at CILCO, and 90% at IP.
All collective bargaining agreements that expired in 2008
have been renegotiated and ratified. Most of the collective
4
bargaining agreements have four- or five-year terms, and
expire in 2011 and 2012. The collective bargaining
agreement between UE and IUOE Local 148, covering
approximately 1,100 employees, expires on June 30, 2009.
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 to our financial statements under Part
II, Item 8, of this report.
BUSINESS SEGMENTS
Ameren has three reportable segments: Missouri
Regulated, Illinois Regulated, and Non-rate-regulated
Generation. CILCORP and CILCO have two reportable
segments: Illinois Regulated and Non-rate-regulated
Generation. See Note 17 – Segment Information to our
financial statements under Part II, Item 8, of this report for
additional information on reporting segments.
RATES AND REGULATION
Rates
Rates that UE, CIPS, CILCO and IP are allowed to
charge for their utility services are an important influence
upon their and Ameren’s consolidated results of operations,
financial position, and liquidity. The utility rates charged to
UE, CIPS, CILCO and IP customers are determined by
governmental entities. Decisions by these entities are
influenced by many factors, including the cost of providing
service, the quality of service, regulatory staff knowledge
and experience, economic conditions, public policy, and
social and political views. 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, or liquidity of UE, CIPS,
CILCORP, CILCO, IP and Ameren.
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 35% of Ameren’s electric and 14% of its gas
operating revenues were subject to regulation by the
MoPSC in the year ended December 31, 2008. About 41%
of Ameren’s electric and 86% of its gas operating revenues
were subject to regulation by the ICC in the year ended
December 31, 2008. 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 81% of UE’s electric operating revenues were
subject to regulation by the MoPSC in the year ended
December 31, 2008.
Following the expiration of a multiyear electric rate
change moratorium, UE filed a request with the MoPSC in
July 2006 for approval of an increase in its annual revenues
for electric service. In May 2007, the MoPSC issued an
order, that, as clarified, granted UE a $43 million increase in
base rates for electric service, effective June 4, 2007.
On January 27, 2009, the MoPSC issued an order
responding to UE’s April 2008 rate increase request,
approving an increase for UE in annual revenues for electric
service of approximately $162 million. The MoPSC also
approved UE’s implementation of a FAC and a vegetation
management and infrastructure inspection cost tracking
mechanism. Rate changes consistent with the MoPSC
order, as well as the FAC and the vegetation management
and infrastructure inspection cost tracking mechanism,
were effective as of March 1, 2009. These cost recovery and
tracking mechanisms help to mitigate the negative effect of
regulatory lag.
The MoPSC initiated a proceeding in December 2008
to develop revised rules for an environmental cost recovery
mechanism, which has been authorized under Missouri law.
Rules for the environmental cost recovery mechanism are
expected to be approved by the MoPSC during the second
quarter of 2009 and will be effective once published in the
Missouri Register. UE will not be able to implement an
environmental cost recovery mechanism until authorized by
the MoPSC as part of a rate case proceeding. UE has not
requested approval of an environmental cost recovery
mechanism.
Gas
All of UE’s gas operating revenues were subject to
regulation by the MoPSC in the year ended December 31,
2008.
If certain criteria are met, UE’s 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 gas infrastructure replacement costs to be passed
directly to the consumer.
As part of a 2007 stipulation and agreement approved
by the MoPSC authorizing 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.
During 2008, the MoPSC approved two UE requests to
establish an ISRS to recover annual revenues of $2 million
in the aggregate, effective in March and November 2008.
5
For further information on Missouri rate matters, see
In September 2008, responding to CIPS’, CILCO’s and
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 to our financial
statements under Part II, Item 8, of this report.
Illinois Regulated
The following table presents the approximate
percentage of electric and gas operating revenues subject to
regulation by the ICC for each of the Illinois Regulated
companies for the year ended December 31, 2008:
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO(a) . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100% 100%
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100
100
100
Electric
Gas
(a) AERG’s revenues are not subject to ICC regulation.
If certain criteria are met, CIPS’, CILCO’s and IP’s 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.
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. Beginning in 2007, 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, 2008, 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.
A multiyear electric rate moratorium expired and new
electric rates for CIPS, CILCO and IP went into effect on
January 2, 2007. The new rates reflected delivery service
tariffs approved by the ICC in November 2006 and a cost
recovery mechanism for power purchased on behalf of the
Ameren Illinois Utilities’ customers. In 2007, an agreement
was reached among key stakeholders in Illinois to address
the increase in electric rates and the future power
procurement process. The Illinois electric settlement
agreement provides $1 billion of funding from 2007 to 2010
for rate relief for certain electric customers in Illinois,
including $488 million to customers of the Ameren Illinois
Utilities. Ameren’s contributions over the four-year period
under the Illinois electric settlement agreement aggregate
$150 million.
IP’s November 2007 electric and natural gas rate adjustment
requests, the ICC issued a consolidated order approving a
net increase in annual revenues for electric 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). Rate changes implementing these
adjustments were effective on October 1, 2008. The ICC also
approved an increase in the percentage of costs to be
recovered through fixed monthly charges for natural gas
customers, as well as an increase in the Supply Cost
Adjustment factors for the customers who take their power
supply from the Ameren Illinois Utilities. These two rate
structure changes help to mitigate the negative effect of
regulatory lag.
For further information on Illinois rate matters,
including the pending court appeal of the September 2008
consolidated electric and gas 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 to our financial
statements under Part II, Item 8, of this report.
Non-rate-regulated Generation
Non-rate-regulated Generation revenues are
determined by market conditions. We expect the Non-rate-
regulated Generation fleet of assets to have
6,480 megawatts of capacity available for the 2009 peak
demand. As discussed below, Genco, AERG, and EEI sell all
of their power and capacity to Marketing Company via
power supply agreements. Marketing Company attempts to
optimize the value of those generation assets and mitigate
risks utilizing 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 like the Ameren Illinois Utilities. See Note 14 –
Related Party Transactions to our financial statements under
Part II, Item 8, of this report for additional information,
including Marketing Company sales to the Ameren Illinois
Utilities.
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
6
authorization from the applicable state public utility
regulatory 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 its Callaway nuclear
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. 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’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 to our financial
statements 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 matters include 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. 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 and the December 2005 breach of the upper
reservoir at UE’s Taum Sauk pumped-storage hydroelectric
plant, 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 to our
financial statements under Part II, Item 8, of this report.
SUPPLY FOR ELECTRIC POWER
Ameren operates an integrated transmission system
that comprises the transmission assets of UE, CIPS, CILCO,
IP and AITC. AITC placed its first transmission assets,
jointly owned with IP, in service during the fourth quarter of
2008. Any transmission assets of AITC would be eligible for
rate recovery upon making the necessary filings with and
acceptance by FERC. Ameren also operates two balancing
authority areas, AMMO (which includes UE) and AMIL
(which includes CIPS, CILCO, IP, AITC, Genco and AERG).
During 2008, the peak demand in AMMO was 8,644 MW
and in AMIL was 8,794 MW. The Ameren transmission
system directly connects with 17 other balancing authority
areas for the exchange of electric energy.
UE, CIPS, CILCO and IP are transmission-owning
members of MISO, and they have transferred functional
control of their systems to 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. The Ameren membership
covers UE, CIPS, CILCO and IP.
See Note 2 – Rate and Regulatory Matters to our
financial statements under Part II, Item 8, of this report for
further 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 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.
7
In March 2006, UE completed the purchase of three CT
facilities, totaling 1,490 megawatts of capacity, at a price of
$292 million. These purchases were designed to help meet
UE’s increased generating capacity needs and to provide UE
with additional flexibility in determining when to add future
baseload generating capacity. UE expects these CT facilities
to satisfy demand growth until 2018 or 2020. However, 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 those that would use coal
or nuclear fuel. In 2008, UE filed an integrated resource
plan with the MoPSC. The 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.
In July 2008, UE filed a COLA with the NRC for a
potential new nuclear unit at UE’s existing Callaway County,
Missouri, nuclear plant site. In addition, in 2008, UE filed an
application with the DOE for loan guarantees associated
with the potential construction of a new nuclear unit. UE
has also signed contracts for certain long lead-time nuclear
plant related equipment. The filing of the COLA and the DOE
loan guarantee application and entering into these contracts
does not mean a decision has been made to build another
nuclear unit. These are only the first steps in the regulatory
licensing and procurement process and are necessary
actions to preserve the option to develop a new nuclear
unit.
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 to
our financial statements under Part II, Item 8, of this report.
Illinois Regulated
As of January 1, 2007, CIPS, CILCO and IP were
required to obtain all electric supply requirements for
customers 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 each of May 2008, 2009 and 2010.
As part of the Illinois electric settlement agreement
reached in 2007, the reverse power procurement auction
process in Illinois was discontinued. It was replaced with a
new power procurement process led by the IPA beginning
in 2009. Under the new plan, the IPA will procure separate
wholesale products (capacity, energy swaps and renewable
energy credits) on behalf of the Ameren Illinois Utilities for
the period of June 1, 2009, through May 30, 2014. The
products will be procured through a RFP process, which is
expected to begin during the first half of 2009. In 2008,
utilities contracted for necessary power and energy
requirements not already supplied through the September
2006 auction contracts, primarily through a RFP process
that was subject to ICC review and approval.
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 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 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 and Note 14
– Related Party Transactions to our financial statements
under Part II, Item 8, of this report for additional
information on power procurement in Illinois.
Non-rate-regulated Generation
In December 2006, Genco and Marketing Company,
and AERG and Marketing Company, entered into power
supply agreements 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 commencing on January 1, 2007. 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.
In December 2005, EEI and Marketing Company entered
into a power supply agreement whereby EEI sells all of its
capacity and energy to Marketing Company commencing
January 1, 2006. This agreement expires on December 31,
2015. All of Genco’s, AERG’s and EEI’s generating capacity
competes for the sale of energy and capacity in the
competitive energy markets through Marketing Company.
See Note 14 – Related Party Transactions to our financial
statements under Part II, Item 8, of this report for additional
information.
Factors that could cause Marketing Company to
purchase power for the Non-rate-regulated Generation
business segment include, among other things, absence of
sufficient owned generation, plant outages, the failure of
suppliers to meet their power supply obligations, and
extreme weather conditions.
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, 2008, 2007 and 2006:
Coal
Nuclear
Natural Gas
Hydroelectric
Oil
Ameren:(a)
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Missouri Regulated:
UE:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-rate-regulated Generation:
Genco:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO (AERG):
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
85%
84
85
77%
76
77
99%
96
97
99%
99
99
EEI:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100%
100
100
Total Non-rate-regulated Generation:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
99%
98
99
12%
12
13
19%
19
20
-%
-
-
-%
-
-
-%
-
-
-%
-
-
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) Less than 1% of total fuel supply.
1%
2
1
1%
2
1
1%
4
2
1%
1
1
-%
-
(b)
1%
2
1
2%
2
1
3%
3
2
-%
-
-
-%
-
-
-%
-
-
-%
-
-
(b)%
(b)
(b)
(b)%
(b)
(b)
(b)%
(b)
1
-%
(b)
(b)
-%
-
-
(b)%
(b)
(b)
9
The following table presents the cost of fuels for electric generation for the years ended December 31, 2008, 2007 and
2006:
Cost of Fuels (Dollars per million Btus)
2008
2007
2006
Ameren:
Coal(a)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
1.572
0.493
10.503
Weighted average – all fuels(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1.573
$
Missouri Regulated:
UE:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal(a)
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
1.426
0.493
10.264
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1.340
$
Non-rate-regulated Generation:
Genco:
Coal(a)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average – all fuels(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO (AERG):
Coal(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EEI:
Coal(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Non-rate-regulated Generation:
Coal(a)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average – all fuels(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
1.958
15.857
2.121
1.598
1.721
1.438
1.746
10.764
1.919
$
$
$
$
$
$
$
1.399
0.490
7.939
1.462
1.284
0.490
7.580
1.271
1.717
8.440
1.939
1.309
1.450
1.329
1.545
8.390
1.759
$
$
$
$
$
$
$
$
$
$
$
1.271
0.434
8.718
1.281
1.084
0.434
8.625
1.035
1.691
9.391
1.865
1.419
1.466
1.266
1.513
8.793
1.677
(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) The fuel cost for natural gas represents the actual cost of natural gas and variable costs for transportation, storage, balancing, and fuel losses
for delivery to the plant. In addition, the fixed costs for firm transportation and firm storage capacity are included in the calculation of fuel cost
for the generating facilities.
(c) Represents all costs for fuels used in our electric generating facilities, to the extent applicable, including coal, nuclear, natural gas, oil, propane,
tire chips, paint products, and handling. Oil, paint, propane, and tire chips are not individually listed in this table because their use is minimal.
(d) 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 owner. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
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 2012. UE, Genco, AERG
and EEI expect to enter into additional contracts to purchase
coal. Coal supply agreements typically have an initial term of
five years, with about 20% of the contracts expiring
annually. Ameren burned 40.3 million (UE – 22.0 million,
Genco – 9.6 million, AERG – 3.7 million, EEI – 5.0 million)
tons of coal in 2008. 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 – 97%,
Genco – 98%, AERG – 77%, 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 been restricted
because of rail maintenance, weather and derailments. As of
December 31, 2008, coal inventories for UE, Genco, AERG
and EEI were adequate and 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 generating fuel generally involves
the mining and milling of uranium ore to produce uranium
concentrates, the conversion of uranium concentrates to
uranium hexafluoride gas, enrichment of that gas, and then
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 will begin manufacture during the
fourth quarter of 2009. Enriched uranium for such
assemblies is in inventory. UE also has agreements or
inventories to price-hedge approximately 95% of Callaway’s
2010 and 55% of Callaway’s 2011 refueling requirements.
UE has uranium (concentrate and hexafluoride) inventories
and supply contracts sufficient to meet all of its uranium
and conversion requirements through at least 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. There is no refueling scheduled in 2009 or
2012. 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, 2008, UE had price-hedged
about 22% and Genco had price-hedged about 30% of their
required gas supply for generation in 2009. As of
December 31, 2008, EEI did not have any of its required gas
supply for generation hedged for price risk.
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 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 to our
financial statements under Part II, Item 8.
INDUSTRY ISSUES
We are facing issues common to the electric and gas
utility industry and the non-rate-regulated 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
and supply;
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 like 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 non-rate-regulated generating entities and
RTOs;
increases or decreases in power prices due to the
balance of supply and demand;
11
‰
‰
‰
‰
‰
‰
‰
‰
the availability of fuel and increases or decreases in fuel
prices;
the availability of 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;
public concern about the siting of new facilities;
construction of power generation and transmission
facilities;
proposals for programs to encourage or mandate
energy efficiency and renewable sources of power;
OPERATING STATISTICS
‰
‰
public concerns about nuclear plant operation and
decommissioning and the disposal of nuclear waste;
and
consolidation of electric and 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 to
our financial statements under Part II, Item 8, of this report.
The following tables present key electric and natural gas operating statistics for Ameren for the past three years:
Electric Operating Statistics – Year Ended December 31,
2008
2007
2006
Electric Sales – kilowatthours (in millions):
Missouri Regulated:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Native load subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonaffiliate interchange sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate interchange sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13,904
14,690
9,256
785
38,635
10,457
-
49,092
14,258
14,766
9,675
759
39,458
10,984
-
50,442
13,081
14,075
9,582
739
37,477
3,132
10,072
50,681
Illinois Regulated:
Residential
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11,667
11,857
11,476
Commercial
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Native load subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-rate-regulated Generation:
Nonaffiliate energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate native energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminate affiliate sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminate Illinois Regulated/Non-rate-regulated Generation common customers . . . . . . . . . . . . . . . . . . . . . . .
6,095
6,147
1,442
11,300
555
37,206
26,395
6,055
32,450
(6,055)
(4,939)
7,232
5,178
1,606
11,199
576
37,648
25,196
7,296
32,492
11,406
269
10,950
2,349
598
37,048
24,921
18,425
43,346
(7,296)
(5,800)
(28,036)
(2,024)
Ameren Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
107,754
107,486
101,015
Electric Operating Revenues (in millions):
Missouri Regulated:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial
Industrial
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
948
838
372
108
$
980
839
390
93
899
796
392
104
Native load subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,266
2,302
2,191
Nonaffiliate interchange sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate interchange sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
490
-
484
-
263
196
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2,756
$
2,786
$
2,650
12
Electric Operating Statistics – Year Ended December 31,
2008
2007
2006
Illinois Regulated:
Residential
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,112
$ 1,055
$
852
Commercial
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial
Generation and delivery service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery service only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
616
77
102
30
285
666
54
105
24
372
784
3
489
2
126
Native load subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,222
$ 2,276
$ 2,256
Non-rate-regulated Generation:
Nonaffiliate energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Affiliate native energy sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,389
441
106
$ 1,936
$ 1,310
461
41
$ 1,812
$ 1,032
662
19
$ 1,713
Eliminate affiliate revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(547)
(591)
(1,019)
Ameren Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 6,367
$ 6,283
$ 5,600
Electric Generation – megawatthour (in millions):
Missouri Regulated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-rate-regulated Generation:
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AERG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EEI
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medina Valley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
49.3
16.6
6.7
8.0
0.2
31.5
80.8
50.3
17.4
5.3
8.1
0.2
31.0
81.3
50.8
15.4
6.7
8.3
0.2
30.6
81.4
Price per ton of delivered coal (average)(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 26.90
$ 25.20
$ 22.74
Source of energy supply:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydroelectric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased and interchanged, net
70.1%
0.8
-
9.5
1.8
17.8
68.7%
1.8
-
9.4
1.6
18.5
65.8%
0.9
0.7
9.7
0.9
22.0
100.0%
100.0%
100.0%
Gas Operating Statistics – Year Ended December 31,
2008
2007
2006
Gas Sales (millions of Dth)
Missouri Regulated:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Regulated:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8
4
1
13
65
28
11
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
104
Other:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Residential
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Eliminate affiliate sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
-
-
4
4
(1)
120
7
4
1
12
59
25
10
94
-
-
2
2
-
7
3
1
11
55
23
13
91
-
-
7
7
-
108
109
13
Gas Operating Statistics – Year Ended December 31,
2008
2007
2006
Natural Gas Operating Revenues (in millions)
Missouri Regulated:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois Regulated:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
121
54
12
14
201
819
338
119
(21)
$
$
$
108
47
12
7
174
687
272
103
39
$
$
$
101
46
13
(2)
158
690
271
82
53
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,255
$ 1,101
$ 1,096
Other:
Residential
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
-
-
26
-
26
$
$
-
-
16
-
16
$
$
-
-
60
-
60
Eliminate affiliate revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(10)
(12)
(19)
Ameren Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,472
$ 1,279
$ 1,295
Peak day throughput (thousands of Dth):
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
158
266
399
615
155
250
401
574
124
242
356
540
Total peak day throughput
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,438
1,380
1,262
(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 to our financial statements under Part II, Item 8, of this report.
AVAILABLE INFORMATION
The Ameren Companies make available free of charge
through Ameren’s Internet 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
Section 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).
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.
These documents are also available in print upon
written request to Ameren Corporation, Attention:
Secretary, P.O. Box 66149, St. Louis, Missouri 63166-
6149. The public may read and copy any materials filed with
the SEC at the SEC’s Public Reference Room at 100 F
Street, N.E., Washington, D.C. 20549. The public may
obtain information on the operation of the Public Reference
Room by calling the SEC at 1-800-SEC-0330.
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 and
Outlook in Management’s Discussion and Analysis of
Financial Condition and Results of Operations under Part II,
Item 7, of this report.
14
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, or liquidity.
The rates that UE, CIPS, CILCO and IP are allowed to
charge for their services are an important item influencing
the results of operations, financial position, and liquidity of
these companies and Ameren. The electric and gas utility
industry is highly regulated. The regulation of the rates that
utility customers are charged is 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
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 entities could have a material
adverse effect on results of operations, financial position, or
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
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 means that these companies may not be
able to earn the allowed return established by their
regulators (often referred to as regulatory lag). As a result,
UE, CIPS, CILCO and IP expect to file more frequent rate
cases. A period of increasing rates to 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, or liquidity.
We are subject to various environmental laws and
regulations that require significant capital expenditures,
can increase our operating costs, and may adversely
influence or limit our results of operations, financial
position or 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
plants, 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 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. Actions required to ensure that our facilities 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.
About 85% of Ameren’s (UE – 77%, Genco – 99%,
CILCO (through AERG) – 99%, EEI – 100%) generating
capacity is coal-fired. The remaining electric generation
comes from nuclear, gas-fired, hydroelectric, and oil-fired
power plants. Federal and state laws require significant
reductions in SO2, NOx and mercury emissions from coal-
fired plants.
Ameren’s estimated capital costs through 2018, based
on current technology, to comply with the federal Clean Air
Interstate Rule and related state implementation plans and
the MPS as well as federal ambient air quality standards
including ozone and fine particulates, and the federal Clean
Air Visibility Rule range from $4.5 billion to $5.5 billion (UE
– $2.2 billion to $2.6 billion; Genco – $1.2 billion to
$1.4 billion, CILCO (through AERG) – $480 million to
$590 million, EEI – $665 million to $830 million). In
addition, the Ameren Companies could incur additional
capital costs with respect to a MACT standard for mercury
emissions. The EPA is expected to move forward with a
MACT standard for mercury emissions as the U.S. Supreme
Court denied in February 2009 a petition to review a U.S.
Court of Appeals decision that vacated the federal Clean Air
Mercury Rule. Further, with respect to the EPA’s
enforcement initiative to determine whether modifications at
a number of coal-fired power plants owned by electric
utilities in the United States are subject to the New Source
Review requirements or New Source Performance
Standards under the Clean Air Act, Ameren, UE, Genco,
AERG and EEI could incur increased capital expenditures for
15
the installation of control technology, increased operations
and maintenance expenses, as well as fines or penalties.
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 power plants 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 or
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 or otherwise
materially adversely affect our results of operations,
financial position or liquidity.
Future initiatives regarding greenhouse gas emissions
and global warming are subject to active consideration in
the U.S. Congress. In October 2008, the U.S. House of
Representatives, Energy and Commerce Committee,
Subcommittee on Energy and Air Quality issued a
“discussion draft” of climate legislation, which proposed
establishing an economy-wide cap-and-trade program. The
overarching goal of such legislation is to reduce
greenhouse gas emissions to 6% below 2005 levels by
2020 and to 80% below 2005 levels by 2050. In addition,
new leadership in the Energy and Commerce Committee is
considering aggressive climate legislation. Finally, President
Obama supports an economy-wide cap-and-trade
greenhouse gas reduction program that would reduce
emissions to 1990 levels by 2020 and 80% below 1990
levels by 2050. President Obama has also indicated support
for auctioning 100% of the emission allowances to be
distributed under the legislation. Although we cannot
predict the date of enactment or the requirements of any
global warming legislation or regulations, we believe it is
likely that some form of federal greenhouse gas legislation
or regulations will become law during President Obama’s
administration.
As a result of our diverse fuel portfolio, our
contribution to greenhouse gases varies among our
generating facilities, but coal-fired power plants are
significant sources of CO2, a principal greenhouse gas.
Ameren’s current analysis shows that under some policy
scenarios being considered in the U.S. Congress,
household costs and rates for electricity could rise
significantly. The burden could fall particularly hard on
electricity consumers and the Midwest economy because of
our 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 electric generation could affect the cost of
heating for our utility customers and many industrial
processes. Ameren believes that under some policy
scenarios being considered by Congress, wholesale natural
gas costs could rise significantly as well. Higher costs for
energy could contribute to reduced demand for both
electricity and natural gas.
Future initiatives regarding greenhouse gas emissions
and global warming may also be subject to the activities
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 reduce
greenhouse gas emissions through a cap-and-trade
mechanism. It is expected that the advisory group to the
Midwest governors will provide recommendations on the
design of a greenhouse gas reduction program by the third
quarter of 2009. However, it is uncertain whether legislation
to implement the recommendations will be implemented or
passed by any of the states, including Illinois.
With regard to greenhouse gas regulation under
existing law, in April 2007, the U.S. Supreme Court issued a
decision 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 was a
result of a Bush Administration ruling denying a waiver
request by the state of California to implement such
regulations. The Supreme Court sent the case back to the
EPA, which must conduct a rulemaking process to
determine whether greenhouse gas emissions contribute to
climate change “which may reasonably be anticipated to
endanger public health or welfare.” In July 2008, the EPA
issued an advance notice of public rulemaking (ANPR) in
response to the U.S. Supreme Court’s directive. The ANPR
solicited public comments on the benefits and ramifications
of regulating greenhouse gases under the Clean Air Act, and
that rulemaking has not been completed. On February 12,
2009, the EPA announced its intent to reconsider the
decision under the Bush Administration denying the waiver
to the state of California for regulating CO2 emissions from
automobiles. On February 17, 2009, the EPA also granted a
petition for reconsideration filed by the Sierra Club to
reexamine a December 2008 Bush Administration ruling
that CO2 should not be regulated under the Clean Air Act
when issuing construction permits for power plants. These
EPA actions will factor into the rulemaking process on the
ANPR and could ultimately lead to regulation of CO2 from
power plants.
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. 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 could lead to possible impairment of
assets. 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.
16
The construction of, and capital improvements to,
Our counterparties may not meet their obligations 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 non-rate-regulated generation facilities
involve substantial risks. These risks include escalating
costs, performance of the projects when completed and
the ability to complete projects as scheduled, which
could result in the closure of facilities and higher costs.
Over the next five years, the Ameren Companies will
incur significant capital expenditures for compliance with
environmental regulations and to make significant
investments in their electric and gas utility infrastructure
and their non-rate-regulated generation facilities. The
Ameren Companies estimate that they will incur up to
$10.4 billion (UE – up to $5.3 billion; CIPS – up to
$565 million; Genco – up to $1.8 billion; CILCO (Illinois
Regulated) – up to $415 million; CILCO (AERG) – up to
$640 million; IP – up to $1.2 billion; EEI – up to
$385 million; Other – up to $160 million) of capital
expenditures during the period 2009 through 2013. These
expenses include construction expenditures, capitalized
interest or allowance for funds used during construction,
and compliance with EPA and state regulations regarding
SO2 and NOx emissions and mercury emissions from coal-
fired power plants. Costs for these types of projects have
escalated in recent years and are expected to either stay at
current levels or further escalate.
Investments in Ameren’s regulated operations are
expected to be recoverable from ratepayers, but are subject
to prudency reviews. The recoverability of amounts
expended in non-rate-regulated 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 not performing 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 the loss of their investment
in the project or facility. The Ameren Companies may also
be required to purchase additional electricity or natural gas
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, or liquidity.
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
current 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, or liquidity could otherwise be adversely affected.
Certain of the Ameren Companies have obligations to
other Ameren Companies or other Ameren subsidiaries
because of transactions involving energy, coal, other
commodities, services, and because 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, or liquidity
could be adversely affected, resulting in the nondefaulting
Ameren entity being unable to meet its obligations to
unrelated third-parties. Our hedging activities are generally
undertaken with a view to the Ameren-wide exposures. Some
Ameren Companies may therefore be more or less hedged
than if they were to engage in such hedging alone.
Increasing costs associated with our defined benefit
retirement plans, health care plans, and other employee-
related benefits may adversely affect our results of
operations, financial position, or 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 at least to the
pension expense. Based on Ameren’s assumptions at
December 31, 2008, and reflecting this pension funding
policy, Ameren expects to make annual contributions of
$90 million to $200 million in each of the next five years.
We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion
of the future funding requirements to be 61%, 6%, 10%,
9%, and 14%, respectively. These amounts are estimates.
They may change with actual investment performance,
changes in interest rates, 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 may adversely affect
our results of operations, financial position, or liquidity.
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Our electric generating, transmission and
If UE must purchase power because of the
distribution facilities are subject to operational risks that
could adversely affect our results of operations, liquidity,
and financial position.
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:
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increased prices for fuel and fuel transportation;
facility shutdowns due to operator error or a failure of
equipment or processes;
longer-than-anticipated maintenance outages;
disruptions in the delivery of fuel and lack of adequate
inventories;
increased purchased power costs;
lack of water for cooling plant operations;
labor disputes;
inability to comply with regulatory or permit
requirements, including environmental contamination;
disruptions in the delivery of electricity, including
impacts on us or our customers;
increased capital expenditure requirements, including
those due to environmental regulation;
handling and storage of fossil-fuel combustion waste
products, such as coal ash;
unusual or adverse weather conditions, including
severe storms, drought and floods;
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 our
systems on which sensitive utility customer data and
account information are stored;
catastrophic events such as fires, explosions, or other
similar occurrences; and
other unanticipated operations and maintenance
expenses and liabilities.
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 an 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 has settled with the FERC and the state of Missouri
all issues associated with the December 2005 Taum Sauk
incident. Other parties have also claimed damages as a
result of the incident. UE has begun rebuilding the upper
reservoir at its Taum Sauk plant. The estimated cost to
rebuild the upper reservoir is in the range of $480 million.
UE expects the Taum Sauk plant to be out of service
through early 2010.
unavailability of the Taum Sauk facility during the rebuild of
the upper reservoir, UE has committed to not seek recovery
of these additional costs from ratepayers. The Taum Sauk
incident is expected to reduce Ameren’s and UE’s 2009
pretax earnings by $15 million to $20 million, excluding any
unreimbursed costs related to the incident or the rebuild,
which are currently not expected. UE expects to realize
higher-cost sources of power, reduced interchange sales,
and increased expenses, net of insurance reimbursement
for replacement power costs.
At this time, UE believes that substantially all damages
and liabilities caused by the breach, including costs related
to the settlement agreement with the state of Missouri, the
cost of rebuilding the plant, and the cost of replacement
power, up to $8 million annually, will be covered by
insurance. Insurance will not cover lost electric margins and
penalties. Under UE’s insurance policies, all claims by or
against UE are subject to review by its insurance carriers.
As a result of this breach, UE is engaged in litigation
initiated by certain private parties and the Department of the
Army, Corp of Engineers. Until all litigation has been
resolved and the insurance review is completed, among
other things, we are unable to determine the total impact
the breach may have on Ameren’s and UE’s results of
operations, financial position, or liquidity beyond those
amounts already recognized.
Genco’s, AERG’s, and EEI’s electric generating
facilities must compete for the sale of energy and
capacity, which exposes them to price 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 non-rate-
regulated subsidiaries generally depend on the prices that
can be obtained for energy and capacity in Illinois and
adjacent markets. Among the factors that could influence
such prices (all of which are beyond our control to a
significant degree) are:
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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;
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the growth rate in electricity usage as a result of
population changes, regional economic conditions, and
the implementation of conservation programs;
climate conditions in the Midwest market; and
environmental laws and regulations.
UE’s ownership and operation of a nuclear
generating facility creates business, financial, and waste
disposal risks.
UE owns the Callaway nuclear plant, which represents
about 12% of UE’s generation capacity and produced 19%
of UE’s 2008 generation. Therefore, UE is subject to the
risks of nuclear generation, which include the following:
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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 UE 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 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, or 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 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.
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,
or liquidity.
Our facilities are considered critical energy
infrastructure and may therefore be targets of acts of
terrorism.
Like other electric and gas utilities and other non-rate-
regulated 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, or 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.
The global capital and credit markets experienced
extreme volatility and disruption in 2008, and we expect
those conditions to continue throughout 2009. Several
factors have driven this situation, including deteriorating
global economic conditions and the weakened condition of
major financial institutions. The extreme disruption in the
financial markets has limited companies’, including the
Ameren Companies’, ability to access the debt and equity
capital markets as well as credit markets to support their
operations and refinance debt, which has led to higher
financing costs compared to recent years. At December 31,
2008, the Ameren Companies had in place revolving bank
credit facilities aggregating $2.15 billion, the size of which
would be reduced if any of the participating banks fail to
honor their commitments. In total, 18 banks participated in
these credit facilities.
We use short-term and long-term debt as a significant
source of liquidity and funding for capital requirements not
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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 need more short-term and
long-term debt financing. 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 in 2008 and 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. 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.
The Ameren Companies have certain debt that
matures, and credit facilities that expire, in 2009 and 2010.
Although we are actively developing plans and strategies to
refinance or otherwise repay this debt and to renew or
replace these credit facilities, we are unable to predict
capital market conditions, our access to the capital markets
or the degree of success we will have in renewing or
replacing any of the credit facilities and whether the size
and terms of any new credit facilities will be comparable to
the existing credit facilities.
Ameren’s and some of the Ameren Companies’
holding company structures could limit their ability to pay
common stock dividends, to service their respective debt
obligations and to pay dividends on their outstanding
preferred stock, as applicable.
Ameren is a holding company, and 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 and some of
the Ameren Companies’ ability to service their respective
debt obligations and to pay dividends on their respective
preferred stock are 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
certain 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 workforce
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.
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ITEM 2. PROPERTIES.
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 to our financial statements under Part II, Item 8, of this
report.
The following table shows what our electric generating facilities and capability are anticipated to be at the time of our
expected 2009 peak summer electrical demand:
Primary Fuel Source
Plant
Location
Net Kilowatt Capability(a)
Missouri Regulated:
UE:
Coal
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Labadie
Rush Island
Sioux
Meramec
Franklin County, Mo.
Jefferson County, Mo.
St. Charles County, Mo.
St. Louis County, Mo.
Total coal
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Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Callaway
Callaway County, Mo.
Hydroelectric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Osage
Keokuk
Lakeside, Mo.
Keokuk, Iowa
Total hydroelectric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pumped-storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taum Sauk
Reynolds County, Mo.
Oil (CTs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (CTs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fairgrounds
Meramec
Mexico
Moberly
Moreau
Howard Bend
Venice
Peno Creek(d)(e)
Meramec(e)
Venice(e)
Viaduct
Kirksville
Audrain(d)
Goose Creek
Raccoon Creek
Pinckneyville
Kinmundy(e)
Jefferson City, Mo.
St. Louis County, Mo.
Mexico, Mo.
Moberly, Mo.
Jefferson City, Mo.
St. Louis County, Mo.
Venice, Ill.
Bowling Green, Mo.
St. Louis County, Mo.
Venice, Ill.
Cape Girardeau, Mo.
Kirksville, Mo.
Audrain County, Mo.
Piatt County, Ill.
Clay County, Ill.
Pinckneyville, Ill.
Kinmundy, Ill.
2,405,000
1,181,000
986,000
841,000
5,413,000
1,190,000
234,000
137,000
371,000
(b)
55,000
59,000
55,000
55,000
55,000
43,000
(c)
322,000
188,000
53,000
500,000
25,000
13,000
608,000
438,000
304,000
316,000
232,000
2,677,000
9,973,000
21
Primary Fuel Source
Plant
Location
Net Kilowatt Capability(a)
Non-rate-regulated Generation:
EEI(f):
Coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (CTs) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total EEI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco:
Coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (CTs) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO (through AERG):
Coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total coal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Oil
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medina Valley:
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Non-rate-regulated Generation . . . . . . . . . . . . .
Total Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Joppa Generating Station
Joppa
Joppa, Ill.
Joppa, Ill.
Newton
Coffeen
Meredosia
Hutsonville
Newton, Ill.
Coffeen, Ill.
Meredosia, Ill.
Hutsonville, Ill.
Meredosia
Hutsonville (Diesel)
Meredosia, Ill.
Hutsonville, Ill.
Grand Tower
Elgin(g)
Gibson City
Joppa 7B
Columbia(h)
Grand Tower, Ill.
Elgin, Ill.
Gibson City, Ill.
Joppa, Ill.
Columbia, Mo.
E.D. Edwards
Duck Creek
Bartonville, Ill.
Canton, Ill.
Sterling Avenue
Indian Trails
CAT/Mapleton
CAT/Mossville
Peoria, Ill.
Pekin, Ill.
Mapleton, Ill
Mossville, Ill
Medina Valley
Mossville, Ill.
1,002,000
74,000
1,076,000
1,198,000
900,000
308,000
151,000
2,557,000
156,000
3,000
159,000
511,000
460,000
228,000
165,000
140,000
1,504,000
4,220,000
715,000
410,000
1,125,000
(i)
(j)
-
9,000
6,000
15,000
1,140,000
44,000
6,480,000
16,453,000
“Net Kilowatt Capability” is the generating capacity available for dispatch from the facility into the electric transmission grid.
(a)
(b) This facility is not operational because of a breach of its upper reservoir in December 2005. It is expected to be out of service through early
2010. Its 2005 peak summer electrical demand net kilowatt capability was 440,000. 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 2009.
(d) There are economic development lease arrangements applicable to these CTs.
(e) Certain of these CTs have the capability to operate on either oil or natural gas (dual fuel).
(f) Ameren owns an 80% interest in EEI. See Part I, Item 1, Business and Note 1 – Summary of Significant Accounting Policies to our financial
statements under Part II, Item 8, of this report. This table reflects the full capability of EEI’s facilities.
(g) There is a tolling agreement in place for one of Elgin’s units (approximately 100 megawatts). The agreement expires on May 31, 2009.
(h) Genco has granted the city of Columbia, Missouri, options to purchase an undivided ownership interest in these facilities, which would result in
a sale of up to 72 megawatts (about 50%) of the facilities. 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. A power purchase agreement pursuant to which
Columbia is now purchasing up to 72 megawatts of capacity and energy generated by these facilities from Marketing Company will terminate if
Columbia exercises the purchase options.
In December 2008, CILCO entered into talks with a third party to sell the Sterling Avenue facility. CILCO expects to sell this facility in 2009.
This facility exclusively serves one industrial customer, which announced in early 2009 a suspension of operations of its plant.
(i)
(j)
22
The following table presents electric and natural gas
utility-related properties for UE, CIPS, CILCO and IP as of
December 31, 2008:
UE
CIPS
CILCO
IP
Circuit miles of electric
transmission lines . . . . . . .
2,942
2,306
331
1,853
Circuit miles of electric
distribution lines . . . . . . . . .
32,956
14,931
8,853
21,607
Circuit miles of electric
distribution lines
underground . . . . . . . . . . . .
Miles of natural gas
transmission and
distribution mains . . . . . . .
Propane-air plants . . . . . . . . .
Underground gas storage
fields . . . . . . . . . . . . . . . . . .
Billion cubic feet of total
working capacity of
underground gas storage
fields . . . . . . . . . . . . . . . . . .
22%
11%
25%
12%
3,232
1
5,338
-
3,907
-
8,770
-
-
-
3
2
2
8
7
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 bond 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,
AERG’s Indian Trails generating facility, Medina Valley’s
generating facility, certain of Ameren’s substations, and
most of our transmission and distribution lines and gas
mains are situated on lands we occupy 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.
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 direct first liens of the
indentures securing their mortgage bonds. In July 2006 and
February 2007, AERG recorded open-ended mortgages and
security agreements with respect to its E.D. Edwards and
Duck Creek power plants. These plants serve as collateral to
secure its obligations under multiyear, senior secured credit
facilities entered into on July 14, 2006, and February 9,
2007, along with other Ameren subsidiaries. See Note 4 –
Short-term Borrowings and Liquidity under Part II, Item 8,
of this report for details of the credit facilities.
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 responsibilities 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.
In March 2006, UE purchased a CT facility located in
Audrain County, Missouri, from NRG Audrain Holding, LLC,
and NRG Audrain Generating LLC, both affiliates of NRG
Energy, Inc. (collectively, NRG). As a part of this
transaction, UE was assigned the rights of NRG as lessee of
the CT facility under a long-term lease with Audrain County
and assumed NRG’s obligations under the lease. The lease
term will expire on December 1, 2023. Under the terms of
this capital lease, UE has all operation and maintenance
responsibilities for the facility, and ownership of the facility
will be transferred to UE at the expiration of the lease. When
ownership of the Audrain County CT facility is transferred to
UE by the county, the property and plant will become
subject to the lien of any outstanding UE first mortgage
bond indenture.
See Note 15 – Commitments and Contingencies to our
financial statements under Part II, Item 8, of this report for
information on mechanics’ liens filed against CILCO’s Duck
Creek plant.
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,
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.
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 to our financial
statements 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 2008 with respect to
any of the Ameren Companies.
23
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, 2008, 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
12/31/08 Positions and Offices Held
62
Name
Gary L. Rainwater
Rainwater began his career with UE in 1979 as an engineer 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 CILCORP and CILCO
in addition to his position as chief executive officer and president of those companies, 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.
Chairman, Chief Executive Officer, President, and Director
Warner L. Baxter
47
Executive Vice President and Chief Financial Officer, Chairman,
Chief Executive Officer, President, and Chief Financial Officer
(Ameren Services)
Baxter joined UE in 1995. He was elected senior vice president, finance, of Ameren, UE, CIPS, Ameren Services, and Genco in
2001 and of CILCORP and CILCO in 2003. Baxter was elected to the position of executive vice president and chief financial
officer of Ameren, UE, CIPS, Genco, CILCORP, 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.
Thomas R. Voss
61
Executive Vice President and Chief Operating Officer, Chairman,
Chief Executive Officer, and President (UE)
Voss joined UE in 1969 as an engineer. He was elected senior vice president of UE, CIPS, and Ameren Services in 1999, of
Genco in 2001, of CILCORP and 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. He was elected to his present position at Ameren in 2005. In 2006, he was
elected executive vice president of UE, CIPS, CILCORP, CILCO and IP. In 2007, Voss was elected chairman, chief executive
officer, and president of UE. He relinquished his positions at CIPS, CILCORP, CILCO and IP in 2007.
Donna K. Martin
Martin joined Ameren Services in 2002 as vice president, human resources. In 2005, Martin was elected senior vice president
and chief human resources officer of Ameren Services. She was elected to the same positions at Ameren in 2007.
Senior Vice President and Chief Human Resources Officer
61
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 CILCORP and
CILCO. He was elected to his present position at Ameren, UE, CIPS, Genco, CILCORP, CILCO, and Ameren Services in 2003, and
at IP in 2004.
Senior Vice President, General Counsel, and Secretary
48
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 CILCORP and CILCO in 2003, and of IP in
2004.
Vice President and Treasurer
54
Martin J. Lyons
Lyons joined Ameren, UE, CIPS, Genco, and Ameren Services in 2001 as controller. He was elected controller of CILCORP and
CILCO in 2003. He was also elected vice president of Ameren, UE, CIPS, Genco, CILCORP, 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.
Senior Vice President and Chief Accounting Officer
42
24
SUBSIDIARIES:
Name
Scott A. Cisel
Age at
12/31/08 Positions and Offices Held
55
Chairman, Chief Executive Officer, and President (CILCO, CIPS 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.
Daniel F. Cole
Cole joined UE in 1976 as an engineer. 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
CILCORP and CILCO in 2003, and of IP in 2004.
Senior Vice President (CILCO, CIPS, CILCORP, IP and UE)
55
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)
44
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)
53
Michael L. Moehn
Moehn joined Ameren Services as assistant controller 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)
39
Michael G. Mueller
Mueller joined UE in 1986 as an engineer. He was elected vice president of AFS in 2000 and president of AFS in 2004.
President (AFS)
45
Charles D. Naslund
56
Chairman, Chief Executive Officer, and President (Resources
Company), 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. Effective in 2008, he was elected chairman,
chief executive officer, and president of Resources Company and president of Genco. Naslund relinquished his position at UE in
2008.
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 of Marketing Company that same year. He relinquished
his position at Ameren Services in 2007.
President (Marketing Company)
47
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 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.
25
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 began trading on January 2, 1998, following
the merger of UE and CIPSCO on December 31, 1997. On April 30, 2008, Ameren submitted to the NYSE a certificate of its
chief executive officer certifying that he was not aware of any violation by Ameren of NYSE corporate governance listing
standards.
Ameren common shareholders of record totaled 72,475 on January 30, 2009. The following table presents the price
ranges, closing prices, and dividends paid per Ameren common share for each quarter during 2008 and 2007.
High
Low
Close
Dividends Paid
AEE 2008 Quarter Ended:
March 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AEE 2007 Quarter Ended:
March 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
54.29
48.39
43.16
39.15
55.00
55.00
53.89
54.74
40.92
41.34
38.49
25.51
48.56
48.23
47.10
51.81
44.04
42.23
39.03
33.26
50.30
49.01
52.50
54.21
63 1⁄2¢
63 1⁄2
63 1⁄2
63 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, CILCORP, CILCO or IP. Ameren holds all
outstanding common stock of UE, CIPS, CILCORP 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 2008 and 2007:
(In millions)
2008
Quarter Ended
2007
Quarter Ended
Registrant
December 31
September 30
June 30
March 31 December 31
September 30
June 30
March 31
UE . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . .
Nonregistrants . . . . . . . .
$
71
-
17
-
15
32
$
88
-
-
-
15
30
$
$
28
-
60
-
15
30
77
-
24
-
15
17
$
21
40
-
-
61
10
Ameren . . . . . . . . . . . . . .
$
135
$
133
$
133
$
133
$
132
$
$
119
-
-
-
-
13
132
$
$
47
-
74
-
-
11
80
-
39
-
-
12
$
132
$
131
On February 13, 2009, 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, 2009, to stockholders of record on March 11, 2009.
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.
None of the Ameren Companies purchased equity securities reportable under Item 703 of Regulation S-K during the
period October 1 to December 31, 2008.
26
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five fiscal years ended December 31,
2008. 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, 2003, in Ameren common stock and in each of the indices shown, and it assumes that all of the
dividends were reinvested.
$225
$200
$175
$150
$125
$100
$75
$50
2003
2004
2005
2006
2007
2008
AEE
S&P 500
EEI Index
December 31,
2003
2004
2005
2006
2007
2008
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S&P 500 Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EEI Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$100.00
100.00
100.00
$115.12
110.88
122.84
$123.48
116.32
142.56
$135.96
134.69
172.15
$144.04
142.09
200.66
$ 94.22
89.51
148.69
Ameren management cautions that the stock price performance shown in the graph above should not be considered
indicative of potential future stock price performance.
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(a)(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Earnings per share – basic and diluted(a)(b) . . . . . . . . . . . . . . . . . . .
Common stock dividends per share . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, excluding current maturities . . . . . . . . . . . . . . . . .
Preferred stock subject to mandatory redemption . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income after preferred stock dividends . . . . . . . . . . . . . . . . . .
Dividends to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, excluding current maturities . . . . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
2007
2006
2005
2004
$
$
$
$
7,839
1,362
605
534
2.88
2.54
22,657
6,554
-
6,963
2,960
514
245
264
11,524
3,673
3,562
7,562
1,359
618
527
2.98
2.54
20,728
5,689
16
6,752
2,961
590
336
267
10,903
3,208
3,601
$
$
$
$
6,895
1,188
547
522
2.66
2.54
19,635
5,285
17
6,583
2,823
620
343
249
10,290
2,934
3,153
$
$
$
$
6,780
1,284
606
511
3.02
2.54
18,171
5,354
19
6,364
2,889
640
346
280
9,277
2,698
3,016
$
$
$
$
5,135
1,078
530
479
2.84
2.54
17,450
5,021
20
5,800
2,640
673
373
315
8,750
2,059
2,996
$
$
$
$
27
For the years ended December 31,
(In millions, except per share amounts)
CIPS:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income after preferred stock dividends . . . . . . . . . . . . . . . . . . . . . . .
Dividends to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, excluding current maturities . . . . . . . . . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, excluding current maturities . . . . . . . . . . . . . . . . . . . . . .
Subordinated intercompany notes (current and long-term) . . . . . . . . . . .
Total stockholder’s equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, excluding current maturities . . . . . . . . . . . . . . . . . . . . . .
Preferred stock of subsidiary subject to mandatory redemption . . . . . . . .
Total stockholder’s equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income after preferred stock dividends(b) . . . . . . . . . . . . . . . . . . . . . .
Dividends to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, excluding current maturities . . . . . . . . . . . . . . . . . . . . . .
Preferred stock subject to mandatory redemption . . . . . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP:(c)
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income after preferred stock dividends(b) . . . . . . . . . . . . . . . . . . . . . .
Dividends to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31:
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, excluding current maturities . . . . . . . . . . . . . . . . . . . . . .
Long-term debt to IP SPT, excluding current maturities . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
2007
2006
2005
2004
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
982
42
12
-
1,917
421
529
908
330
175
101
2,244
774
87
695
1,147
120
42
-
2,865
536
-
750
1,147
132
68
-
2,294
279
-
684
1,696
103
3
60
3,766
1,150
-
1,251
1,005
49
14
40
1,860
456
517
876
258
125
113
1,968
474
126
648
1,011
134
47
-
2,459
537
16
715
1,011
143
74
-
1,862
148
16
622
1,646
109
24
61
3,319
1,014
-
1,308
954
69
35
50
1,855
471
543
992
131
49
113
1,850
474
163
563
747
64
19
50
2,250
542
17
671
747
78
45
65
1,650
148
17
535
1,694
141
55
-
3,212
772
92
1,346
$
$
$
$
$
$
$
$
$
$
934
85
41
35
1,784
410
569
1,038
257
97
88
1,811
474
197
444
747
61
3
30
2,243
534
19
663
742
63
24
20
1,557
122
19
562
1,653
202
95
76
3,056
704
184
1,287
$
$
$
$
$
$
$
$
$
$
735
58
29
75
1,615
430
490
873
265
107
66
1,955
473
283
435
722
61
10
18
2,156
623
20
548
688
58
30
10
1,381
122
20
437
1,539
216
137
-
3,117
713
278
1,280
(a)
Includes amounts for IP since the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant
subsidiaries and intercompany eliminations.
(b) For the year ended December 31, 2005, net income included income (loss) from cumulative effect of change in accounting principle of
$(22) million ($(0.11) per share) for Ameren, $(16) million for Genco, $(2) million for CILCORP, $(2) million for CILCO, and $- million for IP.
Includes 2004 combined financial data under ownership by Ameren and IP’s former ultimate parent.
(c)
28
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
Ameren Executive Summary
Operations
In 2008 and early 2009, we were able to successfully
execute on key aspects of our long-term strategic plan. Our
strategic plan calls for generation excellence and
improvement of customer service and satisfaction. UE’s
Callaway nuclear plant completed its first-ever
breaker-to-breaker run and completed a plant record 28-day
refueling and maintenance outage in the fall of 2008. In
addition, the equivalent availability for UE’s coal-fired
generating units was a solid 88% as compared to 89% in
2007. Ameren’s Non-rate-regulated Generation business
segment set new generation records, producing
approximately 31 million total megawatthours, as equivalent
availability for its coal-fired units was 85% compared to
81% in 2007.
Amidst the economic challenges facing us and our
nation, we have remained focused on our customers and
have made significant investments in our energy
infrastructure to improve overall reliability and customer
satisfaction. In Missouri, through UE’s Power On reliability
program, we buried more than 100 miles of electric line,
trimmed trees along more than 6,500 miles of overhead
line, tested nearly 100,000 wood utility poles, and inspected
more than 8,000 miles of electric line. In Illinois, we
targeted the worst-performing circuits and aggressively
trimmed trees in Illinois Regulated’s 40,000 square-mile
territory and continued to automate its transmission system
to elevate its reliability. We believe that high-quality
customer service is essential to earning solid returns in our
rate-regulated businesses.
In Missouri, UE received approval of an electric rate
increase in January 2009 with new rates effective March 1,
2009. The authorized increase in annual electric revenues is
approximately $162 million based on a 10.76% return on
equity. The MoPSC rate order authorized a FAC, as well as a
vegetation management and infrastructure inspection cost
tracking mechanism. The FAC and tracking mechanisms
improve UE’s ability to continue to invest in its
infrastructure so that UE will be able to meet its customers’
expectations for safe and reliable service.
In Illinois, the ICC authorized in September 2008 new
electric and gas rates for the Ameren Illinois Utilities
effective October 1, 2008. These new rates provide
approximately $161 million in additional annual revenue
based on allowed returns on equity of nearly 10.7%. The
ICC also approved an increase in the fixed non-volumetric
monthly charge for natural gas residential and commercial
customers such that the Ameren Illinois Utilities now
recover 80% of delivery service costs through this charge
versus the prior 53%. The remainder is recovered through
volume-based charges. This will make our gas utility
earnings less sensitive to volumetric swings.
Earnings
Ameren reported net income of $605 million, or
$2.88 per share, for 2008 compared with net income of
$618 million, or $2.98 per share, in 2007. The decline in
earnings in 2008 versus 2007 was principally due to higher
fuel and related transportation prices, increased spending
on utility distribution system reliability, higher plant
operations and maintenance costs, milder weather, and net
unrealized mark-to-market losses on nonqualifying hedges,
among other things.
Those items more than offset the positive items. The
positive items included improved generating plant output
and higher realized margins from Non-rate-regulated
Generation operations, the absence of costs in 2008 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, the reduced impact in 2008 of
the Illinois electric settlement agreement, the absence in
2008 of the March 2007 FERC order that resettled costs
among MISO market participants retroactive to 2005 that
was recorded in 2007 and subsequent recovery of a portion
of these costs in 2008 through a MoPSC order, net
increases in electric and natural gas rates, and a 2008
lump-sum settlement payment from a coal supplier for
expected higher fuel costs in 2009 as a result of a premature
mine closure and contract termination, among other things.
Liquidity
Cash flows from operations of $1.5 billion in 2008 at
Ameren, along with other funds, were used to pay dividends
to common shareholders of $534 million and to partially
fund capital expenditures of $1.9 billion. The remaining
capital expenditures were primarily funded with debt.
We have taken actions to build on our financial strength
and enhance our financial flexibility in light of the current
difficult economic and capital and credit market conditions.
These actions included the February 2009 decision of
Ameren’s board of directors to reduce its common dividend
and accessing the capital markets to increase our available
liquidity, as well as making significant reductions in our
2008 and projected 2009 spending plans while still meeting
our reliability, environmental, and safety objectives.
Outlook
The global capital and credit markets experienced
extreme volatility and disruption in 2008, and we expect
those conditions to continue throughout 2009. We believe
that the disruption in the capital and credit markets will
further weaken global economic conditions. These weak
economic conditions will likely result in volatility in the
power and commodity markets, greater risk of defaults by
our counterparties, weaker customer sales growth,
particularly with respect to industrial sales, higher bad debt
expense and possible impairment of goodwill and long-lived
assets, among other things.
29
Over the next few years, we continue to expect to make
Future federal and state legislation or regulations that
significant investments in our electric and natural gas
infrastructure to improve reliability of our distribution
systems and to comply with environmental requirements.
From 2009 through 2011, we expect our rate-regulated rate
base to grow approximately 9% per year. Earnings growth
in our rate-regulated businesses is expected to come from
updating existing customer rates to reflect these
investments and the current levels of costs UE and the
Ameren Illinois Utilities are experiencing. We consider the
2008 and 2009 Illinois and Missouri rate orders to be
constructive. However, the returns that UE and the Ameren
Illinois Utilities expect to earn in 2009 are below levels
allowed by the respective state utility commissions in their
last rate orders. The new rates were based on historic test
year data and 2009 costs are expected to be higher than the
levels recovered in rates. This is especially true of financing
costs in Illinois, where sharply higher debt financing costs,
which were incurred after our rate cases were filed, are not
being recovered in rates. UE and the Ameren Illinois Utilities
will file more frequent rate cases requesting moderate rate
increases, as well as continue to seek appropriate cost
recovery and tracker mechanisms to mitigate regulatory lag.
In addition, we will continue to optimize Ameren’s
Non-rate-regulated Generation’s assets, focusing on
improving the output of these plants and related energy
marketing. We believe Non-rate-regulated Generation’s
plants will be well positioned for earnings growth in the
future should energy prices improve.
We 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. Between 2009 and 2018, Ameren expects
that certain Ameren Companies will be required to invest
between $4.5 billion and $5.5 billion to retrofit their coal-
fired power plants with pollution control equipment. Any
pollution control investments will result in decreased plant
availability during construction and significantly higher
ongoing operating expenses. Approximately 50% of this
investment is expected to be in our Missouri Regulated
operations, and it is therefore expected to be recoverable
from ratepayers.
Future initiatives regarding greenhouse gas emissions
and global warming are subject to active consideration in
the U.S. Congress. President Obama supports an economy-
wide cap-and-trade greenhouse gas reduction program that
would reduce emissions to 1990 levels by 2020 and to 80%
below 1990 levels by 2050. President Obama has also
indicated support for auctioning 100% of the emission
allowances to be distributed under the legislation. Although
we cannot predict the date of enactment or the
requirements of any global warming legislation or
regulations, it is likely that some form of federal greenhouse
gas legislation or regulations will become law during
President Obama’s administration. Potential impacts from
proposed legislation could vary depending upon proposed
CO2 emission limits, the timing of implementation of those
limits, the method of allocating allowances, and provisions
for cost containment measures.
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. 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 could lead to possible impairment of
assets. 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 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 rate-regulated
electric generation, transmission and distribution
businesses, rate-regulated natural gas transmission and
distribution businesses, and non-rate-regulated electric
generation businesses in Missouri and Illinois, as discussed
below. Dividends on Ameren’s common stock and the
payment of other expenses by the Ameren and CILCORP
holding companies are dependent on distributions made to
it by its subsidiaries. See Note 1 – Summary of Significant
Accounting Policies to our financial statements 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-
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 non-rate-regulated electric generation
business in Illinois and Missouri.
CILCO, a subsidiary of CILCORP (a holding company),
operates a rate-regulated electric and natural gas
transmission and distribution business and a non-rate-
regulated electric generation business (through its
subsidiary, AERG) 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.
30
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. Non-rate-regulated 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 do have natural gas cost recovery
mechanisms for our Illinois and Missouri gas delivery
businesses and purchased power cost recovery
mechanisms for our Illinois electric delivery businesses. As
part of the electric rate order issued by the MoPSC on
January 27, 2009, UE was granted permission to put in
place a FAC, which was effective March 1, 2009. See Note 2
– Rate and Regulatory Matters to our financial statements
under Part II, Item 8, for a discussion of the January 27,
2009, MoPSC order in UE’s electric rate proceeding.
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, 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.
Ameren’s net income was $605 million ($2.88 per
share) for 2008, $618 million ($2.98 per share) for 2007,
and $547 million ($2.66 per share) for 2006.
Ameren’s net income decreased $13 million and
earnings per share decreased 10 cents in 2008 compared
with 2007. Net income increased in the Non-rate-regulated
Generation segment by $71 million in 2008 compared to
2007, while net income 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 mark-to-market 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 mark-to-market 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);
unfavorable weather conditions (estimated at 16 cents
per share);
net unrealized mark-to-market losses on nonqualifying
hedges (11 cents per share);
higher financing costs (10 cents per share);
asset impairment charges recorded during 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
(6 cents per share);
increased depreciation and amortization expense
(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);
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 Non-rate-
regulated Generation segment;
the absence of costs in 2008 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
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);
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 expects to incur in 2009 due to
the premature closure of an Illinois mine at the end of
2007 (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
‰
‰
‰
‰
‰
‰
‰
31
compared with the prior-year refueling and
maintenance outage (4 cents per share).
Compared with 2006 earnings, 2007 earnings were
negatively affected by:
The cents per share information presented above is
based on average shares outstanding in 2007.
Ameren’s net income increased $71 million and
earnings per share increased 32 cents in 2007 compared
with 2006.
Compared with 2006 earnings, 2007 earnings were
favorably affected by:
‰
‰
‰
‰
‰
higher margins in the Non-rate-regulated Generation
segment due to the replacement of below-market
power sales contracts, which expired in 2006, with
higher-priced contracts;
higher electric rates, lower depreciation expense,
decreased income tax expense and $5 million in SO2
emission allowance sales in the Missouri Regulated
segment pursuant to the MoPSC electric rate order for
UE issued in May 2007 (21 cents per share);
decreased costs associated with outages caused by
severe storms (17 cents per share);
the absence of costs in 2007 that were incurred in 2006
related to the reservoir breach at UE’s Taum Sauk plant
(15 cents per share); and
favorable weather conditions (estimated at 14 cents per
share).
‰
‰
‰
‰
‰
‰
‰
‰
‰
‰
‰
the combined effect of the elimination of the Ameren
Illinois Utilities’ bundled electric tariffs, implementation
of new delivery service tariffs effective January 2, 2007,
and the expiration of below-market power supply
contracts;
higher fuel and related transportation prices (31 cents
per share);
electric rate relief and customer assistance programs
provided to certain Ameren Illinois Utilities’ electric
customers under the Illinois electric settlement
agreement (21 cents per share);
higher labor and employee benefit costs (18 cents per
share);
higher financing costs (17 cents per share);
lower emission allowance sales (16 cents per share);
increases in distribution system reliability expenditures
(15 cents per share);
reduced gains on the sale of noncore properties,
including leveraged leases (15 cents per share);
increased depreciation and amortization expense
(13 cents per share);
a planned refueling and maintenance outage at UE’s
Callaway nuclear plant net of an unplanned outage at
Callaway in 2006 (9 cents per share); and
higher bad debt expenses (8 cents per share).
The cents per share information presented above is based on average shares outstanding in 2006.
Because it is a holding company, Ameren’s net income and cash flows are primarily generated by its principal
subsidiaries: UE, CIPS, Genco, CILCORP 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, 2008, 2007 and 2006:
Net income:
UE(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(b)
$
Ameren net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2008
2007
2006
245
12
175
42
3
128
605
$
$
336
14
125
47
24
72
618
$
$
343
35
49
19
55
46
547
(a)
(b)
Includes earnings from a non-rate-regulated 40% interest in EEI through February 29, 2008.
Includes earnings from EEI, other non-rate-regulated operations, as well as corporate general and administrative expenses, and intercompany
eliminations. Includes a 40% interest in EEI prior to February 29, 2008 and an 80% interest in EEI since that date.
32
Below is a table of income statement components by segment for the years ended December 31, 2008, 2007 and 2006:
Missouri
Regulated
Illinois
Regulated
Non-rate-
regulated
Generation
Other /
Intersegment
Eliminations
Total
(47)
(5)
(3)
48
(28)
(1)
(15)
(4)
40
2
(13)
(51)
(8)
(5)
76
(26)
(1)
(8)
10
20
2
9
(46)
(3)
(5)
62
(28)
-
(17)
19
43
2
27
$
$
$
$
$
3,882
415
-
(1,857)
(685)
(393)
49
(440)
(327)
(39)
605
3,729
379
-
(1,687)
(681)
(381)
50
(423)
(330)
(38)
618
3,432
364
-
(1,556)
(661)
(391)
31
(350)
(284)
(38)
$
547
2008
Electric margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operations and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes other than income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minority interest and preferred dividends . . . . . . . . . . . . . . . . . . . . .
Net Income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
Electric margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operations and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes other than income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minority interest and preferred dividends . . . . . . . . . . . . . . . . . . . . .
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006
Electric margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operations and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes other than income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minority interest and preferred dividends . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
$
$
$
1,924
78
3
(922)
(329)
(240)
53
(193)
(134)
(6)
234
1,984
70
2
(900)
(333)
(234)
35
(194)
(143)
(6)
281
1,898
60
2
(800)
(335)
(230)
33
(171)
(184)
(6)
$
$
$
$
$
817
342
-
(627)
(219)
(126)
11
(144)
(16)
(6)
32
759
317
3
(550)
(217)
(121)
20
(132)
(25)
(7)
47
824
307
2
(535)
(192)
(137)
13
(95)
(65)
(7)
$
$
$
$
$
1,188
-
-
(356)
(109)
(26)
-
(99)
(217)
(29)
352
1,037
-
-
(313)
(105)
(25)
3
(107)
(182)
(27)
281
756
-
1
(283)
(106)
(24)
2
(103)
(78)
(27)
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
267
$
115
$
138
$
33
Margins
The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins from the
previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined
as gas revenues less gas purchased for resale. The table covers the years ended December 31, 2008, 2007, and 2006. We
consider electric, interchange and gas margins useful measures to analyze the change in profitability of our electric and 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.
2008 versus 2007
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
$
$
(59)
149
(36) $
16
(6) $
5
$
-
45
(4) $
18
(4) $
18
Electric revenue change:
Effect of weather (estimate) . . . . . . . . . . . . . . . . . . . . . . . . .
Electric rate increases and market price changes . . . . . . . . .
Interchange revenues, excluding estimated weather impact
of $53 million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois settlement agreement, net of reimbursement
. . . . . .
FERC-ordered MISO resettlements . . . . . . . . . . . . . . . . . . . .
Net mark-to-market gains on energy contracts . . . . . . . . . . .
Illinois pass-through power costs . . . . . . . . . . . . . . . . . . . . .
Generation output and other . . . . . . . . . . . . . . . . . . . . . . . . .
(42)
35
(17)
81
(72)
9
(47)
-
-
8
-
29
-
6
-
-
(49)
(8)
-
13
(12)
-
-
(14)
Total electric revenue change . . . . . . . . . . . . . . . . . . . . . . . . . .
$
84
$
(30) $
(52) $
32
$
Fuel and purchased power change:
Fuel:
Generation and other
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Emission allowance costs . . . . . . . . . . . . . . . . . . . . . . . . .
Net mark-to-market losses on fuel contracts . . . . . . . . . .
Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal contract settlement for 2009 . . . . . . . . . . . . . . . . . . . . .
Purchased power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois pass-through power costs . . . . . . . . . . . . . . . . . . . . .
FERC-ordered MISO resettlements . . . . . . . . . . . . . . . . . . . .
Total fuel and purchased power change . . . . . . . . . . . . . . . . . .
Net change in electric margins . . . . . . . . . . . . . . . . . . . . . . . .
Net change in gas margins . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
25
8
(75)
(93)
27
58
72
47
69
153
36
$
$
$
$
$
31
-
(39)
(56)
-
9
-
23
(32) $
(62) $
8
$
-
-
-
-
-
9
49
8
66
14
7
$
$
$
$
26
5
(18)
(13)
27
23
-
-
50
82
-
$
$
$
$
-
9
(4)
-
22
49
90
$
(32) $
1
(3)
(15)
-
8
(22)
4
-
9
(4)
-
22
49
90
$
(32) $
-
(3)
(15)
-
7
(22)
4
(59) $
(61) $
31
$
29
$
(1) $
(1) $
2007 versus 2006
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
Electric revenue change:
$
Effect of weather (estimate) . . . . . . . . . . . . . . . . . . . . . . . . .
UE electric rate increase . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Storm-related outages (estimate) . . . . . . . . . . . . . . . . . . . . .
JDA terminated December 31, 2006 . . . . . . . . . . . . . . . . . . .
Elimination of CILCO/AERG power supply agreement . . . . . .
Interchange revenues, excluding estimated weather impact
of ($47) million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois electric settlement agreement, net of
reimbursement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FERC-ordered MISO resettlement – March 2007 . . . . . . . . .
Mark-to-market losses on energy contracts . . . . . . . . . . . . .
Illinois rate redesign, generation repricing, growth and other
(estimate) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total electric revenue change . . . . . . . . . . . . . . . . . . . . . . . . . .
$
73
29
10
-
108
252
(73)
17
(21)
288
683
$
$
31
29
9
(196)
-
252
-
-
(13)
11
$
123
$
16
-
3
-
-
-
(11)
-
-
36
44
$
$
-
-
(3)
(97)
-
-
(30)
12
-
2
$
(116)
$
9
-
-
-
108
-
(20)
4
-
167
268
$
$
9
-
-
-
108
-
(20)
4
-
167
268
$
$
34
(13)
22
-
7
-
-
(45)
(4)
(33)
-
-
-
-
-
3
45
12
60
27
18
17
-
1
-
-
-
(14)
-
-
(49)
(45)
2007 versus 2006
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
Fuel and purchased power change:
Fuel:
Generation and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Emission allowances sales (costs) . . . . . . . . . . . . . . . . . .
Mark-to-market gains (losses) on fuel contracts . . . . . . . .
Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
JDA terminated December 31, 2006 . . . . . . . . . . . . . . . . . . .
Purchased power
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Entergy Arkansas, Inc. power purchase agreement . . . . . . . .
Elimination of CILCO/AERG power supply agreement . . . . . .
FERC-ordered MISO resettlement – March 2007 . . . . . . . . .
Storm-related energy costs (estimate) . . . . . . . . . . . . . . . . .
$
(35)
(38)
23
(98)
-
(82)
(12)
(108)
(35)
(1)
Total fuel and purchased power change . . . . . . . . . . . . . . . . . .
$ (386)
Net change in electric margins . . . . . . . . . . . . . . . . . . . . . . . .
Net change in gas margins . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
297
15
$
$
$
$
(10)
(29)
9
(84)
97
(5)
(12)
-
(11)
(2)
(47)
76
10
$
-
-
-
-
-
(48)
-
-
(8)
-
$ (56)
$ (12)
$
2
$ (50)
-
6
(5)
196
103
-
-
-
1
$ 251
$ 135
$
-
$
15
14
1
(5)
-
(113)
-
(108)
(4)
-
$
14
11
1
(5)
-
(112)
-
(108)
(4)
-
$
-
-
-
-
-
35
-
-
(12)
1
$ (200)
$ (203)
$
24
$
$
68
5
$
$
65
5
$ (21)
$
1
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
2008 versus 2007
Ameren
Ameren’s electric margin increased by $153 million, or
4%, in 2008 compared with 2007. The following items had
a favorable impact on Ameren’s electric margin:
‰
‰
‰
‰
‰
‰
‰
‰
Net mark-to-market gains on energy transactions of
$81 million, primarily related to nonqualifying hedges
of changes in market prices for electricity.
Improved Non-rate-regulated Generation plant
availability due to the lack of an extended plant outage
in 2008. Non-rate-regulated 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.
The effect of rate increases. The Ameren Illinois
Utilities’ net electric rate increase, effective October 1,
2008, increased electric margin by $27 million. UE’s
electric rate increase, effective June 4, 2007, increased
electric margin by $16 million.
The reduced impact of the Illinois electric settlement
agreement increased electric margin by $35 million.
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 margin in
2008 of these items was $30 million.
A settlement agreement with a coal mine owner
reached in June 2008, which reimbursed Genco, in the
form of a lump-sum payment, for increased costs for
coal and transportation that it expects to incur in 2009
due to the premature closure of an Illinois mine at the
end of 2007, increased electric margin by $27 million.
Other MISO net purchased power costs decreased by
$23 million.
Lower Non-rate-regulated Generation emission
allowance costs of $8 million.
‰
Increased Non-rate-regulated Generation capacity sales
of $6 million.
The following items had an unfavorable impact on
Ameren’s electric margin for 2008 as compared with 2007:
‰
‰
‰
‰
Net mark-to-market losses on fuel-related transactions
of $75 million, primarily related to 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 electric margin by an estimated $65 million.
Compared to normal weather, cooling degree-days in
2008 were 5% lower.
Fuel prices increased by 6%.
Lower interchange margin due to reduced UE plant
availability, partially offset by an 8% increase in realized
prices and a 10% increase in hydroelectric generation.
Nuclear plant availability was unfavorably affected by
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 gas margin increased by $36 million, or 9%,
in 2008 compared with 2007. The following items had a
favorable impact on Ameren’s gas margin:
‰
‰
Favorable weather conditions, as evidenced by a 13%
increase in heating degree-days, which increased gas
margin by an estimated $12 million. Compared to
normal weather, heating degree-days in 2008 were 7%
higher.
The effect of rate increases. The Ameren Illinois
Utilities’ net gas rate increase, effective October 1,
2008, increased gas margin by $4 million. The UE gas
rate increase, effective April 2007, increased gas
margin by $3 million.
35
‰
‰
‰
A September 2008 ICC rate order that concluded that a
portion of previously expensed nonrecoverable
purchased gas costs should be capitalized, which
increased gas margin by $9 million.
A 2% increase in weather normalized sales volumes
and favorable customer sales mix, which increased gas
margin by $5 million.
Increased transportation revenues of $4 million.
Missouri Regulated
UE
UE’s electric margin decreased $62 million, or 3%, in
2008 compared with 2007. The following items had an
unfavorable impact on UE’s electric margin:
‰
Unfavorable weather conditions, as evidenced by a
29% reduction in cooling degree-days, which
decreased electric margin by an estimated $42 million.
Net mark-to-market losses on fuel-related transactions
of $39 million, primarily related to 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.
Fuel prices increased by 5%.
Lower replacement power insurance recoveries of
$12 million due to the lack of an extended plant outage
and an increase in insurance recovery deductible limits.
Lower interchange margin due to reduced plant
availability, partially offset by an 8% increase in realized
prices and a 10% increase in hydroelectric generation.
Nuclear plant availability was unfavorably affected by
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 that had a favorable impact on
electric margin in 2008 as compared with 2007:
‰
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 electric margin in
2008 of these items was $23 million.
Other MISO net purchased power costs decreased by
$15 million.
UE’s electric rate increase, effective June 4, 2007,
which increased electric margin by $16 million.
Net mark-to-market gains of $8 million, primarily
related to nonqualifying hedges of changes in market
prices for electricity.
‰
‰
‰
‰
‰
‰
‰
UE’s gas margin increased by $8 million, or 11%, in
2008 compared with 2007. The following items had a
favorable impact on gas margin:
36
‰
‰
‰
The UE gas rate increase, effective April 2007, which
increased gas margin by $3 million.
Favorable customer sales mix, which increased gas
margin by $3 million.
Favorable weather conditions, as evidenced by a 12%
increase in heating degree-days, which increased gas
margin by an estimated $2 million.
Illinois Regulated
Illinois Regulated’s electric margin increased by
$58 million, or 8%, and gas margin 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 impact margin; however, the
electric revenues and offsetting purchased power costs
fluctuate due primarily to customer switching and usage.
See below for explanations of electric and gas margin
variances for the Illinois Regulated segment.
CIPS
CIPS’ electric margin increased by $14 million, or 6%,
in 2008 compared with 2007. The following items had a
favorable impact on electric margin:
‰
‰
‰
‰
Reduced MISO purchased power costs of $8 million
due to the absence of the March 2007 FERC order.
Other MISO net purchased power costs decreased by
$5 million.
The reduced impact of the Illinois electric settlement
agreement, which increased electric margin by
$6 million.
The CIPS electric rate increase, effective October 1,
2008, increased electric margin 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
margin by an estimated $6 million.
CIPS’ gas margin increased by $7 million, or 10%, in
2008 compared with 2007. The following items had a
favorable impact on gas margin:
‰
‰
‰
‰
Favorable customer sales mix, which increased gas
margin by $3 million.
Favorable weather conditions, as evidenced by a 12%
increase in heating degree-days, which increased gas
margin by an estimated $2 million.
The CIPS gas rate increase, effective in October 2008,
which increased gas margin by $1 million.
A September 2008 ICC rate order, that concluded that a
portion of previously expensed nonrecoverable
purchased gas costs should be capitalized, which
increased gas margin by $1 million.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s
change in electric margin by segment to CILCO’s total
change in electric margin for 2008 compared with 2007:
CILCO (Illinois Regulated) . . . . . . . . . . . . . . . .
CILCO (AERG) . . . . . . . . . . . . . . . . . . . . . . . . .
Total change in electric margin . . . . . . . . . . . .
$
$
17
12
29
2008 versus 2007
CILCO’s (Illinois Regulated) electric margin increased
by $17 million, or 14%, in 2008 compared with 2007. The
following items had a favorable impact on electric margin:
‰
‰
‰
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.
Reduced MISO purchased power costs of $4 million
due to the absence of the March 2007 FERC order.
The reduced impact of the Illinois electric settlement
agreement, which increased electric margin by
$3 million.
These favorable variances were partially offset by
unfavorable weather conditions, as evidenced by a 28%
reduction in cooling degree-days, which decreased electric
margin by an estimated $4 million.
IP’s gas margin increased by $18 million, or 12%, in
2008 compared with 2007. The following items had a
favorable impact on gas margin:
‰
‰
‰
The IP gas rate increase, effective in October 2008,
which increased gas margin by $8 million.
A September 2008 ICC rate order, that concluded that a
portion of previously expensed nonrecoverable
purchased gas costs should be capitalized, which
increased gas margin by $7 million.
Favorable weather conditions, as evidenced by a 15%
increase in heating degree-days, which increased gas
margin by an estimated $6 million.
These favorable variances were partially offset by a 4%
decrease in normalized sales volumes, which decreased gas
margin $3 million.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin
increased by $151 million, or 15%, in 2008 compared with
2007. Non-rate-regulated 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
margin variances for the Non-rate regulated Generation
segment.
Genco
See Non-rate-regulated Generation below for an
explanation of CILCO’s (AERG) electric margin in 2008
compared with 2007.
Genco’s electric margin increased by $82 million, or
16%, in 2008 compared with 2007. The following items had
a favorable impact on electric margin:
CILCO’s (Illinois Regulated) gas margin was
comparable in 2008 and 2007. Favorable weather
conditions, as evidenced by an 11% increase in heating
degree-days, and improved customer sales mix, increased
gas margins by an estimated $4 million. These favorable
variances were offset by CILCO’s gas rate decrease,
effective in October 2008.
IP
IP’s electric margin increased by $27 million, or 7%, in
2008 compared with 2007. The following items had a
favorable impact on electric margin:
‰
‰
‰
The IP electric rate increase, effective October 1, 2008,
which increased electric margin by $22 million.
Reduced MISO purchased power costs of $12 million
due to the absence of the March 2007 FERC order.
The reduced impact of the Illinois electric settlement
agreement, which increased electric margin by
$7 million.
These favorable variances were partially offset by
unfavorable weather conditions, as evidenced by a 34%
reduction in cooling degree-days, which decreased electric
margin by an estimated $13 million.
‰
‰
‰
‰
‰
‰
‰
A settlement agreement with a coal mine owner
reached in June 2008, which reimbursed Genco, in the
form of a lump-sum payment, for increased costs for
coal and transportation that it expects to incur in 2009
due to the premature closure of an Illinois mine at the
end of 2007, increased electric margin by $27 million.
Increased revenues allocated to Genco under its power
supply agreement (Genco PSA) with Marketing
Company. Revenues from the Genco PSA, which
increased by 7% due primarily to the repricing of
wholesale and retail electric power supply agreements,
and an increase in reimbursable expenses in
accordance with the Genco PSA.
Reduced purchased power costs of $17 million due to
the absence of MISO resettlement costs experienced in
early 2007.
The reduced impact of the Illinois electric settlement
agreement, which increased electric margin by
$13 million.
Gains on the sales of excess oil and off-system natural
gas, which increased electric margin by $12 million.
Higher replacement power insurance recoveries of
$9 million 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.
37
The following items had an unfavorable impact on
EEI
electric margin in 2008 compared with 2007:
‰
‰
‰
‰
‰
Fuel prices increased by 2%.
Net mark-to-market losses on fuel-related transactions
of $18 million, primarily related to 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.
Reduced MISO-related revenues of $12 million 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.
Decreased revenues of $9 million due to 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 Parties to our
financial statements under Part II, Item 8, of this report,
for additional information.
CILCO (AERG)
AERG’s electric margin increased by $12 million, or
7%, in 2008 compared with 2007. The following items had
a favorable impact on electric margin:
‰
‰
Increased revenue allocated to AERG under its power
supply agreement (AERG PSA) with Marketing
Company. Revenues from the AERG PSA increased
24% due primarily to 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 availability factors were
approximately 70% and 77%, respectively, in 2008
compared with 55% and 61%, respectively, in 2007.
The reduced impact of the Illinois electric settlement
agreement increased electric margin by $6 million.
The following items had an unfavorable impact on
electric margin in 2008 compared with 2007:
‰
‰
‰
Fuel prices increased by 30%, 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.
Reduced MISO-related revenues of $4 million due to
the absence of the March 2007 FERC order.
Net mark-to-market losses on fuel-related transactions
of $3 million, primarily related to 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.
38
EEI’s electric margin increased by $10 million, or 4%,
in 2008 compared with 2007, primarily because of an 8%
increase in the average sales price for wholesale power.
The following items had an unfavorable impact on
electric margin:
‰
‰
Fuel prices increased by 9%.
Net mark-to-market losses on fuel-related transactions
of $8 million, primarily related to 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.
Marketing Company
Market price fluctuations during 2008 resulted in
nonaffiliated mark-to-market gains on energy transactions
of $73 million, primarily related to nonqualifying hedges of
changes in market prices for electricity.
2007 versus 2006
Ameren
Ameren’s electric margin increased by $297 million, or
9%, in 2007 compared with 2006. The following items had
a favorable impact on Ameren’s electric margin:
‰
‰
‰
‰ More power sold by Non-rate-regulated Generation at
market-based prices in 2007. These 2007 sales
compared favorably with 2006 sales at below-market
prices, pursuant to cost-based power supply
agreements that expired on December 31, 2006.
Favorable weather conditions, as evidenced by a 19%
increase in cooling degree-days, which increased
electric margin by an estimated $35 million. Compared
to normal weather, cooling degree-days in 2007 were
37% higher.
The UE electric rate increase, effective June 4, 2007,
which increased electric margin by $29 million.
An increase in margin on interchange sales, primarily
because of the termination of the JDA on December 31,
2006. This termination of the JDA provided UE with the
ability to sell its excess power, which was originally
obligated to Genco under the JDA at cost, in the spot
market at higher prices. This increase was reduced by
higher purchased power costs of $12 million
associated with an agreement with Entergy Arkansas,
Inc. See Note 2 – Rate and Regulatory Matters to our
financial statements under Part II, Item 8, of this report,
for more information on the UE power purchase
agreement with Entergy Arkansas, Inc.
A 67% increase in hydroelectric generation because of
improved water levels, which allowed additional
generation to be used for interchange sales and
reduced use of higher-priced energy sources, thereby
increasing Ameren’s electric margin by $27 million.
Increased Non-rate-regulated Generation capacity sales
of $11 million.
‰
‰
‰
‰
Reduced severe storm-related outages in 2007
compared with 2006, which negatively affected electric
sales and resulted in a net reduction in overall electric
margin of $9 million in 2006.
Insurance recoveries of $8 million related to power
purchased to replace Taum Sauk generation. See Note
15 – Commitments and Contingencies to our financial
statements under Part II, Item 8, of this report, for
additional information.
The following items had an unfavorable impact on
Ameren’s electric margin in 2007 as compared with 2006:
‰
‰
‰
‰
‰
‰
‰
The combined effect on the Ameren Illinois Utilities of
the elimination of bundled tariffs, implementation of
new delivery service tariffs effective January 2, 2007,
and the expiration of below-market power supply
contracts.
A 14% increase in fuel prices.
Rate relief and customer assistance programs under
the Illinois electric settlement agreement, which
reduced electric margin by $73 million.
The loss of wholesale margins at Genco from power
acquired through the JDA, which terminated in 2006.
Decreased emission allowance sales of $53 million,
offset by lower emission allowance costs of
$15 million.
Net purchased power costs that were $18 million
higher in 2007 because of a March 2007 FERC order
that resettled costs among market participants
retroactive to 2005.
Reduced plant availability. Ameren’s baseload nuclear
and coal-fired generating plants’ average capacity and
equivalent availability factors were approximately 78%
and 86%, respectively, in 2007 compared with 80%
and 88%, respectively, in 2006.
‰
‰
‰
‰
‰
‰
‰
power costs of $12 million associated with an
agreement with Entergy Arkansas, Inc.
The electric rate increase that went into effect June 4,
2007, which increased electric margin by $29 million.
A 67% increase in hydroelectric generation because of
improved water levels. This allowed additional
generation to be used for interchange sales and
reduced UE’s use of higher priced energy sources,
thereby increasing UE’s electric margin by $27 million.
Favorable weather conditions, as evidenced by a 19%
increase in cooling degree-days, which increased
electric margin by an estimated $22 million.
Replacement power insurance recoveries of
$20 million, including $8 million associated with Taum
Sauk. See Note 15 – Commitments and Contingencies
to our financial statements under Part II, Item 8, of this
report, for additional information.
Increased transmission service revenues of $18 million
due to the ancillary service agreement with CIPS,
CILCO, and IP. See Note 14 – Related Party
Transactions to our financial statements under Part II,
Item 8, of this report, for additional information.
Decreased fuel costs due to the lack of $4 million in
fees levied by FERC in 2006 upon completion of its cost
study for generation benefits provided to UE’s Osage
hydroelectric plant, and the May 2007 MoPSC rate
order, which directed UE to transfer $4 million of the
total fees to an asset account, which is being amortized
over 25 years.
Reduced severe storm-related outages in 2007
compared with 2006, which negatively affected electric
sales that year and resulted in a net reduction in overall
electric margin of $7 million in 2006.
The following items had an unfavorable impact on
electric margin in 2007 as compared with 2006:
Ameren’s gas margin increased by $15 million, or 4%,
in 2007. The following items had a favorable impact on
Ameren’s gas margin:
‰
‰
Fuel prices increased by 21%.
A $29 million reduction in emission allowance
revenues.
‰
‰
Favorable weather conditions, as evidenced by an 8%
increase in heating degree-days, which increased gas
margin by an estimated $10 million. Compared to
normal weather, heating degree-days in 2007 were
10% lower.
The UE gas rate increase that went into effect in April
2007, which increased gas margin by $4 million.
Missouri Regulated
UE
UE’s electric margin increased $76 million, or 4%, in
2007 compared with 2006. The following items had a
favorable impact on UE’s electric margin:
‰
An increase in margin on interchange sales, primarily
because of the termination of the JDA on December 31,
2006. The termination of the JDA allowed UE to sell its
excess power, which was originally obligated to Genco
under the JDA at cost, in the spot market at higher
prices. This increase was reduced by higher purchased
‰ MISO purchased power costs that were $11 million
‰
‰
higher due to the March 2007 FERC order.
Other MISO purchased power costs that were
$20 million higher.
Reduced power plant availability because of planned
maintenance activities. UE’s baseload nuclear and coal-
fired generating plants’ average capacity and equivalent
availability factors were approximately 81% and 89%,
respectively, in 2007 compared with 84% and 90%,
respectively, in 2006.
UE’s gas margin increased by $10 million, or 17%, in
2007 compared with 2006. The following items had a
favorable impact on gas margin:
‰
‰
‰
The UE gas rate increase effective in April 2007, which
increased gas margin by $4 million.
Unrecoverable purchased gas costs totaling $4 million
in 2006 that did not recur in 2007.
Favorable weather conditions, as evidenced by an 8%
increase in heating degree-days, which increased gas
margin by an estimated $2 million.
39
Illinois Regulated
‰
Illinois Regulated’s electric margin decreased by
$65 million, or 8%, and gas margin increased by
$10 million, or 3%, in 2007 compared with 2006. See
below for explanations of electric and gas margin variances
for the Illinois Regulated segment.
CIPS
CIPS’ electric margin decreased by $12 million, or 5%,
‰
in 2007 compared with 2006. The following items had an
unfavorable impact on electric margin:
‰
‰
The combined effect of the elimination of bundled
tariffs, implementation of new delivery service tariffs on
January 2, 2007, and the expiration of below-market
power supply contracts.
The Illinois electric settlement agreement, which
reduced electric margin by $11 million.
‰ MISO purchased power costs that increased by
$8 million because of the March 2007 FERC order.
The following items had a favorable impact on electric
margin in 2007 as compared with 2006:
‰
‰
‰
Other MISO purchased power costs, excluding the
effect of the March 2007 FERC order, that were
$19 million lower, partly because of customers
switching to third-party suppliers and the termination
of the JDA agreement at the end of 2006.
Reduced severe storm-related outages in 2007
compared to those that occurred in 2006, which
negatively affected electric sales and resulted in a net
reduction in overall electric margin of $3 million in
2006.
Favorable weather conditions, as evidenced by a 20%
increase in cooling degree-days, which increased
electric margin by an estimated $6 million.
CIPS’ gas margin was comparable in 2007 and 2006.
CILCO (Illinois Regulated)
The following table provides a reconciliation of CILCO’s
change in electric margin by segment to CILCO’s total
change in electric margin for 2007 compared with 2006:
‰
‰
CILCO (Illinois Regulated) . . . . . . . . . . . . . . . .
CILCO (AERG) . . . . . . . . . . . . . . . . . . . . . . . . .
Total change in electric margin . . . . . . . . . . . .
$ (32)
97
$
65
2007 versus 2006
CILCO’s (Illinois Regulated) electric margin decreased
by $32 million, or 20%, in 2007 compared with 2006. The
following items had an unfavorable impact on electric
margin:
‰
The combined effect of the elimination of bundled
tariffs, implementation of new delivery service tariffs on
January 2, 2007, and the expiration of below-market
power supply contracts.
The Illinois electric settlement agreement, which
reduced electric margin by $7 million.
‰ MISO purchased power costs that increased by
$4 million, because of the March 2007 FERC order.
The following items had a favorable impact on electric
margin in 2007 compared with 2006:
‰
Other MISO purchased power costs, that were
$4 million lower, partly because of customers
switching to third-party suppliers.
Favorable weather conditions, as evidenced by an 18%
increase in cooling degree-days, which increased
electric margin by an estimated $2 million.
See Non-rate-regulated Generation below for an
explanation of CILCO’s (AERG) electric margin in 2007
compared with 2006.
CILCO’s (Illinois Regulated) gas margin increased by
$7 million, or 8%, in 2007 compared with 2006, primarily
because of favorable weather conditions, as evidenced by a
7% increase in heating degree-days, increased industrial
sales, and higher transportation volumes.
IP
IP’s electric margin decreased by $21 million, or 5%,
in 2007 compared with 2006. The following items had an
unfavorable impact on electric margin:
‰
The combined effect of the elimination of bundled
tariffs, implementation of new delivery service tariffs on
January 2, 2007, and the expiration of below-market
power supply contracts.
The Illinois electric settlement agreement, which
reduced electric margin by $14 million.
‰
‰ MISO purchased power costs that increased by
$12 million, because of the March 2007 FERC order.
The following items had a favorable impact on electric
margin in 2007 compared with 2006:
‰
Other MISO purchased power costs, that were
$13 million lower, partly because of customers
switching to third-party suppliers.
Favorable weather conditions, as evidenced by a 21%
increase in cooling degree-days, which increased
electric margin by an estimated $5 million.
Reduced severe storm-related outages in 2007
compared with those that occurred in 2006, which
negatively affected electric sales and resulted in an
estimated net reduction in overall electric margin of
$2 million in 2006.
IP’s gas margin was comparable in 2007 and 2006.
Non-rate-regulated Generation
Non-rate-regulated Generation’s electric margin
increased by $281 million, or 37%, in 2007 compared with
2006. Non-rate-regulated Generation’s baseload coal-fired
generating plants’ average capacity and equivalent
availability factors were approximately 74% and 81%,
respectively, in 2007 compared with 74% and 84%,
respectively, in 2006. See below for explanations of electric
margin variances for the Non-rate-regulated Generation
segment.
40
Genco
EEI
Genco’s electric margin increased by $135 million, or
36%, in 2007 compared with 2006. The following items had
a favorable impact on electric margin:
EEI’s electric margin decreased by $8 million, or 3%,
in 2007 compared with 2006. The following items had an
unfavorable impact on electric margin:
‰
‰
‰
Selling power at market-based prices in 2007,
compared with selling power at below-market prices in
2006, pursuant to a cost-based power supply
agreement that expired on December 31, 2006.
Reduced purchased power costs due to the termination
of the JDA.
Increased power plant availability, due to fewer planned
outages in 2007, that reduced purchased power costs.
Genco’s baseload coal-fired generating plants’ average
capacity and equivalent availability factors were
approximately 75% and 86%, respectively, in 2007,
compared with 66% and 82%, respectively, in 2006.
‰ MISO-related revenues that were $12 million higher as
‰
‰
a result of the March 2007 FERC order.
Other MISO purchased power costs that were
$16 million lower.
A reduction of mark-to-market losses on fuel contracts
of $6 million.
The following items had an unfavorable impact on
electric margin in 2007 compared with 2006:
‰
‰
‰
The loss of wholesale margins on sales of power
acquired through the JDA, which terminated in 2006.
Costs of $30 million pursuant to the Illinois electric
settlement agreement.
Fuel prices increased by 4%.
CILCO (AERG)
AERG’s electric margin increased by $97 million, or
87%, in 2007 compared with 2006. The following items had
a favorable impact on electric margin:
‰
Increased revenues due to selling power at market-
based prices in 2007 compared with below-market
prices in 2006, pursuant to a cost-based power supply
agreement that expired on December 31, 2006.
Lower emission allowance costs of $11 million due to
an increase in low sulfur coal consumption in 2007.
‰ MISO-related revenues that were $4 million higher as a
‰
‰
‰
result of the March 2007 FERC order.
Other MISO purchased power costs that were
$7 million lower.
Replacement power insurance recoveries of $7 million
due to an extended plant outage.
The following items had an unfavorable impact on
electric margin in 2007 compared with 2006:
‰
‰
‰
Costs of $13 million pursuant to the Illinois electric
settlement agreement.
Reduced plant availability because of an extended plant
outage. AERG’s baseload coal-fired generating plants’
average capacity and equivalent availability factors were
approximately 55% and 61%, respectively, in 2007,
compared with 69% and 81%, respectively, in 2006.
Fuel prices increased by 5%.
41
‰
‰
‰
The lack of emissions allowance sales in 2007, which
increased 2006 electric margin by $30 million.
Fuel prices increased by 5%.
Reduced plant availability related to increased unit
outages. EEI’s baseload coal-fired generating plant’s
average capacity and equivalent availability factors were
each approximately 92% in 2007, compared with 95%
in 2006.
The decrease in margin was offset by a 12% increase
in market prices at EEI in 2007.
Other Operations and Maintenance Expenses
2008 versus 2007
Ameren
Ameren’s other operations and maintenance expenses
increased $170 million in 2008 compared with 2007,
primarily because of higher distribution system reliability
expenditures of $30 million, increased plant maintenance
expenditures at coal-fired plants of $43 million due to
outages, higher labor costs of $52 million, increased
information technology costs of $10 million, and unrealized
net mark-to-market adjustments of $22 million resulting
from the lower market value of investments used to support
Ameren’s deferred compensation plans. Bad debt expense
also increased $10 million, primarily because of the
continued 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, with no similar
item in 2008.
In addition, other operations and maintenance
expenses 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 is 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 were
lower employee benefit costs of $10 million due to changes
in actuarial estimates and reduced storm expenditures of
$18 million, primarily in UE’s service territory, in 2008
compared with 2007. 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 the current year by a MoPSC accounting
order received in the second quarter of 2008, which
resulted in UE recording a regulatory asset for $25 million
of costs related to 2007 storms that had previously been
expensed.
Variations in other operations and maintenance
expenses in Ameren’s, CILCORP’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
increased $22 million in 2008, as compared with 2007,
primarily because of increased distribution system reliability
expenditures of $16 million, higher labor costs of
$37 million, increased plant maintenance expenditures at
coal-fired plants of $29 million, and unrealized net
mark-to-market adjustments resulting from the lower
market value of investments used to support deferred
compensation plans. Reducing the impact of these items
was 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
refueling and maintenance outage in 2008 compared with
the refueling in 2007. Storm repair expenditures also
decreased by $31 million in 2008 compared with 2007,
further reducing other operations and maintenance
expenses.
Illinois Regulated
Other operations and maintenance expenses increased
$77 million in the Illinois Regulated segment in 2008,
compared with 2007.
CIPS
Other operations and maintenance expenses increased
$24 million in 2008 compared with 2007. The increase was
primarily because of higher distribution system reliability
expenditures of $11 million, including storm costs, along
with increased labor costs and bad debt expense.
Additionally, the reversal in the first quarter of 2007 of an
accrual of $4 million, established in 2006, for contributions
to assist customers through the Illinois Customer Elect
electric rate increase phase-in plan, with no similar item in
2008, resulted in higher other operations and maintenance
expenses in 2008 compared with 2007.
CILCO (Illinois Regulated)
Other operations and maintenance expenses increased
$8 million in 2008, as compared with 2007, primarily
because of increased storm costs of $5 million in 2008.
Additionally, in the first quarter of 2007, CILCO (Illinois
Regulated) reversed a $3 million accrual established in
2006 for the Illinois Customer Elect electric rate increase
phase-in plan contributions, with 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 in 2008, as compared with 2007, primarily
because of higher distribution system reliability
expenditures of $17 million, including storm costs. Labor
costs and bad debt expense increased by $6 million each,
and unrealized net mark-to-market adjustments resulting
from the lower market value of investments used to support
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, with no similar item in 2008. Reducing the
unfavorable effect of these items was a reduction in
employee benefit costs.
Non-rate-regulated Generation
Other operations and maintenance expenses increased
$43 million in the Non-rate-regulated Generation segment in
2008 compared with 2007.
Genco
Other operations and maintenance expenses increased
$12 million at Genco in 2008, as compared with 2007,
primarily because of higher plant maintenance costs of
$9 million, due to scheduled outages, and increased labor
costs of $5 million. Genco paid $3 million to the IPA in the
prior year as part of the Illinois electric settlement
agreement, with no similar item in 2008, reducing other
operations and maintenance expenses between 2008 and
2007.
CILCO (AERG)
Other operations and maintenance expenses increased
$25 million at CILCO (AERG) in 2008, as compared with
2007, primarily because of a $12 million impairment charge
recorded in 2008 related to the Indian Trails cogeneration
plant as discussed above, higher plant maintenance costs of
$7 million due to scheduled outages, and increased labor
costs of $3 million. CILCO (AERG) paid $1.5 million to the
IPA in 2007 as part of the Illinois electric settlement
agreement, with no similar item in 2008, reducing other
operations and maintenance expenses between 2008 and
2007.
CILCORP (parent company only)
Other operations and maintenance expenses increased
$3 million in 2008, as compared with 2007, primarily
because of an asset impairment charge recorded in 2008
related to the Sterling Avenue CT discussed above.
42
EEI
Other operations and maintenance expenses were
comparable in 2008 and 2007.
2007 versus 2006
Ameren
Ameren’s other operations and maintenance expenses
increased $131 million in 2007 compared with 2006.
Maintenance and labor costs associated with the Callaway
nuclear plant refueling and maintenance outage in the
second quarter of 2007 added $35 million. Distribution
system reliability expenditures increased $49 million and
employee benefits and non-Callaway labor costs were
higher by $55 million in 2007 compared with 2006. Bad
debt expenses increased $25 million in 2007, primarily as a
result of the transition to higher electric rates in Illinois.
Increases in maintenance at coal-fired power plants and
injuries and damages reserves also contributed to higher
other operations and maintenance expenses in 2007. We
recognized reduced gains on sales of noncore property in
2007 of $4 million, compared with gains of $16 million in
2006. Additionally, other operations and maintenance
expenses in 2007 included a payment of $4.5 million made
to the IPA as part of the Illinois electric settlement
agreement.
Reducing the effect of these items was the reversal in
2007 of an accrual of $15 million established in 2006 for
contributions to assist customers through the Illinois
Customer Elect electric rate increase phase-in plan. In 2006,
we also recognized costs of $25 million related to the
December 2005 Taum Sauk plant reservoir breach. Costs
associated with storms in the spring and summer of 2006
and a major ice storm in the fourth quarter of 2006
exceeded the costs associated with an ice storm in January
2007 by $42 million, thereby reducing other operations and
maintenance expenses in 2007 compared with 2006.
Variations in other operations and maintenance
expenses for the Ameren, CILCORP and CILCO business
segments and for the Ameren Companies between 2007
and 2006 were as follows.
Missouri Regulated
UE
Other operations and maintenance expenses increased
in 2007 compared with 2006. Maintenance and labor costs
associated with the Callaway nuclear plant refueling and
maintenance outage in 2007 added $35 million to other
operations and maintenance expenses compared with 2006.
Higher distribution system reliability expenditures of
$34 million, increased non-Callaway-related labor costs of
$22 million, and insurance premiums of $19 million for
replacement power coverage paid to a risk insurance
affiliate also increased other operations and maintenance
expenses in 2007 compared with 2006. Reducing the effect
of these items was the absence in 2007 of costs recorded in
2006 related to the Taum Sauk plant reservoir breach
discussed above. Costs associated with storms in the
spring and summer of 2006 and a major ice storm in the
fourth quarter of 2006 exceeded the costs associated with
an ice storm in January 2007 by $13 million, thereby
reducing other operations and maintenance expenses in
2007 compared with 2006.
Illinois Regulated
Other operations and maintenance expenses increased
$15 million in the Illinois Regulated segment in 2007
compared with 2006.
CIPS
Other operations and maintenance expenses increased
$11 million in 2007 compared with 2006, primarily because
of increased bad debt expenses, higher distribution system
reliability expenditures, and increased injuries and damages
reserves. The reversal in 2007 of the Illinois Customer Elect
electric rate increase phase-in plan accrual of $4 million
established in 2006 reduced the effect of these increases.
Costs associated with storms in the spring and summer of
2006 and a major ice storm in the fourth quarter of 2006
were comparable with the costs associated with an ice
storm in January 2007.
CILCO (Illinois Regulated)
Other operations and maintenance expenses were
comparable between 2007 and 2006, as an increase in bad
debt expenses was offset by the reversal of the Illinois
Customer Elect electric rate increase phase-in plan accrual
of $3 million established in 2006. Costs associated with
storms had a minimal impact on CILCO (Illinois Regulated)
other operations and maintenance expenses each year.
IP
IP’s other operations and maintenance expenses were
comparable between 2007 and 2006. Higher employee
benefit costs increased other operations and maintenance
expenses in 2007. Bad debt expenses increased $10 million
in 2007, primarily as a result of the transition to higher
electric rates in Illinois. Offsetting the effect of these items
was the reversal in 2007 of the Illinois Customer Elect
electric rate increase phase-in plan accrual of $8 million
established in 2006 and a reduction of $24 million in storm
repair costs between years.
Non-rate-regulated Generation
Other operations and maintenance expenses increased
$30 million in the Non-rate-regulated Generation segment in
2007 compared with 2006.
Genco
Genco’s other operations and maintenance expenses
increased $10 million in 2007 compared with 2006,
primarily because of higher labor costs, the IPA payment of
$3 million, and insurance premiums for replacement power
coverage paid to a risk insurance affiliate.
43
CILCORP (parent company only)
Other operations and maintenance expenses were
comparable between 2007 and 2006. Increased employee
benefit costs in 2007 were offset by the absence in 2007 of
a write-off in 2006, of an intangible asset established in
conjunction with Ameren’s acquisition of CILCORP.
CILCO (AERG)
Other operations and maintenance expenses increased
$11 million in 2007 compared with 2006, primarily because
of higher power plant maintenance costs due to plant
outages and the IPA payment of $1.5 million.
EEI
Other operations and maintenance expenses increased
$3 million in 2007 compared with 2006, primarily because
of higher power plant maintenance costs.
Depreciation and Amortization
2008 versus 2007
Ameren
Ameren’s depreciation and amortization expenses were
comparable between periods. Increases in depreciation
expense resulting from capital additions during the past
year 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, CILCORP’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 in 2008, compared with 2007, 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 over the past year.
Illinois Regulated
Depreciation and amortization expenses were
comparable in 2008 and 2007 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, which resulted in an increase in depreciation expense
at IP and reductions in depreciation expense at CIPS and
CILCO (Illinois Regulated). The effects of these changes in
useful lives were partially offset by capital additions at CIPS
and CILCO (Illinois Regulated). IP’s depreciation and
amortization expenses increased due to the effect of the rate
order and capital additions.
Non-rate-regulated Generation
Depreciation and amortization expenses increased
$4 million in the Non-rate-regulated Generation segment in
2008 compared with 2007. Depreciation and amortization
expenses increased $8 million at CILCO (AERG) because of
capital additions over the past year. Depreciation and
amortization expenses decreased $4 million at Genco,
primarily as a result of a depreciation study completed in
September 2007, which was mitigated by capital additions.
2007 versus 2006
Ameren
Ameren’s depreciation and amortization expenses
increased $20 million in 2007 over 2006. The increases
were primarily because of amortization of a regulatory asset
in 2007 at IP, as discussed below, and capital additions in
2006 and 2007. A decrease in depreciation expense as a
result of the MoPSC electric rate order effective in June
2007, discussed above, somewhat mitigated that effect.
Variations in depreciation and amortization expenses
for the Ameren, CILCORP and CILCO business segments
and for the Ameren Companies between 2007 and 2006
were as follows.
Missouri Regulated
UE
Depreciation and amortization expenses in 2007 were
comparable with 2006. Increased expenses associated with
capital additions in 2006 and 2007 were offset by a
reduction in depreciation as a result of the MoPSC electric
rate order, effective June 2007, discussed above.
Illinois Regulated
Depreciation and amortization expenses increased
$25 million in the Illinois Regulated segment in 2007
compared with 2006.
CIPS & CILCO (Illinois Regulated)
Depreciation and amortization expenses were
comparable between 2007 and 2006.
IP
Depreciation and amortization expenses, including
amortization of regulatory assets on IP’s statement of
income, increased $19 million in 2007 compared with 2006,
primarily because of the start of amortization in 2007 of a
regulatory asset associated with acquisition integration
costs, as required by an ICC order, and capital additions.
Non-rate-regulated Generation
Depreciation and amortization expenses were
comparable between 2007 and 2006 in the Non-rate-
regulated Generation segment and for Genco, CILCORP
(parent company only), CILCO (AERG) and EEI.
44
Taxes Other Than Income Taxes
Illinois Regulated
2008 versus 2007
Ameren
Ameren’s taxes other than income taxes increased
$12 million in 2008 compared with 2007, 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, CILCORP’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 in 2008 compared with 2007, primarily because
of higher property taxes.
Illinois Regulated
Taxes other than income taxes increased $5 million in
2008 compared with 2007 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.
Non-rate-regulated Generation
Taxes other than income taxes were comparable
between 2008 and 2007 in the Non-rate-regulated
Generation segment and for Genco, CILCORP (parent
company only), CILCO (AERG) and EEI.
2007 versus 2006
Ameren
Ameren’s taxes other than income taxes decreased
$10 million in 2007 compared with 2006, primarily because
of lower gross receipts and property taxes.
Variations in taxes other than income taxes for the
Ameren, CILCORP and CILCO business segments and for
the Ameren Companies between 2007 and 2006 were as
follows.
Missouri Regulated
UE
Taxes other than income taxes increased $4 million in
2007 over 2006, primarily because of increased gross
receipts taxes.
Taxes other than income taxes decreased $16 million
in 2007 compared with 2006 in the Illinois Regulated
segment. Taxes other than income taxes decreased
$7 million at CIPS, $2 million at CILCO (Illinois Regulated),
and $7 million at IP in 2007 compared with 2006, primarily
as a result of reduced property taxes and excise taxes.
Non-rate-regulated Generation
Taxes other than income taxes were comparable
between 2007 and 2006 for the Non-rate-regulated
Generation segment and for Genco, CILCORP (parent
company only), CILCO (AERG), and EEI.
Other Income and Expenses
2008 versus 2007
Ameren
Miscellaneous income increased $5 million in 2008
compared with 2007, primarily because of an increase at UE
in allowance for funds used during construction, reduced
by lower interest income. Miscellaneous expense increased
$6 million in 2008 compared with 2007, primarily because
of increased expenses associated with contributions to
social programs.
Variations in other income and expenses in Ameren’s,
CILCORP’s and CILCO’s business segments and for the
Ameren Companies between 2008 and 2007 were as
follows.
Missouri Regulated
UE
Miscellaneous income increased $24 million in 2008
compared with 2007, primarily because of an increase in
allowance for funds used during construction. The increase
in allowance for funds used during construction resulted
from higher rates and increased construction-in-progress
balances. Miscellaneous expenses were comparable in 2008
and 2007.
Illinois Regulated
Other income and expenses decreased $9 million in
2008 in the Illinois Regulated segment and at CIPS, CILCO
(Illinois Regulated) and IP, compared with 2007, primarily
because of lower interest income.
Non-rate-regulated Generation
Other income and expenses in the Non-rate-regulated
Generation segment and at Genco, CILCORP (parent
company only), CILCO (AERG) and EEI were comparable
between 2008 and 2007.
45
2007 versus 2006
Ameren
Missouri Regulated
UE
Miscellaneous income increased $25 million in 2007
compared with 2006, primarily because of increased
interest and investment income. Cash balances were higher
because of uncertainty regarding the ultimate resolution of
legislative and regulatory issues in Illinois. Miscellaneous
expense increased $6 million in 2007 compared with 2006,
primarily because we made contributions to our charitable
trust and because Illinois Regulated made contributions of
$5 million for energy efficiency and customer assistance
programs as part of the Illinois electric settlement
agreement. See Note 2 – Rate and Regulatory Matters to
our financial statements under Part II, Item 8, of this report.
Variations in other income and expenses for the
Ameren, CILCORP and CILCO business segments and for
the Ameren Companies between 2007 and 2006 were as
follows.
Missouri Regulated
UE
Other income and expenses were comparable in 2007
and 2006.
Illinois Regulated
Other income and expenses increased $7 million in the
Illinois Regulated segment in 2007 compared with 2006,
primarily because of increased interest income at IP. Other
income and expenses were comparable between years at
CIPS and CILCO (Illinois Regulated).
Interest expense was comparable in 2008 and 2007.
Interest expense 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 due to the long-term debt financings. Senior
secured notes were issued to refinance auction-rate
environmental improvement revenue refunding bonds, to
fund the maturity of $148 million of first mortgage bonds,
and to reduce short-term borrowings. Additionally, interest
expense was reduced by $8 million resulting from the
income tax settlements noted above.
Illinois Regulated
Interest expense increased $12 million in the Illinois
Regulated segment in 2008 compared with 2007.
CIPS
Interest expense decreased $7 million in 2008
compared with 2007, primarily because of reduced short-
term borrowings. Additionally, interest expense was
reduced by $3 million as a result of an income tax
settlement.
CILCO (Illinois Regulated)
Interest expense was comparable in 2008 and 2007.
Non-rate-regulated Generation
IP
Other income and expenses were comparable between
2007 and 2006 in the Non-rate-regulated Generation
segment and for Genco, CILCORP (parent company only),
CILCO (AERG), and EEI.
Interest
2008 versus 2007
Ameren
Interest expense increased $17 million in 2008
compared with 2007. 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. See Insured Auction-Rate
Tax-exempt Bonds under Part II, Item 7A. Quantitative and
Qualitative Disclosures About Market Risk of this report for
additional information. These increases were reduced as a
result of income tax settlements in 2008.
Variations in interest expense in Ameren’s, CILCORP’s
and CILCO’s business segments and for the Ameren
Companies between 2008 and 2007 were as follows.
Interest expense increased $22 million in 2008
compared with 2007, 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 the other
debt issuances were used to reduce short-term borrowings.
Non-rate-regulated Generation
Interest expense decreased $8 million in the Non-rate-
regulated Generation segment in 2008 compared with 2007.
Genco
Interest expense was comparable in 2008 and 2007.
Increased interest expense resulting from the issuance of
$300 million of senior unsecured notes in April 2008 was
mitigated by a resulting reduction in short-term borrowings.
Additionally, interest expense was reduced by $3 million as
a result of an income tax settlement.
46
CILCORP (parent company only) and CILCO (AERG)
Non-rate-regulated Generation
Interest expense decreased $3 million at CILCORP
(parent company only) and $4 million at CILCO (AERG), in
2008 compared with 2007, primarily because of reduced
short-term borrowings.
EEI
Interest expense was comparable in 2008 and 2007.
2007 versus 2006
Ameren
Interest expense increased $73 million in 2007
compared with 2006, primarily because of increased short-
term borrowings, higher interest rates due to reduced credit
ratings, and other items noted below. With the adoption of
FIN 48 in 2007, we also began to record interest associated
with uncertain tax positions as interest expense rather than
income tax expense. These interest charges were
$10 million for 2007. Reducing the effect of the above
unfavorable items were maturities of $350 million of long-
term debt in the first half of 2007 at Ameren and
redemptions/maturities at the Ameren Companies as noted
below.
Variations in interest expense for Ameren’s, CILCORP’s
and CILCO’s business segments and for the Ameren
Companies between 2007 and 2006 were as follows.
Missouri Regulated
UE
Interest expense increased $23 million in 2007 over
2006, primarily because of increased short-term
borrowings, higher interest rates due to reduced credit
ratings, and the issuance of $425 million of senior secured
notes in June 2007. Interest expense recorded in
conjunction with uncertain tax positions was $3 million in
2007.
Illinois Regulated
Interest expense increased $37 million in the Illinois
Regulated segment and increased at CIPS and IP in 2007
compared with 2006, primarily because of increased short-
term borrowings and higher interest rates due to reduced
credit ratings and the issuance of senior secured notes in
2007 and 2006. IP issued $250 million and $75 million of
senior secured notes in November 2007 and June 2006,
respectively. CIPS and CILCO (Illinois Regulated) issued
$61 million and $96 million of senior secured notes,
respectively, in June 2006. Reducing the effect of the above
items was the maturity of $50 million of first mortgage
bonds at CILCO (Illinois Regulated) in January 2007 and
payments made on IP’s note payable to IP SPT in 2007 and
2006.
Interest expense increased $4 million in the Non-rate-
regulated Generation segment in 2007 compared with 2006.
CILCORP (parent company only) and CILCO (AERG)
Interest expense increased $3 million at CILCORP
(parent company only) and $5 million at CILCO (AERG) in
2007 over 2006, primarily because of increased short-term
borrowings and higher interest rates due to reduced credit
ratings.
Genco
Interest expense decreased $5 million in 2007
compared with 2006, primarily because of reduced
intercompany borrowings. Reducing this benefit was
increased interest expense of $3 million recorded in
conjunction with uncertain tax positions in 2007.
EEI
Interest expense was comparable in 2007 and 2006.
Income Taxes
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,
CILCORP’s and CILCO’s business segments and for the
Ameren Companies between 2008 and 2007 were as
follows.
Missouri Regulated
UE
The effective tax rate increased in 2008 from 2007,
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 in 2008 compared with 2007, because
of the items detailed below.
CIPS
The effective tax rate decreased in 2008 from 2007,
primarily because of the impact of net amortization of
property-related regulatory assets and liabilities and
permanent items on lower pretax income in 2008.
47
CILCO (Illinois Regulated)
Missouri Regulated
The effective tax rate for 2008 was higher than the
UE
effective tax rate for 2007, primarily because of lower tax
credits, lower favorable net amortization of property-related
regulatory asset and liabilities, and lower favorable
permanent benefits related to company-owned life
insurance.
IP
The effective tax rate for 2008 was higher than the
effective tax rate for 2007, 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.
Non-rate-regulated Generation
The effective tax rate decreased in 2007 from 2006,
primarily because of the implementation of changes ordered
by the MoPSC in UE’s 2007 electric rate order. These
changes decreased the unfavorable effect of the net
amortization of property-related regulatory assets and
liabilities in 2007 compared to 2006, decreased reserves for
uncertain tax positions in 2007 compared to increases in
2006, and increased Internal Revenue Code Section 199
production activity deductions in 2007 compared with
2006.
Illinois Regulated
The effective tax rate decreased in the Illinois
Regulated segment in 2007 compared with 2006, because
of the items detailed below.
The effective tax rate decreased in 2008 compared with
CIPS
2007 in the Non-rate-regulated Generation segment,
because of the items detailed below.
Genco
The effective tax rate decreased in 2008 from 2007,
primarily because of the increased impact of Internal
Revenue Code Section 199 production activity deductions
and research tax credits.
CILCO (AERG)
The effective tax rate increased in 2008 compared with
2007, primarily because of the impact of Internal Revenue
Code Section 199 production activity deductions.
CILCORP (parent company only)
The effective tax rate increased in 2008 compared with
2007, primarily because of the effect of state audit
settlements.
EEI
The effective tax rate increased, primarily because of
higher reserves for uncertain tax positions in 2007
compared to 2006, the unfavorable effect of the net
amortization of property-related regulatory assets and
liabilities in 2007 compared to favorable net amortization of
property-related regulatory assets and liabilities in 2006,
lower permanent benefit for SFAS No. 106-2, as it relates to
Medicare Part D provisions, and other miscellaneous items,
offset by the increased impact of the amortization of
investment tax credit, and other items on lower pretax book
income.
CILCO (Illinois Regulated)
The effective tax rate decreased, primarily because of
an increase in the permanent benefit for SFAS No. 106-2, as
it relates to Medicare Part D provisions, along with an
increase in the favorable effect of the net amortization of
property-related regulatory assets and liabilities, and
increased impact of the amortization of investment tax
credit on lower pretax book income.
The effective tax rate was comparable in 2008 and
IP
2007.
2007 versus 2006
Ameren
Ameren’s effective tax rate increased between 2007
and 2006.
Variations in effective tax rates for Ameren’s,
CILCORP’s and CILCO’s business segments and for the
Ameren Companies between 2007 and 2006 were as
follows.
The effective tax rate decreased, primarily because of
the favorable effect of the net amortization of property-
related regulatory assets and liabilities in 2007 compared to
unfavorable net amortization of property-related regulatory
assets and liabilities in 2006.
Non-rate-regulated Generation
The effective tax rate increased in the Non-rate-
regulated Generation segment in 2007 compared with 2006,
because of the items detailed below.
Genco
The effective tax rate increased, primarily because of
lower decreases in reserves for uncertain tax positions in
48
2007 compared to 2006, and decreased Internal Revenue
Code Section 199 production activity deductions in 2007
compared to 2006.
CILCO (AERG)
CILCORP (parent company only)
The effective tax rate decreased, primarily because of a
change in the permanent benefit for SFAS No. 106-2, as it
relates to Medicare Part D provisions.
The effective tax rate increased in 2007, primarily
EEI
because of higher reserves for uncertain tax positions in
2007 compared to 2006 and decreased impact of
amortization of investment tax credit on higher pretax book
income, offset by increased Internal Revenue Code
Section 199 production activity deductions in 2007
compared to 2006, and differences between the book and
tax treatment of the sales of noncore properties in 2006.
LIQUIDITY AND CAPITAL RESOURCES
The effective tax rate decreased, primarily because of
increased 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 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 the September 2006 Illinois power procurement auction, financial contracts that were part of the Illinois electric
settlement agreement, and the 2008 Illinois RFP process for energy and capacity that was used pursuant to the Illinois electric
settlement agreement. Marketing Company is also selling 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 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, 2008, for Ameren, UE, Genco,
CILCORP, CILCO, and IP. The Ameren Companies may reduce their 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 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, containing approximately 50% to 55% equity. Consequently, we expect to
make equity issuances in the future consistent with this objective, as well as to address any unanticipated events, should the
need arise. We plan to implement our long-term financing plans for debt, equity or equity-linked securities in order to
appropriately finance our operations, meet scheduled debt maturities and maintain financial strength and flexibility.
The global capital and credit markets experienced extreme volatility and disruption in 2008, and continue to experience
volatility and disruption in 2009. See Outlook for a discussion of the implications of this volatility and disruption for the
Ameren Companies and our plans to address these issues.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years
ended December 31, 2008, 2007 and 2006:
Net Cash Provided By
Operating Activities
Net Cash (Used In)
Investing Activities
Net Cash Provided By
(Used In)
Financing Activities
2008
2007
2006
2008
2007
2006
2008
2007
2006
Ameren(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,533
545
103
244
184
209
180
$ 1,102
588
14
255
32
74
28
$ 1,279
734
118
138
133
153
172
$ (2,097) $ (1,468) $ (1,266) $ 301
303
(72)
84
128
102
97
(1,033)
(57)
(328)
(318)
(317)
(233)
(732)
(66)
(110)
(90)
(161)
(180)
(700)
(42)
(210)
(213)
(212)
(180)
$ 584
296
48
(44)
183
141
158
$ 28
(21)
(46)
(27)
(42)
9
8
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
49
Cash Flows from Operating Activities
2008 versus 2007
Ameren’s cash from operating activities increased in
2008, compared to 2007, primarily because of higher
electric and gas margins as discussed above, 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 to 2007
because of the timing of cash receipts for MISO receivables.
The 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 to our financial statements under Part II, Item 8, of
this report for a discussion of the 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 expects to incur in 2009 due to the premature
closure of an Illinois mine at the end of 2007. See Note 1 –
Summary of Significant Accounting Policies to our Financial
Statements 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
companies, an increase in 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 to 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 Illinois electric settlement agreement also had
a positive effect on cash from operations in 2008 compared
to 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 Illinois electric settlement
agreement compared with 2007. Partially offsetting the
favorable variance in cash flow from operations was a larger
increase in gas inventories during 2008 compared with
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 Illinois
electric settlement agreement in 2008 compared with 2007.
Cash from operating activities increased for CILCORP
and CILCO in 2008 compared to 2007. The increase was
primarily due to net income tax refunds of $33 million and
$15 million in 2008 compared with net income tax
payments of $16 million and $35 million in 2007 at
CILCORP and CILCO, respectively, 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 potential
settlement agreement, and deterioration of collections.
However, collections improved in 2008. The Illinois electric
settlement agreement also had a positive effect on cash
from operations in 2008 compared with 2007. The cash
outflows from the settlement, including AERG’s obligation,
were $16 million lower in 2008 than in 2007. CILCORP
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 Illinois electric settlement agreement
50
compared with 2007. Partially offsetting these increases in
cash from operations were a larger increase in gas
inventories during 2008 compared with 2007, as both price
and volumes increased, and higher levels of collateral, net,
posted with suppliers. Additionally, CILCORP’s operating
cash flows in 2008 were reduced by $22 million compared
with 2007 due to higher interest payments.
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 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 Illinois electric
settlement agreement also had a positive effect on cash
from operations in 2008 compared to 2007. IP cash
outflows from 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 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 was a
$10 million increase in interest payments and higher net
levels of collateral posted with suppliers in 2008.
2007 versus 2006
Ameren’s cash from operating activities decreased in
2007, as compared with 2006. This was primarily because
of an increase in working capital investment as the
collection of higher electric rates from Illinois electric
customers lagged payments for power purchases, and
past-due accounts increased because of the higher rates.
The Illinois electric settlement agreement resulted in a 2007
net cash outflow of $88 million: $211 million of customer
refunds, credits, and program funding, minus related
reimbursements from nonaffiliated Illinois generators of
$123 million. An additional payment of $4.5 million was
made to fund the IPA. As of the end of 2007, $34 million
was due from nonaffiliated generators. See Note 2 – Rate
and Regulatory Matters to our financial statements under
Part II, Item 8, of this report for a discussion of the Illinois
electric settlement agreement. Other factors also reduced
cash flow: increased interest payments as a result of lower
credit ratings and increased debt. In addition, cash spent for
fuel inventory increased because UE increased its inventory,
and AERG experienced increased inventory as a result of an
extended plant outage. Also reducing operating cash flows
was a $25 million increase in pension and postretirement
benefit contributions. In 2007, a $120 million decrease in
income taxes paid (net of refunds) benefited cash flows
from operations in 2007. Increases in electric and gas
margins of $296 million and $15 million, respectively, also
benefited operating cash flows, but were reduced by higher
operations and maintenance expenses, as discussed in
Results of Operations.
At UE, cash from operating activities decreased in
2007, compared with 2006, primarily because of an
increase in accounts receivable caused by higher prices for
interchange power sales, colder weather in December 2007
than in December 2006, and increased electric rates.
Further reducing cash flows in 2007, was an increase in
interest payments and other operations and maintenance
expenditures, including $35 million for the Callaway nuclear
plant refueling and maintenance outage. In addition, UE
increased its fuel inventory. Compared with 2006, cash
flows from operations in 2007 benefited from an increase in
margin, as discussed in Results of Operations, a decrease
in cash paid for Taum Sauk incident-related costs (net of
insurance recoveries) of $6 million, and a decrease in
income tax payments (net of refunds) of $79 million.
At CIPS, cash from operating activities decreased in
2007, compared with 2006. The Illinois electric settlement
agreement resulted in a 2007 net cash outflow of
$19 million, including $74 million of customer refunds,
credits, and program funding, and related reimbursements
from nonaffiliated Illinois generators of $55 million. As of
the end of 2007, $13 million was due from nonaffiliated
generators. See Note 2 – Rate and Regulatory Matters to
our financial statements under Part II, Item 8, of this report
for a complete discussion of the Illinois electric settlement
agreement. Cash from operations was further reduced by a
decrease in electric margins and higher expenses, as
discussed in Results of Operations. In addition, there was
an increase in working capital investment, as the collection
of higher electric rates from customers lagged payments for
power purchases, and past-due customer accounts
increased because of higher rates. Income tax payments
(net of refunds) decreased $18 million, benefiting cash
flows from operations.
Genco’s cash from operating activities increased in
2007 compared with 2006, primarily because electric
margins increased, as discussed in Results of Operations,
and because cash spent for fuel inventory decreased. In
2006, large cash outlays were made to replenish coal
inventory after delivery disruptions caused by train
derailments. Reducing these increases in cash from
operating activities was an increase in income tax payments
(net of refunds) of $41 million.
Cash from operating activities decreased for CILCORP
and CILCO in 2007, compared with 2006. The Illinois
electric settlement agreement resulted in a 2007 net cash
outflow of $12 million: $41 million of customer refunds,
credits, and program funding, minus related
reimbursements from nonaffiliated Illinois generators of
$29 million. As of the end of 2007, $7 million was due from
nonaffiliated generators. See Note 2 – Rate and Regulatory
Matters to our financial statements under Part II, Item 8, of
51
this report for a complete discussion of the Illinois electric
settlement agreement. Working capital investment
increased because the collection of higher electric rates
from customers lagged payments for power purchases,
past-due customer accounts increased due to higher rates,
and inventory levels increased at AERG due to an extended
plant outage. In addition, income tax payments (net of
refunds) increased $20 million for CILCORP and $18 million
for CILCO. Increased electric and gas margins, as discussed
in Results of Operations, benefited cash flows from
operating activities.
IP’s cash from operating activities decreased in 2007,
compared with 2006. The Illinois electric settlement
agreement resulted in a 2007 net cash outflow of
$24 million: $96 million of customer refunds, credits, and
program funding, minus related reimbursements from
nonaffiliated Illinois generators of $72 million. As of the end
of 2007, $14 million was due from nonaffiliated generators.
See Note 2 – Rate and Regulatory Matters to our financial
statements under Part II, Item 8, of this report for a
complete discussion of the Illinois electric settlement
agreement. Further reducing cash from operating activities
compared to the prior year was a reduction in electric
margins, as discussed in Results of Operations, and a
$13 million increase in pension and postretirement benefit
contributions. Working capital investment increased
because the collection of higher electric rates from
customers lagged payments for power purchases, and
past-due customer accounts increased because of higher
rates. Income tax payments (net of refunds) increased by
$27 million, further reducing cash flows from operations.
Pension Funding
Ameren’s pension plans are funded in compliance with
income tax regulations and to achieve 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. Based on Ameren’s assumptions at
December 31, 2008, and investment performance in 2008,
and reflecting this pension funding policy, Ameren expects
to make annual contributions of $90 million to $200 million
in each of the next five years. We expect UE’s, CIPS’,
Genco’s, CILCO’s, and IP’s portion of the future funding
requirements to be 61%, 6%, 10%, 9% and 14%,
respectively. These amounts are estimates; the numbers
may change with actual asset performance, changes in
interest rates, any pertinent changes in government
regulations, and any voluntary contributions. In 2008,
Ameren contributed $66 million to its pension plans. See
Note 11 – Retirement Benefits to our financial statements
under Part II, Item 8, of this report and Outlook for
additional information.
Cash Flows from Investing Activities
2008 versus 2007
Ameren used more cash for investing activities during
2008, compared with 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 of the transmission and
distribution system. During both years, this was offset by
cash received from payments on an intercompany note
receivable.
Genco’s cash used in investing activities increased in
2008 compared with the same period in 2007. Capital
expenditures increased $126 million, principally due to a
power plant scrubber project. This increase was offset, in
part, by a $7 million decrease in emission allowance
purchases.
CILCORP’s and 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 due
to 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 of the transmission and distribution system.
Net money pool advances increased by $44 million in 2008
compared with 2007.
2007 versus 2006
Ameren used more cash for investing activities in 2007
than in 2006. Net cash used for capital expenditures
increased in 2007 as a result of power plant scrubber
installation projects, other upgrades at various power
plants, and reliability improvements of the transmission and
52
distribution systems, but this increase was reduced by the
absence in 2007 of CT acquisitions that occurred in 2006.
The $43 million decrease in 2007 of proceeds from sales of
noncore properties also increased net cash used in
investing activities. An $18 million decrease in emission
allowance purchases benefited cash flows from investing
activities, while cash received in 2007 for emission
allowance sales was $66 million less than in the prior year,
because remaining allowances are expected to be retained
for environmental compliance needs.
UE’s cash used in investing activities decreased in
2007, compared with 2006, principally because of the
$292 million expended for CT purchases in 2006 that was
not spent in 2007. Otherwise, capital expenditures increased
$135 million because of storm repair costs, a power plant
scrubber installation project, and other upgrades at various
power plants. Other impacts on cash used in investing
activities were the absence of sales of noncore properties in
2007 compared with a $13 million sale in 2006, and the
2006 receipt of $67 million in proceeds from an
intercompany note related to the transfer of UE’s Illinois
territory to CIPS. Additionally, nuclear fuel expenditures
increased $29 million in 2007 over 2006 because of a
refueling outage, and sales of emission allowances
decreased $35 million because remaining allowances are
being retained for environmental compliance needs.
CIPS’ cash used in investing activities decreased in
2007, compared with 2006. CIPS’ investing cash flow was
positively affected by a $3 million increase in proceeds from
CIPS’ note receivable from Genco in 2007 compared with
2006 and the lack of a 2006 $17 million expenditure to
repurchase its own outstanding bond. Capital expenditures
were $3 million lower in 2007 than in 2006.
Genco had an increase in net cash used in investing
activities for 2007, compared with 2006. This increase was
due primarily to a $106 million increase in capital
expenditures related to a scrubber project at one of its
power plants and various other plant upgrades. Emission
allowance purchases decreased by $6 million.
CILCORP’s and CILCO’s cash used in investing
activities increased in 2007, compared with 2006. Cash flow
used in investing activities increased as a result of a
$135 million increase in capital expenditures, primarily due
to a power plant scrubber project and other plant upgrades
at AERG. The absence in 2007 of $11 million of proceeds
received in 2006 from the sale of leveraged leases, and (for
CILCORP only) the absence in 2007 of a 2006 note
receivable payment from Ameren Energy Resources
Company in the amount of $71 million related to the 2005
transfer of leveraged leases from CILCORP to Ameren
Energy Resources Company, contributed to the increase in
cash used in investing activities in 2007. The net year-over-
year reduction of $83 million and $84 million in money pool
advances for CILCORP and CILCO, respectively, and a
$12 million reduction of emission allowance purchases
benefited cash flows from investing activities in 2007.
IP’s net use of cash in investing activities for 2007 was
comparable with 2006.
See Environmental Capital Expenditures below and
Note 15 – Commitments and Contingencies to our financial
statements under Part II, Item 8, of this report for a further
discussion of future environmental capital investment
estimates.
Capital Expenditures
The following table presents the capital expenditures
by the Ameren Companies for the years ended
December 31, 2008, 2007, and 2006:
Capital Expenditures
2008
2007
2006
Ameren(a) . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . . .
CILCO (Illinois Regulated) . . .
CILCO (AERG) . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . .
$
1,896
874
96
317
319
61
258
186
$
1,381
625
79
191
254
64
190
178
$ 1,284
782
82
85
119
53
66
179
(a)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries.
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 damage-related
expenditures of $12 million. CIPS and IP incurred storm
damage-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 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 damage-related
expenditures of $56 million. IP incurred storm damage-
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 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 2006 capital expenditures principally
consisted of the following expenditures at its subsidiaries.
UE purchased three CTs totaling $292 million. In addition,
UE spent $40 million toward a scrubber at one of its power
plants, and incurred storm damage-related expenditures of
53
$47 million. CIPS and IP incurred storm damage-related
expenditures of $16 million and $27 million, respectively. At
Genco and AERG, there were cash outlays of $24 million
and $11 million, respectively, for scrubber projects. Genco
also made expenditures for a power plant boiler upgrade of
$16 million. Other capital expenditures were principally to
maintain, upgrade and expand the reliability of the
transmission and distribution systems of UE, CIPS, CILCO,
and IP.
The following table estimates the capital expenditures
that will be incurred by the Ameren Companies from 2009
through 2013, including construction expenditures,
capitalized interest and allowance for funds used during
construction (except for Genco and AERG, which have no
allowance for funds used during construction), and
estimated expenditures for compliance with environmental
standards:
2009
2010 - 2013
Total
UE . . . . . . . . . . . . . . . . . . $
CIPS . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . .
CILCO (Illinois Regulated) .
CILCO (AERG) . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . .
EEI . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . .
350-
835 $ 3,335- $ 4,435 $ 4,170- $ 5,270
565
90
475
1,770
1,180- 1,500
270
415
340
75
640
555
85
1,180
960
220
385
335
50
160
100
60
440-
1,450-
325-
525-
935-
305-
135-
250-
440-
715-
255-
75-
Ameren(a) . . . . . . . . . . . . . $ 1,685 $ 6,600- $ 8,700 $ 8,285- $ 10,385
(a)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries.
UE’s estimated capital expenditures include
transmission, distribution and generation-related activities,
as well as expenditures for compliance with new
environmental regulations discussed below. CIPS’, CILCO’s
(Illinois Regulated), and IP’s estimated capital expenditures
are primarily for electric and gas transmission and
distribution-related activities. Genco’s estimated capital
expenditures are primarily for compliance with
environmental regulations and upgrades to existing coal
and gas-fired generating facilities. CILCO (AERG)’s estimate
includes capital expenditures primarily for compliance with
environmental regulations at AERG’s generating facilities, as
well as generation-related activities.
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. In addition, Ameren and
Genco are currently considering divestiture of some of
Genco’s smaller non-rate-regulated generating units. 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.
As a result of the disruption and uncertainties in the
capital and credit markets, we are actively evaluating
54
opportunities to defer or reduce our planned capital
spending. This included reducing our 2009 expenditures
from previously expected levels. See Outlook in
Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7 of
this report for further discussion.
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, including 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 used to remove electric generating
units from the list of sources subject to the maximum
available control technology requirements under the Clean
Air Act. The EPA and a group representing the electric utility
industry filed petitions for rehearing; however, the court
denied those petitions in May 2008. A group representing
the electric utility industry and the EPA filed petitions for
review of the U.S. Court of Appeals decision with the U.S.
Supreme Court in September 2008 and October 2008,
respectively. In February 2009, the EPA withdrew its
petition to the U.S. Supreme Court. In February 2009, the
U.S. Supreme Court denied the 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. The standard is
expected to be available in draft form by mid to late 2009,
and compliance is expected to be required in the 2013 to
2015 timeframe.
We are currently evaluating the impact that the court
decision will have on our environmental compliance
strategy. At this time, we are unable to predict the outcome
of this legal proceeding, the actions the EPA or U.S.
Congress may take in response to the court decision and
the timing of such actions. We also cannot predict at this
time the ultimate impact the court decision and resulting
regulatory actions will have on our estimated capital costs
for compliance with 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 filed petitions
for rehearing with the U.S. Court of Appeals. In December
2008, the U.S. Court of Appeals essentially reversed their July
2008 decision to vacate the federal Clean Air Interstate Rule.
The U.S. Court of Appeals granted the EPA petition for
reconsideration and decided to remand 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 state of Missouri adopted state rules to implement
the federal Clean Air Interstate Rule for regulating SO2 and
NOx emissions from electric generating units in Missouri.
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 requirements of the federal Clean Air
Visibility Rule. As a result of the Missouri rules, UE will
manage emission allowances and install pollution control
equipment. Missouri also adopted state rules to implement
the federal Clean Air Mercury Rule; however, the state 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 the court decision that vacated the
federal Clean Air Mercury Rule will significantly affect
pollution control obligations in Illinois. Under the MPS,
Illinois generators may defer until 2015 the requirement to
reduce mercury emissions by 90% in exchange for
accelerated installation of NOx and SO2 controls. To comply
with the rule, Genco, CILCO (AERG) and EEI have begun
putting into service equipment designed to reduce mercury
emissions. As a result of the Illinois rules, Genco, AERG
and EEI will need to procure allowances and install pollution
control equipment. Current plans include the installation of
scrubbers for SO2 reduction and optimizing operations of
selective catalytic reduction (SCR) systems for NOx
reduction at certain coal-fired plants in Illinois.
In October 2008, Genco, CILCO (AERG) and EEI
submitted a request for a variance from the MPS to the
Illinois Pollution Control Board. In preparing this request,
Genco, CILCO (AERG) and EEI worked with the Illinois EPA
and agreed to the installation of more stringent SO2 and NOx
controls at various stages between 2010 and 2020 in order
to make the variance proposal “environmentally neutral.” In
January 2009, the Illinois Pollution Control Board denied
the variance request on procedural grounds. Genco, CILCO
(AERG) and EEI filed a motion for reconsideration in
February 2009 and, with the Illinois EPA’s concurrence,
seek to amend the MPS within a pending rulemaking
pertaining to technical amendments of the underlying
mercury regulations. Revisions to the MPS within that
rulemaking will require Illinois Pollution Control Board
approval. If approved, this variance or rule amendment
could allow Genco to defer approximately $375 million of
environmental capital expenditures from the 2009-2012
timeframe to the 2013-2015 timeframe. This amount is
reduced from the $500 million disclosed in Genco’s
Quarterly Report on Form 10-Q for the period ended
September 30, 2008, because of revisions to the size and
timing of projected environmental capital expenditures if no
variance is granted. A decision is expected in 2009.
The EPA finalized regulations in March 2008 that will
lower the ambient standard for ozone. States must submit
their nonattainment plans in March 2009. A final action by
the EPA to designate areas as nonattainment is expected in
March 2010, and state implementation plans will need to be
submitted in 2013 unless Illinois and Missouri seek
extensions of various requirement dates. Additional
emission reductions may be required as a result of future
state implementation plans. At this time, we are unable to
determine the impact such state actions would have on our
results of operations, financial position, or liquidity.
55
The table below presents estimated capital costs that
are based on current technology to comply with the federal
Clean Air Interstate Rule and related state implementation
plans through 2018 as well as federal ambient air quality
standards including ozone and fine particulates, and the
federal Clean Air Visibility rule. The estimates described
below could change depending upon additional federal or
state requirements, the implementation of any revisions to
the federal Clean Air Interstate Rule, the requirements under
a mercury MACT standard, whether the variance or rule
amendment request with respect to the Illinois MPS
discussed above is granted, new technology, variations in
costs of material or labor, or alternative compliance
strategies, among other reasons. 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.
2009
2010 - 2013
2014 - 2018
Total
. . . . . $ 100 $
UE(a)
Genco . . . .
AERG . . . .
. . . . . .
EEI
230
55
15
525- $
875-
365-
120-
655 $ 1,530- $ 1,885 $ 2,155- $ 2,640
1,440
125
590
80
830
660
1,200-
480-
665-
95-
60-
530-
1,085
455
155
Ameren . . . $ 400 $ 1,885- $ 2,350 $ 2,215- $ 2,750 $ 4,500- $ 5,500
(a) UE’s expenditures are expected to be recoverable in rates over
time.
See Note 15 – Commitments and Contingencies to our
financial statements under Part II, Item 8, of this report for
a further discussion of environmental matters.
Cash Flows from Financing Activities
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
debt borrowings of $860 million and long-term borrowings
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 resulting 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.
56
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 rates as a result of the collapse of
the auction-rate securities market, and to fund the current
maturity 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
debt borrowings.
CIPS had a net use of cash from financing activities in
2008, compared with a net source of cash in 2007. This
change was because CIPS used net money pool borrowings
and existing cash to fund a net reduction in short-term
debt, to redeem $35 million of auction-rate environmental
improvement revenue refunding bonds that had adjusted to
higher 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 debt borrowings of $90 million to
fund working capital needs and 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.
CILCORP’s and CILCO’s cash provided by financing
activities decreased in 2008 compared with 2007. This
decrease was primarily the result of CILCORP’s and
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 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.
Also benefiting cash flows for the year ended December 31,
2008, were net borrowings of a $150 million direct loan
from Ameren at CILCORP compared with $71 million net
repayments during 2007.
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 repay short-term debt. Additionally, during 2008, IP
funded $60 million of common stock dividends to Ameren
and had net short-term debt 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.
2007 versus 2006
Ameren had an increase of $556 million in its net cash
from financing activities in 2007, compared to 2006.
Positive effects on cash included a net increase of
$441 million in net short-term debt proceeds in 2007 over
2006, and a $442 million increase in the issuance of long-
term debt. These increased proceeds were used to fund a
$324 million increase in redemptions, repurchases, and
maturities of long-term debt and to fund the working capital
needs of UE, CIPS, CILCO and IP.
UE had a net source of cash from financing activities in
2007, compared with a net use of cash in 2006. The
primary reasons for the change include a $380 million
capital contribution from Ameren and the issuance of
$424 million of senior secured notes in 2007. The proceeds
were used to repay short-term debt and to fund working
capital and capital expenditures. Other net uses of cash in
2007 included the repayment of a note Ameren issued in
2006 and an $18 million increase in common stock
dividend payments.
CIPS had a net source of cash from financing activities
in 2007, compared with a net use of cash in 2006. This was
primarily the result of an increase of $55 million in net short-
term debt proceeds in 2007 over 2006, and a $10 million
Short-term Borrowings and Liquidity
decrease in dividend payments. Cash was also positively
affected in 2007 by a $20 million decrease in redemptions,
repurchases, and maturities of long-term debt and the
absence in 2007 of the 2006 payments of $67 million on an
intercompany note with UE. Cash flows in 2006 benefited
from $61 million in proceeds from long-term debt issuances
that did not recur in 2007.
Genco had a net increase in cash used in financing
activities for 2007 over 2006, principally because of a
$125 million decrease in capital contributions received from
Ameren. Cash benefited in 2007 by a $100 million increase
in net proceeds from short-term debt.
CILCORP had a net source of cash from financing
activities in 2007, compared with a net use of cash in 2006.
CILCO’s cash provided by financing activities increased in
2007, compared with 2006. Net money pool repayments
decreased $154 million at CILCORP and $161 million at
CILCO. A net increase in short-term debt of $90 million at
CILCORP and $15 million at CILCO in 2007 resulted in a
positive effect on cash. In 2007, CILCORP and CILCO did
not issue any dividends on common stock; in 2006
CILCORP issued $50 million and CILCO $65 million. As a
result, cash flows from financing activities benefited in 2007
as compared to 2006. Additionally, in 2006 a note payable
to Ameren was repaid, which resulted in a net use of cash
of $113 million at CILCORP. Note payable repayments were
only $71 million in 2007. These positive effects on cash
were reduced by the lack of proceeds from the issuance of
long-term debt in 2007 compared with $96 million at both
CILCORP and CILCO in 2006.
IP had an increase in its net cash provided by financing
activities in 2007 compared with 2006. This was primarily
the result of an increase in proceeds from short-term debt
and a $175 million increase from the issuance of long-term
debt. The proceeds from the 2007 long-term debt issuance
were used to repay borrowings under the Ameren utility
money pool and under the 2007 credit facility. Other net
uses of cash included $61 million of common stock
dividends in 2007.
External short-term borrowings typically consist of drawings under committed bank credit facilities. See Note 4 – Short-
term Borrowings and Liquidity to our financial statements 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 various committed bank credit facilities of the Ameren Companies and AERG, and their
availability as of December 31, 2008:
Credit Facility
Ameren, UE and Genco:
Expiration
Amount Committed
Amount Available(a)
Multiyear revolving(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July 2010
$
1,150
$
540(f)
CIPS, CILCORP, CILCO, IP and AERG:
2007 Multiyear revolving(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 Multiyear revolving(c)(e) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
January 2010
January 2010
500
500
415
220
(a) After excluding $75 million and $17 million of unfunded Lehman Brothers Bank, FSB participations as of December 31, 2008, under the
$1.15 billion credit facility and 2006 $500 million credit facility, respectively.
57
(b) Ameren Companies may access this credit facility through intercompany borrowing arrangements.
(c) See Note 4 – Short-term Borrowings and Liquidity to our financial statements under Part II, Item 8, of this report for discussion of the
amendments to these facilities.
(d) The maximum amount available to each borrower under this facility at December 31, 2008, including for the issuance of letters of credit, was
limited as follows: CILCORP – $125 million, CILCO – $75 million, IP – $200 million and AERG – $100 million. CIPS and CILCO have the option
of permanently reducing their ability to borrow under the 2006 $500 million credit facility and shifting such capacity, up to the same limits, to
the 2007 $500 million credit facility. In July 2007, CILCO shifted $75 million of its sublimit under the 2006 $500 million credit facility to this
facility.
(e) The maximum amount available to each borrower under this facility at December 31, 2008, including for the issuance of letters of credit, was
limited as follows: CIPS – $135 million, CILCORP – $50 million, CILCO – $75 million, IP – $150 million and AERG – $200 million. In July 2007,
CILCO shifted $75 million of its capacity under this facility to the 2007 $500 million credit facility. Accordingly, as of December 31, 2008,
CILCO had a sublimit of $75 million under this facility and a $75 million sublimit under the 2007 credit facility.
In addition to amounts drawn on this facility, the amount available is further reduced by standby letters of credit issued under the facility. The
amount of such letters of credit at December 31, 2008, was $9 million.
(f)
Ameren can directly borrow under the $1.15 billion
facility, as amended, up to the entire amount of the facility.
UE can directly borrow under this facility up to $500 million
on a 364-day basis. Genco can directly borrow under this
facility up to $150 million on a 364-day basis. The amended
facility will terminate on July 14, 2010, with respect to all
borrowers thereunder. The termination date for UE and
Genco is July 9, 2009, subject to the annual 364-day
renewal provisions for their individual sublimits under the
facility. This facility was 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 non-rate-regulated subsidiaries,
including, but not limited to, Ameren Services, Resources
Company, Genco, 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 short-term
borrowings by IP, may not exceed $500 million, pursuant to
authorization from the ICC. IP is not currently borrowing
under the unilateral borrowing agreement.
On September 15, 2008, Lehman filed for protection
under Chapter 11 of the federal Bankruptcy Code in the U.S.
Bankruptcy Court in the Southern District of New York. As of
December 31, 2008, Lehman Brothers Bank, FSB, a
subsidiary of Lehman, had lending commitments of
$100 million and $21 million under the $1.15 billion credit
facility and the 2006 $500 million credit facility, respectively.
At this time, we do not know if Lehman Brothers Bank, FSB
will seek to assign to other parties any of its commitments
under our credit facilities. Assuming Lehman Brothers Bank,
FSB does not fund its pro-rata share of funding requests
under these two facilities, and such participations are not
assigned or otherwise transferred to other lenders, total
amounts accessible by the Ameren Companies and AERG will
be limited to amounts not less than $1.05 billion under the
$1.15 billion credit facility and $479 million under the 2006
$500 million credit facility. The Ameren Companies and
AERG do not believe that the potential reduction in available
capacity under the credit facilities if Lehman Brothers Bank,
FSB does not fund its commitments will have a material
impact on their liquidity.
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. See Note 4 – Short-term
Borrowings and Liquidity to our financial statements under
Part II, Item 8, of this report for additional information.
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. See Note 4 –
Short-term Borrowings and Liquidity to our financial
statements under Part II, Item 8, of this report for additional
information.
Ameren Services is responsible for operation and
administration of the money pool agreements. See Note 4 –
Short-term Borrowings and Liquidity to our financial
statements under Part II, Item 8, of this report for a detailed
explanation of the money pool arrangements and the
unilateral borrowing agreement.
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, 2008, Ameren, UE, CIPS, Genco, CILCORP,
CILCO, and IP had $92 million, less than $1 million, less
than $1 million, $2 million, less than $1 million, less than
$1 million and $50 million, respectively, of cash and cash
equivalents.
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 short-
term debt 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. IP
has unlimited short-term debt authorization from FERC.
58
Genco was authorized by FERC in its March 2008 order
to have up to $500 million of short-term debt outstanding at
any time. AERG and EEI have unlimited short-term debt
authorization from FERC.
The issuance of short-term debt securities by Ameren
and CILCORP (parent) is not subject to approval by any
regulatory body.
Long-term Debt and Equity
The Ameren Companies continually evaluate the
adequacy and appropriateness of their credit arrangements
given changing business conditions. When business
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
2008, 2007 and 2006 for the Ameren Companies and EEI. 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 to our
financial statements under Part II, Item 8, of this report.
Month Issued, Redeemed,
Repurchased or Matured
2008
2007
2006
Issuances
Long-term debt
UE:
6.40% Senior secured notes due 2017 . . . . . . . . . . . . . . . . . . . . . . . .
6.00% Senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . . . . .
6.70% Senior secured notes due 2019 . . . . . . . . . . . . . . . . . . . . . . . .
CIPS:
6.70% Senior secured notes due 2036 . . . . . . . . . . . . . . . . . . . . . . . .
Genco:
7.00% Senior notes due 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO:
6.20% Senior secured notes due 2016 . . . . . . . . . . . . . . . . . . . . . . . .
6.70% Senior secured notes due 2036 . . . . . . . . . . . . . . . . . . . . . . . .
8.875% Senior secured notes due 2013 . . . . . . . . . . . . . . . . . . . . . . .
IP:
6.25% Senior secured notes due 2016 . . . . . . . . . . . . . . . . . . . . . . . .
6.125% Senior secured notes due 2017 . . . . . . . . . . . . . . . . . . . . . . .
6.25% Senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . . . . .
9.75% Senior secured notes due 2018 . . . . . . . . . . . . . . . . . . . . . . . .
June
April
June
June
April
June
June
December
June
November
April
October
$
-
250
449
-
300
-
-
150
-
-
336
394
Total Ameren long-term debt issuances . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,879
Common stock
Ameren:
DRPlus and 401(k) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Various
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:
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 . . . . . . . . . . . . . . . . . . .
CIPS:
7.05% First mortgage bonds due 2006 . . . . . . . . . . . . . . . . . . . . . . . .
2004 Series pollution control bonds due 2025 . . . . . . . . . . . . . . . . . .
5.375% Senior secured notes due 2008 . . . . . . . . . . . . . . . . . . . . . . .
CILCORP:
February
May
Various
April
May
May
May
May
June
April
December
9.375% Senior bonds due 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Various
$
$
$
$
154
154
2,033
-
-
4
63
64
60
43
148
-
35
15
-
59
$
$
424
-
-
-
-
-
61
-
54
42
-
75
-
-
-
$
232
$
$
$
$
96
96
328
-
-
4
-
-
-
-
-
20
-
-
12
$
$
$
$
$
-
-
-
-
-
-
250
-
-
674
91
91
765
100
250
4
-
-
-
-
-
-
-
-
-
Month Issued, Redeemed,
Repurchased or Matured
2008
2007
2006
CILCO:
7.73% First mortgage bonds due 2025 . . . . . . . . . . . . . . . . . . . . . . . . .
7.50% First mortgage bonds due 2007 . . . . . . . . . . . . . . . . . . . . . . . . .
2004 Series pollution control bonds due 2039 . . . . . . . . . . . . . . . . . . . .
IP:
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:
5.54% Series due 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.65% Series due 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Preferred Stock
CILCO:
July
January
April
May
May
May
May
June
Various
Various
5.85% Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July
Total Ameren long-term debt and preferred stock redemptions,
repurchases and maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
-
-
19
112
75
70
45
35
-
54
16
-
50
-
-
-
-
-
-
-
84
1
21
-
-
-
-
-
-
-
107
-
1
$
858
$
489
$
165
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,
2008:
. . . . . . . . . .
Ameren(a)
UE(b)
. . . . . . . . . . . . . .
CIPS(a) . . . . . . . . . . . . .
Genco(a) . . . . . . . . . . . .
CILCO(a) . . . . . . . . . . . .
IP(a) . . . . . . . . . . . . . . .
Effective
Date
November 2008
June 2008
November 2008
November 2008
November 2008
November 2008
Authorized
Amount
Not Limited
Not Limited
Not Limited
Not Limited
Not Limited
Not Limited
(a)
(b)
In November 2008, Ameren, as a well-known seasoned issuer,
along with 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, as a well-known seasoned issuer, 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.
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 currently selling newly issued shares of
its common stock under its 401(k) plan pursuant to an
effective SEC Form S-8 registration statement. Under
DRPlus and its 401(k) plan (including a subsidiary plan that
is now merged into the Ameren 401(k) plan), Ameren
issued 4.0 million, ($154 million) shares of common stock
in 2008, 1.7 million ($91 million) in 2007, and 1.9 million
($96 million) in 2006.
Ameren, UE, CIPS, Genco, CILCO and IP may sell all or
a portion of the remaining 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 – Short-term Borrowings and Liquidity and
Note 5 – Long-term Debt and Equity Financings to our
financial statements 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, 2008, the Ameren Companies were in
compliance with their credit facility, term loan agreement,
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.
60
Dividends
Ameren paid to its shareholders common stock
dividends totaling $534 million, or $2.54 per share, in 2008,
$527 million, or $2.54 per share, in 2007, and $522 million,
or $2.54 per share, in 2006. This resulted in a payout rate
based on net income of 88% in 2008, 85% in 2007, and
95% in 2006. Dividends paid to common shareholders in
relation to net cash provided by operating activities for the
same periods were 35% in 2008, 48% in 2007 and 41% in
2006.
On February 13, 2009, 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, 2009,
to shareholders of record on March 11, 2009. The board’s
action was consistent with an annualized dividend of
$1.54 per share, or a 39% reduction from the previous
annual dividend level of $2.54 per share. The new
annualized dividend rate of $1.54 per share would represent
a payout rate of 53% based on 2008 net income.
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, return on investments with similar risk
characteristics, impacts of regulatory orders or legislation,
and other key business considerations.
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, 2008, except as discussed below with
respect to the 2007 $500 million credit facility and the 2006
$500 million credit facility, 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 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.
CILCORP has common and preferred stock dividend
payment restrictions if leverage ratio and interest coverage
ratio thresholds are not met, or if CILCORP’s senior long-
term debt does not have the ratings described in its
indenture. 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.
The 2007 $500 million credit facility and the 2006
$500 million credit facility limit CIPS, CILCORP, CILCO and
IP to common and preferred stock dividend payments of
$10 million per year each if CIPS’, CILCO’s or IP’s senior
secured long-term debt securities or first mortgage bonds,
or CILCORP’s senior unsecured long-term debt securities,
have received a below investment-grade credit rating from
either Moody’s or S&P. With respect to AERG, which
currently is not rated by Moody’s or S&P, the common and
preferred stock dividend restriction will not apply if its ratio
of consolidated total debt to consolidated operating cash
flow, pursuant to a calculation defined in the facilities, is
less than or equal to 3.0 to 1. CILCORP’s senior unsecured
credit ratings from Moody’s and S&P are below investment-
grade, causing it to be subject to this dividend payment
limitation. As of December 31, 2008, AERG failed to meet
the debt-to-operating cash flow ratio test in the 2007 and
2006 $500 million credit facilities. AERG therefore is
currently limited in its ability to pay dividends to a
maximum of $10 million per fiscal year. The other
borrowers thereunder are not currently limited in their
dividend payments by this provision of the 2007 or 2006
$500 million credit facilities.
The following table presents common stock dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their
respective parents.
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonregistrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Dividends paid by Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2008
2007
2006
264
-
101
-
60
109
534
$
$
267
40
113
-
61
46
527
$
$
249
50
113
50
-
60
522
(a) CILCO paid to CILCORP dividends of $- million, $- million and $65 million for the years ended December 31, 2008, 2007 and 2006,
respectively.
61
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 – Stockholder Rights Plan
and Preferred Stock to our financial statements under Part
II, Item 8, of this report for further detail concerning the
preferred stock issuances.
Contractual Obligations
The following table presents our contractual obligations as of December 31, 2008. See Note 11 – Retirement Benefits to
our financial statements 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.
Total
Less than
1 Year
1 - 3 Years
3 - 5 Years
Ameren:(a)
Long-term debt and capital lease obligations(b)(c) . . . . . . . . . . . . . . . . . . . . .
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest payments(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating leases(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois electric settlement agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other obligations(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
6,894
1,174
5,210
392
29
5,427
$
378
1,174
444
39
27
1,359
$
358
-
831
66
2
2,456
$
534
-
787
54
-
974
After
5 Years
$
5,624
-
3,148
233
-
638
Total cash contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
19,126
$
3,421
$
3,713
$
2,349
$
9,643
UE:
Long-term debt and capital lease obligations(c)
. . . . . . . . . . . . . . . . . . . . . .
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intercompany note payable – Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest payments(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating leases(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other obligations(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cash contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS:
Long-term debt(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Borrowings from money pool
Interest payments(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating leases(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois electric settlement agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other obligations(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cash contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco:
Long-term debt(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intercompany note payable – CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Borrowings from money pool
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest payments(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating leases(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois electric settlement agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other obligations(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cash contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt(b)(g)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term debt(g)
Borrowings from money pool
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intercompany note payable – Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest payments(d)(g)
Operating leases(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois electric settlement agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other obligations(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
3,684
251
92
2,698
174
2,439
9,338
422
62
44
313
2
4
369
1,216
775
87
80
739
143
12
602
2,438
334
50
98
152
420
18
7
797
Total cash contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,876
$
62
$
4
251
92
215
15
586
$
8
-
-
430
28
1,087
$
383
-
-
415
25
387
$
3,289
-
-
1,638
106
379
$
1,163
$
1,553
$
1,210
$
5,412
$
$
$
$
$
-
62
44
27
-
4
110
247
-
42
80
60
9
11
144
346
124
50
98
152
28
1
7
178
638
$
$
$
$
$
$
150
-
-
49
1
-
135
335
200
45
-
100
17
1
330
693
-
-
-
-
40
3
-
332
375
$
$
$
$
$
$
-
-
-
34
1
-
78
113
-
-
-
86
17
-
120
223
-
-
-
-
40
2
-
171
213
$
$
$
272
-
-
203
-
-
46
521
575
-
-
493
100
-
8
$
1,176
$
$
210
-
-
-
312
12
-
116
650
Total
Less than
1 Year
1 - 3 Years
3 - 5 Years
CILCO:
Long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Borrowings from money pool
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest payments(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating leases(e)
Illinois electric settlement agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other obligations(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
279
236
98
195
18
7
797
$
-
236
98
21
1
7
178
$
-
-
-
42
3
-
332
Total cash contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,630
$ 541
$ 377
IP:
Long-term debt(b)(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest payments(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating leases(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Illinois electric settlement agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other obligations(f) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,400
845
8
6
616
Total cash contractual obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,875
$ 250
93
3
5
173
$ 524
$
-
170
4
1
267
$ 442
$ 258
After
5 Years
$
$
128
-
-
90
12
-
116
346
$ 1,150
412
-
-
89
$ 1,651
$ 151
-
-
42
2
-
171
$ 366
$
-
170
1
-
87
(a)
Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations.
(b) Excludes fair-market value adjustments of long-term debt of $49 million for CILCORP and $10 million for IP.
(c) Excludes unamortized discount of $7 million at UE, $1 million at CIPS, $1 million at Genco, and $10 million at IP.
(d) The weighted average variable-rate debt has been calculated using the interest rate as of December 31, 2008.
(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) Represents parent company only.
The Ameren Companies adopted the provisions of FIN
Credit Ratings
48, “Accounting for Uncertainty in Income Taxes” on
January 1, 2007. As of December 31, 2008, the amounts of
unrecognized tax benefits under the provisions of FIN 48
were $110 million, $20 million, $- million, $47 million,
$25 million, $25 million and $- million for Ameren, UE,
CIPS, Genco, CILCORP, 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 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, 2008, 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.
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 . . . . . . . . . . . . .
CILCORP:
Issuer/corporate credit rating . . . . . . . .
Senior unsecured debt . . . . . . . . . . . . .
CILCO:
Issuer/corporate credit rating . . . . . . . .
Secured debt . . . . . . . . . . . . . . . . . . . .
IP:
Issuer/corporate credit rating . . . . . . . .
Secured debt . . . . . . . . . . . . . . . . . . . .
Moody’s
S&P
Fitch
Baa3
Baa3
Baa2
Baa1
Ba1
Baa3
Ba1
-
Baa3
BBB-
BB+
BBB+
BBB+
BBB-
BBB
BBB-
BBB+
BBB-
A-
A+
BBB-
BBB+
BBB
BBB-
BBB-
BBB+
BBB+
-
Ba2
BBB-
BB+
BBB-
BBB-
Ba1
Baa2
Ba1
Baa3
BBB-
BBB+
BBB
A-
BBB-
BBB
BBB-
BBB+
63
Moody’s Ratings Actions
On February 12, 2008, Moody’s affirmed the ratings of
Ameren and Genco but changed their rating outlook to
negative from stable. Moody’s placed the long-term credit
ratings of UE under review for possible downgrade and
affirmed UE’s commercial paper rating. In addition,
Moody’s affirmed the ratings of CIPS, CILCORP, CILCO and
IP and maintained a positive rating outlook on these four
companies. According to Moody’s, the review of UE’s
ratings was prompted by declining cash flow coverage
metrics, increased operating costs, higher capital
expenditures for environmental compliance and
transmission and distribution system investment, and
significant regulatory lag in the recovery of these costs.
Moody’s stated that the negative outlook on the credit rating
of Genco reflected Genco’s “position as a predominantly
coal generating company that is likely to be seriously
affected by more stringent environmental regulations,
including a potential cap or tax on carbon emissions.” The
negative outlook on the ratings of Ameren, according to
Moody’s, reflects the factors that impacted its subsidiaries,
UE and Genco.
On May 21, 2008, Moody’s lowered the credit ratings
of UE to Baa1 for its senior secured debt and to Baa2 for its
issuer rating and changed the rating outlook to stable. In its
reasons for these actions, Moody’s reiterated the items
noted above, attributing the declining cash flow metrics to
increased fuel and purchased power costs, growing capital
expenditures for environmental compliance and for
transmission system reliability, and higher labor costs. They
noted that UE was one of the few utilities in the country at
the time of their report operating without fuel, purchased
power, and environmental cost recovery mechanisms.
Moody’s also placed UE’s commercial paper rating on
review for possible downgrade due to its review of
Ameren’s short-term rating as noted below. At the same
time, the ratings of Ameren and Genco were changed from
negative outlook to being on review for possible
downgrade.
On August 13, 2008, Moody’s downgraded both the
issuer and senior unsecured debt ratings of Ameren and the
senior unsecured debt rating of Genco to Baa3 from
Baa2 and changed the outlooks on these ratings to
stable. Moody’s also downgraded the commercial paper
ratings of Ameren and UE to P-3 from P-2. Moody’s stated
that these downgrades were because of declining
consolidated coverage ratios over the last several years and
the expectation that ongoing cost pressures and the lack of
timely regulatory recovery of some costs will prevent ratios
from returning to historical levels in the near-term.
On January 29, 2009, Moody’s affirmed the ratings of
CIPS, CILCORP, CILCO and IP and changed their rating
outlooks to stable from positive. According to Moody’s, the
change in the rating outlooks of these four companies was
based on the near-term expiration of the 2007 and 2006
$500 million 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, CILCORP, CILCO, and IP with a
stable outlook. The affirmation reflects Moody’s view that
Ameren’s announcement to reduce its common dividend by
39% is a conservative, prudent, and credit positive action
that will 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 expire in 2010. They stated
the dividend reduction should continue to reduce reliance
on the credit facilities going forward and will likely be
viewed favorably by lenders considering renewing or
entering into new facilities with Ameren and its subsidiaries,
which is important considering currently constrained credit
market conditions. According to Moody’s, the stable
outlook on Ameren, UE, CIPS, Genco, CILCORP, CILCO,
and IP reflects recently 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; and Moody’s
expectation that financial and cash flow coverage metrics
should remain adequate to maintain current rating levels. In
addition, Moody’s notes that the recent dividend reduction
is supportive of the stable ratings outlooks and provides
Ameren and its subsidiaries additional cushion at current
rating levels.
S&P Ratings Actions
On March 19, 2008, S&P raised its senior unsecured
debt ratings for CIPS to BBB- from B+ and for CILCORP to
BB from B+.
On September 11, 2008, S&P upgraded its corporate
credit ratings on CILCORP, CILCO, CIPS and IP to BBB-
from BB. Senior secured debt ratings at CILCO and CIPS
were upgraded to BBB+ from BBB and were upgraded at IP
to BBB from BBB-. CILCORP’s senior unsecured debt rating
was raised to BB+ from BB. All of Ameren’s other ratings
were affirmed and all outlooks were stable. At the same
time, S&P raised the business profiles of CIPS and IP to
“strong” from “satisfactory.” The business profiles of
CILCORP and CILCO remain “satisfactory.” S&P stated that
the ratings upgrades were due to its assessment that the
regulatory and political environment in Illinois will be
reasonably supportive of investment grade credit quality
with regard to the Ameren Illinois Utilities’ then pending rate
cases. See Note 2 – Rate and Regulatory Matters under Part
II, Item 8, of this report for a discussion of the order issued
by the ICC in these rate cases on September 24, 2008.
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
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“strong” to reflect the recent electric rate order issued by
the MoPSC, which S&P viewed as constructive. See Note
2 – Rate and Regulatory Matters under Part II, Item 8, of
this report for a discussion of the rate order issued by the
MoPSC on January 27, 2009. S&P lowered the business
profile of CILCO to “satisfactory” from “strong” reflecting
S&P’s concerns regarding large capital expenditures
needed to meet environmental compliance standards, while
relying on falling market prices, due to the economic
recession, for recovery.
Fitch Ratings Actions
On October 16, 2008, Fitch upgraded its issuer credit
ratings on CILCO to BBB from BB+ and on CILCORP, CIPS
and IP to BBB- from BB+. The senior secured debt ratings
were raised at CIPS and IP to BBB+ from BBB and at CILCO
to A- from BBB. Senior unsecured debt ratings were raised
at CIPS and IP to BBB from BBB-, at CILCO to BBB+ from
BBB-, and at CILCORP to BBB- from BB+. The outlook for
each of these entities was changed to stable from rating
watch positive. Fitch stated that the ratings upgrades were a
result of the expected positive financial impact of electric
and gas rate case decisions issued by the ICC in September
2008 and the reduction in business risk associated with the
Illinois electric settlement agreement in 2007.
On February 17, 2009, Fitch stated that the reduction in
Ameren’s common stock dividend and other cost cutting
measures will 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.
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 at December 31, 2008, were
$109 million, $15 million, $26 million, $16 million,
$16 million, and $36 million at Ameren, UE, CIPS,
CILCORP, CILCO and IP, respectively. The amount of
collateral external counterparties posted with Ameren was
$7 million at December 31, 2008. Sub-investment-grade
issuer or senior unsecured debt ratings (lower than “BBB-”
or “Baa3”) at December 31, 2008, could have resulted in
Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP being
required to post additional collateral or other assurances for
certain trade obligations amounting to $202 million,
$67 million, $24 million, $19 million, $36 million,
$36 million, and $51 million, respectively. In addition,
changes in commodity prices could trigger additional
collateral postings and prepayments.
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. See Quantitative and Qualitative Disclosures
About Market Risk –Interest Rate Risk under Part II,
Item 7A, for information on credit rating changes with
respect to insured tax-exempt auction-rate bonds.
OUTLOOK
Below are some key trends that may affect the Ameren
Companies’ financial condition, results of operations, or
liquidity in 2009 and beyond.
Economy and Capital and Credit Markets
The global capital and credit markets experienced
extreme volatility and disruption in 2008, and we expect
those conditions to continue throughout 2009 and
potentially longer. Several factors have driven this situation,
including deteriorating global economic conditions and the
weakened condition of major financial institutions, as
evidenced by the bankruptcy of Lehman. These conditions
have led governments around the world to establish policies
and programs that are designed to strengthen the global
financial system, to enhance liquidity, and to restore
investor confidence. We believe that these events have
several implications for the capital and credit markets, the
economy and our industry as a whole, including Ameren.
They include the following:
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Access to Capital Markets – The extreme disruption in
the capital markets has 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. We are unable to
predict how long these conditions will persist, but we
expect the capital markets to remain uncertain
throughout 2009 and potentially longer. However, we
believe we will continue to have access to the capital
markets on terms commercially acceptable to us, as
evidenced by IP’s sale of $400 million in senior secured
notes in October 2008 and CILCO’s sale of $150 million
of senior secured notes in December 2008. CILCORP
and IP have long-term debt maturities of $124 million
and $250 million, respectively, in 2009. In addition,
Ameren’s $300 million term loan agreement is due in
2009. We currently expect to issue approximately
$650 million of debt at our rate-regulated utilities,
$250 million at Ameren, and approximately
$500 million at the non-rate-regulated generation
subsidiaries in 2009.
Credit Facilities – At December 31, 2008, the Ameren
Companies had in place revolving bank credit facilities
aggregating $2.15 billion. In total, 18 financial
institutions participated in these credit facilities. In
January 2010, $1 billion of these facilities expire, and
the revolving $1.15 billion facility expires in July 2010.
Due to the Lehman bankruptcy filing, the size of these
facilities was effectively reduced by up to $121 million.
We cannot predict whether other lenders that are
currently participating in our credit facilities will declare
65
bankruptcy or otherwise fail to honor their
commitments thereunder, and thus reduce the level of
access to credit facilities. We are actively developing
plans and strategies to renew these facilities prior to
their expiration dates. We are unable to predict the
degree of success we will have in renewing or replacing
any of these facilities and whether the size and terms of
any new credit facilities will be comparable to the
existing facilities.
Cost of Capital – The disruption in the capital and credit
markets has led to higher financing costs compared
with recent years. We expect this trend to continue
while the current level of uncertainty in the financial
markets persists.
Economic Conditions – We believe that the disruption
in the capital and credit markets will further weaken
global economic conditions. Limited access to capital
and credit and higher cost of capital for businesses and
consumers will reduce spending and investment, result
in job losses, and pressure economic growth for the
foreseeable future. These weak economic conditions
will likely result in volatility in the power and
commodity markets, greater risk of defaults by our
counterparties, weaker customer sales growth,
particularly with respect to industrial sales, higher bad
debt expense, and possible impairment of goodwill and
long-lived assets, among other things. The estimated
fair values of CILCORP’s Illinois Regulated reporting
unit and Non-rate-regulated Generation reporting unit
exceeded carrying values by a nominal amount as of
October 31, 2008, when we conducted our annual
evaluation of goodwill. As a result, the failure in the
future of either of these reporting units to achieve
forecasted operating results and cash flows or a
decrease in observable market multiples, may reduce
their estimated fair value below their carrying value and
would likely result in the recognition of a goodwill
impairment charge. We will continue to monitor the
actual and forecasted operating results and cash flows
of these reporting units for signs of possible declines in
estimated fair value and potential goodwill impairment.
We would not necessarily expect any future goodwill
impairment charge recorded at the CILCORP reporting
unit level to also result in a goodwill impairment charge
at the consolidated Ameren level because of the
aggregation of reporting units. To date, the level of
defaults by counterparties, lower sales growth, and bad
debt expense resulting from the weak economy have
not significantly affected the Ameren Companies.
However, we are unable to predict the ultimate impact
of these weak economic conditions on our results of
operations, financial position, or liquidity.
Investment Returns – The disruption in the capital
markets, coupled with weak global economic
conditions, has adversely affected financial markets. As
a result, we experienced lower than assumed
investment returns in 2008 in our pension and
postretirement benefit plans. The market value of plan
assets in 2008 declined by 7% and 26% within the
pension and postretirement benefit plans, respectively,
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compared with assumed 2008 investment returns of
8.25% for both funds. These lower returns will increase
our future pension and postretirement expenses and
pension funding levels. Our future expenses and
funding levels will also be affected by future discount
rate levels. Based on Ameren’s assumptions at
December 31, 2008, and investment performance in
2008, and reflecting Ameren’s pension funding policy,
Ameren expects to make annual contributions of
$90 million to $200 million in each of the next five
years.
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,
due to the significant level of disruption and
uncertainties in the capital and credit markets, we are
actively evaluating opportunities to defer or reduce
planned capital spending and operating expenses to
mitigate the risks associated with accessing these
uncertain markets. We took action in this regard by
reducing 2009 operating and capital expenditures from
levels previously expected. Separately, Genco, AERG
and EEI are seeking a variance from the Illinois
Pollution Control Board to an environmental
requirement in Illinois that, while “environmentally
neutral,” would defer approximately $375 million of
Genco’s environmental capital expenditures scheduled
for 2009 through 2012 to subsequent years. Any
expenditure control initiatives would be balanced
against our 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 February 13, 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 $1.3 billion,
excluding unfunded Lehman bank facility participation
commitments, which was $448 million higher than the
same time last year. We expect our available liquidity to
remain at acceptable levels through the end of 2009 as
we strategically access the capital markets and execute
the expenditure control initiatives. However, we are
unable to predict whether significant changes in
economic conditions, further disruption in the capital
and credit markets, or other unforeseen events could
materially impact our estimate.
Although we believe that the uncertainty in the capital
and credit markets will persist throughout 2009 and
potentially longer, we do believe that actions taken by the
U.S. government and governments around the world will
66
ultimately help ease the extreme volatility and disruption of
these markets. In addition, we believe we will continue to
have access to the capital markets on terms commercially
acceptable to us. As discussed above, additional financings
are expected through 2009, subject to market conditions.
Also, in February 2009, Ameren’s board of directors made
the decision to reduce the common stock dividend. The
dividend was reduced to enhance Ameren’s financial
strength and flexibility as the company executes its long-
term business strategy through the dramatically weakened
state of the economy and the continued uncertainties in the
capital, credit, and commodity markets. In addition,
Ameren’s board of directors was mindful of the company’s
current business mix and need to make reliability and
environmental infrastructure investments. Specifically, this
dividend reduction would be consistent with an annual
dividend level that would allow Ameren to retain
approximately $215 million of cash annually, which would
provide incremental funds to enhance reliability to meet our
customers’ expectations; satisfy federal and state
environmental requirements; reduce our reliance on dilutive
equity and high cost debt financings; and enhance our
access to the capital and credit markets. We believe that our
expected operating cash flows, capital expenditures, and
related financing plans (including accessing our existing
credit facilities) will provide the necessary liquidity to meet
our operating, investing, and financing needs through the
end of 2009, at a minimum. 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 impact our
ability to execute our expected operating, capital or
financing plans, including our plans to renew or replace our
existing credit facilities.
Current Capital Expenditure Plans
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Between 2009 and 2018, Ameren expects that certain
Ameren Companies will be required to invest between
$4.5 billion and $5.5 billion to retrofit their 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 50% of this investment is expected to be
in our Missouri Regulated operations, and it is
therefore expected to be recoverable from ratepayers.
The recoverability of amounts expended in Non-rate-
regulated Generation operations will depend on
whether market prices for power adjust as a result of
market conditions reflecting increased environmental
costs for generators.
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. 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.
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Investments to control carbon emissions at Ameren’s
coal-fired power plants would significantly increase
future capital expenditures and operation and
maintenance expenses.
UE continues to evaluate its longer-term needs for new
baseload and peaking electric generation capacity. At
this time, UE does not expect to require new baseload
generation capacity until 2018 to 2020. However, 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 those that
would use coal or nuclear fuel. In July 2008, UE filed a
COLA with the NRC for a potential new nuclear unit at
UE’s existing Callaway County, Missouri, nuclear plant
site. Pursuant to DOE’s procedures, in 2008 UE filed
with the DOE Part I and Part II of its application for a
loan guarantee to support the potential construction
and operation of a new nuclear unit. UE has also signed
contracts for certain long lead-time nuclear-unit related
equipment (heavy forgings). The filing of the COLA and
the DOE loan guarantee application and entering into
these contracts does not mean a decision has been
made to build a new nuclear unit. These are only the
first steps in the regulatory licensing and procurement
process. They are necessary actions to preserve the
option to develop a new nuclear unit. As of
December 31, 2008, UE spent $52 million and
$6 million on the COLA and heavy forgings,
respectively. If UE elects not to build a new nuclear
unit, we believe the COLA and heavy forgings could be
sold in the open market during this time of expected
growth in the nuclear industry.
The Missouri Clean and Renewable Energy
Construction Act was introduced in the Missouri Senate
and House of Representatives in early 2009. This bill
would allow the MoPSC to authorize the use of certain
financing tools for constructing clean and renewable
electric generation, including a tool that would allow
utilities to recover the costs of financing and tax
payments associated with a new generating plant while
that plant is being constructed. UE has stated that
legislation allowing timely recovery of financing costs
during construction must be enacted in order for UE to
elect to build a new nuclear unit to meet its baseload
generation capacity needs. However, passage of such
legislation does not commit or guarantee that UE will
elect to build a new nuclear unit. UE is unable to predict
whether this legislation will be adopted by lawmakers.
UE intends to submit a license extension application
with the NRC to extend its Callaway nuclear plant’s
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
67
to be ultimately recovered in rates, although regulatory
lag could materially impact our cash flows and related
financing needs.
Increased investments for environmental compliance,
reliability improvement, and new baseload capacity will
result in higher depreciation and financing costs.
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Revenues
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The earnings of UE, CIPS, CILCO and IP are largely
determined by the regulation of their rates by state
agencies. Rising costs, including fuel and related
transportation, purchased power, 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 requests to increase rates to continue to
recover such costs on a timely basis are granted by
state regulators. Ameren, UE, CIPS, CILCO and IP
expect more frequent rate cases will be necessary in
the future. UE has agreed not to file a natural gas
delivery rate case before March 15, 2010.
The ICC issued a consolidated order in September 2008
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. Because of
the Ameren Illinois Utilities’ pledge to keep the overall
residential electric bill increase resulting from these rate
changes during the first year to less than 10% for each
utility, IP will not recover approximately $10 million in
revenue in the first year the electric delivery service
rates are in effect. Thereafter, residential electric
delivery service rates will be adjusted to recover the full
increase. In addition, the ICC changed the depreciable
lives used in calculating depreciation expense for the
Ameren Illinois Utilities’ electric and natural gas rates.
As a result, annual depreciation expense for the Ameren
Illinois Utilities will be reduced for financial reporting
purposes by a net $13 million in the aggregate (CIPS –
$4 million reduction, CILCO – $26 million reduction,
and IP – $17 million increase).
Because of continuing investments in the Ameren
Illinois Utilities’ infrastructure, rising operating costs
and costs of capital, the Ameren Illinois Utilities are not
expected to earn the return on equity allowed in the ICC
September 2008 consolidated order. The Ameren
Illinois Utilities’ return on equity in 2009 is estimated to
be approximately 6%. As a result, rate case filings with
the ICC are being targeted for late in the second quarter
or early in the third quarter of 2009.
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The MoPSC issued an electric rate order in January
2009 approving an increase in annual electric revenues
of approximately $162 million based on a 10.76%
return on equity, a capital structure composed of 52%
common equity, and a rate base of $5.8 billion. The rate
change was 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 will be amortized and recovered over a two-year
period beginning March 1, 2009.
Because of continuing investments in UE’s utility
infrastructure, rising operating costs and costs of
capital, UE is not expected to earn the return on equity
allowed in the MoPSC’s January 2009 electric rate
order during 2009. UE’s return on equity in 2009 is
estimated to be approximately 8%. As a result, UE
expects to file another electric rate case in Missouri
later this year. The exact timing will depend on the
timing and magnitude of cost increases and rate base
additions, among other things.
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 the ICC consolidated electric and
natural gas rate order issued in September 2008, the
ICC rejected the Ameren Illinois Utilities’ requested rate
adjustment mechanisms for electric infrastructure
investments. As an alternative to the Ameren Illinois
Utilities’ requested decoupling of natural gas revenues
from sales volumes, the ICC order approved an
increase in the percentage of costs to be recovered
through fixed non-volumetric residential and
commercial customer charges to 80% from 53%. This
increase will impact 2009 quarterly results of
operations and cash flows but is not expected to have
any impact on annual margins. The ICC also approved
an increase in the Supply Cost Adjustment (SCA)
factors for the Ameren Illinois Utilities. The SCA is a
charge applied only to the bills of customers who take
their power supply from the Ameren Illinois Utilities.
The change in the SCA factors is expected to result in
increased electric revenues of $9.5 million per year in
the aggregate (CIPS – $2.6 million, CILCO –
$1.6 million, and IP – $5.3 million) covering the
increased cost of administering the Ameren Illinois
Utilities’ power supply responsibilities. In the MoPSC
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
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and purchased power costs, net of off-system
revenues, including MISO costs and revenues, above or
below the amount set in base rates, subject to MoPSC
prudency review. 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.
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 major winter ice storm in
January 2009, Noranda’s smelter plant experienced a
power outage related to non-UE lines delivering power
to the substation serving the plant. Noranda stated that
the outage affected approximately 75% of the smelter
plant’s capacity and that based on preliminary
information and management’s initial assessment,
restoring full plant capacity may take up to 12 months,
with partial capacity phased in during the 12 month
period. To the extent UE’s sales to Noranda are
reduced, generation made available could be sold as
off-system sales. However, the FAC approved in the
2009 MoPSC electric rate order would require UE to
flow substantially all of the off-system revenues to
customers. If this were to occur, and the Noranda
smelter plant operates at 25% capacity for 12 months,
UE estimates its pretax earnings during such period
could be reduced by up to approximately $73 million
due to the loss of up to approximately 3.2 million
megawatthours of retail sales. In order to adjust the
FAC for this unanticipated event, UE sought rehearing
by the MoPSC of its January 2009 electric rate order in
February 2009, to allow UE to first recover from the
off-system sales any revenues it would lose as a result
of the reduced tariff sales to Noranda with any excess
revenues collected being provided to customers
through the FAC. Also in February 2009, other parties
to the rate case filed for rehearing of certain aspects of
the MoPSC order. In February 2009, the MoPSC denied
all rate case rehearing requests filed by UE and other
parties. UE continues to consider other alternatives to
recover any lost revenues resulting from the Noranda
power outage.
The Illinois electric settlement agreement reached in
2007 provides approximately $1 billion over a four-year
period that began in 2007 to fund rate relief for certain
electric customers in Illinois, including approximately
$488 million to customers of the Ameren Illinois
Utilities. Funding for the settlement is coming from
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
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the following contributions remained to be made at
December 31, 2008:
Ameren
CIPS
CILCO
(Illinois
Regulated)
2009(a) . .
2010(a) . .
$ 26.6
1.9
Total
. . .
$ 28.5
$ 3.9
0.3
$ 4.2
$ 1.9
0.1
$ 2.0
IP
$ 5.1
0.4
$ 5.5
Genco
$ 10.8
0.8
$ 11.6
CILCO
(AERG)
$ 4.9
0.3
$ 5.2
(a) Estimated.
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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 (capacity,
energy swaps, and renewable energy credits) that the
IPA will procure on behalf of the Ameren Illinois
Utilities for the period of June 1, 2009, through
May 30, 2014. The products will be procured through a
RFP process, during the first half of 2009. The Ameren
Illinois Utilities will be allowed to pass through to
customers the costs of procuring electric power supply
with no markup by the utility, plus any reasonable costs
that the utility incurs in arranging and providing for the
supply of electric power.
As part of the 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
Illinois electric settlement agreement, these financial
contracts are deemed prudent, and the Ameren Illinois
Utilities are permitted full recovery of their costs in
rates.
In addition, the Illinois electric settlement agreement
would allow the Ameren Illinois Utilities to lease or
invest in generation facilities, subject to ICC approval.
Volatile power prices in the Midwest can affect the
amount of revenues Ameren, UE (though to a lesser
extent after the implementation of UE’s FAC), 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. Lower prices are expected in 2009 as
compared with 2008.
The availability and performance of UE’s, Genco’s,
AERG’s and EEI’s electric generation fleet can materially
impact their revenues. Genco and AERG are seeking to
raise the equivalent availability and capacity factors of
their power plants over the long term through greater
investments and a process improvement program. The
Non-rate-regulated Generation segment expects to
generate 30 million megawatthours of power in 2009
(Genco – 16 million, AERG – 7 million, EEI – 7 million)
based on expected power prices in 2009. Should power
69
‰
‰
‰
‰
‰
prices rise more than expected in 2009, the Non-rate-
regulated Generation segment has the capacity and
availability to sell more generation.
In 2008, two million contracted megawatthours of
Genco’s and AERG’s legacy power supply agreements,
which had an average embedded selling price of
$33 per megawatthour, expired. These agreements
were replaced with market-based sales.
The marketing strategy for the Non-rate-regulated
Generation 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 Non-rate-regulated
Generation segment has established hedge targets for
near-term years. Through a mix of physical and financial
sales contracts, Marketing Company targets to hedge
Non-rate-regulated 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
February 13, 2009, Marketing Company had sold
approximately 95% of Non-rate-regulated Generation’s
expected 2009 generation, at an average price of $53 per
megawatthour, and had sold approximately 60% of
Non-rate-regulated Generation’s 2010 generation at an
average price of $51 per megawatthour.
The development of ancillary services and capacity
markets in MISO could increase the electric margins of
UE, Genco, AERG and EEI. Ancillary services are
services necessary to support the transmission of
energy from generation resources to loads while
maintaining reliable operation of the transmission
provider’s system. MISO’s regional wholesale ancillary
services market began in January 2009. We expect
MISO will begin development of a capacity market now
that its ancillary services market is in place. A capacity
requirement obligates a load serving entity to acquire
capacity sufficient to meet its obligations.
UE and the Ameren Illinois Utilities have committed to
developing energy efficiency programs for their
customers. UE expects it will spend $24 million on
electric energy efficiency programs in 2009. That
number will increase to $56 million annually by 2015.
The Ameren Illinois Utilities expect to spend
$14 million, $29 million, and $45 million in the 2008,
2009, and 2010 program years, respectively, in
accordance with their electric energy efficiency and
demand response plan approved by the ICC in 2007.
The Ameren Illinois Utilities also expect to spend
$2 million, $4 million, and $6 million in the 2009, 2010,
and 2011 program years, respectively, in accordance
with their natural gas energy efficiency plan approved
by the ICC in 2008. The Illinois program years run from
June 1 through May 31. The costs incurred by the
Ameren Illinois Utilities are recoverable from customers
through rate riders.
Future energy efficiency programs developed by UE,
CIPS, CILCO and IP and others could also result in
reduced demand for our electric generation and our
electric and gas transmission and distribution services.
Fuel and Purchased Power
‰
‰
‰
‰
In 2008, 85% of Ameren’s electric generation (UE –
77%, Genco – 99%, AERG – 99%, EEI – 100%) was
supplied by coal-fired power plants. About 96% of the
coal used by these plants (UE –97%, Genco – 98%,
AERG – 77%, EEI – 100%) was delivered by rail from
the Powder River Basin in Wyoming. In the past,
deliveries from the Powder River Basin have been
restricted because of rail maintenance, weather, and
derailments. As of December 31, 2008, 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.
Genco is incurring incremental fuel costs in 2009 to
replace coal from an Illinois mine that was prematurely
closed by its owner at the end of 2007. A settlement
agreement reached with the coal mine owner in June
2008 fully reimbursed Genco, in the form of a lump-sum
payment of $60 million, for increased costs for coal and
transportation that it incurred in 2008 ($33 million) and
expects to incur in 2009 ($27 million). The entire
settlement was recorded in 2008 earnings, so Ameren’s
and Genco’s earnings in 2009 will be lower than they
otherwise would have been.
The annual NOx trading program under the federal
Clean Air Interstate Rule was reinstated by the U.S.
Court of Appeals for the District of Columbia in
December 2008. At this time, Genco and AERG may not
have sufficient NOx allowances to meet forecasted 2009
obligations under the annual NOx trading program. The
costs of these allowances would depend on market
prices at the time these allowances are purchased.
Genco and AERG currently estimate that they could
incur additional fuel expense in 2009 of $11 million and
$5 million, respectively, to purchase additional NOx
allowances to come into compliance with the program.
Ameren’s fuel costs (including transportation) are
expected to increase in 2009 and beyond. 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 2009 through 2013.
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 has settled with the FERC and the state of Missouri
all issues associated with the December 2005 Taum
Sauk incident. In addition, UE received approval from
FERC to rebuild the upper reservoir at its Taum Sauk
plant and is in the process of rebuilding the facility. The
estimated cost to rebuild the upper reservoir is in the
range of $480 million. UE expects the Taum Sauk plant
to be out of service through early 2010. UE believes
70
that substantially all damages and liabilities caused by
the breach, including costs related to the settlement
agreement with the state of Missouri, the cost of
rebuilding the plant, and the cost of replacement
power, up to $8 million annually, will be covered by
insurance. Insurance will not cover lost electric margins
and penalties paid to FERC. Under UE’s insurance
policies, all claims by or against UE are subject to
review by its insurance carriers. As a result of this
breach, UE is engaged in litigation initiated by certain
private parties and the Department of the Army, Corps
of Engineers. We are unable to predict the timing or
outcomes of this litigation, or its possible effect on
UE’s results of operation, financial position, or liquidity.
See Note 15 – Commitments and Contingencies to our
financial statements under Part II, Item 8, of this report
for a further discussion of Taum Sauk matters.
UE’s Callaway nuclear plant had a 28-day scheduled
refueling and maintenance outage during the fourth
quarter of 2008. UE’s Callaway nuclear plant’s next
scheduled refueling and maintenance outage is in the
spring of 2010. 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, versus 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
‰
Under an executory tolling agreement, CILCO
purchased steam, chilled water, and electricity from
Medina Valley, which CILCO in turn sold to an industrial
REGULATORY MATTERS
‰
customer. In January 2009, CILCO transferred both the
tolling agreement and the related power supply
agreement with the industrial customer to Marketing
Company. The transfer of these agreements is expected
to benefit CILCO’s non-rate-regulated 2009 pretax
operating generation income by $6 million compared
with its 2008 operating income.
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 are
required to be issued by the MoPSC to implement the
law. UE expects that any related costs or investments
would ultimately be recovered in rates.
The above items could have a material impact on our
results of operations, financial position, or liquidity.
Additionally, in the ordinary course of business, we evaluate
strategies to enhance our results of operations, financial
position, or liquidity. These strategies may include
acquisitions, divestitures, opportunities to reduce costs or
increase revenues, and other strategic initiatives to increase
Ameren’s shareholder 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, or liquidity.
See Note 2 – Rate and Regulatory Matters to our financial statements 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
Uncertainties Affecting Application
Regulatory Mechanisms and Cost Recovery
All of the Ameren Companies, except Genco, defer costs
as regulatory assets in accordance with SFAS No. 71,
“Accounting for the Effects of Certain Types of
Regulation,” and make investments that they assume will
be collected in future rates.
‰
‰
‰
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, we record a charge to earnings, which could be
material. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for
quantification of these assets by registrant.
71
Accounting Estimate
Unbilled Revenue
At the end of each period, we project expected usage, and
we estimate the amount of revenue to record for services
that have been provided to customers but not yet billed.
Uncertainties Affecting Application
‰
‰
‰
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 under Part II, Item 8, of this report for unbilled revenue amounts.
Derivative Financial Instruments
We account for derivative financial instruments under
SFAS No. 133, “Accounting for Derivatives and Hedging
Activities,” as amended, and related interpretations and
measure their fair value in accordance with SFAS No. 157,
“Fair Value Measurements,” and related interpretations.
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 to our
financial statements under Part II, Item 8, of this report.
Basis for Judgment
‰
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 our derivatives that have been
designated as hedges
Counterparty default risk
‰
‰
‰
We determine whether to exclude the fair value of certain derivatives from valuation under the normal purchase and normal
sales provisions of SFAS No. 133 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 SFAS No. 157, 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. Without 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 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
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 valuation methodologies to determine
valuations, including earnings before interest, taxes, depreciation and amortization multiples, and discounted, undiscounted,
and probabilistic discounted cash flow models with multiple 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
to our financial statements under Part II, Item 8, of this report for quantification of our goodwill and intangible assets.
72
Accounting Estimate
Benefit Plan Accounting
Based on actuarial calculations, we accrue costs of
providing future employee benefits in accordance with
SFAS Nos. 87, 106, 112 and 158, which provide guidance
on benefit plan accounting. See Note 11 – Retirement
Benefits to our financial statements under Part II, Item 8,
of this report.
Uncertainties Affecting Application
‰
‰
‰
‰
‰
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Future rate of return on pension and other plan assets
Interest rates used in valuing benefit obligations
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 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 to our financial statements 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 to our financial statements under Part II, Item 8, of this report.
EFFECTS OF INFLATION AND CHANGING PRICES
Our 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. Our Non-rate-regulated Generation businesses
do not have regulated recovery mechanisms.
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 a part of the electric rate order
issued by the MoPSC on January 27, 2009, UE was granted
permission to put in place, effective March 1, 2009, a FAC.
See Note 2 – Rate and Regulatory Matters to our financial
statements under Part II, Item 8, of this report for
information on UE’s electric rate order.
In July 2005, a law was enacted that enables the
MoPSC to also put in place mechanisms for Missouri’s
utilities to recover environmental costs directly from
customers outside of a rate case proceeding. The MoPSC
initiated a proceeding in December 2008 to develop revised
rules for the environmental cost recovery mechanisms.
Rules for the environmental cost recovery mechanism are
expected to be approved by the MoPSC during the second
quarter of 2009 and will be effective once published in the
Missouri Register. 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.
Effective January 2, 2007, ICC-approved tariffs in
Illinois allow CIPS, CILCO and IP to recover power supply
costs from electric customers by adjusting rates to
accommodate changes in power prices. See Note 2 – Rate
and Regulatory Matters to our financial statements under
Part II, Item 8, of this report for information on the Illinois
electric rate settlement agreement that addressed legislative
and other efforts to limit full recovery of power costs in
Illinois.
In our Missouri and Illinois retail gas utility
jurisdictions, changes in gas costs are generally reflected in
billings to gas customers through PGA clauses. During
2008, the MoPSC approved two UE requests to recover gas
infrastructure replacement costs through the establishment
of an ISRS. UE commenced recovering annual revenues of
$2 million in the aggregate, effective in March and
November 2008 through the ISRS.
UE, Genco, CILCORP 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 further information. Also see Note 2 – Rate and
Regulatory Matters to our financial statements under Part II,
Item 8, of this report for further information on the cost
recovery mechanisms discussed above.
73
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:
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long-term and short-term variable-rate debt;
fixed-rate debt;
commercial paper; and
auction-rate long-term debt.
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, 2008:
Interest Expense
Net Income(a)
Ameren(b)
. . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . .
$ 14
6
1
1
5
3
(c)
$ (9)
(3)
(1)
(c)
(3)
(2)
(c)
(a) Calculations are based on an effective tax rate of 38%.
(b)
(c) Less than $1 million.
Includes intercompany eliminations.
The estimated changes above do not consider 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.
Insured Tax-exempt Auction-Rate Bonds
Certain auction-rate tax-exempt environmental
improvement and pollution control revenue bonds
previously issued for the benefit of UE, CIPS, CILCO and IP
through governmental authorities were insured by
“monoline” bond insurers. See Note 5 – Long-term Debt
and Equity Financings under Part II, Item 8, of this report
for a description and details of this indebtedness. As a
result of developments in the capital markets with respect
to residential mortgage-backed securities and collateralized
debt obligations, the credit rating agencies have
downgraded the credit ratings of the monoline bond
insurers that insured such securities. As a result, our
insured auction-rate bonds were similarly downgraded. In
2008, we experienced higher interest expense and/or “failed
auctions,” in which there were not sufficient clearing bids in
an auction to set the interest rate for a portion of our
auction-rate bonds. According to press reports, many other
series of auction-rate securities similarly experienced “failed
auctions.”
To mitigate the effect of these credit ratings
downgrades and the resulting impact on the interest rates
of our auction-rate tax-exempt environmental improvement
and pollution control revenue bonds, we redeemed all of
UE’s, CIPS’, CILCO’s and IP’s outstanding auction-rate
bonds, except for UE’s 1992 Series and 1998 Series A, B
and C bonds, which had an aggregate balance of
$207 million at December 31, 2008, and interest rates
ranging from 1.313% to 9.975% during the year ended
December 31, 2008. In April 2008, UE and IP issued senior
secured notes in the principal amount of $250 million and
$337 million, respectively, to refinance their auction-rate
indebtedness. See Note 5 – Long-term Debt and Equity
Financings under Part II, Item 8, of this report for a
description of these redemptions and refinancings.
Credit Risk
Credit risk represents the loss that would be
recognized if counterparties fail to perform as contracted.
NYMEX-traded futures contracts are supported by the
financial and credit quality of the clearing members of the
NYMEX 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.
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.
74
The 2007 increase in electric rates in Illinois, and a
Equity Price Risk
related increase in extended payment plan arrangements,
resulted in an increase in the Ameren Illinois Utilities’
past-due accounts receivable balances during 2007 and the
first quarter of 2008. Such past-due balances have
improved during the last nine months of 2008, primarily as
a result of enhanced collection efforts and an increase in the
volume of write-offs of past-due balances deemed
uncollectible. The Ameren Illinois Utilities will continue to
monitor the impact of increased electric rates on customer
collections and to make adjustments to their allowances for
doubtful accounts, as deemed necessary, to ensure that
such allowances are adequate to cover estimated
uncollectible customer account balances.
At December 31, 2008, no single nonaffiliated
customer represented more than 10%, in the aggregate, of
our accounts receivable. Our revenues are primarily derived
from sales of electricity and natural gas to customers in
Missouri and Illinois. UE, CIPS, Genco, 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, 2008, UE’s,
CIPS’, Genco’s, CILCO’s, IP’s, AFS’, and Marketing
Company’s combined credit exposure to nonaffiliated
non-investment-grade trading counterparties related to
interchange or wholesale purchases and sales was less than
$1 million, net of collateral (2007 – 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 Day Two
Energy Market to be $46 million at December 31, 2008
(2007 – $63 million).
The Ameren Illinois Utilities will be exposed to credit
risk in the event of nonperformance by the parties
contributing to the Illinois comprehensive rate relief and
assistance programs under the Illinois electric settlement
agreement. The agreement provides to certain electric
customers of the Ameren Illinois Utilities $488 million in
rate relief over a four-year period that commenced in 2007.
Under funding agreements among the parties contributing
to the rate relief and assistance programs, at the end of
each month, the Ameren Illinois Utilities bill the
participating generators for their proportionate share of that
month’s rate relief and assistance, which is due in 30 days,
or drawn from the funds provided by the generators’
escrow. See Note 2 – Rate and Regulatory Matters to our
financial statements under Part II, of this report for
additional information.
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 earn the highest possible return on plan assets
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. Assumed
projected rates of return for each asset class were selected
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%. See Outlook in
Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7 of
this report for discussion of the impact of 2008 investment
returns.
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, 2008, this fund was
invested primarily in domestic equity securities (55%) and
debt securities (45%). It totaled $239 million (in 2007 –
$307 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 fixed-rate, fixed-income
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.
75
Foreign Currency Risk
Ameren and UE are exposed to foreign currency
exchange risk from UE’s procurement agreement related to
construction of a potential new nuclear unit. This agreement
provides a fixed price for heavy forgings as well as
consulting services to aid with design certification. The
agreement requires UE to pay for goods and services in
euros. UE uses foreign currency forward contracts for the
purchase of euros to mitigate the impact of changes in
foreign currency exchange rates, which could affect the
amount of U.S. dollars required to satisfy the obligation
denominated in euros. To the extent the value of the U.S.
dollar versus the euro declines, the effect would be reflected
in construction work in process within property and plant,
net, and would be subject to routine depreciation and
impairment considerations.
Commodity Price Risk
We are exposed to changes in market prices for
electricity, 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 2009 through 2012:
Ameren(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO (AERG) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EEI
Net Income(a)
$
(27)
(10)
(9)
(3)
(7)
(a) Calculations are based on an effective tax rate of 38%.
(b)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries and intercompany eliminations.
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
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.
On September 15, 2008, Lehman filed for protection
under Chapter 11 of the federal Bankruptcy Code in the U.S.
Bankruptcy Court in the Southern District of New York. At
that time, UE, CIPS, Genco, IP, Marketing Company and
AFS were counterparties with Lehman Brothers Commodity
Services Inc. (Lehman Commodity Services), a subsidiary
of Lehman, in energy commodity transactions that support
their utility and generation businesses. The obligations of
Lehman Commodity Services were guaranteed by Lehman,
and the Lehman bankruptcy filing gives UE, CIPS, Genco,
IP, Marketing Company and AFS the right to terminate any
open transactions. On October 21, 2008, Ameren sent
notice to Lehman Commodity Services terminating all
transactions between UE, Genco, and Marketing Company
and Lehman Commodity Services. As of December 31,
2008, Ameren’s and its subsidiaries’ direct exposure to
Lehman Commodity Services, based on existing
transactions and current market prices, was estimated to be
less than $1 million before taxes, collectively.
We manage risks associated with changing prices of
fuel for generation using similar techniques as 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 was effective March 1, 2009. The
FAC allows UE to recover directly from its electric
customers 95% of changes in fuel and purchased power
costs, net of off-system revenues, including MISO costs
and revenues, above or below the amount set in base rates,
subject to MoPSC prudency review. Thus, 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,
76
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.
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
2009 through 2013, as of December 31, 2008. The projected required supply of these commodities could be significantly
affected by changes in our assumptions for such matters as customer demand of our electric generation and our electric and
natural gas distribution services, generation output, and inventory levels, among other matters.
2009
2010
2011 - 2013
Ameren:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for distribution(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power for Illinois Regulated(b)
UE:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for distribution(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
95%
100
100
31
84
80
96%
100
100
22
85
86%
76
100
3
36
57
90%
63
100
5
45
CIPS:
Natural gas for distribution(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power(b)
87%
80
40%
57
Genco:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO:
Coal (AERG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation (AERG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas for distribution(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power(b)
94%
100
30
89%
100
87
80
87%
67
-
67%
67
37
57
IP:
Natural gas for distribution(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased power(b)
80%
80
31%
57
EEI:
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
96%
89%
100
100
22%
37
81
-
13
32
23%
25
81
-
13
16%
32
16%
45
-
31%
46
10
32
13%
32
24%
67
(a) Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2009 represents January
2009 through March 2009. The year 2010 represents November 2009 through March 2010. This continues each successive year through
March 2013.
(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 to our financial statements 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.
77
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 2009 through 2013.
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.
Coal
Transportation
Fuel
Expense
Net
Income(a)
Fuel
Expense
Net
Income(a)
Ameren(b)
. . . . . . .
UE . . . . . . . . . . . . .
Genco . . . . . . . . . .
CILCORP . . . . . . . .
CILCO . . . . . . . . . .
. . . . . . . . . . . .
EEI
$
37
15
14
5
5
3
$
(23)
(10)
(8)
(3)
(3)
(2)
$
17
13
2
1
1
1
$
(11)
(8)
(1)
(1)
(1)
(1)
(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 $13 million annually (UE –
$7 million, Genco – $3 million, AERG – $1 million and EEI –
$2 million). As of December 31, 2008, Ameren had price-
hedged approximately 100% of expected fuel surcharges in
2009.
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 fixed-priced and base-price-with-
escalation agreements, or it 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 2009 or
2012. UE has price hedges for 87% of the 2010 to 2013
nuclear fuel requirements.
Although nuclear fuel market prices declined in 2008,
pricing remains subject to an unpredictable supply and
demand environment. UE has continued to follow a strategy
of managing 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 which cannot now be accurately
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
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 Day Two Energy 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 natural gas distribution business
and, commencing March 1, 2009, its electric distribution
business, and to 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 to our financial statements under Part II,
Item 8, of this report for further information.
78
Fair Value of Contracts
Most of our commodity contracts qualify for treatment
as normal purchases and normal sales. We use derivatives
principally to manage the risk of changes in market prices
for natural gas, fuel, electricity, FTRs and emission
allowances.
Price fluctuations in natural gas, fuel, electricity, FTRs
and emission allowances may cause any of these
conditions:
‰
an unrealized appreciation or depreciation of our
contracted commitments to purchase or sell when
purchase or sales prices under the commitments are
compared with current commodity prices;
‰ market values of fuel and natural gas inventories or
purchased power that differ from the cost of those
commodities in inventory under contracted
commitment; or
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.
See Note 7 – Derivative Financial Instruments to our
financial statements under Part II, Item 8, of this report for
further 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, 2008. We use various methods to determine the fair value of our
contracts. In accordance with SFAS No. 157 hierarchy levels, our sources 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.
Ameren(a)
UE
CIPS
Genco
CILCORP/
CILCO
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 technique
and assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of new contracts entered into during the period . . . . . . . . . .
Other changes in fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Fair value of contracts outstanding at end of year, net . . . . . . . . . . . . . .
$
13
(20)
-
48
(21)
20
$
$
7
(17)
$
38
2
$
-
21
5
16
-
(25)
(99)
$ (84)
$
(4)
4
-
(1)
-
(1)
$
$
21
4
-
(23)
(61)
(59)
IP
$
55
10
-
(38)
(161)
$
(134)
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
The following table presents maturities of derivative contracts as of December 31, 2008, 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maturity
Less than
1 Year
Maturity
1 - 3 Years
Maturity
4 - 5 Years
Maturity in
Excess of
5 Years
Total
Fair Value
(8)
13
46
51
-
11
14
25
-
-
(31)
(31)
-
-
(1)
(1)
$
$
$
$
$
$
$
$
-
-
(25)
(25)
-
-
(8)
(8)
-
-
(41)
(41)
-
-
-
-
$
$
$
$
$
$
$
$
-
-
(6)
(6)
-
-
(1)
(1)
-
-
(12)
(12)
-
-
-
-
$
$
$
$
$
$
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$
$
$
$
$
$
$
$
(8)
13
15
20
-
11
5
16
-
-
(84)
(84)
-
-
(1)
(1)
$
$
$
$
$
$
$
$
79
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
CILCORP/CILCO:
Level 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 2(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 3(b)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP:
Level 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 2(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 3(b)
$
$
$
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(4)
-
(25)
(29)
-
-
(56)
(56)
$
$
$
$
-
-
(25)
(25)
-
-
(61)
(61)
$
$
$
$
-
-
(5)
(5)
-
-
(17)
(17)
$
$
$
$
-
-
-
-
-
-
-
-
$
$
$
$
(4)
-
(55)
(59)
-
-
(134)
(134)
(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 coal and SO2 option values based on a Black-Scholes model that includes information from external sources and our estimates.
Level 3 also includes interruptible power forward and 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, 2008 and 2007, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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. Also, in our opinion,
the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008,
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 schedule, 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 schedule, 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.
As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007.
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.
80
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
March 2, 2009
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, 2008 and 2007, and
the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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.
As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
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, 2008 and 2007, and the results of its
operations and its cash flows for each of the three years in the period ended December 31, 2008 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.
As discussed in Note 13 to the financial statements, the Company changed the manner in which it accounts for uncertain tax
positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
81
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, 2008 and
2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31,
2008 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
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.
As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder
of CILCORP Inc.:
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 CILCORP Inc. and its subsidiaries at December 31, 2008 and 2007, and the results
of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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.
As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
82
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, 2008 and 2007,
and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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.
As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
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, 2008 and 2007, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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.
As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for
uncertain tax positions as of January 1, 2007.
/s/PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
83
AMEREN CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(In millions, except per share amounts)
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, Minority Interest, and Preferred Dividends
of Subsidiaries
Income Taxes
Income Before Minority Interest and Preferred Dividends of Subsidiaries
Minority Interest and Preferred Dividends of Subsidiaries
Net Income
Earnings per Common Share – Basic and Diluted
Dividends per Common Share
Average Common Shares Outstanding
Year Ended December 31,
2008
2007
2006
$ 6,367
1,472
$ 6,283
1,279
$ 5,600
1,295
7,839
7,562
6,895
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
$
$
$
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
1,018
1,150
931
1,556
661
391
5,707
1,188
50
(19)
31
350
869
284
585
38
547
2.66
2.54
205.6
$
$
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
84
AMEREN CORPORATION
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
Current Assets:
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $28 and
ASSETS
$22, 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 STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt
Short-term debt
Accounts and wages payable
Taxes accrued
Mark-to-market derivative liabilities
Other current liabilities
Total current liabilities
Long-term Debt, Net
Preferred Stock of Subsidiary Subject to Mandatory Redemption
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
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption
Minority Interest in Consolidated Subsidiaries
Commitments and Contingencies (Notes 2, 14, 15 and 16)
Stockholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 212.3 and
208.3, respectively
Other paid-in capital, principally premium on common stock
Retained earnings
Accumulated other comprehensive income
Total stockholders’ equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
December 31,
2008
2007
$
92
$
355
502
427
292
842
207
153
2,515
16,567
570
359
262
735
35
146
2,462
15,069
239
831
167
1,732
606
3,575
$ 22,657
307
831
198
1,158
703
3,197
$ 20,728
$
380
1,174
813
54
155
487
3,063
6,554
-
2,131
100
1,291
406
1,495
438
5,861
195
21
$
223
1,472
687
84
24
414
2,904
5,689
16
2,046
109
1,240
562
839
354
5,150
195
22
2
4,780
2,181
-
6,963
$ 22,657
2
4,604
2,110
36
6,752
$ 20,728
The accompanying notes are an integral part of these consolidated financial statements.
85
AMEREN CORPORATION
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
activities:
Gain on sales of emission allowances
Gain on sales of noncore properties
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
Minority interest
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued, net
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
CT acquisitions
Proceeds from sales of noncore properties, net
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 debt, net
Dividends paid to minority interest holder
Redemptions, repurchases, and maturities:
Long-term debt
Preferred stock
Issuances:
Common stock
Long-term debt
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:
Interest
Income taxes, net
Year Ended December 31,
2008
2007
2006
$
605
$
618
$
547
(8)
-
14
(3)
705
37
20
167
29
(9)
25
(100)
57
(30)
63
183
(4)
(69)
(149)
(8)
(3)
-
(3)
735
37
19
(28)
27
12
(194)
(88)
-
21
49
(36)
27
(27)
(56)
(60)
(37)
-
(2)
656
36
15
91
27
13
173
(75)
(91)
(72)
(95)
85
97
(6)
(23)
1,533
1,102
1,279
(1,896)
-
-
(173)
(520)
497
(12)
4
3
(2,097)
(534)
(12)
(298)
(30)
(842)
(16)
154
1,879
301
(263)
355
92
450
106
$
$
(1,381)
-
13
(68)
(142)
128
(24)
5
1
(1,468)
(527)
(4)
860
(21)
(488)
(1)
91
674
584
218
137
355
422
283
$
$
(992)
(292)
56
(39)
(110)
98
(42)
71
(16)
(1,266)
(522)
(4)
419
(28)
(164)
(1)
96
232
28
41
96
137
320
403
$
$
The accompanying notes are an integral part of these consolidated financial statements.
86
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
Reclassification of unearned compensation
Shares issued (less issuance costs of $-, $-, and $1, respectively)
Stock-based compensation cost
Tax benefit of stock option exercises
Other paid-in capital, end of year
Retained Earnings:
Beginning of year
Net income
Dividends
Adjustment to adopt FIN 48
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
Minimum pension liability, beginning of year
Change in minimum pension liability
Minimum pension liability, end of year
Deferred retirement benefit costs, beginning of year
Adjustment to adopt SFAS No. 158
Change in deferred retirement benefit costs
Deferred retirement benefit costs
Total accumulated other comprehensive income, end of year
Other:
Beginning of year
Reclassification of unearned compensation
Other, end of year
Total Stockholders’ Equity
Comprehensive Income, Net of Taxes:
December 31,
2007
2008
2006
$
$
2
-
2
$
2
-
2
2
-
2
4,604
-
154
22
-
4,780
2,110
605
(534)
-
2,181
9
39
48
-
-
-
27
-
(75)
(48)
-
4,495
-
91
18
-
4,604
2,024
618
(527)
(5)
2,110
60
(51)
9
-
-
-
2
-
25
27
36
4,399
(12)
96
11
1
4,495
1,999
547
(522)
-
2,024
40
20
60
(64)
64
-
-
2
-
2
62
-
-
-
$ 6,963
-
-
-
$ 6,752
(12)
12
-
$ 6,583
$
618
$
547
Net income
Unrealized net gain (loss) on derivative hedging instruments, net of income
$
taxes (benefit) of $65, $(7), and $11, respectively
Reclassification adjustments for derivative (gains) included in net income,
net of income taxes of $43, $22, and $3, respectively
Minimum pension liability adjustment, net of income taxes of $-, $-, and
$41, respectively
Pension and other postretirement activity, net of taxes (benefit) of $(45),
$1, and $-, respectively
Total Comprehensive Income, Net of Taxes
$
605
116
(77)
-
(75)
569
(12)
(39)
-
25
592
$
Common stock shares at beginning of year
Shares issued
Common stock shares at end of year
208.3
4.0
212.3
206.6
1.7
208.3
The accompanying notes are an integral part of these consolidated financial statements.
87
28
(8)
64
-
631
$
204.7
1.9
206.6
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
Year Ended December 31,
2007
2008
2006
Operating Revenues:
Electric – excluding off-system
Electric – off-system
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
$ 2,266
490
201
3
$ 2,302
484
174
1
$ 2,204
459
158
2
2,960
2,961
2,823
672
160
123
922
329
240
2,446
514
62
(9)
53
193
374
134
240
11
251
6
608
192
104
900
333
234
2,371
590
38
(7)
31
194
427
140
287
55
342
6
492
261
98
787
335
230
2,203
620
38
(8)
30
171
479
184
295
54
349
6
Net Income Available to Common Stockholder
$
245
$
336
$
343
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
88
UNION ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except per share amounts)
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $6, respectively)
Unbilled revenue
Miscellaneous accounts and notes receivable
Advances to money pool
Accounts receivable – affiliates
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
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
Taum Sauk pumped-storage hydroelectric facility liability
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
December 31,
2008
2007
-
142
111
261
-
32
339
50
48
983
8,995
239
48
907
352
$
185
191
118
213
15
90
301
7
43
1,163
8,189
307
56
697
491
1,546
1,551
$ 11,524
$ 10,903
$
4
251
92
360
151
20
56
18
103
1,055
3,673
1,372
80
922
317
494
49
3,234
511
1,119
113
1,794
25
$
152
82
-
315
212
78
47
103
59
1,048
3,208
1,273
85
865
476
297
50
3,046
511
1,119
113
1,855
3
Total stockholders’ equity
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
3,562
$ 11,524
3,601
$ 10,903
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
89
UNION ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2007
2008
2006
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
$
251
$
342
$
349
activities:
Gain on sales of emission allowances
Net mark-to-market (gain) loss on derivatives
Gain on sale of noncore properties
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, net
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
CT acquisitions
Nuclear fuel expenditures
Changes in money pool advances, net
Proceeds from intercompany note receivable
Sale of noncore properties
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
Changes in 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 (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
Income taxes, net
(5)
29
-
329
37
6
89
(28)
85
(32)
(89)
(61)
22
61
-
(149)
545
(874)
-
(173)
-
36
-
(520)
497
1
(1,033)
(264)
(6)
(5)
169
92
(382)
699
-
-
303
(185)
185
-
196
130
$
$
(5)
(2)
-
333
37
6
1
(6)
(60)
(65)
42
12
39
(48)
18
(56)
588
(625)
-
(68)
3
-
-
(142)
128
4
(700)
(267)
(6)
(3)
(152)
(77)
(4)
424
380
1
296
184
1
185
218
106
$
$
$
$
(34)
(7)
(13)
335
36
5
38
(1)
52
(37)
21
7
(79)
49
36
(23)
734
(490)
(292)
(39)
(18)
67
13
(110)
98
39
(732)
(249)
(6)
-
154
77
(4)
-
6
1
(21)
(19)
20
1
144
185
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
90
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 FIN 48
Retained earnings, end of year
Accumulated Other Comprehensive Income:
Derivative financial instruments, beginning of year
Change in derivative financial instruments
Derivative financial instruments, end of year
Minimum pension liability, beginning of year
Change in minimum pension liability
Minimum pension liability, end of year
Total accumulated other comprehensive income, end of year
Total Stockholders’ Equity
Comprehensive Income, Net of Taxes:
December 31,
2007
2008
2006
$
511
$
511
$
511
1,119
-
1,119
113
1,855
251
(264)
(6)
(42)
-
1,794
3
22
25
-
-
-
25
739
380
1,119
113
1,783
342
(267)
(6)
-
3
1,855
7
(4)
3
-
-
-
3
733
6
739
113
1,689
349
(249)
(6)
-
-
1,783
5
2
7
(35)
35
-
7
$ 3,562
$ 3,601
$ 3,153
Net income
Unrealized net gain on derivative hedging instruments, net of income taxes
$
251
$
342
$
349
of $22, $-, and $4, respectively
Reclassification adjustments for derivative (gains) included in net income,
net of income taxes of $9, $2, and $4, respectively
Minimum pension liability adjustment, net of income taxes of $-, $-, and
$22, respectively
36
(14)
-
-
(4)
-
Total Comprehensive Income, Net of Taxes
$
273
$
338
$
9
(7)
35
386
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
91
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF INCOME
(In millions)
Year Ended December 31,
2007
2008
2006
$
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
Net Income Available to Common Stockholder
$
720
259
3
982
461
179
196
67
37
940
42
11
(3)
8
30
20
5
15
3
12
$
$
772
230
3
1,005
527
157
172
66
34
956
49
17
(3)
14
37
26
9
17
3
14
$
$
728
220
6
954
471
149
161
63
41
885
69
17
(2)
15
31
53
15
38
3
35
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
92
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 $6 and $5,
$
-
$
26
December 31,
2008
2007
respectively)
Unbilled revenue
Miscellaneous accounts and notes receivable
Accounts receivable – affiliates
Current portion of intercompany note receivable – Genco
Current portion of intercompany tax receivable – Genco
Materials and supplies
Counterparty collateral asset
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:
Current maturities of long-term debt
Short-term debt
Accounts and wages payable
Accounts payable – affiliates
Borrowings from money pool
Taxes accrued
Customer deposits
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 and investment tax credits, 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, 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
79
74
1
4
42
9
70
21
22
322
1,212
62
66
1
9
39
9
66
-
16
294
1,174
45
93
212
33
383
$ 1,917
87
105
113
87
392
$ 1,860
$
-
62
48
49
44
7
16
17
14
51
308
421
268
234
79
78
659
$
15
125
44
19
-
8
16
1
-
30
258
456
269
265
67
28
629
-
191
50
288
529
$ 1,917
-
191
50
276
517
$ 1,860
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
93
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2007
2008
2006
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
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, net
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
Bond repurchase
Changes in money pool advances, net
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
Changes in money pool borrowings, net
Redemptions, repurchases, and maturities:
Long-term debt
Intercompany note payable
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 (Refunded) During the Year:
Interest
Income taxes, net
$
15
$
17
$
38
67
1
(2)
(8)
(4)
14
(1)
(5)
26
-
103
(96)
39
-
-
(57)
-
(3)
-
(63)
44
(50)
-
-
-
(72)
(26)
26
-
32
(21)
$
$
66
1
(27)
(19)
5
(48)
(2)
21
(3)
3
14
(79)
37
-
-
(42)
(40)
(3)
-
90
-
-
-
-
1
48
20
6
26
36
44
$
$
63
1
(13)
50
4
2
(16)
(12)
(5)
6
118
(82)
34
(17)
(1)
(66)
(50)
(3)
(1)
35
(2)
(20)
(67)
61
1
(46)
6
-
6
27
62
$
$
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
94
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Equity contribution from parent
Other paid-in capital, end of year
Preferred Stock Not Subject to Mandatory Redemption
Retained Earnings:
Beginning of year
Cumulative effect adjustment
Beginning of year – as adjusted
Net income
Common stock dividends
Preferred stock dividends
Retained earnings, end of year
Accumulated Other Comprehensive Income:
Derivative financial instruments, beginning of year
Change in derivative financial instruments
Derivative financial instruments, end of year
Minimum pension liability, beginning of year
Change in minimum pension liability
Minimum pension liability, end of year
Total accumulated other comprehensive income, 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 $(3), respectively
Reclassification adjustments for (gains) included in net income, net of
income taxes of $-, $1, and $1, respectively
Minimum pension liability adjustment, net of income taxes of $-, $-, and
$4, respectively
December 31,
2007
2008
2006
$
-
$
-
$
-
191
-
191
50
276
-
276
15
-
(3)
288
-
-
-
-
-
-
-
$
$
529
15
$
$
-
-
-
190
1
191
50
302
-
302
17
(40)
(3)
276
1
(1)
-
-
-
-
-
517
17
-
(1)
-
16
189
1
190
50
329
(12)
317
38
(50)
(3)
302
7
(6)
1
(6)
6
-
1
543
38
(5)
(1)
6
38
$
$
$
Total Comprehensive Income, Net of Taxes
$
15
$
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
95
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
Year Ended December 31,
2007
2008
2006
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
$
908
$
876
$
992
377
(60)
-
175
65
21
578
330
1
(1)
-
55
275
100
344
-
23
163
69
19
618
258
-
-
-
55
203
78
$
175
$
125
$
298
-
320
153
72
18
861
131
-
-
-
60
71
22
49
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
96
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
Materials and supplies
Other current assets
Total current assets
Property and Plant, Net
Intangible Assets
Other Assets
TOTAL ASSETS
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-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
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
December 31,
2008
2007
$
2
88
15
122
10
237
1,950
49
8
$
2
93
12
93
4
204
1,683
63
18
$ 2,244
$ 1,968
$
$
-
42
80
82
58
9
16
43
330
774
45
136
6
93
49
67
49
400
-
503
241
(49)
695
100
39
54
61
57
9
15
30
365
474
87
161
7
105
47
32
42
394
-
503
167
(22)
648
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
$ 2,244
$ 1,968
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
97
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2007
2008
2006
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
$
175
$
125
$
49
activities:
Gain on sales of emission allowances
Net mark-to-market (gain) loss on derivatives
Depreciation and amortization
Deferred income taxes and investment tax credits, net
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued, net
Assets, other
Liabilities, other
Pension and other postretirement benefits
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Purchases of emission allowances
Sales of emission allowances
Net cash used in investing activities
Cash Flows From Financing Activities:
Dividends on common stock
Debt 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
Income taxes, net
(2)
16
92
14
-
(13)
(29)
(11)
(4)
10
(5)
1
244
(317)
(13)
2
(328)
(101)
(2)
(100)
26
(39)
300
-
84
-
2
2
61
62
$
$
(2)
(2)
101
30
1
10
3
(4)
(7)
3
(8)
5
255
(191)
(20)
1
(210)
(113)
-
100
(69)
(37)
-
75
(44)
1
1
2
59
49
$
$
(1)
5
104
25
(1)
16
(23)
3
(15)
(29)
(1)
6
138
(85)
(26)
1
(110)
(113)
-
-
(80)
(34)
-
200
(27)
1
-
1
51
8
$
$
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
98
December 31,
2007
2008
2006
$
-
$
-
$
-
503
-
503
167
175
(101)
-
241
(1)
(5)
(6)
-
-
-
(21)
-
(22)
(43)
(49)
695
175
-
(5)
-
(22)
428
75
503
156
125
(113)
(1)
167
3
(4)
(1)
-
-
-
(24)
-
3
(21)
(22)
648
125
(3)
(1)
-
3
228
200
428
220
49
(113)
-
156
2
1
3
(6)
6
-
-
(24)
-
(24)
(21)
563
49
3
(2)
6
-
$
$
$
$
AMEREN ENERGY GENERATING COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Capital contribution from Ameren
Other paid-in capital, end of year
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Adjustment to adopt FIN 48
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
Minimum pension liability, beginning of year
Change in minimum pension liability
Minimum pension liability, end of year
Deferred retirement benefit costs, beginning of year
Adjustment to adopt SFAS No. 158
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 gain (loss) on derivative hedging instruments, net of income
taxes (benefit) of $-, $(2), and $2, respectively
Reclassification adjustments for derivative gains included in net income,
net of income taxes of $3, $1, and $1, respectively
Minimum pension liability, net of income taxes of $-, $-, and $4,
respectively
Pension and other postretirement activity, net of taxes (benefit) of $(19),
$5, and $-, respectively
$
$
Total Comprehensive Income, Net of Taxes
$
148
$
124
$
56
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
99
CILCORP INC.
CONSOLIDATED STATEMENT OF INCOME
(In millions)
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 expenses
Interest Charges
Income Before Income Taxes and Preferred Dividends of Subsidiaries
Income Taxes (Benefit)
Income Before Preferred Dividends of Subsidiaries
Preferred Dividends of Subsidiaries
Net Income
$
Year Ended December 31,
2007
2008
2006
$
$
771
375
1
$
681
329
1
1,147
1,011
413
333
1
747
109
49
246
179
75
25
683
64
2
(4)
(2)
52
10
(11)
21
2
19
126
291
284
220
81
25
1,027
120
2
(5)
(3)
55
62
19
43
1
42
$
77
281
237
181
78
23
877
134
5
(5)
-
64
70
21
49
2
47
$
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
100
CILCORP INC.
CONSOLIDATED BALANCE SHEET
(In millions, except shares)
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $3 and $2,
$
-
$
6
December 31,
2008
2007
respectively)
Unbilled revenue
Accounts and notes receivable – affiliates
Advances to money pool
Materials and supplies
Deferred taxes – current
Other current assets
Total current assets
Property and Plant, Net
Investments and Other Assets:
Goodwill
Intangible assets
Regulatory assets
Other assets
Total investments and other assets
TOTAL ASSETS
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Current maturities of long-term debt
Short-term debt
Borrowings from money pool
Intercompany note payable – Ameren
Accounts and wages payable
Accounts payable – affiliates
Taxes accrued
Other current liabilities
Total current liabilities
Long-term Debt, Net
Preferred Stock of Subsidiary Subject to Mandatory Redemption
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
Accumulated deferred investment tax credits
Regulatory liabilities
Pension and other postretirement benefits
Other deferred credits and liabilities
Total deferred credits and other liabilities
Preferred Stock of Subsidiary Not Subject to Mandatory Redemption
Commitments and Contingencies (Notes 2, 14 and 15)
Stockholder’s Equity:
Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding
Other paid-in capital
Retained earnings
Accumulated other comprehensive income
Total stockholder’s equity
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY
60
65
59
2
131
24
27
368
1,710
52
54
48
1
110
17
23
311
1,494
542
35
188
22
787
$ 2,865
542
41
32
39
654
$ 2,459
$
126
286
98
152
117
84
4
97
964
536
-
212
5
59
216
104
596
19
$
-
520
-
2
75
34
3
54
688
537
16
193
6
92
127
66
484
19
-
627
100
23
750
$ 2,865
-
627
58
30
715
$ 2,459
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
101
CILCORP INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2007
2008
2006
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
$
42
$
47
$
19
activities:
Net mark-to-market loss on derivatives
Depreciation and amortization
Amortization of debt issuance costs and premium/discounts
Deferred income taxes and investment tax credits
Loss on asset impairments
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued, net
Assets, other
Liabilities, other
Pension and postretirement benefits
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital expenditures
Proceeds from affiliate note receivable
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
Intercompany note payable – Ameren, net
Money pool borrowings, net
Redemptions, repurchases, and maturities of:
Long-term debt
Preferred stock
Issuances of long-term debt
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
9
81
1
20
14
-
(32)
(21)
65
11
(10)
15
(11)
184
(319)
-
(1)
-
-
2
(318)
-
(1)
(234)
150
98
(19)
(16)
150
128
(6)
6
-
72
(33)
-
87
1
(5)
-
1
(45)
(17)
(21)
(2)
10
(12)
(12)
32
(254)
-
41
-
-
-
(213)
-
-
305
(71)
-
(50)
(1)
-
183
2
4
6
50
16
$
$
$
$
1
91
1
10
-
8
36
(8)
(8)
1
-
-
(18)
133
(119)
71
(42)
(12)
1
11
(90)
(50)
(2)
215
(113)
(154)
(33)
(1)
96
(42)
1
3
4
53
(4)
$
$
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
102
CILCORP INC.
CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Common stock dividends
Contribution from intercompany sale of leveraged leases
Other paid-in capital, end of year
Retained Earnings:
Beginning of year
Net income
Common stock dividends
Retained earnings, end of year
Accumulated Other Comprehensive Income:
Derivative financial instruments, beginning of year
Change in derivative financial instruments
Derivative financial instruments, end of year
Minimum pension liability, beginning of year
Change in minimum pension liability
Minimum pension liability, end of year
Deferred retirement benefit costs, beginning of year
Adjustment to adopt SFAS No. 158
Change in deferred retirement benefit costs
Deferred retirement benefit costs, end of year
Total accumulated other comprehensive income, 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 $-, $(1), and $(13), respectively
Reclassification adjustments for derivative (gains) included in net income,
net of income taxes of $1, $1, and $1, respectively
Minimum pension liability adjustment, net of income taxes of $-, $-, and
$2, respectively
Pension and other postretirement activity, net of taxes (benefit) of $(5), $-,
and $-, respectively
Total Comprehensive Income, Net of Taxes
$
$
$
December 31,
2007
2008
2006
$
-
$
-
$
-
627
-
-
627
58
42
-
100
1
(1)
-
-
-
-
29
-
(6)
23
23
750
42
-
(1)
-
(6)
35
627
-
-
627
11
47
-
58
4
(3)
1
-
-
-
29
-
-
29
30
715
47
(1)
(2)
-
-
$
$
$
$
$
44
$
640
(42)
29
627
-
19
(8)
11
25
(21)
4
(2)
2
-
-
29
-
29
33
671
19
(20)
(1)
2
-
-
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
103
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
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 expenses
Interest Charges
Income Before Income Taxes
Income Taxes
Net Income
Preferred Stock Dividends
Net Income Available to Common Stockholder
$
Year Ended December 31,
2007
2008
2006
$
$
771
375
1
$
681
329
1
1,147
1,011
413
333
1
747
99
49
246
180
70
25
669
78
1
(4)
(3)
18
57
10
47
2
45
121
291
284
217
77
25
1,015
132
2
(5)
(3)
21
108
39
69
1
68
71
280
237
184
73
23
868
143
5
(6)
(1)
27
115
39
76
2
74
$
$
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
104
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $3 and $2,
$
-
$
6
December 31,
2008
2007
respectively)
Unbilled revenue
Accounts receivable – affiliates
Materials and supplies
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
Accounts and wages payable
Accounts payable – affiliates
Taxes accrued
Other current liabilities
Total current liabilities
Long-term Debt, Net
Preferred Stock Subject to Mandatory Redemption
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net
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, 20.0 shares authorized – 13.6 shares outstanding
Other paid-in capital
Preferred stock not subject to mandatory redemption
Retained earnings
Accumulated other comprehensive income (loss)
Total stockholders’ equity
60
65
51
131
42
349
52
54
45
110
27
294
1,734
1,492
1
188
22
211
1
32
43
76
$ 2,294
$ 1,862
$
$
236
98
117
83
8
88
630
279
-
171
5
206
216
103
701
-
429
19
240
(4)
684
345
-
75
34
3
45
502
148
16
155
6
220
127
66
574
-
429
19
172
2
622
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$ 2,294
$ 1,862
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
105
CENTRAL ILLINOIS LIGHT COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2007
2008
2006
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
$
69
$
76
$
47
activities:
Net mark-to-market 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
Other
Changes in assets and liabilities:
Receivables
Materials and supplies
Accounts and wages payable
Taxes accrued, net
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
Sales 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
Money pool borrowings, net
Redemptions, repurchases, and maturities of:
Long-term debt
Preferred stock
Issuances of long-term debt
Capital contribution from parent
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
Income taxes, net
9
77
1
15
12
-
(27)
(21)
65
12
(7)
15
(11)
209
(319)
-
-
-
2
(317)
-
(1)
(1)
(109)
98
(19)
(16)
150
-
102
(6)
6
-
32
(15)
-
74
1
(1)
-
-
(42)
(17)
(6)
(2)
2
(12)
1
74
(254)
42
-
-
-
(212)
-
(2)
-
180
-
(50)
(1)
-
14
141
3
3
6
38
35
$
$
$
$
1
82
1
13
-
5
33
(8)
(19)
-
13
(15)
-
153
(119)
(42)
(12)
1
11
(161)
(65)
(2)
(2)
165
(161)
(21)
(1)
96
-
9
1
2
3
19
17
$
$
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
106
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 FIN 48
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
Minimum pension liability, beginning of year
Change in minimum pension liability
Minimum pension liability, end of year
Deferred retirement benefit costs, beginning of year
Adjustment to adopt SFAS No. 158
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 $-, $(1), and $(13), respectively
Reclassification adjustments for derivative (gains) included in net income,
net of income taxes of $1, $1, and $1, respectively
Minimum pension liability adjustment, net of income taxes of $-, $-, and
$10, respectively
Pension and other postretirement activity, net of taxes (benefit) of $(4), $2,
and $-, respectively
Total Comprehensive Income, Net of Taxes
$
$
$
December 31,
2007
2008
2006
$
-
$
-
$
-
429
-
429
19
172
69
-
(1)
-
240
1
(1)
-
-
-
-
1
-
(5)
(4)
(4)
684
69
-
(1)
-
(5)
63
415
14
429
19
99
76
-
(2)
(1)
172
4
(3)
1
-
-
-
(2)
-
3
1
2
622
76
(1)
(2)
-
3
$
$
$
$
$
76
$
415
-
415
19
119
47
(65)
(2)
-
99
25
(21)
4
(16)
16
-
-
(2)
-
(2)
2
535
47
(20)
(1)
16
-
42
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
107
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions)
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
Net Income Available to Common Stockholder
$
Year Ended December 31,
2007
2008
2006
$ 1,071
620
5
$ 1,104
540
2
$ 1,149
543
2
1,696
1,646
1,694
654
452
318
85
17
67
1,593
103
11
(5)
6
99
10
5
5
2
3
714
390
271
80
16
66
1,537
109
14
(5)
9
77
41
15
26
2
24
$
738
394
271
77
-
73
1,553
141
6
(4)
2
49
94
37
57
2
55
$
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
108
ILLINOIS POWER COMPANY
CONSOLIDATED BALANCE SHEET
(In millions)
Current Assets:
ASSETS
Cash and cash equivalents
Accounts receivable – trade (less allowance for doubtful accounts of $12 and $9,
$
50
$
6
December 31,
2008
2007
respectively)
Unbilled revenue
Accounts receivable – affiliates
Advances to money pool
Materials and supplies
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
Current maturities of long-term debt payable to IP SPT
Short-term debt
Accounts and wages payable
Accounts payable – affiliates
Taxes accrued
Customer deposits
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
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
152
133
23
44
144
77
623
2,329
137
118
17
-
134
38
450
2,220
214
553
47
814
$ 3,766
214
316
119
649
$ 3,319
$
250
-
-
94
105
8
50
36
20
85
648
1,150
176
76
314
151
717
$
-
56
175
85
36
7
40
8
-
32
439
1,014
148
129
189
92
558
-
1,194
46
7
4
1,251
$ 3,766
-
1,194
46
64
4
1,308
$ 3,319
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
109
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
Year Ended December 31,
2007
2008
2006
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating
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, net
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
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
IP SPT maturities
Overfunding of TFNs
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
Income taxes, net
$
5
$
26
$
57
93
9
26
-
(36)
(10)
57
3
(8)
46
(5)
180
(186)
(44)
(3)
(233)
(60)
(2)
(5)
(175)
-
(337)
730
(54)
-
97
44
6
50
76
(43)
$
$
105
8
4
(1)
(65)
(12)
(44)
-
(16)
28
(5)
28
(178)
-
(2)
(180)
(61)
(2)
(2)
100
(43)
-
250
(87)
3
158
6
-
6
66
18
$
$
21
4
75
-
71
-
(17)
(8)
(13)
(8)
(10)
172
(179)
-
(1)
(180)
-
(2)
(1)
75
(32)
-
75
(86)
(21)
8
-
-
-
39
(9)
$
$
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
110
ILLINOIS POWER COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
Common Stock
Other Paid-in Capital:
Beginning of year
Other
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:
Derivative financial instruments, beginning of year
Change in derivative financial instruments
Derivative financial instruments, end of year
Deferred retirement benefit costs, beginning of year
Adjustment to adopt SFAS No. 158
Change in deferred retirement benefit costs
Deferred retirement benefit costs, end of year
Total accumulated other comprehensive income, 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 losses included in net income,
net of income taxes (benefit) of $-, $-, and $(2), respectively
Pension and other postretirement activity, net of taxes of $-, $-, and $-,
respectively
Total Comprehensive Income, Net of Taxes
December 31,
2007
2008
2006
$
-
$
-
$
-
1,194
-
1,194
46
64
5
(60)
(2)
7
-
-
-
4
-
-
4
4
1,194
-
1,194
46
101
26
(61)
(2)
64
-
-
-
5
-
(1)
4
4
1,196
(2)
1,194
46
46
57
-
(2)
101
(1)
1
-
-
5
-
5
5
$ 1,251
$ 1,308
$ 1,346
$
$
5
-
-
-
5
$
26
$
57
-
-
(1)
25
$
(2)
3
-
$
58
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
111
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (Consolidated)
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
AMEREN ENERGY GENERATING COMPANY
(Consolidated)
CILCORP INC. (Consolidated)
CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)
ILLINOIS POWER COMPANY (Consolidated)
COMBINED NOTES TO FINANCIAL STATEMENTS
December 31, 2008
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 rate-regulated electric generation, transmission and
distribution businesses, rate-regulated natural gas
transmission and distribution businesses, and non-rate-
regulated electric generation businesses in Missouri and
Illinois. Dividends on Ameren’s common stock and the
payment of other expenses by the Ameren and CILCORP
holding companies 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 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
1902. It supplies electric and 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 393,000 customers and natural gas service to
185,000 customers.
Genco, or Ameren Energy Generating Company,
operates a non-rate-regulated electric generation
business in Illinois and Missouri. Genco was
incorporated in Illinois in March 2000. Genco owns
‰
‰
2,557 megawatts of coal-fired electric generating
capacity and 1,663 megawatts of natural gas and
oil-fired electric generating capacity.
CILCO, or Central Illinois Light Company, also known
as AmerenCILCO, is a subsidiary of CILCORP (a
holding company). It operates a rate-regulated electric
transmission and distribution business, a non-rate-
regulated electric generation business, and a rate-
regulated natural gas transmission and distribution
business in Illinois. CILCO was incorporated in Illinois
in 1913. It supplies electric and 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 214,000 customers and natural gas
service to 216,000 customers. AERG, a non-rate-
regulated wholly-owned subsidiary of CILCO, owns
1,125 megawatts of coal-fired electric generating
capacity and 15 megawatts of oil-fired electric
generating capacity. CILCORP was incorporated in
Illinois in 1985.
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 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 627,000 customers and natural gas
service to 421,000 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. See Note 14 – Related Party
Transactions for additional information.
The following table presents summarized financial
information of EEI (in millions):
For the years ended December 31,
2008
2007
2006
Operating revenues . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . .
$ 520
226
142
$ 427
216
136
$ 371
227
136
As of December 31,
Current assets . . . . . . . . . . . . . . . . . . . .
Noncurrent assets . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . .
Noncurrent liabilities . . . . . . . . . . . . . . .
$
76
140
93
43
$
69
124
60
10
$
58
108
70
17
112
The financial statements of Ameren, Genco, CILCORP
and CILCO are prepared on a consolidated basis. CIPS has
no subsidiaries and therefore is not consolidated. UE had a
subsidiary in 2007 and 2006 (Union Electric Development
Corporation), but in January 2008 this subsidiary was
transferred to Ameren in the form of a stock dividend. In
March 2008 it was merged into an Ameren nonregistrant
subsidiary. Accordingly, UE’s financial statements were
prepared on a consolidated basis for 2007 and 2006 only.
IP had a subsidiary in 2007 and 2006 (Illinois Gas Supply
Company) that was dissolved at December 31, 2007.
Accordingly, IP’s financial statements were prepared on a
consolidated basis for 2007 and 2006 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.
Materials and Supplies
Regulation
Certain Ameren subsidiaries are regulated by the
MoPSC, the ICC, the NRC, and FERC. In accordance with
SFAS No. 71, “Accounting for the Effects of Certain Types
of Regulation,” UE, CIPS, CILCO and IP defer certain costs
pursuant to actions of our rate regulators. These companies
are currently recovering such costs in rates charged to
customers. See Note 2 – Rate and Regulatory Matters for
further information.
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 collections
environment.
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method.
Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed.
The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 2008
and 2007:
2008:
Fuel(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas stored underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007:
Fuel(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas stored underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
(b) Consists of coal, oil, paint, propane, and tire chips.
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
$ 290
277
275
$ 842
$ 253
245
237
$ 735
$ 139
32
168
$
-
54
16
$
92
-
30
$
32
75
24
$
32
75
24
$
-
117
27
$ 339
$ 70
$ 122
$ 131
$ 131
$ 144
$ 129
30
142
$ 301
$
$
-
52
14
$ 66
$
67
-
26
93
$
36
52
22
$
36
52
22
$
-
110
24
$ 110
$ 110
$ 134
Property and Plant
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, or the cost of borrowed
funds and the cost of equity funds (preferred and common
stockholders’ equity) applicable to rate-regulated
construction expenditures, is also added for our rate-
regulated assets. Interest during construction is added for
non-rate-regulated 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 value, are
charged to accumulated depreciation. Asset removal costs
incurred by our non-rate-regulated 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 further
information.
113
Depreciation
Depreciation is provided over the estimated lives of the
various classes of depreciable property by applying
composite rates on a straight-line basis. The provision for
depreciation for the Ameren Companies in 2008, 2007 and
2006 generally ranged from 3% to 4% of the average
depreciable cost. Due to the ICC consolidated electric and
gas rate order that became effective on October 1, 2008,
annual depreciation expense for the Ameren Illinois Utilities
will be reduced for financial reporting purposes by a net
$13 million in the aggregate (CIPS – $4 million reduction,
CILCO – $26 million reduction, and IP – $17 million
increase).
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the
allowance for funds used during construction, 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 allowance for funds used
during construction rates that were utilized during 2008,
2007 and 2006:
Ameren . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill and Intangible Assets
2008
2007
2006
1% - 7% 6% - 7% 6% - 9%
7
1
1
5
6
6
7
6
6
9
6
6
Goodwill. Goodwill represents the excess of the
purchase price of an acquisition over the fair value of the
net assets acquired. As of December 31, 2008, Ameren,
CILCORP, and IP had goodwill of $831 million,
$542 million, and $214 million, respectively. Ameren’s and
IP’s goodwill relates to the acquisition of IP in 2004.
Ameren’s and CILCORP’s goodwill relates to the acquisition
of CILCORP in 2003. Ameren’s goodwill also includes an
additional 20% ownership interest in EEI acquired in 2004
as well as the acquisition of Medina Valley in 2003.
In accordance with the specific provisions of SFAS
No. 142, “Goodwill and Other Intangible Assets,” we test
goodwill for impairment at the reporting unit level. Ameren
has identified three reporting units, which also represent
Ameren’s reportable segments and operating segments
under SFAS No. 131, “Disclosures About Segments of an
Enterprise and Related Information.” The Ameren reporting
units include Missouri Regulated, Illinois Regulated, and
Non-rate-regulated Generation. Ameren’s reporting units
have been defined and goodwill is evaluated at the operating
segment level because we believe the components within
each operating segment have similar economic
characteristics. The following table details how goodwill has
been assigned to the reporting units:
Missouri
Regulated
Illinois
Regulated
Non-rate-regulated
Generation
Ameren . . . .
CILCORP . . .
IP . . . . . . . . .
$ -
-
-
$ 411
197
214
$ 420(a)
345
-
Total
$ 831(a)
542
214
(a) Includes amounts for Ameren registrant and nonregistrant
subsidiaries.
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.
Impairment testing of goodwill 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, the second step is performed to
measure the amount of impairment, if any. The second step
requires a calculation of the implied fair value of goodwill.
The goodwill impairment test performed in the fourth
quarter of 2008 did not require a second step assessment; it
indicated no impairment of Ameren’s, CILCORP’s or IP’s
goodwill. The fair value of Ameren’s, CILCORP’s and IP’s
reporting units was estimated based on a 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 future cash flows, and an
exit value based on observable market multiples. We use our
best estimates in making these evaluations and consider
various factors, including forward price curves for energy,
fuel costs, the regulatory environment, and operating costs.
The failure to achieve projected future operating results and
cash flows, or adjustments to other valuation assumptions,
could change our estimate of reporting unit fair value, in
which case we might be required, at a later date, to record an
impairment charge related to goodwill.
At Ameren and IP, 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 any of the reporting units exceeding their
fair values.
The estimated fair values of CILCORP’s Illinois
Regulated reporting unit and Non-rate-regulated Generation
reporting unit exceeded carrying values by a nominal
amount as of October 31, 2008. As a result, the failure in
the future of either of these reporting units to achieve
forecasted operating results and cash flows may reduce its
estimated fair value below its carrying value and would
likely result in the recognition of a goodwill impairment
charge. CILCORP will continue to monitor the actual and
forecasted operating results and cash flows and observable
market multiples of these reporting units for signs of
114
possible declines in estimated fair value and potential
goodwill impairment. Ameren would not necessarily expect
any future goodwill impairment charge recorded at the
CILCORP reporting unit level to also result in a goodwill
impairment charge at the consolidated Ameren level
because of the aggregation of reporting units.
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, CILCORP’s and CILCO’s intangible assets at
December 31, 2008 and 2007, 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, 2008. Emission
allowances consist of various individual emission allowance
certificates and do not have expiration dates. Emission
allowances are charged to fuel expense as they are used in
operations.
SO2 and NOx in tons
Ameren(d) . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . .
CILCORP(f) . . . . . . . . . . . . .
CILCO (AERG) . . . . . . . . . .
EEI . . . . . . . . . . . . . . . . . . .
(a)
SO2
3,014,000
1,640,000
720,000
337,000
337,000
317,000
(b)
NOx
15,035
5,505
8,125
209
209
1,196
Book Value(c)
$167(e)
48
49
35
1
9
(a) Vintages are from 2008 to 2018. Each company possesses
additional allowances for use in periods beyond 2018.
(b) Vintage is 2008.
(c) The book value at December 31, 2008, represents SO2 and NOx
emission allowances for use in periods through 2031. The book
value at December 31, 2007, for Ameren, UE, Genco, CILCORP,
CILCO (AERG), and EEI was $198 million, $56 million,
$63 million, $41 million, $1 million, and $9 million, respectively.
Includes amounts for Ameren registrant and nonregistrant
subsidiaries and intercompany eliminations.
Includes $26 million of fair-market value adjustments recorded in
connection with Ameren’s acquisition of an additional 20%
ownership interest in EEI.
Includes fair-market value adjustments recorded in connection
with Ameren’s acquisition of CILCORP.
(d)
(e)
(f)
The following table presents the amortization expense
based on usage of emission allowances, net of gains from
emission allowance sales, for Ameren, UE, Genco,
CILCORP, and CILCO (AERG) during the years ended
December 31, 2008, 2007, and 2006:
. . . . . . . . . . . . . . . . . . . . . . . .
Ameren(a)(b)
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP(b)
. . . . . . . . . . . . . . . . . . . . . . . .
CILCO (AERG) . . . . . . . . . . . . . . . . . . . . . .
2008
2007
2006
$ 28
(5)
25
6
(c)
$ 35
(5)
30
7
1
$ (3)
(34)
30
21
11
(b)
Includes allowances consumed that were recorded through
purchase accounting.
(c) Less than $1 million.
Impairment of Long-lived Assets
We evaluate long-lived assets for impairment when
events or changes in circumstances indicate that the
carrying value of such assets may not be recoverable.
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 the amount of the impairment by
estimating the fair value of the assets and recording a
provision for loss. During the fourth quarter of 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
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. These
charges were recorded in Operating Expenses – Other
Operations and Maintenance Expense in the applicable
statements of income and were included with Non-rate-
regulated 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 we believe would be recovered in electric rates paid
by UE’s 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
Environmental costs are recorded on an undiscounted
basis when it is probable that a liability has been incurred and
that 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
(a)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries and intercompany eliminations.
Discount, premium and expense associated with long-
term debt are amortized over the lives of the related issues.
115
Revenue
Operating Revenues
UE, CIPS, Genco, CILCO and IP record operating
revenue for electric or gas service when it is delivered to
customers. We accrue an estimate of electric and 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 and Purchased Gas Costs
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.
In UE’s, CIPS’, CILCO’s, and IP’s retail natural gas
utility jurisdictions, changes in 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 in the balance sheets of UE, CIPS, CILCO
and IP. The deferred amounts are either billed or refunded
to their natural gas utility customers prospectively 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 due to 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 SEC Staff Accounting
Bulletin No. 101, “Revenue Recognition in Financial
Statements.”
Stock-based Compensation
In accounting for stock-based compensation, Ameren
measures the cost of employee services received in
exchange for an award of equity instruments by the grant-
date fair value of the award over the requisite service period.
See Note 12 – Stock-based Compensation for further
information.
Excise Taxes
Excise taxes imposed on us are reflected on Missouri
electric, Missouri gas, and Illinois 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
Operating Expenses – Taxes Accrued. The following table
presents excise taxes recorded in Operating Revenues and
Operating Expenses – Taxes Other than Income Taxes for
the years ended 2008, 2007 and 2006:
2008
2007
2006
Ameren . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 172
109
16
13
13
34
$ 166
110
15
11
11
30
$ 169
106
16
12
12
35
Income Taxes
Ameren uses an asset and liability approach for its
financial accounting and reporting of income taxes, in
accordance with the provisions of SFAS No. 109,
“Accounting for Income Taxes.” Deferred tax assets and
liabilities are recognized for transactions that are treated
differently for financial reporting and tax return purposes.
These deferred tax assets and liabilities are determined by
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
due to 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 SFAS No. 109.
Investment tax credits used on tax returns for prior
years have been deferred for book purposes; they are being
amortized over the useful lives of the related properties.
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, CILCORP, CILCO, and IP are parties
to a tax sharing agreement with Ameren that provides for
the allocation of consolidated tax liabilities. The tax sharing
116
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 to the capital of the
party receiving the benefit.
Minority Interest and Preferred Dividends of Subsidiaries
For the years ended December 31, 2008, 2007, and
2006, Ameren had minority interest expense related to EEI
of $29 million, $27 million, and $27 million, respectively,
and preferred dividends of subsidiaries of $10 million,
$11 million, and $11 million, respectively.
Earnings per Share
There were no material differences between Ameren’s
basic and diluted earnings per share amounts in 2008,
2007, and 2006. 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,
35,545 shares in 2007, and 38,438 shares in 2006.
Accounting Changes and Other Matters
SFAS No. 157, Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157,
which defines fair value, establishes a framework for
measuring fair value, and expands required disclosures
about fair value measurements. SFAS No. 157 clarifies that
fair value is a market-based measurement that should be
based on the assumptions that market participants would
use in pricing an asset or liability. See Note 8 – Fair Value
Measurements for additional information on our adoption of
SFAS No. 157.
SFAS No. 159, The Fair Value Option for Financial Assets
and Financial Liabilities, Including an Amendment of SFAS
No. 115
In February 2007, the FASB issued SFAS No. 159,
which permits companies to choose to measure at fair
value many financial instruments and certain assets and
liabilities that are not currently required to be measured at
fair value on an instrument-by-instrument basis. Entities
electing the fair value option will be required to recognize
changes in fair value in earnings and to expense upfront
cost and fees associated with the item for which the fair
value option is elected. SFAS No. 159 was effective as of
the beginning of our 2008 fiscal year. We did not elect the
fair value option for any of our eligible financial instruments
or other items.
FSP FIN 39-1, Amendment of FASB Interpretation No. 39
In April 2007, the FASB issued FSP FIN 39-1, effective
for us as of the beginning of our 2008 fiscal year. FSP FIN
39-1 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. We did not
elect to adopt FSP FIN 39-1 for any of our eligible financial
instruments or other items.
SFAS No. 141 (Revised 2007), Business Combinations
In December 2007, the FASB issued SFAS No. 141(R),
which replaces SFAS No. 141. SFAS No. 141(R) applies to
all transactions in which an entity obtains control of one or
more businesses and combinations without the transfer of
consideration. SFAS No. 141(R) requires the acquiring
entity in a business combination to recognize assets
acquired and liabilities assumed in the transaction at fair
value; it requires certain contingent assets and liabilities
acquired be recognized at their fair values on the acquisition
date; and it requires expensing of acquisition-related costs
as incurred, among other provisions. SFAS No. 141(R) was
effective as of January 1, 2009. It applies prospectively to
business combinations completed on or after that date.
SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements, an amendment of ARB No. 51
In December 2007, the FASB issued SFAS No. 160,
which establishes accounting and reporting standards for
minority interests, which will be recharacterized as
noncontrolling interests. Under the provisions of SFAS
No. 160, noncontrolling interests will 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 will be accounted for as equity
transactions; net income attributable to the noncontrolling
interest will 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, will be
recorded at fair value, with any gain or loss recognized in
earnings. SFAS No. 160 was effective for us as of the
beginning of our 2009 fiscal year. It applies prospectively,
except for the presentation and disclosure requirements, for
which it applies retroactively. This standard is applicable to
the minority interest in EEI, as EEI is 80% owned by
Ameren.
SFAS No. 161, Disclosures about Derivative Instruments
and Hedging Activities – an amendment of SFAS No. 133
In March 2008, the FASB issued SFAS No. 161, which
requires enhanced disclosures about (1) how and why an
entity uses derivative instruments, (2) how derivative
instruments and related hedged items are accounted for
under SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” and its related
interpretations, and (3) how derivative instruments and
related hedged items affect an entity’s financial position,
financial performance, and cash flows. SFAS No. 161
requires qualitative disclosures about objectives and
strategies for using derivatives, quantitative disclosures
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about fair value amounts of and gains and losses on
derivative instruments, and disclosures about credit-risk-
related contingent features in derivative agreements. SFAS
No. 161 was effective in the first quarter of 2009. The
adoption of SFAS No. 161 did not have a material impact on
our results of operations, financial position, or liquidity,
because it provides enhanced disclosure requirements only.
FSP SFAS No. 157-3, Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not
Active
In October 2008, the FASB issued FSP SFAS
No. 157-3, which clarifies the application of SFAS No. 157
in a market that is not active. FSP SFAS No. 157-3 provides
an example to illustrate key considerations in determining
the fair value of a financial asset when the market for that
financial asset is not active. FSP SFAS No. 157-3 was
effective upon issuance, and it applied retroactively to
periods for which financial statements had not yet been
issued. The adoption of FSP SFAS No. 157-3 did not have a
material impact on our results of operations, financial
condition, or liquidity.
FSP SFAS No. 140-4 and FIN 46(R), Disclosures by Public
Entities (Enterprises) about Transfers of Financial Assets
and Interests in Variable Interest Entities
In December 2008, FASB issued FSP SFAS No. 140-4
and FIN 46(R), effective for us as of December 31, 2008.
Asset Retirement Obligations
FSP SFAS No. 140-4 and FIN 46(R) require enhanced
qualitative and quantitative information about an
enterprise’s involvement with a variable-interest entity (VIE)
and its continuing involvement with transferred financial
assets. For VIEs, enhanced qualitative and quantitative
information about an enterprise’s involvement with a VIE,
financial or other support provided by the enterprise to the
VIE, and the methodology applied in determining whether
an enterprise is the primary beneficiary should be
disclosed. See Variable-interest Entities below for further
information.
FSP SFAS No. 132(R)-1, Employers’ Disclosures about
Postretirement Benefit Plan Assets
In December 2008, FASB issued FSP SFAS
No. 132(R)-1, which will be effective for us as of
December 31, 2009. FSP SFAS No. 132(R)-1 requires
additional disclosures related to pension and other
postretirement benefit plan assets. Additional disclosures
include the investment allocation decision-making process,
the fair value of each major category of plan assets as well
as the inputs and valuation techniques used to measure fair
value and significant concentrations of risk within the plan
assets. The adoption of FSP SFAS No. 132(R)-1 will not
have a material impact on our results of operations,
financial position or liquidity, because it provides enhanced
disclosure requirements only.
SFAS No. 143, “Accounting for Asset Retirement Obligations,” and FIN 47, “Accounting for Conditional Asset Retirement
Obligations” – an Interpretation of FASB Statement No. 143, require 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 in AROs based on changes in estimated fair value. 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, CILCORP, 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.
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The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2008 and
2007:
Ameren(a)(b)
UE(b)
CIPS
Genco
CILCORP/
CILCO
Balance at December 31, 2006
Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion in 2007(d)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in estimates(e)
Balance at December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion in 2008(d)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in estimates(f)
$ 553
1
(2)
32
(17)
$ 567
(4)
33
(186)
$ 491
1
(1)
28
(43)
$ 476
(c)
27
(186)
$ 2
-
-
(c)
(c)
$ 2
-
(c)
-
$ 35
-
(1)
2
16
$ 52
(1)
3
(c)
$ 17
-
(c)
1
10
$ 28
(2)
2
(c)
IP
$ 2
-
-
(c)
-
$ 2
(c)
(c)
-
Balance at December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 410
$ 317
$ 2
$ 54
$ 28
$ 2
(a) Ameren amounts do not equal total due to AROs at EEI.
(b) The nuclear decommissioning trust fund assets of $239 million and $307 million as of December 31, 2008 and 2007, respectively, are
restricted for decommissioning of the Callaway nuclear plant.
(c) Less than $1 million.
(d) Substantially all accretion expense was recorded as an increase to regulatory assets.
(e) UE, Genco and CILCO changed estimates related to retirement costs for their ash ponds. Additionally, UE changed estimates related to its
Callaway nuclear plant decommissioning costs.
(f) 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.
Variable-interest Entities
According to FIN 46R, “Variable-interest Entities,” an
entity is considered a variable-interest entity (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 its equity interests, debt obligations,
leases, contracts, and other agreements to determine its
relationship to a VIE. We have determined that the following
significant VIEs were held by the Ameren Companies at
December 31, 2008:
a 50 percent interest and receives the benefits and
accepts the risks consistent with its limited partner
interest. In 2008, a subsidiary of UE that owned
affordable housing partnerships was eliminated in an
internal reorganization. Those investments were
transferred to a nonregistrant Ameren subsidiary.
IP’s variable interest in IP SPT was eliminated, as the
TFNs for which the IP SPT was established were redeemed in
September 2008. IP had indemnified IP SPT; IP was liable to
IP SPT if IP did not bill the applicable charges to its
customers on behalf of IP SPT or if it did not remit the
collections to IP SPT. However, the note holders were
considered the primary beneficiaries of this special-purpose
trust. Accordingly, Ameren and IP did not consolidate IP SPT.
‰
Leveraged lease and affordable housing partnership
investments. Ameren has investments in affordable
housing and low-income real estate development
partnership arrangements that are variable interests.
Ameren also has an investment in a leveraged lease. 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. At December 31,
2008, and December 31, 2007, Ameren had investments
in affordable housing and low-income real estate
development partnerships of $82 million and $100
million, respectively. At December 31, 2008, and
December 31, 2007, Ameren had a net investment in a
leveraged lease of $9 million. For these variable
interests, Ameren is a limited partner. It owns less than
Coal Contract Settlement
In June 2008, Genco entered into an agreement with a
coal mine owner. The owner provided Genco with a
lump-sum payment of $60 million in July 2008 due to the
coal supplier’s premature closing of a mine and the early
termination of a coal supply contract. The settlement
agreement compensates Genco, in total, for higher fuel costs
it incurred in 2008 ($33 million) and expects to incur in 2009
($27 million) as a result of the mine closure and contract
termination.
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.
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Missouri
2007 Electric Rate Order
In May 2007, the MoPSC issued an order, as clarified,
granting UE a $43 million increase in base rates for electric
service based on a return on equity of 10.2% and a capital
structure of 52% common equity. New electric rates
became effective June 4, 2007.
In July 2007, UE and other parties appealed certain
aspects of the MoPSC decision, to the Circuit Court of Cole
County in Jefferson City, Missouri and subsequently to the
Court of Appeals for the Western District of Missouri. In
January 2009, the Court of Appeals for the Western District
of Missouri issued an order affirming, in all respects, the
order issued by the MoPSC in May 2007, and the time to
appeal this court decision has expired.
2009 Electric Rate Order
In April 2008, UE filed a request with the MoPSC to
increase its annual revenues for electric service by
$251 million. The electric rate increase request proposed an
average increase in electric rates of 12.1%. It was based on
a 10.9% return on equity, a capital structure composed of
52% common equity, a rate base of $5.9 billion, and a test
year ended March 31, 2008, with updates for known and
measurable changes through September 30, 2008.
As part of the proceeding, UE requested that the
MoPSC also approve implementation of a FAC and a
vegetation management and infrastructure inspection cost
recovery mechanism.
On January 27, 2009, the MoPSC issued an order
approving an increase for UE in annual revenues for electric
service of approximately $162 million based on a 10.76%
return on equity, a capital structure composed of 52%
common equity, and a rate base of $5.8 billion. The rate
changes necessary to implement the provisions of the
MoPSC’s order were effective March 1, 2009, with the
MoPSC’s acceptance of conforming tariffs filed by UE. The
MoPSC order also included the following significant
provisions:
‰
‰
Approval of the implementation of a FAC. The
mechanism provides for the 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, above or below the amount set in base rates,
subject to MoPSC prudency review.
Approval of the implementation of a vegetation
management and infrastructure inspection cost
tracking mechanism. The mechanism provides for the
tracking of expenditures that are more 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.
‰
‰
Pursuant to an accounting order issued by the MoPSC
in April 2008 that gave UE the ability to seek direct
recovery of all or a portion of operations and
maintenance expenses incurred as a result of a severe
ice storm in January 2007, the rate order concluded
that the $25 million of operations and maintenance
expenses incurred as a result of the severe ice storm
should be amortized and recovered over a five-year
period starting March 1, 2009. UE recorded these costs
as a regulatory asset in 2008.
Allowance for recovery of $12 million of costs
associated with a March 2007 FERC order that resettled
costs among MISO market participants. The costs were
previously expensed. A regulatory asset was recorded
at December 31, 2008, and will be amortized over a
two-year period starting March 1, 2009.
UE provides power to Noranda’s smelter plant in New
Madrid, Missouri. This plant has historically used
approximately four million megawatthours of power
annually, making Noranda UE’s single largest customer and
constituting approximately 8% of UE’s total electric sales.
As a result of a major winter ice storm in Southeastern
Missouri in January 2009, Noranda’s smelter plant
experienced a power outage related to non-UE lines
delivering power to the substation serving the plant.
Noranda stated that the outage affected approximately 75%
of the smelter plant’s capacity. In addition, Noranda stated
that based on preliminary information and management’s
initial assessment, restoring full plant capacity may take up
to 12 months, with partial capacity phased in during the
12 month period.
To the extent UE’s sales to Noranda are reduced,
generation made available could be sold as off-system
sales. However, the FAC approved in the January 2009
electric rate order would require UE to pass through
substantially all of the off-system revenues to customers.
In order to adjust the FAC for this unanticipated event,
UE sought rehearing by the MoPSC of its January 2009
electric rate order on February 5, 2009, to allow UE to first
recover from the off-system sales any revenues it would
lose as a result of the reduced tariff sales to Noranda with
any excess revenues collected being provided to customers
through the FAC. Also in February 2009, other parties to the
rate case filed for rehearing of certain aspects of the MoPSC
order. In February 2009, the MoPSC denied all rate order
rehearing requests filed by UE and other parties. UE
continues to consider other alternatives to recover any lost
revenues resulting from the Noranda power outage. UE
cannot predict whether court appeals will be filed by other
parties to the rate case.
Environmental Cost Recovery Mechanism
A Missouri law enacted in July 2005 enables the
MoPSC to put in place an environmental cost recovery
mechanism for Missouri’s utilities. The law also includes
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rate case filing requirements, a 2.5% annual rate increase
cap for the environmental cost recovery mechanism, and
prudency reviews, among other things. The MoPSC initiated
a proceeding in December 2008 to develop revised rules for
the cost recovery mechanism. Rules for the environmental
cost recovery mechanism are expected to be approved by
the MoPSC during the second quarter of 2009 and will be
effective once published in the Missouri Register. 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.
Renewable Energy Portfolio Requirement
A ballot initiative passed by Missouri voters in
November 2008 that 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 are
required to be issued by the MoPSC to implement the law.
UE expects that any related costs or investments would
ultimately be recovered in rates.
Illinois
The ICC rejected the Ameren Illinois Utilities’ requested
rate adjustment mechanisms for electric infrastructure
investments. As an alternative to the Ameren Illinois
Utilities’ requested decoupling of natural gas revenues from
sales volumes, the ICC order approved an increase in the
percentage of costs to be recovered through fixed
non-volumetric residential and commercial customer
charges, to 80% from 53%. This increase will impact 2009
quarterly results of operations and cash flows, but is not
expected to have any impact on annual margins. The ICC
also approved an increase in the Supply Cost Adjustment
(SCA) factors for the Ameren Illinois Utilities. The SCA is a
charge applied only to the bills of customers who take their
power supply from the Ameren Illinois Utilities. The change
in the SCA factors is expected to result in increased electric
revenues of $9.5 million per year in the aggregate (CIPS –
$2.6 million, CILCO – $1.6 million, and IP – $5.3 million),
which is expected to cover the increased cost of
administering the Ameren Illinois Utilities’ power supply
responsibilities.
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 to the Appellate
Court of Illinois, Fourth District, the ICC’s denial of the
rehearing request. The Ameren Illinois Utilities cannot
predict the outcome of the court appeal.
2008 Electric and Natural Gas Delivery Service Rate Order
Illinois Electric Settlement Agreement
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 10.68% return on equity with respect
to natural gas delivery service. These rate changes were
effective on October 1, 2008. Because of the Ameren Illinois
Utilities’ pledge to keep the overall residential electric bill
increase resulting from these rate changes to less than 10%
for each utility during the first year, IP will not be able to
recover approximately $10 million in revenue in the first
year electric delivery service rates are in effect. Thereafter,
residential electric delivery service rates will be adjusted to
recover the full increase.
In addition, the ICC in its order changed the
depreciable lives used in calculating depreciation expense
for the Ameren Illinois Utilities’ electric and natural gas
rates. As a result, annual depreciation expense for the
Ameren Illinois Utilities will be reduced for financial
reporting purposes by a net $13 million in the aggregate
(CIPS – $4 million reduction, CILCO – $26 million
reduction, and IP – $17 million increase).
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 Illinois electric settlement
agreement provided approximately $1 billion of funding
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 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, 2008.
The Ameren Illinois Utilities, Genco, and CILCO (AERG)
recognize in their financial statements the costs of their
respective rate relief contributions and program funding in a
manner corresponding with the timing of the funding.
Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and
CILCO (AERG) incurred charges to earnings, primarily
recorded as a reduction to electric operating revenues,
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during the year ended December 31, 2008, of $42 million,
$6 million, $3 million, $8 million, $17 million, and
$8 million, respectively (year ended December 31, 2007 –
$82 million, $12 million, $7 million, $15 million,
$33 million, and $15 million, respectively) under the terms
of the 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 first prior to seeking reimbursement from the
generators. At December 31, 2008, Ameren, CIPS, CILCO
(Illinois Regulated) and IP had receivable balances from
nonaffiliated Illinois generators for reimbursement of
customer rate relief and program funding of $15 million,
$5 million, $3 million, and $7 million, respectively. See Note
14 – Related Party Transactions for information on the
impact of intercompany settlements.
The Illinois electric settlement agreement provides that
if legislation is enacted in Illinois before August 1, 2011,
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 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 Plan
As part of the Illinois electric settlement agreement, the
reverse auction used for power procurement in Illinois was
discontinued. It was replaced with a new power
procurement process led by the IPA, which was established
as a part of the Illinois electric settlement agreement,
beginning in 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
(capacity, energy swaps and renewable energy credits) that
the IPA will procure on behalf of the Ameren Illinois Utilities
for the period June 1, 2009, through May 30, 2014. The
products are expected to be procured through a RFP
process during the first half of 2009.
Except for those that expired in May 2008, existing
supply contracts from the September 2006 reverse power
procurement auction remain in place. In the September
2006 auction, the Ameren Illinois Utilities procured power
to serve the electric load needs of fixed-price residential and
small commercial customers, with one-third of the supply
contracts expiring in each of May 2008, 2009, and 2010.
The Ameren Illinois Utilities used RFP processes in early
2008 to replace the supply contracts that expired in May
2008. See Note 15 – Commitments and Contingencies for
information on the Ameren Illinois Utilities’ purchased
power agreements.
Also as part of the 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 14
– Related Party Transactions for information on these
financial contracts.
Natural Gas Energy Efficiency Plans
In February 2008, the Ameren Illinois Utilities filed a
consolidated natural gas energy efficiency plan with the ICC.
In October 2008, the ICC issued an order approving the
Ameren Illinois Utilities’ natural gas energy efficiency plan
as well as the cost recovery mechanism by which the
program costs will be recovered from natural gas
customers. The natural gas energy efficiency plan includes
annual reduction targets in natural gas usage as well as
spending limits for the 2009, 2010, and 2011 program
years of $2 million, $4 million, and $6 million, respectively.
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 recommendations. The plan was submitted to the
ICC in November 2008. The Ameren Illinois Utilities are
currently in discussions with the ICC and Liberty Consulting
Group about this matter. Liberty Consulting Group will
monitor the Ameren Illinois Utilities’ efforts to implement
the recommendations and any initiatives that the Ameren
Illinois Utilities undertake. At this time, we are unable to
determine the impact such implementation will have on our
results of operations, financial position, or liquidity.
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
122
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
receive 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 permit 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 provides 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.
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 the MISO and PJM for revenues lost when FERC
eliminated the regional through-and-out rates previously
applicable to transactions crossing the border between the
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). 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 charge of $10 million,
$3 million, $1 million, and $6 million, respectively. CILCO’s
net SECA charges were less than $1 million. Until FERC acts
on the pending settlements and issues a final order on the
initial decision, we cannot predict the ultimate impact of the
SECA proceedings 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
granted the request for clarification and directed MISO to
123
reallocate certain costs and provide refunds as requested.
On November 10, 2008, FERC granted relief requested in
the complaints filed by UE, CIPS, CILCO, IP and others
regarding these same MISO operational charges and
directed MISO to calculate refunds for the period from
August 10, 2007, forward.
Several parties to these proceedings have protested
MISO’s proposed implementation of these refunds, have
requested rehearing of FERC’s orders and, in some cases,
have appealed FERC’s orders to the courts. Additional
amounts may be receivable or due depending on the final
outcome of these proceedings.
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, which 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.
Additional charges are expected to continue during the
remainder of the term of the power purchase agreement,
which expires August 25, 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 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 is just and reasonable. FERC is expected to
issue an order with respect to the administrative law judge’s
initial decision in 2009. UE is unable to predict whether
FERC will grant it any relief.
Additionally, LPSC appealed FERC’s orders regarding
LPSC’s complaint against Entergy 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 decision. 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.
However, UE would contest such an order vigorously.
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, 2008. UE plans to participate in any
proceeding that FERC initiates to address the court’s
decision.
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 potential
new 1,600 megawatt nuclear unit at UE’s existing Callaway
County, Missouri, nuclear plant site. This COLA filing is not
a commitment to build another nuclear unit, but it is a
necessary step to preserve the option to develop a new
nuclear unit in the future. The regulatory process for a
COLA involves a comprehensive review, estimated by the
NRC to require up to 42 months for completion.
As authorized by the Energy Policy Act of 2005, the
DOE may make available up to $18.5 billion in loan
guarantees in connection with debt financing of certain new
nuclear unit projects. Pursuant to DOE’s procedures, in
2008 UE filed with the DOE Part I and Part II of its
application for a loan guarantee to support the potential
construction and operation of a new nuclear unit. UE’s loan
guarantee application is not a commitment to build another
nuclear unit, and there is no assurance that the DOE will
provide any such guarantee to UE.
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 renewal is pending.
124
Regulatory Assets and Liabilities
In accordance with SFAS No. 71, 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, 2008 and 2007:
Ameren(a)
UE
CIPS
CILCORP
CILCO
IP
2008:
Regulatory assets:
Pension and postretirement benefit costs(b)(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation(c)(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Callaway costs(f)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized loss on reacquired debt(c)(g)
Recoverable costs – contaminated facilities(c)(h)
. . . . . . . . . . . . . . . . . . . . . . . . . .
IP integration(i) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .
Recoverable costs – debt fair value adjustment(j)
Financial contracts(k)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivatives marked-to-market(l) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SO2 emission allowances sale tracker(m)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FERC-ordered MISO resettlements-March 2007(n) . . . . . . . . . . . . . . . . . . . . . . . . .
Vegetation management and infrastructure inspection cost tracker(o) . . . . . . . . . .
Storm costs(p)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Demand-side costs(q) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserve for workers’ compensation liabilities(c)(r)
. . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(c)(s)
$
936
255
65
58
63
97
33
10
-
118
13
12
9
33
4
15
11
$ 410
248
60
58
30
-
-
-
-
16
13
12
9
33
4
9
5
$ 107
6
2
-
5
18
-
-
42
27
-
-
-
-
-
3
2
Total regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,732
$ 907
$ 212
Regulatory liabilities:
Income taxes(t) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Removal costs(u)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Emission allowances(v)
Pension and postretirement benefit costs tracker(w)
. . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MISO resettlements(x)
$
180
1,018
47
41
5
$ 154
675
47
41
5
$
14
220
-
-
-
Total regulatory liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,291
$ 922
$ 234
2007:
Regulatory assets:
Pension and postretirement benefit costs(b)(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation(c)(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Callaway costs(f)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized loss on reacquired debt(c)(g)
Recoverable costs – contaminated facilities(c)(h)
. . . . . . . . . . . . . . . . . . . . . . . . . .
IP integration(i) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recoverable costs – debt fair value adjustment(j)
. . . . . . . . . . . . . . . . . . . . . . . . .
Derivatives marked-to-market(l) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SO2 emission allowances sale tracker(m)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(c)(y)
$
395
255
188
62
59
106
50
20
3
7
13
$ 161
248
183
62
28
-
-
-
-
7
8
$
75
6
2
-
4
24
-
-
1
-
1
Total regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,158
$ 697
$ 113
Regulatory liabilities:
Income taxes(t) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Removal costs(u)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Emission allowances(v)
Pension and postretirement benefit costs tracker(w)
. . . . . . . . . . . . . . . . . . . . . . .
Financial contracts(k)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivatives marked-to-market(l) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
195
980
56
8
-
1
$ 162
638
56
8
-
1
$
19
208
-
-
38
-
$ 125
-
1
-
5
8
-
-
22
25
-
-
-
-
-
-
2
$ 188
$
$
$
$
$
12
47
-
-
-
59
19
-
1
-
5
5
-
-
-
-
2
32
14
60
-
-
18
-
92
$ 125
-
1
-
5
8
-
-
22
25
-
-
-
-
-
-
2
$ 294
1
2
-
23
71
33
10
64
50
-
-
-
-
-
3
2
$ 188
$ 553
$
$
12
194
-
-
-
$ 206
$
-
76
-
-
-
76
$
$
$
19
-
1
-
5
5
-
-
-
-
2
32
14
188
-
-
18
-
$ 140
1
2
-
22
77
50
20
2
-
2
$ 316
$
-
74
-
-
55
-
$ 220
$ 129
Total regulatory liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,240
$ 865
$ 265
$
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) 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. Ameren believes it is probable that these costs will be
recovered through rates in future periods. See Note 11 – Retirement Benefits for additional information.
(c) These assets do not earn a return.
125
(d) Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 – Income Taxes for amortization
period.
(e) Recoverable costs for AROs at our rate-regulated operations, including net realized and unrealized gains and losses related to the nuclear
decommissioning trust fund investments. See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.
(f) 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.
(g) 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 issuances if no new debt was issued.
(h) The recoverable portion of accrued environmental site liabilities, primarily collected from electric and gas customers through ICC-approved
cost recovery riders in Illinois. The period of recovery will depend on the timing of actual expenditures.
(i) Reorganization costs related to the integration of IP into the Ameren system and the restructuring of IP. Pursuant to the ICC order approving
Ameren’s acquisition of IP, these costs are recoverable in rates through 2010.
(k)
(j) A portion of IP’s unamortized debt fair value adjustment recorded upon Ameren’s acquisition of IP at September 30, 2004. This portion is being
amortized over the remaining life of the related debt beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007.
Financial contracts entered into by the Ameren Illinois Utilities with Marketing Company, as part of the Illinois electric settlement agreement.
See Illinois – Power Procurement Plan discussion above for additional information.
(l) Deferral of SFAS No. 133 natural gas-related derivative mark-to-market gains and losses.
(m) 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.
(n) 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 and will be amortized over a two-year period beginning March 1, 2009, as approved by the
January 2009 MoPSC electric rate order.
(o) UE’s vegetation management and infrastructure inspection costs incurred from January 1, 2008, through December 31, 2008, relating to
compliance with the MoPSC vegetation management and infrastructure rules. The costs incurred between January 1, 2008, through
September 30, 2008, will be amortized over three years beginning March 1, 2009, as approved by the January 2009 MoPSC electric rate order.
The amortization period for the costs incurred between October 1, 2008 through December 31, 2008, will be determined in the next UE rate
case.
(p) 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 a five-year period which began June 4, 2007. The 2008 storm costs are being amortized over a five-year period beginning
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 March 1, 2009, as approved by the January 2009 MoPSC electric
rate order.
(q) Demand-side costs including the costs of developing, implementing and evaluating customer energy efficiency and demand response
programs. These costs are being amortized over a ten-year period beginning March 1, 2009, as approved by the January 2009 MoPSC rate
order.
(r) Reserve for workers’ compensation liabilities. Ameren believes it is probable that these costs will be recovered through electric and gas rates in
(s)
future periods.
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 the low-income weatherization and energy efficiency programs.
(t) Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 – Income Taxes for amortization period.
(u) Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our
rate-regulated operations. See discussion in Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.
(v) The deferral of gains on emission allowance vintage swaps UE entered into during 2005.
(w) A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by UE under GAAP
and the level of such costs built into electric rates effective June 4, 2007, as approved in a MoPSC order.
(x) A portion of UE’s expected refund relating to MISO resettlements associated with the November 2008 FERC orders. See Federal – FERC Order –
MISO Charges discussion above for additional information.
(y) Y2K expenses being amortized over six years starting in 2002, in conjunction with the 2002 settlement of UE’s Missouri electric rate case, and
a DOE decommissioning assessment that was amortized over 14 years through 2007.
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.
126
NOTE 3 – PROPERTY AND PLANT, NET
The following table presents property and plant, net for each of the Ameren Companies at December 31, 2008 and 2007:
Ameren(a)
UE
CIPS
Genco
CILCORP(b)
CILCO
(Illinois
Regulated)
CILCO
(AERG)
IP
2008:
Property and plant, at original cost:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 21,244
1,505
381
$ 13,214
347
76
$ 1,744
365
6
$ 2,451
-
6
$ 1,348
227
44
$
954
506
3
$ 948
-
2
Less: Accumulated depreciation and
amortization . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction work in progress:
Nuclear fuel in process . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23,130
13,637
2,115
2,457
1,619
1,463
8,499
14,631
190
1,746
5,539
8,098
190
707
915
1,200
-
12
1,013
1,444
-
506
279
1,340
-
370
721
742
-
12
950
329
621
-
359
$ 1,840
565
21
2,426
152
2,274
-
55
Property and plant, net
. . . . . . . . . . . . . . . . . . .
$ 16,567
$
8,995
$ 1,212
$ 1,950
$ 1,710
$
754
$ 980
$ 2,329
2007:
Property and plant, at original cost:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 20,325
1,421
354
$ 12,670
332
71
$ 1,682
350
5
$ 2,423
-
4
$ 1,196
209
42
$
921
488
3
$ 827
-
1
Less: Accumulated depreciation and
amortization . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction work in progress:
Nuclear fuel in process . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
22,100
13,073
2,037
2,427
1,447
1,412
8,196
13,904
103
1,062
5,437
7,636
103
450
878
1,159
-
15
972
1,455
-
228
231
1,216
-
278
697
715
-
22
828
329
499
-
256
$ 1,740
530
21
2,291
111
2,180
-
40
Property and plant, net
. . . . . . . . . . . . . . . . . . .
$ 15,069
$
8,189
$ 1,174
$ 1,683
$ 1,494
$
737
$ 755
$ 2,220
(a)
(b)
Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations.
Includes CILCO (Illinois Regulated) and CILCO (AERG) with adjustments due to purchase accounting.
In March 2006, following the receipt of all required regulatory approvals, UE completed the purchase of a 640-megawatt
CT facility located in Audrain County, Missouri, at a price of $115 million from NRG Audrain Holding LLC, and NRG Audrain
Generating LLC, both affiliates of NRG Energy Inc. (collectively, NRG). As a part of this transaction, UE was assigned the rights
of NRG as lessee of the CT facility under a long-term lease with Audrain County, and UE assumed NRG’s obligations under the
lease. The lease will expire on December 1, 2023.
Also in March 2006, following the receipt of all required regulatory approvals, UE completed the purchase from
subsidiaries of Aquila Inc., of the 510-megawatt Goose Creek CT facility in Piatt County, Illinois, at a price of $106 million, and
the 340-megawatt Raccoon Creek CT facility located in Clay County, Illinois, at a price of $71 million.
The following table provides accrued capital expenditures at December 31, 2008, 2007 and 2006, which represent
noncash investing activity excluded from the statements of cash flows:
2008:
Accrued capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007:
Accrued capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006:
Accrued capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
NOTE 4 – SHORT-TERM BORROWINGS AND LIQUIDITY
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
$ 213
$ 110
$ 3
$ 41
$ 45
$ 45
$ 14
$ 153
$
76
$ 3
$ 28
$ 35
$ 35
$
7
$ 159
$
92
$ 5
$ 22
$ 15
$ 15
$ 20
The liquidity needs of the Ameren Companies are typically supported through the use of available cash and drawings
under committed bank credit facilities.
127
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, 2008 and 2007, respectively, and excludes letters of credit issued under
this credit facility:
2008:
Average daily borrowings outstanding during 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding short-term debt at period end . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average interest rate during 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Peak short-term borrowings during 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Peak interest rate during 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007:
Average daily borrowings outstanding during 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding short-term debt at period end . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average interest rate during 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Peak short-term borrowings during 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Peak interest rate during 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ameren
(Parent)
$ 389
275
3.58%
$ 675
7.25%
$ 198
550
5.75%
$ 550
8.25%
UE
Genco
Total
$ 154
251
3.25%
$ 493
5.65%
$ 292
82(a)
5.66%
$ 506
8.25%
$ 41
-
3.97%
$ 150
5.53%
$ 22
100
5.43%
$ 100
5.76%
$ 584
526
3.52%
$1,068
7.25%
$ 512
732(a)
5.68%
$ 856
8.25%
(a)
Includes issuances under commercial paper programs of $80 million at Ameren and UE supported by this facility as of December 31, 2007.
The following table summarizes the borrowing activity and relevant interest rates under the 2007 $500 million credit
facility described below for the years ended December 31, 2008 and 2007:
CIPS
CILCORP
(Parent)
CILCO
(Parent)
IP
AERG
Total
2008:
Average daily borrowings outstanding during 2008 . . . . . . . . . . . . . .
Outstanding short-term debt at period end . . . . . . . . . . . . . . . . . . . . .
Weighted-average interest rate during 2008 . . . . . . . . . . . . . . . . . . . .
Peak short-term borrowings during 2008 . . . . . . . . . . . . . . . . . . . . . .
Peak interest rate during 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007:
Average daily borrowings outstanding during 2007 . . . . . . . . . . . . . .
Outstanding short-term debt at period end . . . . . . . . . . . . . . . . . . . . .
Weighted-average interest rate during 2007 . . . . . . . . . . . . . . . . . . . .
Peak short-term borrowings during 2007 . . . . . . . . . . . . . . . . . . . . . .
Peak interest rate during 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ -
-
-
$ -
-
$ -
-
-
$ -
-
$ 100
-
4.62%
$ 125
6.66%
$ 105
125
6.94%
$ 125
8.63%
$ 56
-
4.02%
$ 75
6.47%
$ 36
75
6.43%
$ 75
6.47%
$ 133
-
4.28%
$ 200
6.15%
$ 134
175
6.59%
$ 200
6.64%
$ 95
85
3.95%
$ 150
6.22%
$ 80
65
6.86%
$ 100
7.02%
$ 384
85
4.25%
$ 500
6.66%
$ 355
440
6.74%
$ 500
8.63%
The following table summarizes the borrowing activity and relevant interest rates under the 2006 $500 million credit
facility described below for the years ended December 31, 2008 and 2007, respectively:
2008:
Average daily borrowings outstanding during 2008 . . . . . . . . . . . . . .
Outstanding short-term debt at period end . . . . . . . . . . . . . . . . . . . .
Weighted-average interest rate during 2008 . . . . . . . . . . . . . . . . . . .
Peak short-term borrowings during 2008 . . . . . . . . . . . . . . . . . . . . .
Peak interest rate during 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007:
Average daily borrowings outstanding during 2007 . . . . . . . . . . . . . .
Outstanding short-term debt at period end . . . . . . . . . . . . . . . . . . . .
Weighted-average interest rate during 2007 . . . . . . . . . . . . . . . . . . .
Peak short-term borrowings during 2007 . . . . . . . . . . . . . . . . . . . . .
Peak interest rate during 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS
$ 58
62
4.21%
$ 135
6.31%
$ 98
125
6.52%
$ 135
8.25%
CILCORP
(Parent)
CILCO
(Parent)
IP
AERG
Total
$ 50
50
4.50%
$ 50
7.01%
$ 49
50
6.89%
$ 50
7.04%
$ 37
-
3.78%
$ 75
5.98%
$ 63
40
6.35%
$ 100
6.47%
$ 27
-
4.08%
$ 150
6.50%
$ 63
-
6.56%
$ 125
6.64%
$ 151
151
3.94%
$ 200
7.01%
$ 107
165
6.84%
$ 200
8.25%
$ 323
263
4.07%
$ 465
7.01%
$ 380
380
6.63%
$ 500
8.25%
At December 31, 2008, Ameren and certain of its
subsidiaries had $2.15 billion of committed credit facilities,
consisting of the three facilities shown above, in the
amounts of $1.15 billion, $500 million, and $500 million,
maturing in July 2010, January 2010, and January 2010,
respectively.
Ameren can directly borrow under the $1.15 billion
facility, as amended, up to the entire amount of the facility.
UE can directly borrow under this facility up to $500 million
on a 364-day basis. Genco can directly borrow under this
facility up to $150 million on a 364-day basis. The amended
facility will terminate on July 14, 2010, with respect to all
128
borrowers. The termination date for UE and Genco is July 9,
2009, subject to the annual 364-day renewal provisions of
the facility.
Under the $1.15 billion credit facility, the principal
amount of each revolving loan will be due and payable no
later than the final maturity of the facility in the case of
Ameren and the last day of the then-applicable 364-day
period in the case of UE and Genco. Swingline loans will be
made on same-day notice and will mature five business
days after they are made.
Ameren, UE and Genco will use the proceeds of any
borrowings under the facility for general corporate
purposes. These purposes include working capital and
funding loans under the Ameren money pool arrangements.
The $1.15 billion credit facility may be used to support
the commercial paper programs of Ameren and UE.
However, Ameren and UE are currently limited in their
access to the commercial paper market as a result of
downgrades in their short-term credit ratings. Access to the
$1.15 billion credit facility, the 2006 $500 million credit
facility, and the 2007 $500 million credit facility for the
Ameren Companies is subject to reduction as borrowings
are made by affiliates.
CIPS, CILCORP, CILCO, IP and AERG are parties to the
2007 $500 million credit facility and to the 2006
$500 million credit facility.
The obligations of each borrower under the 2006
$500 million credit facility and the 2007 $500 million credit
facility are several and not joint, and are not guaranteed by
Ameren or any other subsidiary of Ameren. The maximum
amount available to each borrower under the 2006
$500 million credit facility, including for issuance of letters
of credit on its behalf, is limited as follows: CIPS –
$135 million, CILCORP – $50 million, CILCO – $75 million,
IP – $150 million and AERG – $200 million. Each of the
companies has drawn various loans under this credit
facility. Under the 2007 $500 million credit facility, the
maximum amount available to each borrower, including for
issuance of letters of credit on its behalf, is limited as
follows: CILCORP – $125 million, CILCO – $75 million, IP –
$200 million and AERG – $100 million. CIPS and CILCO
have the option of permanently reducing their borrowing
authority under the 2006 $500 million credit facility and
shifting, in one or more transactions, such capacity to the
2007 $500 million credit facility up to the same limits. The
total borrowing authority of CIPS and CILCO under the
2006 $500 million credit facility and the 2007 $500 million
credit facility cannot at any time exceed $135 million and
$150 million, respectively, in the aggregate. Until either
CIPS or CILCO elects to increase its borrowing capacity
under the 2007 $500 million credit facility and issue first
mortgage bonds as security for its obligations thereunder,
as described below, it will not be considered a borrower
under the 2007 $500 million credit facility and will not be
subject to the covenants thereof (except as a subsidiary of a
borrower). The borrowing companies will use the proceeds
of any borrowings for working capital and other general
corporate purposes. However, a portion of the borrowings
by AERG may be limited to financing or refinancing the
development, management and operation of any of its
projects or assets. The 2006 and 2007 $500 million credit
facilities will terminate on January 14, 2010.
The obligations of CIPS, CILCO and IP under the 2006
$500 million facility are secured by the issuance of first
mortgage bonds by each such utility under its respective
mortgage indenture in the amounts of $135 million,
$75 million, and $150 million, respectively. The obligations
of CILCO and IP under the 2007 $500 million credit facility
are secured by the issuance of first mortgage bonds in the
amounts of $75 million and $200 million, respectively. If
either CIPS or CILCO elects to transfer borrowing authority
from the 2006 $500 million credit facility to the 2007
$500 million credit facility, it must retire an appropriate
amount of first mortgage bonds issued with respect to the
2006 $500 million credit facility and issue new bonds in an
equal amount to secure its obligations under the 2007
$500 million credit facility. In July 2007, CILCO
permanently reduced its $150 million of borrowing
authority under the 2006 $500 million credit facility by
$75 million and shifted that amount of capacity to the 2007
$500 million credit facility. CILCO is now considered a
borrower under both credit facilities and is subject to the
covenants of both. The obligations of CILCORP under both
the 2006 $500 million credit facility and the 2007
$500 million credit facility are secured by a pledge of the
common stock of CILCO. The obligations of AERG under
both the 2006 $500 million credit facility and the 2007
$500 million credit facility are secured by a mortgage and
security interest in its E.D. Edwards and Duck Creek power
plants and related licenses, permits, and similar rights.
On September 15, 2008, Lehman filed for protection
under Chapter 11 of the federal Bankruptcy Code in the U.S.
Bankruptcy Court in the Southern District of New York. As
of December 31, 2008, Lehman Brothers Bank, FSB, a
subsidiary of Lehman, had lending commitments of
$100 million and $21 million under the $1.15 billion credit
facility and the 2006 $500 million credit facility,
respectively. Assuming Lehman Brothers Bank, FSB does
not fund its pro-rata share of funding or letter of credit
issuance requests under these two facilities, and such
participations are not assigned or otherwise transferred to
other lenders, total amounts accessible by the Ameren
Companies and AERG will be limited to amounts not less
than $1.05 billion under the $1.15 billion credit facility and
$479 million under the 2006 $500 million credit facility.
Based on outstanding borrowings under the
$1.15 billion credit facility and the 2007 and 2006
$500 million credit facilities (including reductions for
$9 million of letters of credit issued under the $1.15 billion
credit facility and unfunded Lehman participations under the
$1.15 billion credit facility and the 2006 $500 million credit
facility), the available amounts under the facilities at
December 31, 2008, were $540 million, $415 million, and
$220 million, respectively.
129
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. If Ameren issues capital stock or
other equity interests (except for director or employee
benefit or dividend reinvestment plan purposes), or certain
equity-like hybrid securities, or certain additional
indebtedness in amounts exceeding $25 million, Ameren is
required under the term loan agreement to use the resulting
net proceeds to prepay amounts borrowed under the
agreement. The lenders under the term loan agreement
have waived this prepayment requirement to the extent that
the net proceeds from the issuance of certain funded
indebtedness are applied to repurchase or to redeem
indebtedness of CILCORP. Additionally, if Ameren replaces
its $1.15 billion credit facility with one or more credit
facilities having a total available commitment in excess of
$1.15 billion, Ameren is required under the term loan
agreement to prepay amounts borrowed thereunder in an
amount equal to the excess of the new commitments over
$1.15 billion. Such mandatory prepayments are without
premium or penalty (except for any funding indemnity due
in respect of Eurodollar loans).
Borrowings under the $300 million term loan
agreement will bear interest, at the election of Ameren, at
(1) a Eurodollar rate plus a margin, which margin is subject
to a floor of 0.90% per annum and a cap of 1.50% per
annum, or (2) a rate equal to the higher of the prime rate or
the federal funds effective rate plus 0.50% per year. Ameren
used the proceeds borrowed under the term loan agreement
to reduce amounts borrowed under the $1.15 billion credit
facility, which thereby made additional amounts available
for borrowing under that credit facility. The average annual
interest rate for borrowing under the $300 million term loan
agreement was 3.93% from its inception through
December 31, 2008. The obligations of Ameren under the
term loan agreement are unsecured. No subsidiary of
Ameren is a party to, guarantor of, or borrower under the
term loan agreement.
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. Borrowings
under the $20 million term loan agreement will bear
interest, at the election of Ameren, at (1) a rate equal to the
applicable LIBOR rate plus 1.70% per annum, or (2) a rate
equal to the highest of the prime rate, the federal funds
effective rate plus 0.50% per annum and the applicable
LIBOR rate plus 2.00% per annum. The obligations of
Ameren under the $20 million term loan agreement are
unsecured. No subsidiary of Ameren is a party to, guarantor
of, or borrower under the agreement.
Indebtedness Provisions and Other Covenants
The Ameren Companies’ bank credit facilities contain
provisions that, among other things, place restrictions on
their ability to incur liens, sell assets, and merge with other
entities. The $1.15 billion credit facility contains provisions
that limit total indebtedness of each of Ameren, UE and
Genco to 65% of total consolidated capitalization pursuant
to a calculation defined in the facility. Exceeding these debt
levels would result in a default under the $1.15 billion credit
facility.
The $1.15 billion credit facility also contains provisions
for default, including cross-defaults, with respect to a
borrower. Defaults can result from an event of default under
any other facility covering indebtedness of that borrower or
certain of its subsidiaries in excess of $50 million in the
aggregate. The obligations of Ameren, UE and Genco under
the facility are several and not joint, and except under
limited circumstances, the obligations of UE and Genco are
not guaranteed by Ameren or any other subsidiary. CIPS,
CILCORP, CILCO, IP and AERG are not considered
subsidiaries for purposes of the cross-default or other
provisions.
Under the $1.15 billion credit facility, restrictions apply
limiting investments in and other transfers to CIPS,
CILCORP, CILCO, IP, AERG and their subsidiaries by
Ameren and certain subsidiaries. Additionally, CIPS,
CILCORP, CILCO, IP, AERG and their subsidiaries are
excluded for purposes of determining compliance with the
65% total consolidated indebtedness to total consolidated
capitalization financial covenant in the facility.
Both the 2007 $500 million credit facility and the 2006
$500 million credit facility entered into by CIPS, CILCORP,
CILCO, IP and AERG limit the indebtedness of each
borrower to 65% of consolidated total capitalization
pursuant to a calculation set forth in the facilities. Events of
default under these facilities apply separately to each
borrower (and, except in the case of CILCORP, to their
subsidiaries). An event of default under these facilities does
not constitute an event of default under the $1.15 billion
credit facility, or vice versa. In addition, if CIPS’, CILCO’s or
IP’s senior secured long-term debt securities or first
mortgage bonds, or CILCORP’s senior unsecured long-term
debt securities, should receive a below-investment-grade
credit rating from either Moody’s or S&P, then each such
borrower will be limited to common and preferred stock
dividend payments of $10 million per year while such
below-investment-grade credit rating is in effect. On
July 26, 2006, Moody’s downgraded CILCORP’s senior
unsecured long-term debt credit rating to below-
investment-grade, causing it to be subject to this dividend
payment limitation. No similar restriction applies to AERG,
which is currently not rated by Moody’s or S&P, if its
debt-to-operating- cash-flow ratio, as set forth in these
facilities, is less than or equal to a 3.0 to 1.0 ratio. As of
December 31, 2008, AERG failed to meet the
debt-to-operating-cash-flow ratio test in the 2007 and 2006
$500 million credit facilities. AERG’s ability to pay dividends
is therefore currently limited to a maximum of $10 million
per fiscal year. CIPS, CILCO and IP are not currently limited
in their dividend payments by this provision of the 2007
$500 million or 2006 $500 million credit facilities. Ameren’s
access to dividends from CILCO and AERG is currently
limited by dividend restrictions at CILCORP.
The 2007 $500 million credit facility and the 2006
$500 million credit facility also limit the amount of other
130
secured indebtedness issuable by each borrower. For CIPS,
CILCO and IP, other secured debt is limited to that
permitted under their respective mortgage indentures. For
CILCORP, other debt secured by the pledge of CILCO
common stock is limited (1) under the 2007 $500 million
credit facility to $425 million (in addition to the principal
amount of CILCORP’s outstanding senior notes and senior
bonds and its obligations under the 2006 $500 million
credit facility) and (2) under the 2006 $500 million credit
facility to $500 million (including the principal amount of
CILCORP’s outstanding senior notes and senior bonds and
amounts drawn on the 2007 $500 million credit facility). For
AERG, other debt secured on an equal basis with its
obligations under the facilities is limited to $100 million by
the 2007 $500 million credit facility (excluding amounts
drawn by AERG under the 2006 $500 million credit facility)
and $200 million by the 2006 $500 million credit facility.
The limitations on other secured debt at CILCORP and
AERG in the 2007 $500 million credit facility are subject to
adjustment based on the borrowing sublimits of these
entities under this facility or under the 2006 $500 million
credit facility. In addition, the 2007 $500 million credit
facility and the 2006 $500 million credit facility prohibit
CILCO from issuing any preferred stock if, after such
issuance, the aggregate liquidation value of all CILCO
preferred stock issued after February 9, 2007, and July 14,
2006, respectively, would exceed $50 million.
Under the 2007 $500 million and 2006 $500 million
credit facilities, each of CIPS, CILCO and IP was originally
required to reserve future bonding capacity under its
respective mortgage indentures (that is, it agreed to forgo
the issuance of additional mortgage bonds otherwise
permitted under the terms of each mortgage indenture). On
March 26, 2008, CIPS, CILCO and IP and other parties to
the credit facilities entered into amendments to the credit
facilities, that eliminated this requirement.
The $300 million term loan agreement entered into in
June 2008 has terms similar to the $1.15 billion credit
facility, except that amounts repaid under the term loan
agreement may not be reborrowed. The term loan
agreement also contains nonfinancial covenants, including
restrictions on the ability to incur liens, dispose of assets,
and merge with other entities. In addition, the term loan
agreement has nonfinancial covenants to limit the ability of
Ameren to invest in or transfer assets to other entities,
including affiliates. The events of default under the term
loan agreement, including a cross-default to the occurrence
of an event of default under the $1.15 billion credit facility
or any other agreement covering indebtedness of Ameren
and its subsidiaries in excess of $25 million in the
aggregate, are similar to those contained in the $1.15 billion
credit facility. Each of CIPS, CILCORP, CILCO, IP, AERG and
each of their subsidiaries is excluded from the definition of
“subsidiary” under the term loan agreement and
accordingly is not subject to certain of the covenants,
representations, or warranties under the term loan
agreement. The term loan agreement requires Ameren to
maintain consolidated indebtedness of not more then 65%
of consolidated total capitalization pursuant to a calculation
defined in the term loan agreement.
Under the $20 million term loan agreement entered
into in January 2009, Ameren may elect, for up to three
30-day periods, to pay down and reduce to zero the
outstanding principal balance. The term loan agreement
also contains nonfinancial covenants, including restrictions
on the ability to incur liens, dispose of assets, and merge
with other entities. In addition, the term loan agreement has
nonfinancial covenants to limit the ability of Ameren to
invest in or transfer assets to other entities, including
affiliates. The events of default under the term loan
agreement, including a cross-default to the occurrence of
an event of default under the $1.15 billion credit facility or
any other agreement covering indebtedness of Ameren and
its subsidiaries in excess of $50 million in the aggregate,
are similar to those contained in the $1.15 billion credit
facility. Each of CIPS, CILCORP, CILCO, IP, AERG and each
of their subsidiaries is excluded from the definition of
“subsidiary” under the term loan agreement and
accordingly is not subject to certain of the covenants,
representations, or warranties under the agreement. The
term loan agreement requires Ameren to maintain a
consolidated capitalization ratio of not more than 65%
pursuant to a calculation defined in the agreement.
As of December 31, 2008, the ratios of total
indebtedness to total consolidated capitalization, calculated
in accordance with the provisions of the $1.15 billion credit
facility for Ameren, UE and Genco were 54%, 51% and
53%, respectively. The ratios for CIPS, CILCORP, CILCO, IP
and AERG, calculated in accordance with the provisions of
the 2006 $500 million credit facility and the 2007
$500 million credit facility, were 51%, 60%, 48%, 53% and
45%, respectively. The ratio for Ameren calculated in
accordance with the provisions of the $300 million term
loan agreement was 54%.
None of Ameren’s credit facilities or financing
arrangements contain credit rating triggers that would
cause an event of default or acceleration of repayment of
outstanding balances. At December 31, 2008, 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
131
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 is the 2006 $500 million and the 2007
$500 million credit facilities. 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, 2008, was 2.85% (2007 – 5.80%).
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 Ameren’s $1.15 billion credit facility through a
non-state-regulated subsidiary money pool agreement. The
total amount available to the pool participants at any time is
NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS
reduced by borrowings from Ameren made by its
subsidiaries and 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 $1.15 billion credit facility at
December 31, 2008. 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, 2008 was 3.51% (2007 – 5.14%).
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, 2008, 2007, and 2006.
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 short-term 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 agreement.
The following table presents long-term debt outstanding for the Ameren Companies as of December 31, 2008 and 2007:
2008
2007
UE:
First mortgage bonds:(a)
6.75% Series due 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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)
$
-
173
200
104
114
260
425
250
200
450
300
85
44
184
300
$148
173
200
104
114
260
425
-
200
-
300
85
44
184
300
132
Environmental improvement and pollution control revenue bonds: (a)(b)(c)(d)
1991 Series due 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1992 Series due 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1998 Series A due 2033 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1998 Series B due 2033 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1998 Series C due 2033 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2000 Series A due 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2000 Series B due 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2000 Series C due 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subordinated deferrable interest debentures:
7.69% Series A due 2036(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital lease obligations:
2008
2007
-
47
60
50
50
-
-
-
66
43
47
60
50
50
64
63
60
66
City of Bowling Green capital lease (Peno Creek CT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Audrain County capital lease (Audrain County CT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
82
240
86
240
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,684
3,366
Less: Unamortized discount and premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year
(7)
(4)
(6)
(152)
Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 3,673
$ 3,208
CIPS:
First mortgage bonds:(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.375% Senior secured notes due 2008(b)
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:
2004 Series due 2025(a)(b)(c)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year
$
-
150
40
60
61
-
51
35
8
17
422
(1)
-
15
150
40
60
61
35
51
35
8
17
472
(1)
(15)
Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
421
$
456
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Unamortized discount and premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
200
275
300
775
(1)
200
275
-
475
(1)
Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
774
$
474
CILCORP (Parent):(f)
Unsecured notes:
8.70% Senior notes due 2009(g) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9.375% Senior bonds due 2029(g)
Fair-market value adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year
$
124
210
49
383
(126)
Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
257
$
124
210
55
389
-
389
133
CILCO:
First mortgage bonds:(a)
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)
Series 2004 due 2039(b)(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.20% Series 1992B due 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.90% Series 1993 due 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year
Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP consolidated long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1997 Series A, B and C due 2032(d)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Series 2001 Non-AMT due 2028(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Series 2001 AMT due 2017(d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair-market value adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
2008
2007
$
$
$
$
150
54
42
-
1
32
279
-
279
536
250
75
250
337
400
36
19
33
-
-
-
10
-
54
42
19
1
32
148
-
148
537
250
75
250
-
-
36
19
33
150
112
75
18
Total long-term debt, gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,410
1,018
Less: Unamortized discount and premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year
(10)
(250)
(4)
-
Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,150
$ 1,014
Long-term debt payable to IP SPT:
5.65% due 2008 A-7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Overfunded amount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair-market value adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total long-term debt payable to IP SPT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Maturities due within one year
Long-term debt payable to IP SPT, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
-
-
-
-
-
-
$
$
86
(32)
2
56
(56)
-
Ameren consolidated long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 6,554
$ 5,689
(a) At December 31, 2008, 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
102% of par, declining to 101% of par in October 2009 and 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 103.04% of par declining annually thereafter to 100% of par in June 2012)
which, pursuant to a covenant contained in the 6.70% Series due 2036, may not be called in full prior to June 15, 2009; 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 – 7.50% Series due 2009, 6.125% Series due 2017, 6.25% Series due 2018, 9.75% Series due 2018 and all IP pollution control
revenue bonds.
(c) Environmental improvement or pollution control series secured by first mortgage bonds. In addition, all of the series except UE’s 5.45% Series,
CILCO’s 6.20% Series 1992B, and 5.90% Series 1993 bonds are backed by an insurance guarantee policy.
134
(d)
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 2008 and 2007 were as follows:
2008
2007
2008
2007
UE 1991 Series . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE 1992 Series . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE 1998 Series A . . . . . . . . . . . . . . . . . . . . . . . . .
UE 1998 Series B . . . . . . . . . . . . . . . . . . . . . . . . .
UE 1998 Series C . . . . . . . . . . . . . . . . . . . . . . . . .
UE 2000 Series A . . . . . . . . . . . . . . . . . . . . . . . . .
UE 2000 Series B . . . . . . . . . . . . . . . . . . . . . . . . .
UE 2000 Series C . . . . . . . . . . . . . . . . . . . . . . . . .
Retired
3.66% CIPS Series 2004 . . . . . . . . . . . . . . . . . . . . . .
3.66% 3.72% CIPS 1993 Series B-1 . . . . . . . . . . . . . . . . . . .
3.97% 3.69% CILCO Series 2004 . . . . . . . . . . . . . . . . . . . . .
3.71% 3.66% IP 1997 Series A . . . . . . . . . . . . . . . . . . . . . . .
4.06% 3.66% IP 1997 Series B . . . . . . . . . . . . . . . . . . . . . . .
3.55% IP 1997 Series C . . . . . . . . . . . . . . . . . . . . . . .
3.55% IP Series 2001 (AMT) . . . . . . . . . . . . . . . . . . .
3.56% IP Series 2001 (Non-AMT) . . . . . . . . . . . . . . .
Retired
Retired
Retired
Retired
3.68%
1.98% 3.25%
3.68%
3.93%
3.89%
3.84%
3.89%
3.69%
Retired
Retired
Retired
Retired
Retired
Retired
(e) Under the terms of the subordinated debentures, UE may, under certain circumstances, defer the payment of interest for up to five years. Upon
the election to defer interest payments, UE dividend payments to Ameren are prohibited. UE has not elected to defer any interest payments.
(f) CILCORP’s long-term debt is secured by a pledge of the common stock of CILCO.
(g) These notes are subject to a revocable tender offer whereby holders may receive up to $1,057.50 and $1,230, respectively, for each $1,000
principal amount of 8.70% senior notes due 2009 and 9.375% senior bonds due 2029 tendered.
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren
Companies at December 31, 2008:
2009 . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . .
$
UE
4
4
4
178
205
3,289
CIPS
Genco
CILCORP
(Parent)
CILCO
$
-
-
150
-
-
272
$
-
200
-
-
-
575
$ 126(a)
$
-
-
-
-
210
-
-
-
1
150
128
$
IP
250
-
-
-
-
1,150
Ameren
Consolidated
$
380
204
154
179
355
5,624
Total
. . . . . . . . . . . . . . . . . . . . . . .
$ 3,684(b)
$ 422(b)
$ 775(b)
$ 336(c)
$ 279
$ 1,400(b)(d)
$ 6,896
Includes $2 million of fair-market value adjustments related to CILCORP’s current maturities of long-term debt.
(a)
(b) Excludes unamortized discount and premium of $7 million, $1 million, $1 million, and $10 million at UE, CIPS, Genco, and IP, respectively.
(c) Excludes $47 million related to CILCORP’s long-term debt fair-market value adjustments.
(d) Excludes $10 million related to IP’s long-term debt fair-market value adjustments.
All of the Ameren Companies expect to fund maturities of long-term debt, short-term debt and contractual obligations
through a combination of cash flow from operations and external financing. See Note 4 – Short-term Borrowings and Liquidity
for a discussion of external financing availability.
The following table presents information with respect
(b)
to the Form S-3 shelf registration statements filed and
effective for certain Ameren Companies as of December 31,
2008:
In June 2008, UE, as a well-known seasoned issuer, 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.
Effective Date
Authorized Amount
Ameren(a) . . . . . . . . . . . . . .
UE(b) . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . .
CIPS(a)
. . . . . . . . . . . . . . .
Genco(a)
. . . . . . . . . . . . . . .
CILCO(a)
. . . . . . . . . . . . . . . . . .
IP(a)
November 2008
June 2008
November 2008
November 2008
November 2008
November 2008
Not limited
Not limited
Not limited
Not limited
Not limited
Not limited
(a)
In November 2008, Ameren, as a well-known seasoned issuer,
along with 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.
Ameren
Ameren’s acquisitions of CILCORP and IP resulted in
fair value adjustments to long-term debt of $111 million
and $195 million, respectively. The fair value adjustments
are being amortized to interest expense over the remaining
life or to the expected redemption date of each debt
issuance. As of December 31, 2008, the remaining
unamortized balance of the fair-market value adjustments
for CILCORP and IP were $49 million and $10 million,
respectively. At IP, the amortization of fair value
adjustments is offset in interest expense by a related
amortization of a regulatory asset. See Note 2 – Rate and
Regulatory Matters for more information on the regulatory
asset.
135
The following table presents the amortization of the
CILCORP and IP fair value adjustments for the succeeding
five years:
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a) Amount is less than $1 million.
CILCORP
IP
$ 5
2
2
2
2
36
$ 5
(a)
(a)
(a)
(a)
4
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 (including a subsidiary plan that has now been
merged into the Ameren 401(k) plan), Ameren issued
4.0 million, 1.7 million, and 1.9 million shares of common
stock in 2008, 2007, and 2006, respectively, which were
valued at $154 million, $91 million, and $96 million for the
respective years.
In February 2007, $100 million of Ameren’s 5.70%
notes matured and were retired.
In May 2007, $250 million of Ameren’s senior notes
matured and were retired.
UE
In June 2007, UE issued $425 million of 6.40% senior
secured notes due June 15, 2017, with interest payable
semi-annually on June 15 and December 15 of each year,
beginning in December 2007. These notes are secured by
first mortgage bonds. UE received net proceeds of
$421 million, which were used to repay short-term debt.
In connection with UE’s June 2007 issuance of
$425 million of senior secured notes, UE agreed, that so
long as those senior secured notes are outstanding, it will
not, prior to June 15, 2012, optionally redeem, purchase or
otherwise retire in full its outstanding first mortgage bonds
not subject to release provisions, thus causing a first
mortgage bond release date to occur. Such 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 ranking equally with any other
outstanding senior unsecured indebtedness of UE. UE
further agreed that the interest rate for these $425 million of
senior secured notes will be subject to an increase of up to
a maximum of 2.00% if such release date occurs between
June 15, 2012, and June 15, 2017 (the maturity date of the
$425 million senior secured notes), and if Moody’s or S&P
downgrades the rating assigned to these senior secured
notes below investment grade as a result of the release
within 30 days of such release (subject to extension if and
for so long as the rating for such senior secured notes is
under consideration for possible downgrade).
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 will 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
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 will 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
136
$298 million, which is used to fund capital expenditures, to
repay short-term debt, and for general corporate purposes.
Genco exchanged the outstanding unregistered unsecured
notes for registered unsecured notes in July 2008.
CILCORP
As discussed above, in conjunction with Ameren’s
acquisition of CILCORP, CILCORP’s long-term debt was
increased to fair value by $111 million. Amortization related
to fair-value adjustments was $6 million, $6 million, and
$6 million for the years ended December 31, 2008, 2007,
and 2006, respectively, and costs related to repayments
were $- million, $- million, and $2 million for the years
ended December 31, 2008, 2007, and 2006, respectively.
These amounts were included in interest expense in the
Consolidated Statements of Income of Ameren and
CILCORP.
See Note 4 – Short-term Borrowings and Liquidity
regarding CILCORP’s pledge of the common stock of CILCO
as security for its obligations under the 2006 $500 million
credit facility and the 2007 $500 million credit facility.
In September 2008, CILCORP commenced a cash
tender offer for any and all of its outstanding 8.70% senior
notes due 2009 ($123.755 million aggregate principal
amount) and its 9.375% senior bonds due 2029
($210.565 million aggregate principal amount), collectively,
the “notes.” Concurrent with the tender offer, CILCORP
solicited consents from the holders of the notes to certain
proposed amendments to the indenture governing these
securities. Any holder tendering securities as part of this
offer is deemed to consent to the proposed amendments.
No consents will be accepted separate from a tender of
such holder’s securities. The amendments would eliminate
certain restrictive covenants in the indenture and the notes.
The total consideration for each $1,000 principal amount of
2009 notes validly tendered on or prior to the current
consent and expiration date, which has been extended to
April 30, 2009, is $1,057.50. The total consideration
includes a consent payment of $40 per $1,000 principal
amount of such 2009 notes tendered on or prior to such
date. The total consideration for each $1,000 principal
amount of 2029 bonds validly tendered on or prior to the
current April 30, 2009, consent and expiration date is
$1,230, which includes a consent payment of $50 per
$1,000 principal amount of such 2029 bonds tendered on
or prior to such date. Holders validly tendering and not
withdrawing notes on or before the extended consent and
expiration date are eligible to receive the applicable total
consideration. In addition, tenders of notes, including
previously tendered notes, may be withdrawn (and related
consents may be rescinded) at any time prior to April 30,
2009. As of January 28, 2009, CILCORP had received
consents, net of those rescinded, from the holders of
$121.3 million, or 98.0%, of its outstanding 2009 8.70%
senior notes and $206.6 million, or 98.1%, of its
outstanding 2029 bonds. Consummation of the tender offer
and the consent solicitation is subject to a number of
conditions, including the absence of certain adverse legal
and market developments, as described in the offer to
purchase. CILCORP has reserved the right to amend,
further extend, terminate, or waive any conditions to the
tender offer and the consent solicitation at any time. The
impact on CILCORP’s net income of the tender offer is
expected to be approximately $3 million, if consummated.
CILCO
In July 2007, CILCO redeemed 11,000 shares of its
5.85% Class A preferred stock at a redemption price of
$100 per share plus accrued and unpaid dividends. The
redemption satisfied CILCO’s mandatory sinking fund
redemption requirement for this series of preferred stock
for 2007.
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 debt. 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 will 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
As discussed above, in conjunction with Ameren’s
acquisition of IP, IP’s long-term debt was increased to fair
value by $195 million. Amortization related to fair value
adjustments was $13 million for the year ended
December 31, 2006, and was included in interest expense
in the consolidated statements of income of Ameren and IP.
Beginning in 2007, the amortization related to fair value
adjustments was recoverable in rates and a regulatory asset
was established. See Note 2 – Rate and Regulatory Matters
for more information.
In November 2007, IP issued and sold, with
registration rights in a private placement, $250 million of
6.125% senior secured notes due November 15, 2017, with
interest payable semiannually on May 15 and November 15
of each year, beginning in May 2008. These notes are
137
secured by mortgage bonds, which are subject to fallaway
provisions as defined in the related financing agreements.
IP received net proceeds of $248 million, which were used
to repay short-term debt. IP exchanged the outstanding
unregistered secured notes for registered secured notes in
April 2008.
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
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 will
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
Indenture Provisions and Other Covenants
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.
In September 2008, IP redeemed the remaining
portion of its $54 million principal amount 5.65% note
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, as allowed under the Illinois
Electric Utility Transition Funding Law.
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 will 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.
UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions related
to the issuances of first mortgage bonds and preferred stock. UE, CIPS, CILCO and IP are required to meet certain ratios to
issue first mortgage bonds and preferred stock. 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,
2008, at an assumed interest and dividend rate of 8%.
UE . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . .
Required Interest
Coverage Ratio(a)
≥2.0
≥2.0
≥2.0(d)
≥2.0
Actual Interest
Coverage Ratio
Bonds Issuable(b)
Required Dividend
Coverage Ratio(c)
Actual Dividend
Coverage Ratio
Preferred Stock
Issuable
3.0
2.1
13.5
2.0
$ 1,102
33
181
296
≥2.5
≥1.5
≥2.5
≥1.5
40.4
1.4
51.4
1.0
$ 1,126
-
331(e)
-
(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 additional first mortgage bonds are issued on the basis of retired bonds.
(b) Amount of bonds issuable based either on meeting required coverage ratios or unfunded property additions, whichever is more restrictive. The
amounts shown also include bonds issuable based on retired bond capacity of $161 million, $18 million, $44 million and $286 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, 2008, CILCO had earnings equivalent to at
least 31% of the principal amount of all mortgage bonds outstanding.
(d)
(e) See Note 4 – Short-term Borrowings and Liquidity for a discussion regarding a restriction on the issuance of preferred stock by CILCO under
the 2006 $500 million credit facility and the 2007 $500 million credit facility.
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, 2008.
138
CILCO’s articles of incorporation contain certain
provisions that prohibit the payment of dividends on its
common stock (1) from either paid-in surplus or any
surplus created by a reduction of stated capital or capital
stock, or (2) if at the time of dividend declaration, there
shall not remain to the credit of earned surplus account
(after deducting the amount of such dividends) an amount
at least equal to two times the annual dividend requirement
on all outstanding shares of CILCO’s preferred stock.
Genco’s and CILCORP’s indentures include provisions
that require the companies to maintain certain debt service
coverage and/or debt-to-capital ratios in order for the
companies 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, 2008:
Required
Interest
Coverage
Ratio
≥1.75(b)
≥2.2
Actual
Interest
Coverage
Ratio
6.9
3.8
Required
Debt-to-
Capital
Ratio
≤60%
≤67%
Actual
Debt-to-
Capital
Ratio
51%
32%
Genco(a) . . . . . . . . .
. . . . . .
CILCORP(c)
(a)
Interest coverage ratio relates to covenants regarding 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 most recently ended four
fiscal quarters.
(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.
NOTE 6 – OTHER INCOME AND EXPENSES
(c) CILCORP must maintain the required interest coverage ratio and
debt-to-capital ratio in order to make any payment of dividends
or intercompany loans to affiliates other than direct or indirect
subsidiaries.
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. Even if CILCORP is
not in compliance with these restrictions, CILCORP may
still make payments of dividends or intercompany loans if
its senior long-term debt rating is at least BB+ from S&P,
Baa2 from Moody’s, and BBB from Fitch. At December 31,
2008, CILCORP’s senior long-term debt ratings from S&P,
Moody’s and Fitch were BB+, Ba2, and BBB-, respectively.
The common stock of CILCO is pledged as security to the
holders of CILCORP’s senior notes and bonds and credit
facility obligations.
In order for the Ameren Companies to issue securities
in the future, they will have to comply with any applicable
tests in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2008, 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.
The following table presents Other Income and Expenses for each of the Ameren Companies for the years ended
December 31, 2008, 2007 and 2006:
2008
2007
2006
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 15
28
28
9
$ 80
$ (13)
(18)
$ (31)
UE:
Miscellaneous income:
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income on industrial development revenue bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for equity funds used during construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
5
28
28
1
$ 27
28
5
15
$ 75
$ (13)
(12)
$ (25)
$
4
28
4
2
$ 10
28
4
8
$ 50
$
(5)
(14)
$ (19)
$
3
28
3
4
Total miscellaneous income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 62
$ 38
$ 38
Miscellaneous expense:
Donations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
(3)
(6)
(9)
$
$
(2)
(5)
(7)
$
$
(2)
(6)
(8)
139
2008
2007
2006
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP:
Miscellaneous income:
Interest and dividend income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense:
Donations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous expense:
Donations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total miscellaneous expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
9
2
11
(2)
(1)
(3)
1
1
(1)
(1)
1
1
2
(2)
(3)
(5)
1
1
2
(2)
(3)
(5)
5
6
11
(3)
(2)
(5)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
16
1
17
(2)
(1)
(3)
-
-
-
-
4
1
5
(1)
(4)
(5)
4
1
5
(1)
(5)
(6)
8
6
14
(3)
(2)
(5)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
15
2
17
(1)
(1)
(2)
-
-
-
-
2
-
2
(1)
(3)
(4)
1
-
1
(1)
(3)
(4)
4
2
6
(1)
(3)
(4)
NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of
changes in market prices for natural gas, fuel, electricity,
and emission allowances. Price fluctuations in natural gas,
fuel, and electricity may cause any of 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 fuel and natural gas inventories or
purchased power that differ from the cost of those
commodities in inventory; or
‰
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.
Certain derivative contracts are entered into on a
regular basis as part of our risk management program, but
140
these do not qualify for hedge accounting or the normal
purchase and normal sales exceptions under SFAS No. 133,
“Accounting for Derivative Instruments and Hedging
Activities,” as amended.
Accordingly, such contracts are recorded at fair value.
Changes in the fair value are charged or credited to the
income statement in the period in which the change occurs.
Contracts we enter into as part of our risk management
program may be settled financially, by physical delivery, or
net settled with the counterparty.
Cash Flow Hedges
Our risk management processes identify the
relationships between hedging instruments and hedged
items, as well as the risk management objective and
strategy for undertaking various hedge transactions. The
mark-to-market value of cash flow hedges will continue to
fluctuate with changes in market prices up to contract
expiration.
We monitor and value derivative positions daily as part
of our risk management processes. We use published
sources for pricing when possible to mark positions to
market. We rely on modeled valuations only when no other
method exists.
The following table presents the pretax net gain (loss)
for the years ended December 31, 2008, 2007 and 2006, of
power hedges included in Operating Revenues – Electric.
This pretax net gain (loss) represents the impact of
discontinued cash flow hedges, the ineffective portion of
cash flow hedges, and the reversal of amounts previously
recorded in OCI for transactions that have since been
delivered or settled:
Gains (Losses)
2008
2007
2006
Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 103
7
-
-
$ 40
-
-
-
$ 9
11
2
(7)
(a)
Includes amounts from Ameren registrants and non-registrant
subsidiaries.
Other Derivatives
The following table represents the net change in
market value for the years ended December 31, 2008, 2007
and 2006, of option and swap transactions used to manage
our positions in SO2 allowances, coal, heating oil, FTRs and
power. Certain of these transactions are treated as
nonhedge transactions under SFAS No. 133, “Accounting
for Derivative Instruments and Hedging Activities,” as
amended. The net changes in the market value of nonhedge
power and gas transactions are recorded in Operating
Revenues – Electric, and Operating Revenues – Gas, while
the net changes in the market value of coal, heating oil, and
SO2 options and swaps is recorded as Operating Expenses
– Fuel.
Gains (Losses)
SO2 options and swaps:
2008
2007
2006
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Coal options:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Heating oil options:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO . . . . . . . . . . . . . . . . . . . .
FTRs:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonhedge power swaps and forwards:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . .
Gas forwards and swaps:
-
-
-
-
-
(53)
(26)
(16)
(3)
3
2
2
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO . . . . . . . . . . . . . . . . . . . .
(12)
(3)
(6)
$ 8
6
1
$(2)
4
(4)
2
2
6
1
1
-
-
-
(2)
-
-
-
(2)
(2)
(2)
-
-
-
-
-
-
-
-
-
(a)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries and intercompany eliminations.
During the third quarter ended September 30, 2008,
UE entered into foreign currency forward contracts. These
derivative instruments are intended to fix the amount of
U.S. dollars UE will pay for future equipment deliveries
denominated in euros as part of a firm commitment to
purchase heavy forgings, which would be used in building a
second nuclear unit. These forward contracts qualify as fair
value hedges and, as a result, both the derivative positions
and the foreign currency exposure on the firm commitment
are recorded at fair value. Changes in the fair value of both
the derivative instrument and the hedged item are recorded
in earnings. For the year ended December 31, 2008, this
hedging program was highly effective, resulting in no
impact to net income.
141
The following table presents the carrying value of all derivative instruments and the amount of pretax net gains (losses)
on derivative instruments in Accumulated OCI, regulatory assets, or regulatory liabilities, at December 31, 2008 and 2007:
Ameren(a)
UE
CIPS
Genco
CILCORP/
CILCO
IP
2008:
Derivative instruments carrying value:
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gains (losses) deferred in Accumulated OCI:
Power forwards(c)
Interest rate swaps(d)(e)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gains (losses) deferred in regulatory assets or liabilities:
Gas forwards and futures contracts(f)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial contracts(g) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 207
47
155
79
84
(11)
(118)
-
$ 50
-
24
10
40
-
$ -
-
31
53
$
-
-
1
-
-
-
-
(11)
$
-
-
29
30
-
-
$
-
-
56
78
-
-
(16)
-
(27)
(56)
-
-
(25)
(29)
(50)
(85)
2007:
Derivative instruments carrying value:
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 35
9
24
7
$ 7
1
1
-
$ 1
38
1
-
$ 2
-
6
-
Gains (losses) deferred in Accumulated OCI:
Power forwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas swaps and futures contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gains (losses) deferred in regulatory assets or liabilities:
Gas forwards and futures contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial contracts(g) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15
(2)
-
1
(2)
-
4
-
-
1
1
-
-
-
-
-
(1)
40
-
(2)
-
-
-
-
$ 2
20
1
-
-
-
1
-
-
19
$ 2
61
8
-
-
-
-
-
(2)
57
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Includes Ameren’s and UE’s carrying value of fair value foreign currency forward contracts.
(a)
(b)
(c) Represents the mark-to-market value for the hedged portion of electricity price exposure for periods of up to three years, including $123 million
(d)
(e)
and $39 million in 2009 at Ameren and UE, respectively.
Includes a gain 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, 2008 was $2 million.
Includes a loss 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 cumulative gain and loss on the interest rate swaps will be amortized
over a 10-year period that began in April 2008. The carrying value at December 31, 2008, was $13 million.
(f) Represents gains associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements
through October 2012 at UE, through March 2013 at CIPS and IP, and through March 2012 at CILCORP and CILCO.
(g) Current losses deferred as regulatory assets of $14 million at CIPS, $7 million at CILCO, and $21 million at IP that were recorded in other
current assets at December 31, 2008. Current gains deferred as regulatory liabilities include $2 million at CIPS, $1 million at CILCO, and
$2 million at IP that were recorded in other current liabilities at December 31, 2007.
As part of the Illinois electric settlement agreement, the
Ameren Illinois Utilities entered into financial contracts with
Marketing Company. These financial contracts are derivative
instruments being accounted for as cash flow hedges at the
Ameren Illinois Utilities and Marketing Company.
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. In Ameren’s
consolidated financial statements, all financial statement
effects of the derivative instruments are eliminated. See
Note 2 – Rate and Regulatory Matters for additional
information on these financial contracts.
Derivative instruments are subject to various credit-
related losses in the event of nonperformance by
counterparties to the contracts. In order to mitigate these
risks, collateral requirements are established. As of
December 31, 2008, Ameren, UE, CIPS, CILCORP, CILCO
and IP had collateral postings with external parties of
$109 million, $15 million, $26 million, $16 million,
$16 million, and $36 million, respectively. The amount of
collateral external counterparties posted with Ameren was
$7 million at December 31, 2008. The amounts of collateral
external counterparties posted with UE, CIPS, CILCORP,
CILCO, and IP were immaterial at December 31, 2008. See
Note 14 – Related Party Transactions for information
regarding collateral postings with affiliates.
On September 15, 2008, Lehman filed for protection
under Chapter 11 of the federal Bankruptcy Code in the U.S.
Bankruptcy Court in the Southern District of New York. On
October 21, 2008, Ameren sent notice to Lehman
142
Commodity Services terminating all transactions between
Genco, UE, and Marketing Company and Lehman
Commodity Services. As of December 31, 2008, Ameren’s
and its subsidiaries’ direct exposure to Lehman Commodity
Services, based on existing transactions and current market
prices, was estimated to be less than $1 million before
taxes, collectively.
NOTE 8 – FAIR VALUE MEASUREMENTS
SFAS No. 157 provides a framework for measuring fair
value for all assets and liabilities that are measured and
reported at fair value. The Ameren Companies adopted
SFAS No. 157 as of the beginning of their 2008 fiscal year
for financial assets and liabilities and as of the beginning of
their 2009 fiscal year for nonfinancial assets and liabilities,
except those already reported at fair value on a recurring
basis. The impact of the adoption of SFAS No. 157 for
financial assets and liabilities at January 1, 2008, and for
nonfinancial assets and liabilities at January 1, 2009, was
not material. SFAS No. 157 defines fair value 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 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. SFAS No. 157 also establishes 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 primarily include 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 as part of the Illinois electric settlement
agreement. We value Level 3 instruments 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, a review 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 SFAS No. 157. 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.
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). SFAS No. 157 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 $5 million in losses in the fourth
quarter of 2008 related to valuation adjustments for
counterparty default risk. At December 31, 2008, the
counterparty default risk valuation adjustment related to net
derivative (assets) liabilities totaled $(1) million, $- million,
$9 million, $6 million, and $16 million for Ameren, UE,
CIPS, CILCORP/CILCO and IP, respectively.
143
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)
Assets:
Ameren(a)
UE
CIPS
Genco
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative assets(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear Decommissioning Trust Fund(c) . . . . . . . . . . . . .
Derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear Decommissioning Trust Fund(c) . . . . . . . . . . . . .
Derivative assets(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative assets(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO
Derivative assets(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP
Liabilities:
Ameren(a)
UE
CIPS
Genco
Derivative assets(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Derivative liabilities(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP/CILCO
Derivative liabilities(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
IP
Derivative liabilities(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
$
-
1
164
-
164
-
-
-
-
9
-
-
-
4
-
$
-
19
81
14
81
$
-
-
-
-
6
3
-
-
-
-
Total
$
6
254
247
50
247
-
-
-
-
$
6
234
2
36
2
-
-
-
-
$ 219
$ 234
31
84
1
55
34
84
1
59
134
134
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.
The following table summarizes the changes in the fair value of 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)
Beginning
Balance at
January 1,
2008
Included
in
Earnings(a)
Included
In OCI
Included
in
Regulatory
Assets/
Liabilities
Total
Realized
and
Unrealized
Gains
(Losses)
Ameren . . . . . . . . .
$
-
$
-
$
-
$
-
$
-
Purchases,
Issuances,
and
Other
Settlements,
Net
-
$
Net
Transfers
Into
(Out of)
Level 3
Ending
Balance at
December 31,
2008
$
6
$
6
Change in
Unrealized
Gains (Losses)
Related to
Assets/
Liabilities Still
Held at
December 31,
2008
$
-
Ameren . . . . . . . . .
UE . . . . . . . . . . . . .
CIPS . . . . . . . . . . . .
Genco . . . . . . . . . . .
CILCORP/CILCO . . .
IP . . . . . . . . . . . . . .
Ameren . . . . . . . . .
UE . . . . . . . . . . . . .
$ 19
3
38
1
21
55
5
5
$
$ (18)
1
(1)
(2)
(34)
(1)
-
-
$
$ 13
13
-
-
-
-
-
-
$
$ (35)
13
(127)
-
(43)
(209)
-
-
$
$ (40)
27
(128)
(2)
(77)
(210)
-
-
$
$ 8
(42)
6
-
1
21
$ (3)
(3)
$ 28
17
-
-
-
-
-
-
$
$ 15
5
(84)
(1)
(55)
(134)
2
2
$
$ (206)
(6)
(106)
-
(62)
(174)
-
-
$
Other current
assets
Net derivative
contracts
Nuclear
Decommissioning
Trust Fund
(a) Net gains and losses on power options are recorded in Operating Revenues – Electric, while net gains and losses on coal, heating oil, and SO2
options and swaps are recorded as Operating Expenses – Fuel.
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 compared with previous periods for the
year ended December 31, 2008. 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.
144
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.
The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at
December 31, 2008 and 2007:
Ameren:(a)
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)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP:
Long-term debt (including current portion)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO:
Long-term debt (including current portion)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP:
Long-term debt (including current portion)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
2007
Fair
Value
Carrying
Amount
Fair
Value
$ 6,144
100
$ 5,912
211
$ 5,821
147
Carrying
Amount
$ 6,934
195
$ 3,677
113
$ 3,156
62
$ 3,360
113
$ 3,255
85
$
$
$
$
421
50
774
662
19
279
19
$
$
$
$
371
22
661
630
10
255
10
$
$
$
$
471
50
474
537
35
148
35
$
$
$
$
472
27
510
516
27
149
27
$ 1,400
46
$ 1,326
24
$ 1,070
46
$ 1,067
32
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
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 further 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, 2008, and 2007.
Investments by the nuclear decommissioning trust
fund have a target allocation of 60% to 70% in equity
securities with the balance invested in fixed-income
securities. Due to recent market conditions, the equity
securities weighting was below 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 on those sales for
the years ended December 31, 2008, 2007 and 2006:
Proceeds from sales . . . . .
Gross realized gains . . . . .
Gross realized losses . . . .
2008
$ 497
5
8
2007
$ 128
4
3
2006
$ 98
2
2
Net realized and unrealized gains and losses are
reflected in regulatory assets or regulatory liabilities on
Ameren’s and UE’s Consolidated Balance Sheets. This
reporting is consistent with the method we use to account
for the decommissioning costs recovered in rates. Gains or
losses on assets in the trust fund could result in lower or
higher funding requirements for decommissioning costs,
which we believe would be reflected in electric rates paid by
UE’s customers. See Note 2 – Rate and Regulatory Matters.
145
The following table presents the costs and fair values of investments in debt and equity securities in UE’s nuclear
decommissioning trust fund at December 31, 2008 and 2007:
Security Type
Cost
Gross Unrealized Gain
Gross Unrealized Loss
Fair Value
2008:
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007:
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 109
123
2
(8)
$ 226
$ 109
104
1
1
$ 215
$
$
$
5
40
-
-
45
3
97
-
-
$ 100
$
3
29
-
-
$ 32
$
$
1
7
-
-
8
$ 111
134
2
(8)
$ 239
$ 111
194
1
1
$ 307
(a) 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 decommissioning
trust fund according to their contractual maturities at December 31, 2008:
Less than 5 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5 years to 10 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Due after 10 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
40
37
32
$
40
38
33
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 109
$ 111
Cost
Fair Value
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 with the NRC to extend its 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, 2008:
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less than 12 Months
12 Months or Greater
Total
Gross
Unrealized
Losses
$
2
16
$ 18
Fair Value
$
7
6
$ 13
Gross
Unrealized
Losses
$
1
13
$ 14
Fair Value
$ 27
36
$ 63
Gross
Unrealized
Losses
$
3
29
$ 32
Fair Value
$ 20
30
$ 50
NOTE 10 – STOCKHOLDER RIGHTS PLAN AND
PREFERRED STOCK
Stockholder Rights Plan
In 1998, Ameren’s board of directors adopted a share
purchase rights plan designed to assure stockholders of fair
and equal treatment in the event of a proposed takeover.
The rights were exercisable only if a person or group
acquired 15% or more of Ameren’s outstanding common
stock or announced a tender offer that would result in
ownership by a person or group of 15% or more of the
Ameren common stock. Ameren’s stockholder rights plan
expired on October 9, 2008, and Ameren’s Board of
Directors decided not to renew it.
Preferred Stock
All classes of UE’s, CIPS’, CILCO’s and IP’s preferred
stock are entitled to cumulative dividends and have voting
rights. 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 and
CILCO has 2 million shares of no par value preference stock
authorized, with no such preference stock 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. No shares of preference
stock have been issued by any of the Ameren Companies.
146
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 entitled to cumulative dividends and is redeemable, at the option of the issuer, at the prices
presented as of December 31, 2008 and 2007:
Redemption Price (per share)
2008
2007
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
CIPS:
With par value of $100 per share, 2 million shares authorized
4.00% Series
4.25% Series
4.90% Series
4.92% Series
5.16% Series
6.625% Series
Total
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
150,000 shares
50,000 shares
75,000 shares
50,000 shares
50,000 shares
125,000 shares
CILCO:
With par value of $100 per share, 1.5 million shares authorized
4.50% Series
4.64% Series
Total
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
111,264 shares
79,940 shares
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
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
225,510 shares
143,760 shares
104,280 shares
102,190 shares
145,170 shares
191,765 shares
$
$
110.00
104.75
105.625
105.00
110.00(a)
102.47
102.176
110.00
103.82(b)
101.00
102.00
102.00
103.50
102.00
100.00
$
110.00
102.00
$
51.50
52.00
51.50
51.50
51.50
50.00
$
13
4
15
4
21
20
2
1
33
$ 113
$
$
$
$
$
$
15
5
8
5
5
12
50
11
8
19
12
7
5
5
7
10
46
$
13
4
15
4
21
20
2
1
33
$ 113
$
$
$
$
$
$
15
5
8
5
5
12
50
11
8
19
12
7
5
5
7
10
46
Less: Shares of IP preferred stock owned by Ameren . . . . . . . . . . . . . . . . . . . . . . .
Total Ameren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(33)
$ 195
(33)
$ 195
In the event of voluntary liquidation, $105.50.
(a)
(b) Declining to $100 per share in 2012.
NOTE 11 – RETIREMENT BENEFITS
We offer defined benefit and postretirement benefit
plans covering substantially all employees of UE, CIPS,
CILCORP, 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.
We adopted the provisions of SFAS No. 158,
“Employers’ Accounting for Defined Benefit Pension and
Other Postretirement Plans, an amendment of FASB
Statements No. 87, 88, 106 and 132(R),” effective
December 31, 2006. SFAS No. 158 requires employers to
recognize the overfunded or underfunded positions of
defined benefit postretirement plans, including pension
plans, as an asset or liability in their balance sheets.
Employers must also recognize as a component of OCI, net
of tax, the gains or losses and prior service costs or credits
that arise during the period but are not recognized as
components of net periodic benefit cost. Upon adoption of
this provision, Ameren recorded the unfunded obligation of
its defined benefit and postretirement benefit plans. The
unfunded obligation is the difference between plan assets
and the projected benefit obligation for defined benefit plans
or accumulated postretirement benefit obligation for
postretirement benefit plans. Ameren’s adoption of SFAS
No. 158 resulted in increases (decreases) to Ameren’s,
UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s, and IP’s
accrued pension and other postretirement benefits of
$406 million, $234 million, $95 million, $36 million,
$(51) million, $55 million, and $(8) million, respectively.
UE, CIPS, CILCO and IP recorded regulatory assets of
$270 million, $108 million, $63 million, and $205 million,
respectively, based on the expected recovery of these costs
from ratepayers. The adoption of SFAS No. 158 had no
147
material impact on accumulated other comprehensive
income at Ameren. CILCORP and IP recognized gains in
accumulated other comprehensive income of $29 million
and $5 million, respectively, net of taxes, as a result of
SFAS No. 158 obligations being reduced from those
previously recognized. Genco and CILCO recorded a charge
to accumulated other comprehensive income of $25 million
and $2 million, respectively, net of taxes.
Investment Strategy and Return on Asset Assumption
The primary objective of the Ameren retirement plan
and postretirement benefit plans is to provide eligible
employees with pension and postretirement health care
benefits. Ameren manages plan assets in accordance with
the “prudent investor” guidelines contained in ERISA.
Ameren’s goal is to earn the highest possible return on plan
assets 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.
Pension benefits are based on the employees’ years of
service and compensation. Ameren’s pension plans are
funded in compliance with income tax regulations and to
achieve 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. Taking into consideration
our assumptions at December 31, 2008, the investment
performance in 2008, and our pension funding policy,
Ameren expects to make annual contributions of
$90 million to $200 million in each of the next five years.
We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion
of the future funding requirements to be 61%, 6%, 10%,
9%, and 14%, respectively. These amounts are estimates.
They may change with actual investment performance,
changes in interest rates, any pertinent changes in
government regulations, and any voluntary contributions.
Our 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 benefit liability
recorded in the balance sheets of each of the Ameren
Companies as of December 31, 2008:
Ameren(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
$ 1,499
496
79
67
216
216
314
(a)
Includes amounts for Ameren registrant and nonregistrant
subsidiaries.
148
The following table presents the funded status of our pension and postretirement benefit plans for the years ended
December 31, 2008 and 2007:
2008
2007
Pension Benefits(a)
Postretirement
Benefits(a)
Pension Benefits(a)
Postretirement
Benefits(a)
Change in benefit obligation:
Net benefit obligation at beginning of year . . . . . . . . . . . . . . . .
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plan amendments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Participant contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial (gain) loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reflection of Medicare Part D:
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less federal subsidy on benefits paid . . . . . . . . . . . . . . . . . . .
Net benefit obligation at end of year
. . . . . . . . . . . . . . . . . . . . . .
Accumulated 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 (gain) loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost (credit)
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 3,076
60
186
2
-
145
(166)
-
3,303
3,051
2,698
(205)
66
-
-
(166)
2,393
$
$
$
$
910
910
2
908
910
597
40
-
57
10
-
$ 1,253
18
70
-
14
(105)
(73)
5
1,182
(b)
787
(187)
47
5
14
(73)
593
589
589
2
587
589
327
(40)
12
43
(16)
-
$
$
$
$
$ 3,120
63
180
3
-
(126)
(164)
-
3,076
2,837
2,608
202
52
-
-
(164)
2,698
378
378
3
375
378
142
49
-
(34)
10
-
$
$
$
$
$ 1,297
21
72
-
12
(83)
(71)
5
1,253
(b)
742
49
51
4
12
(71)
787
466
466
2
464
466
233
(45)
16
17
(20)
-
$
$
$
$
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
704
$
326
$
167
$
201
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(a)
(b) Not applicable.
Ameren’s current reconciliation of funded status shows certain amounts that will be recognized as a benefit cost in future
years. The unrecognized loss in postretirement benefits is largely a result of declining discount rates over the past several
years and market losses on plan assets.
No plan assets are expected to be returned to Ameren during 2009.
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, resulting 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. Ameren’s postretirement benefit plan did not have a
similar interest rate hedge.
149
The following table presents the assumptions used to determine our benefit obligations at December 31, 2008 and 2007:
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
Postretirement Benefits
2008
5.75%
4.00
-
-
-
2007
6.15%
4.00
-
-
-
2008
2007
5.75%
4.00
7.00
5.00
4 years
6.05%
4.00
9.00
5.00
4 years
The following table presents the cash contributions made to our defined benefit retirement plan qualified trusts and to our
postretirement plans during 2008 and 2007:
Ameren(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension Benefits
Postretirement Benefits
2008
$ 66
36
5
5
7
7
11
2007
$ 52
28
5
4
4
4
9
2008
$ 47
13
2
-
8
8
24
2007
$ 51
27
4
-
13
13
7
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Ameren determines the discount rate assumptions by using an interest rate yield curve to make judgments pursuant to
EITF No. D-36, “Selection of Discount Rates Used for Measuring Defined Benefit Pension Obligations and Obligations of
Postretirement Benefit Plans Other Than Pensions.” The yield curve is based on the yields of more than 300 high-quality,
noncallable 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.
In determining the current year market-related asset value, the prior-year market-related value of assets is adjusted by
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 following table presents our target allocations for 2009 and our pension and postretirement plan asset categories as
of December 31, 2008 and 2007. Ameren’s pension plan debt security weighting was at the high end of the target allocation
range at the end of 2008. Due to current market conditions, Ameren expects the debt security weighting will remain near the
high end of the target allocation range in 2009.
Asset
Category
Target Allocation
2009
Percentage of Plan Assets at December 31,
2008
2007
Pension Plan:
Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Postretirement Plan:
Equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30 - 80%
25 - 60
0 - 10
0 - 10
30 - 80%
15 - 55
0 - 15
36%
56
6
2
100%
51%
43
6
100%
52%
40
6
2
100%
62%
33
5
100%
150
The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit
plans during 2008, 2007 and 2006:
Pension Benefits
Ameren(a)
Postretirement Benefits
Ameren(a)
2008:
Service cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of:
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 60
186
(213)
-
11
3
Net periodic benefit cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 47
2007:
Service cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of:
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 63
180
(206)
-
11
22
Net periodic benefit cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 70
2006:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 63
173
(198)
-
11
42
Net periodic benefit cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 91
$ 18
70
(58)
2
(8)
9
$ 33
$ 21
72
(53)
2
(8)
24
$ 58
$ 22
72
(50)
2
(7)
35
$ 74
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit cost
in 2009 are as follows:
Regulatory assets:
Pension Benefits
Ameren(a)
Postretirement Benefits
Ameren(a)
Net actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost (credit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated OCI:
Net actuarial loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service cost (credit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transition obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 39
8
-
$
1
2
-
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 50
$ 20
(4)
4
$
-
(3)
-
$ 17
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries
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.
151
UE, CIPS, Genco, CILCORP, CILCO and IP are responsible for their share of the pension and postretirement costs. The
following table presents the pension costs and the postretirement benefit costs incurred for the years ended December 31,
2008, 2007 and 2006:
Ameren(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Pension Costs
2007
$ 70
44
10
7
-
8
4
2008
$ 47
35
7
5
(2)
5
(2)
2006
$ 91
51
11
9
10
13
9
Postretirement Costs
2007
2008
2006
$ 33
13
3
2
1
6
14
$ 58
26
6
3
8
13
13
$ 74
40
9
3
9
14
13
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, are as follows:
Pension Benefits
Paid from
Qualified
Trust
Paid from
Company
Funds
Postretirement Benefits
Paid from
Company
Funds
Paid from
Qualified
Trust
Federal
Subsidy
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 - 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
192
194
200
207
213
1,183
$
3
3
3
3
2
10
$
83
89
94
97
100
530
$
2
2
3
3
3
13
$
5
6
6
6
6
33
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, 2008, 2007 and 2006:
Pension Benefits
2007
2006
2008
Postretirement Benefits
2006
2007
2008
Ameren, UE, CIPS , Genco, CILCORP, CILCO and IP:
Discount rate at measurement date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in future compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medical cost trend rate (initial) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medical cost trend rate (ultimate) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Years to ultimate rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.15% 5.85% 5.60%
8.50
8.25
4.00
4.00
-
-
-
-
-
-
8.50
3.25
-
-
-
6.05% 5.80% 5.60%
8.50
8.25
4.00
4.00
9.00
9.00
5.00
5.00
4 years
4 years
8.50
3.25
8.00
5.00
3 years
(a) The Ameren Companies will utilize an expected return on plan assets of 8% in 2009.
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1
2
-
-
$ 104
13
-
-
$ -
-
2
(2)
$ 30
-
29
(26)
Pension
Postretirement
Service Cost
and Interest
Cost
Projected
Benefit
Obligation
Service Cost
and Interest
Cost
Postretirement
Benefit
Obligation
Other
Ameren sponsors a 401(k) plan for eligible employees.
The Ameren plan covered all eligible employees of the
Ameren Companies at December 31, 2008. 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 $23 million, $21 million, and $19 million in 2008,
152
2007, and 2006, respectively. Prior to February 1, 2008,
CIPS employees represented by IBEW Local 702 were
covered by a separate 401(k) plan. The CIPS-related 401(k)
plan was merged into the Ameren plan effective February 1,
2008. CIPS’ matching contributions to the CIPS-related
401(k) plan were less than $1 million annually in 2008,
2007 and 2006.
The following table presents the portion of the 401(k) matching contribution to the Ameren plan for each of the Ameren
Companies for the years ended December 31, 2008, 2007 and 2006:
Ameren(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
$ 23
14
2
2
2
2
2
2007
$ 21
14
1
1
2
2
3
2006
$ 19
13
1
1
2
2
2
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
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, 2008, and changes during the year ended December 31, 2008, under
the 1998 Plan and the 2006 Plan are presented below:
Nonvested at January 1, 2008 . . . . . . . . . . . . . . . . . . . . . . . . .
Granted(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unearned or forfeited(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Earned and vested(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested at December 31, 2008 . . . . . . . . . . . . . . . . . . . . . .
Performance Share Units
Restricted Shares
Shares
669,403
495,847
-
(213,854)
(275,419)
675,977
Weighted-average
Fair Value Per Unit
$ 57.88
32.35
-
55.82
49.37
$ 43.28
Shares
316,768
-
13,364
(2,163)
(114,286)
213,683
Weighted-average
Fair Value Per Share
$ 46.23
-
38.91
48.19
44.05
$ 47.46
(a)
(b)
(c)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in February
2008 under the 2006 Plan.
Includes share units granted in 2006 that were not earned based on performance provisions of the awarded grants.
Includes share units granted in 2006 that vested as of December 31, 2008, 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
$22 million, $18 million, and $11 million for the years
ended December 31, 2008, 2007, and 2006, respectively,
and a related tax benefit of $8 million, $7 million, and
$4 million for the years ended December 31, 2008, 2007,
and 2006, respectively. As of December 31, 2008, total
compensation cost of $13 million related to nonvested
awards not yet recognized is expected to be recognized over
a weighted-average period of 19 months.
Performance Share Units
Performance share unit awards were granted under the
1998 Plan and the 2006 Plan from 2006 to 2008. With
these awards, 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, Ameren has achieved certain
performance goals 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. When a share unit awarded from 2006
to 2008 vests, Ameren will issue the related shares to the
employee two years after vesting, but dividends on the
shares will be paid to the employee at the same time they
are paid to other shareholders.
The fair value of each share unit awarded in February
2008 under the 2006 Plan was determined to be $32.35,
based on Ameren’s closing common share price of $44.30
per share at the grant date and lattice simulations used to
estimate expected share payout based on Ameren’s
attainment of certain financial measures relative to the
designated peer group. 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 maintenance of its $2.54 annual dividend
over the performance period.
The fair value of each share unit awarded in February
2007 under the 2006 Plan was determined to be $59.60.
That figure was based on Ameren’s closing common share
price of $53.99 per share at the grant date and lattice
simulations used to estimate expected share payout based
on Ameren’s attainment of certain financial measures
relative to the designated peer group. The significant
153
assumptions used to calculate fair value also included a
three-year risk-free rate of 4.735%, dividend yields of 2.3%
to 5.2% for the peer group, volatility of 12.91% to 18.33%
for the peer group, and Ameren’s maintenance of its $2.54
annual dividend over the performance period.
Restricted Stock
Restricted stock awards in 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.
NOTE 13 – INCOME TAXES
Stock Options
Ameren
Options in Ameren common stock were granted under
the 1998 Plan at a price not less than the fair-market value
of the common shares at the date of grant. Granted options
vest over a period of five years, beginning at the date of
grant, and 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 85,800 at
December 31, 2008, expire on various dates through 2010.
There is no expense from stock options for the years ended
December 31, 2008, 2007 and 2006, as all options granted
were fully vested.
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, 2008, 2007 and 2006:
Ameren
UE
CIPS
Genco
CILCORP
CILCO
IP
2008:
Statutory federal income tax rate:
Increases (decreases) from:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35%
35%
35% 35%
35%
35% 35%
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Permanent items(a)
Depreciation differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of investment tax credit
. . . . . . . . . . . . . . . . . . . . . . . . . . .
State tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserve for uncertain tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(b)
(1)
-
(1)
4
(1)
(2)
1
(1)
(1)
3
(1)
-
(1)
(2)
(10)
5
(1)
(1)
(2)
-
-
5
(1)
(1)
(3)
(1)
(1)
4
1
(4)
(1)
(1)
(1)
5
-
(1)
7
-
-
5
2
1
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34%
36%
25% 36%
31%
36% 50%
2007:
Statutory federal income tax rate:
Increases (decreases) from:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35%
35%
35% 35%
35%
35% 35%
Permanent items(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of investment tax credit
. . . . . . . . . . . . . . . . . . . . . . . . . . .
State tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserve for uncertain tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(c)
(2)
-
(1)
4
(1)
(1)
(2)
-
(1)
4
(1)
(2)
2
3
(6)
6
-
(4)
(1)
-
(1)
5
-
-
(5)
(2)
(2)
3
-
1
(2)
(1)
(1)
3
-
-
1
(3)
-
5
-
(1)
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34%
33%
36% 38%
30%
34% 37%
2006:
Statutory federal income tax rate:
Increases (decreases) from:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35%
35%
35% 35%
35%
35% 35%
Permanent items(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales of noncore properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nondeductible expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of investment tax credit
State tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserve for uncertain tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(c)
(2)
(2)
1
1
(1)
4
(1)
(2)
(2)
-
2
2
(1)
3
-
(1)
-
-
-
(5)
(3)
5
(2)
(1)
(4)
-
-
-
(1)
5
(2)
(2)
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33%
38%
29% 31%
(d)
(d)
(d)
(d)
(d)
(d)
(d)
(d)
(d)
(5)
(2)
-
(3)
(2)
5
(11)
-
1
-
-
-
-
5
-
(1)
17% 40%
(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, CILCORP and CILCO, company-owned life insurance for Ameren, CILCORP and CILCO, SFAS No. 106-2
Medicare Part D for Ameren, UE, Genco, CILCORP and CILCO, employee stock ownership plan dividends for Ameren, and nondeductible
expenses for IP.
(b) Primarily includes settlements with state taxing authorities for Ameren, state apportionment changes for Ameren, CIPS, Genco, CILCORP, and
CILCO, research credits for Ameren, Genco, CILCORP, and CILCO and low-income housing tax credits for Ameren and CIPS.
(c) Primarily includes low-income housing tax credits for Ameren, UE, CIPS, Genco, CILCORP, and IP.
154
(d) The 2006 difference between the reported federal income tax benefit and income tax expense calculated using the statutory rate resulted
primarily from tax benefits from permanent effects of company-owned life insurance ($1 million), Internal Revenue Code Section 199
production activity deductions ($1 million), plant-related depreciation differences ($2 million), investment tax credit amortization ($1 million),
adjustments to reserves for uncertain tax positions ($6 million), reconciliation of tax return to accrual ($2 million), leveraged leases ($1 million)
and state tax impact of $1 million.
The following table presents the components of income tax expense (benefit) for the years ended December 31, 2008,
2007 and 2006:
2008:
Current taxes:
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 165
10
$
Deferred taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits, amortization . . . . . . . . . . . . . . . . . . . . . . . . .
130
31
(9)
37
5
86
11
(5)
$
4
3
$
81
15
$ 15
(9)
$ 25
5
$ (11)
(11)
2
(2)
(2)
5
-
(1)
6
8
(1)
9
1
(1)
17
10
-
Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 327
$ 134
$
5
$ 100
$ 19
$ 39
$
5
2007:
Current taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 311
17
$ 105
8
$ 21
2
$
Deferred taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits, amortization . . . . . . . . . . . . . . . . . . . . . . . . .
7
4
(9)
22
10
(5)
(10)
(2)
(2)
49
9
17
4
(1)
$ 21
6
$ 36
5
$
3
(2)
1
(6)
(1)
1
(2)
(1)
11
3
-
Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 330
$ 140
$
9
$
78
$ 21
$ 39
$ 15
2006:
Current taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 179
33
$ 123
22
$ 21
7
$
Deferred taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits, amortization . . . . . . . . . . . . . . . . . . . . . . . . .
80
2
(10)
52
(7)
(6)
(7)
(4)
(2)
(6)
4
20
5
(1)
$ (16)
(3)
$
4
5
(1)
3
(1)
2
7
(1)
$ (33)
(3)
63
10
-
Total income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 284
$ 184
$ 15
$
22
$ (11)
$ 10
$ 37
(a)
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
differences at December 31, 2008 and 2007:
Ameren(a)
UE
CIPS
Genco
CILCORP
CILCO
IP
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,377
4
37
(281)
38
6
(27)
(19)
$ 1,427
(3)
44
(92)
-
-
5
(12)
$ 182
90
(4)
(5)
-
-
-
(10)
$ 289
(87)
-
(32)
-
-
(21)
2
$ 242
-
(3)
(54)
43
-
(11)
(29)
$ 242
-
(3)
(59)
-
-
(11)
(13)
$ 205
-
-
(1)
(33)
-
-
(10)
Total net accumulated deferred income tax liabilities(b) . . . . . . . . . . . . . .
$ 2,135
$ 1,369
$ 253
$ 151
$ 188
$ 156
$ 161
2007:
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,186
4
36
(209)
33
7
(35)
(39)
$ 1,355
(4)
42
(91)
-
-
(11)
(39)
$ 171
99
(2)
(8)
-
-
-
(10)
$ 276
(95)
-
(11)
-
-
(14)
12
$ 224
-
(3)
(60)
45
-
(9)
(21)
$ 224
-
(3)
(54)
-
-
(9)
(10)
$ 149
-
-
30
(42)
-
-
(2)
Total net accumulated deferred income tax liabilities(c) . . . . . . . . . . . . . .
$ 1,983
$ 1,252
$ 250
$ 168
$ 176
$ 148
$ 135
155
(a)
(b)
(c)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Includes $3 million, $5 million, $24 million, $15 million, and $15 million as current assets recorded in the balance sheets for UE, CIPS,
CILCORP, CILCO, and IP, respectively. Includes $4 million and $15 million as current liabilities recorded in the balance sheets for Ameren and
Genco, respectively.
Includes $61 million, $21 million, $8 million, $17 million, $7 million and $13 million as current assets recorded in the balance sheets for
Ameren, UE, CIPS, CILCORP, CILCO, and IP, respectively. Includes $7 million as current liabilities recorded in the balance sheet for Genco.
Ameren, CILCORP and IP have Illinois net operating loss carryforwards of $15 million, $11 million, and $4 million,
respectively. These will begin to expire in 2019.
On February 20, 2009, the Illinois Supreme Court handed down its decision in Exelon Corporation v. The Department of
Revenue, which concluded that an electric utility in Illinois qualifies for the Illinois investment tax credit. The decision in the
case may have implications for the Ameren Companies’ income, sales, and use taxes. The Ameren Companies are assessing
the impact the decision may have on their results of operations, financial position or liquidity.
FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of SFAS No. 109 (FIN 48)
On January 1, 2007, the Ameren Companies adopted the provisions of FIN 48, which addresses 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 from January 1, 2007, to December 31, 2008, is as
follows:
Ameren
UE
CIPS
Genco
CILCORP
CILCO
IP
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 . . . . . . . . . . . . . . . . . . .
$ 155
31
(21)
17
(60)
(6)
$ 116
16
(46)
31
(7)
-
$ 58
4
(8)
6
(28)
(6)
$ 26
2
(13)
6
(1)
-
Unrecognized tax benefits – December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 110
$ 20
Total unrecognized tax benefits (detriments) that, if recognized,
would impact the effective tax rates as of December 31, 2008 . . . . . . . . . . . . .
$
12
$ 1
$ 15
-
(3)
-
(12)
-
$
$
$
-
-
-
-
-
-
-
-
$ 36
10
(8)
6
(4)
-
$ 40
4
(9)
13
(1)
-
$ 47
$ 18
3
-
5
(7)
-
$ 19
2
(4)
8
-
-
$ 25
$ 18
3
-
5
(7)
-
$ 19
2
(4)
8
-
-
$ 25
$ (2)
$
-
$
-
$ 12
-
(2)
-
(10)
-
$
$
$
-
-
-
-
-
-
-
-
As of January 1, 2007, the Ameren Companies adopted a policy of recognizing interest expense (income) and penalties
accrued on tax liabilities on a pretax basis as interest expense (income) or miscellaneous expense in the statements of income.
Prior to January 1, 2007, the Ameren Companies recognized such items in the provision for taxes on a net-of-tax basis.
A reconciliation of the change in the liability (receivable) for interest on unrecognized tax benefits from January 1, 2007,
to December 31, 2008, is as follows:
Liability (receivable) for interest – January 1, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 12
Interest expense (income) for 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5
Ameren
UE
$ 5
-
$ 1
-
Liability (receivable) for interest – December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . .
$ 17
$ 5
$ 1
Interest expense (income) for 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(7)
(3)
(1)
Liability (receivable) for interest – December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . .
$ 10
$ 2
$ -
$ 4
3
$ 7
(3)
$ 4
$ 1
1
$ 2
-
$ 2
IP
$ -
-
$ 1
1
$ 2
$ -
-
-
$ 2
$ -
CIPS
Genco
CILCORP
CILCO
As of January 1, 2007, December 31, 2007, and December 31, 2008, the Ameren Companies have accrued no amount for
penalties with respect to unrecognized tax benefits.
Ameren is currently under U.S. federal income tax examination by the Internal Revenue Service for years 2005, 2006, and
2007. 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 now have material state income tax issues under examination,
administrative appeals, or litigation.
156
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.
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.
Illinois Electric Settlement Agreement
As part of the 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 providing $1 billion of
funding for rate relief to certain Illinois electric customers,
including customers of the Ameren Illinois Utilities. At
December 31, 2008, CIPS, CILCO and IP had receivable
balances from Genco for reimbursement of customer rate
relief of $1 million, less than $1 million, and $1 million,
respectively. Also at December 31, 2008, CIPS, CILCO and
IP had receivable balances from AERG for reimbursement
of customer rate relief of less than $1 million, less than
$1 million, and $1 million, respectively. During the year
ended December 31, 2008, Genco incurred charges to
earnings of $17 million for customer rate relief
contributions and program funding reimbursements to the
Ameren Illinois Utilities (CIPS – $6 million, CILCO –
$3 million, IP – $8 million), and AERG incurred charges to
earnings of $8 million (CIPS – $3 million, CILCO –
$1 million, and IP – $4 million). The Ameren Illinois Utilities
recorded most of the reimbursements received from Genco
and AERG as electric revenue with an immaterial amount
recorded as miscellaneous revenue.
Also as part of the 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. 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 being accounted for as cash flow hedges at the
Ameren Illinois Utilities and Marketing Company.
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. Below are the
contracted volumes and prices per megawatthour.
Period
Volume
Price per
Megawatthour
400 MW
June 1, 2008 – December 31, 2008 . . . . .
400 MW
January 1, 2009 – May 31, 2009 . . . . . . . .
800 MW
June 1, 2009 – December 31, 2009 . . . . .
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
$ 47.45
49.47
49.47
51.09
51.09
52.06
53.08
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, 2008,
2007, and 2006:
December 31,
2008
2007
2006
Genco sales to Marketing Company(a) . . .
Marketing Company sales to CIPS(a) . . . .
. .
Genco sales to Marketing Company(b)
AERG sales to Marketing Company(b) . . .
Marketing Company sales to CIPS(c) . . . .
Marketing Company sales to CILCO(c) . . .
Marketing Company sales to IP(c) . . . . . .
-
-
- 21,941
- 12,593
-
-
-
-
-
16,551 17,425
5,316
6,677
2,396
2,050
1,167
909
3,493
2,870
(a) These agreements expired or terminated on December 31, 2006.
(b)
In December 2006, Genco and Marketing Company, and AERG
and Marketing Company, entered into power supply agreements
whereby Genco and AERG sell and Marketing Company
purchases all the capacity available from Genco’s and AERG’s
generation fleets and all the associated energy commencing on
January 1, 2007.
(c) Marketing Company contracted with CIPS, CILCO, and IP to
provide power based on the results of the Illinois reverse auction
in September 2006. The values in this table reflect the physical
sales volumes provided in that agreement.
In December 2006, Genco and Marketing Company
entered into a new power supply agreement (Genco PSA)
whereby Genco agreed to sell and Marketing Company
agreed to purchase all of the capacity available from
Genco’s generation fleet and all the associated energy. On
March 28, 2008, Genco and Marketing Company entered
into an amendment of the Genco PSA. Under the
amendment, Genco is 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 liability in such case will be for
the positive difference, if any, between the market price of
capacity and/or energy Genco does not deliver and the
contract price under the Genco PSA for that capacity and/or
energy. Genco has insurance with an affiliate company that
covers many, but not all, of these situations, subject to
deductibles and policy limits. An unplanned outage or
derate that continues for one year or more is an event of
157
default under the Genco PSA. In the event of Marketing
Company’s unexcused failure to receive energy under the
Genco PSA, Marketing Company would be required to pay
Genco the positive difference, if any, between the contract
price and the price actually received by Genco, acting in a
commercially reasonable manner, to resell the unreceived
energy, less any reasonable related transmission, ancillary
service, or brokerage costs.
Also in December 2006, AERG and Marketing Company
entered into a power supply agreement (AERG PSA)
whereby AERG agreed to sell and Marketing Company
agreed to purchase all of the capacity available from AERG’s
generation fleet and all the associated energy. On March 28,
2008, AERG and Marketing Company entered into an
amendment of the AERG PSA that is substantially identical
to the amendment to the Genco PSA described
above. Under the amendment, AERG is liable to Marketing
Company in the event of an unplanned outage or derate due
to sudden, unanticipated failure or accident within the
generating plant site of one or more of its generating
units. AERG’s liability in such case will be for the positive
difference, if any, between the market price of capacity and/
or energy AERG does not deliver and the contract price
under the AERG PSA for that capacity and/or energy. AERG
has insurance with an affiliate company that covers many,
but not all of these situations, subject to deductibles and
policy limits. An unplanned outage or derate that continues
for one year or more is an event of default under the AERG
PSA. In the event of Marketing Company’s unexcused failure
to receive energy under the AERG PSA, Marketing Company
would be required to pay AERG the positive difference, if
any, between the contract price and the price actually
received by AERG, acting in a commercially reasonable
manner, to resell the unreceived energy, less any reasonable
related transmission, ancillary service, or brokerage costs.
Both the Genco PSA and the AERG PSA 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 Ending
May 31, 2008
17 Months
May 31, 2009
29 Months
May 31, 2010
41 Months
. . . . . . . . .
300
750
750
Term
Megawatts(a)
Cost per
megawatthour . . . . . .
$ 64.77
$ 64.75
$ 66.05
(a) Before impact to Ameren Illinois Utilities’ load due to customer
switching.
One-third of the Ameren Illinois Utilities’ supply
contracts that served the load needs of their fixed-price
residential and small commercial customers, and all of the
supply contracts that served large commercial and
industrial customers, expired on May 31, 2008. To replace
these expired supply contracts, the Ameren Illinois Utilities
used RFP processes in early 2008, pursuant to the Illinois
electric settlement agreement, to contract for the necessary
energy and capacity requirements 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 and capacity RFPs. Marketing Company
entered into financial instruments that fixed the price that
the Ameren Illinois Utilities will pay for about two million
megawatthours at approximately $60 per megawatthour.
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.
Separately, the Ameren Illinois Utilities used an RFP
process to procure ancillary services for 2007 and 2008
required to maintain reliable operation of their transmission
systems. Both UE and Marketing Company were among the
winning suppliers in both years’ ancillary services RFPs. In
January 2009, the Ameren Illinois Utilities began procuring
ancillary services from the MISO ancillary services market.
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
are required to support the additional electric power
upgrades being made at Genco’s Coffeen power
plant. Under the agreement, Genco will pay CIPS for the
costs of the transmission upgrades. When the transmission
assets are placed in service, CIPS will be required to repay
Genco, with interest, for the costs of the transmission
upgrades. At December 31, 2008, CIPS had recorded
$2 million in Other Deferred Credits and Liabilities and
Genco had recorded $2 million in Accounts Receivable –
Affiliates. These transactions were eliminated in
consolidation on Ameren’s financial statements.
158
Joint Dispatch Agreement
Money Pools
Prior to December 31, 2006, UE and Genco dispatched
electric generation under a joint dispatch agreement among
UE, CIPS and Genco. UE and Genco had the option to serve
their load requirements from their own generation first, and
then each could give its affiliates access to any available
generation at incremental cost. Any excess generation not
used by UE or Genco to serve load requirements was sold
to third parties on a short-term basis. To allocate power
costs between UE and Genco, an intercompany sale was
recorded by the company providing the power. By mutual
consent of UE, CIPS, and Genco, the JDA was terminated
on December 31, 2006.
The following table presents the amount of
gigawatthour sales under the JDA during the year ended
December 31, 2006:
UE sales to Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco sales to UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006
10,072
3,917
The following table presents the short-term power
sales margins under the JDA for UE and Genco during the
year ended December 31, 2006:
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006
$ 108
33
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 141
Support Services Agreements
Costs of support services provided by Ameren
Services, AFS, and Ameren Energy, Inc., until December 31,
2007, to their affiliates, including wages, employee benefits,
professional services, and other expenses are based on, or
are an allocation of, actual costs incurred. Ameren Energy,
Inc. was dissolved on December 31, 2007.
Executory Tolling, Gas Sales, and Transportation
Agreements
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.
Transitional Funding Securitization Financing Agreement
See Note 1 – Summary of Significant Accounting
Policies for further information. In 2008, the TFNs were
redeemed.
See Note 5 – Long-term Debt and Equity Financings for
discussion of affiliate borrowing arrangements.
Intercompany Borrowings
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. 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 expense for this note recorded by
CIPS and Genco, respectively, was $7 million, $10 million,
and $12 million for the years ended December 31, 2008,
2007, and 2006, respectively.
CILCORP had outstanding borrowings directly from
Ameren of $152 million and $2 million, at December 31,
2008 and 2007, respectively. The average interest rate on
these borrowings was 3.6% for the year ended
December 31, 2008 (2007 – 5.14%). CILCORP recorded
interest expense of $1 million, less than $1 million, and
$7 million for Ameren borrowings for the years ended
December 31, 2008, 2007, and 2006, respectively.
UE had outstanding borrowings directly from Ameren
of $92 million at December 31, 2008. The average interest
rate on these borrowings was 3.6% for the year ended
December 31, 2008. UE recorded interest expense of
$1 million, $4 million, and $1 million for Ameren
borrowings for the years ended December 31, 2008, 2007,
and 2006, respectively.
At December 31, 2007, UE held a $30 million
intercompany note receivable from its wholly owned
subsidiary, Union Electric Development Corporation. This
note was transferred to Ameren Development Company from
Union Electric Development Corporation in connection with
the merger discussed below under Intercompany Transfers.
The note was paid off in November 2008. The average
interest rate on this note while outstanding during 2008 was
5.17%. UE recorded interest revenue of $2 million for this
note for the year ended December 31, 2008.
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, cash 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, meaning that Marketing
Company as the supplier is the only counterparty required
to post collateral. At December 31, 2008, there were no
collateral postings by Marketing Company related to the
2006 auction power supply agreements, and at
December 31, 2007, Marketing Company had posted
$1 million, less than $1 million, and $1 million for the
benefit of CIPS, CILCO, and IP, respectively.
159
In addition, under the terms of the 2008 Illinois power
procurement RFPs, cash collateral must be posted by
Marketing Company and the Ameren Illinois Utilities under
certain market conditions. The collateral postings are
bilateral, meaning that either counterparty may 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.
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. Genco recorded operating
revenues from the lease agreement of $2 million,
$11 million, and $11 million for the three years ended
December 31, 2008, 2007, and 2006, respectively. 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.
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 entire 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 now has an 80%
ownership interest in EEI and consolidates it accordingly.
The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the
years ended December 31, 2008, 2007 and 2006. It is based primarily on the agreements discussed above and the money pool
arrangements discussed in Note 4 – Short-term Borrowings and Liquidity.
Agreement
Genco and AERG power supply
agreements with Marketing Company
Ancillary services and capacity agreements
with CIPS, CILCO and IP(c)
Power supply agreement with Marketing
Company – expired December 31, 2006
UE and Genco gas transportation agreement
Income Statement Line Item
Operating Revenues
Operating Revenues
Operating Revenues
Operating Revenues
JDA – terminated December 31, 2006
Genco gas sales to distribution companies
Operating Revenues
Operating Revenues
Total Operating Revenues
UE and Genco gas transportation agreement
Fuel
CIPS, CILCO and IP agreements with
Marketing Company(d)
Ancillary services and capacity agreements
with UE(c)
Ancillary services agreement with Marketing Company
JDA – terminated December 31, 2006
Power supply agreement with Marketing
Company – expired December 31, 2006
Executory tolling agreement with Medina Valley
Purchased Power
Purchased Power
Purchased Power
Purchased Power
Purchased Power
Purchased Power
Total Purchased Power
Insurance recoveries
Operating Revenues and
Purchased Power
160
UE
Genco
CIPS
$ (b) $ (b) $ 893
831
(b)
(b)
(b)
(b)
(b)
793
(b)
(b)
13
18
(b)
CILCORP(a)
$ 344
279
(b)
(b)
5
1
1
1
196
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
97
7
(b)
(b)
(b)
(b)
(b)
$ 14
19
197
$ (b) $ 900
831
890
(b)
(b)
$ 344
279
5
$ (b) $ (b) $
(b)
(b)
(b)
(b)
$
$ (b) $145
157
4
6
6
3
(b)
448
(b)
(b)
(b)
(b)
(b)
97
(b)
(b)
(b)
(b)
(b)
(b)
(b)
1
1
1
(b)
(b)
(b)
(b)
(b)
(b)
196
(b)
(b)
(b)
(b)
$
$
(b)
(b)
(b)
65
76
2
3
3
1
(b)
1
39
38
39
$ (b) $155
166
448
(b)
97
$
(b)
(b)
196
$ (e) $ (b) $ (11)
(2)
(b)
(12)
$ 109
118
40
$
(4)
(7)
IP
$ (b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
(b)
$ (b)
(b)
(b)
$ (b)
(b)
(b)
$204
227
7
9
8
4
(b)
(b)
(b)
(b)
(b)
$219
240
(b)
$ (b)
(b)
2008
2007
2008
2007
2006
2008
2007
2006
2006
2008
2008
2007
2006
2008
2007
2006
2008
2007
2008
2007
2008
2007
2006
2006
2008
2007
2006
2008
2007
2006
2008
2007
Agreement
Income Statement Line Item
UE
CIPS
Genco
CILCORP(a)
IP
Gas purchases from Genco
Ameren Services support services agreement
Ameren Energy, Inc. support services agreement
AFS support services agreement
Insurance premiums(g)
Total Other Operations and Maintenance Expenses
Gas Purchased for Resale
Other Operations and
Maintenance
Other Operations and
Maintenance
Other Operations and
Maintenance
Other Operations and
Maintenance
Money pool borrowings (advances)
Interest (Expense)
Income
2008
2008
2007
2006
2008
2007
2006
2008
2007
2006
2008
2007
2008
2007
2006
2008
2007
2006
$
(b)
$ (e)
$ (b)
$ 130
137
136
$50
47
47
$28
24
23
(f)
8
7
7
6
5
8
19
$ 145
170
148
$
(e)
(e)
(e)
(b)
(b)
(b)
2
2
1
(b)
(b)
$52
49
48
$ (e)
(e)
2
(f)
(e)
2
3
2
2
4
4
$35
30
27
$ (e)
8
10
$ 6
$51
49
48
(b)
(b)
(b)
2
2
2
3
2
$56
53
50
$ (e)
(e)
4
$ (b)
$76
73
71
(b)
(b)
(b)
2
2
2
(b)
(b)
$78
75
73
$ (e)
1
2
(a) Amounts represent CILCORP and CILCO activity.
(b) Not applicable.
(c) Represents ancillary services to the Ameren Illinois Utilities in 2007 and 2008 and capacity to the Ameren Illinois Utilities beginning in
June 2008.
(d) Represents power supply costs under agreements entered into as part of the Illinois September 2006 auction and the 2008 energy and capacity
RFPs.
(e) Amount less than $1 million.
(f) Ameren Energy, Inc. was eliminated December 31, 2007, through an internal reorganization.
(g) Represents insurance premiums paid to 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, 2008. The property
coverage and the nuclear liability coverage must be renewed on October 1 and January 1, respectively, of each year.
Maximum Coverages Maximum Assessments for Single Incidents
Type and Source of Coverage
Public liability and nuclear worker liability:
American Nuclear Insurers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pool participation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
300(a)
10,461
$10,761(c)
Property damage:
Nuclear Electric Insurance Ltd.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,750(d)
Replacement power:
Nuclear Electric Insurance Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy Risk Assurance Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
490(e)
64(f)
$
-
117.5(b)
$ 117.5
$ 21.6
$
$
8.5
-
(a) Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b) Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This is subject to
retrospective assessment with respect to a covered loss in excess of $300 million from an incident at any licensed U.S. commercial reactor,
payable at $17.5 million per year.
(c) Limit of liability for each incident under Price-Anderson. This limit is subject to change to account for the effects of inflation and changes in the
number of licensed reactors.
(d) Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up
to $2.25 billion for losses in excess of the $500 million primary coverage.
161
(e) Provides the replacement power cost insurance in the event of a prolonged accidental outage at a 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.
(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at a 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, 2008:
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)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 717
395
322
392
$ 32
28
4
39
$ 65
56
9
66
$ 65
55
10
54
$ 555
256
299
233
Total lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 714
$ 43
$ 75
$ 64
$ 532
UE:
Capital lease payments(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less amount representing interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Present value of minimum capital lease payments . . . . . . . . . . . . . . . . . . . .
Operating leases(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 717
395
322
174
$ 32
28
4
15
$ 65
56
9
28
$ 65
55
10
25
$ 555
256
299
106
Total lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 496
$ 19
$ 37
$ 35
$ 405
CIPS:
Operating leases(c)
Genco:
Operating leases(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2
$
-
$
1
$
1
$
-
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 143
$
9
$ 17
$ 17
$ 100
CILCORP and CILCO:
Operating leases(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
18
$
1
$
3
$
2
$
12
IP:
Operating leases(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
8
$
3
$
4
$
1
$
-
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) See Properties under Part I, Item 2 of this report for further 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
amount because that period is indefinite.
162
We lease various facilities, office equipment, plant equipment, and rail cars under operating leases. We also have capital
leases relating to UE’s Peno Creek and Audrain County CT facilities. The following table presents total rental expense, included
in other operations and maintenance expenses, for the years ended December 31, 2008, 2007 and 2006:
Ameren(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP and CILCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 19
20
9
2
7
13
$ 15
19
9
2
7
12
$ 15
20
9
2
6
11
2008
2007
2006
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
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, and nuclear fuel. We also have entered into various long-term
commitments for the purchase of electricity and natural gas for distribution. The following table presents the estimated fuel,
electric capacity, and natural gas commitments at December 31, 2008. In addition, the following table presents in the Other
column minimum purchase commitments for heavy forgings contracts related to a potential second nuclear unit, meter
reading contracts, and an Ameren tax credit obligation. Ameren’s tax credit obligation is a $75 million note payable issued for
an investment in a low-income real estate development partnership to acquire New Markets Tax Credits. This note payable was
netted against the related investment in Other Assets at December 31, 2008, as Ameren has a legally enforceable right to offset
it under FIN 39.
Coal
Gas
Nuclear
Electric
Capacity
Other
Total
Ameren:(a)
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
$
728
841
652
440
31
-
$
486
399
268
176
82
173
$
68
75
53
67
59
173
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,692
$ 1,584
$ 495
UE:
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
$
393
429
313
136
-
-
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,271
CIPS:
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco:
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
$
$
$
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
-
-
-
-
-
-
-
134
185
129
112
-
-
560
$
$
$
$
$
$
80
67
47
32
23
38
$
68
75
53
67
59
173
287
$ 495
106
71
60
44
30
28
339
10
8
8
5
3
8
42
$
$
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$ 14
-
-
-
-
-
$ 14
$ 14
-
-
-
-
-
$ 14
$ (c)
-
-
-
-
-
$
$
$
-
-
-
-
-
-
-
-
$
63
89
79
79
40
292
$ 1,359
1,404
1,052
762
212
638
$ 642
$ 5,427
$
31
57
46
46
24
168
$
586
628
459
281
106
379
$ 372
$ 2,439
$
$
$
$
4
2
2
2
2
18
30
-
-
-
-
-
-
-
$
$
$
$
110
73
62
46
32
46
369
144
193
137
117
3
8
602
163
Coal
Gas
Nuclear
Electric
Capacity
Other
Total
CILCORP and CILCO:
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
$
62
84
85
79
31
-
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
341
IP:
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter(b)
$
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
-
-
-
-
-
-
-
$
$
$
$
113
93
64
40
15
91
416
162
158
88
54
11
8
481
$
$
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$ (c)
-
-
-
-
-
$
-
$ (c)
-
-
-
-
-
$
-
$
$
$
$
$
$
3
3
3
3
3
25
40
11
10
11
11
11
81
$ 135
$
178
180
152
122
49
116
797
173
168
99
65
22
89
616
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(a)
(b) Commitments for natural gas and nuclear fuel are until 2021 and 2020, respectively.
(c) At December 31, 2008, less than $1 million of electric capacity contracts were executed for the Ameren Illinois Utilities for 2009 with
approximately 33% of the capacity resources dedicated to CIPS, 17% to CILCO, and 50% to IP. For 2009, approximately one-third of the
Ameren Illinois Utilities capacity was obtained through the Illinois power procurement auction. The IPA plans to go forward with RFPs to
purchase capacity for the Ameren Illinois Utilities during the first half of 2009. See below for additional information.
Ameren Illinois Utilities’ Purchased Power Agreements
Commencing 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.
One-third of the Ameren Illinois Utilities’ supply
contracts that served the load needs of their fixed-price
residential and small commercial customers, and all of the
supply contracts that served large commercial and
industrial customers, expired on May 31, 2008. The Ameren
Illinois Utilities used RFP processes in early 2008 to replace
these expired supply contracts, pursuant to the Illinois
electric settlement agreement. Specifically, the Ameren
Illinois Utilities used RFPs to procure energy swaps,
capacity, and renewable energy credits for the period
June 1, 2008, through May 31, 2009. The Ameren Illinois
Utilities contracted to purchase approximately two million
megawatthours of energy swaps at an average price of
$60 per megawatthour. As a result of a capacity RFP, the
Ameren Illinois Utilities contracted to purchase about
1,800 megawatts of capacity at an average price of $50 per
MW-day. A renewable energy credits RFP resulted in the
Ameren Illinois Utilities contracting to purchase
415,000 credits at an average price of $17 per credit.
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
Term Ending
May 31, 2009
29 Months
May 31, 2010
41 Months
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS’ load in megawatts(a)
CILCO’s load in megawatts(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP’s load in megawatts(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
639
328
928
Total load in megawatts(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,895
Cost per megawatthour
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 64.75
639
328
928
1,895
$ 66.05
(a) Represents peak forecast load for CIPS, CILCO and IP. Actual load 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.
164
Illinois Electric Settlement Agreement
The Illinois electric settlement agreement provides
$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 will come from 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, 2008:
Ameren CIPS
CILCO
(Illinois
Regulated)
2009(a)
2010(a)
. .
. .
$ 26.6
1.9
$ 3.9
0.3
Total . . . .
$ 28.5
$ 4.2
$ 1.9
0.1
$ 2.0
IP
Genco
$ 5.1 $ 10.8
0.8
0.4
$ 5.5 $ 11.6
CILCO
(AERG)
$ 4.9
0.3
$ 5.2
(a) Estimated.
Also as part of the 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 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
plants, 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 and water, protected and cultural
resources (such as wetlands, endangered species, and
archeological and historical resources), and chemical and
waste handling. Our activities often require complex and
lengthy processes as we 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, including
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 maximum
available control technology requirements under the Clean
Air Act. The EPA and a group representing the electric utility
industry filed petitions for rehearing; however, the court
denied those petitions in May 2008. A group representing
the electric utility industry and the EPA both filed petitions
for review of the U.S. Court of Appeals decision with the
U.S. Supreme Court in September 2008 and October 2008,
respectively. In February 2009, the EPA withdrew its
petition to the U.S. Supreme Court. In February 2009, the
U.S. Supreme Court denied the 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. The standard is
expected to be available in draft form by mid to late 2009,
and compliance is expected to be required in the 2013 to
2015 timeframe.
We are currently evaluating the impact that the court
decision will have on our environmental compliance
strategy. We are unable to predict the outcome of this legal
proceeding, the actions the EPA or U.S. Congress may take
in response to the court decision, or the timing of such
actions. We also cannot predict at this time the ultimate
impact the court decision and resulting regulatory actions
will have on our estimated capital costs for compliance with
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.
165
The state of Missouri has adopted state 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 30% and SO2 emissions 75% by 2015. As a
result of the Missouri rules, UE will manage allowances and
install pollution control equipment. Missouri also adopted
state rules to implement the federal Clean Air Mercury Rule.
However, those state 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. Under the MPS,
Illinois generators may defer until 2015 the requirement to
reduce mercury emissions by 90%, in exchange for
accelerated installation of NOx and SO2 controls. To comply
with the rule, Genco, CILCO (AERG) and EEI have begun
putting into service equipment designed to reduce mercury
emissions. This rule, when fully implemented, is expected
to reduce mercury emissions 90%, NOx emissions 50%,
and SO2 emissions 70% by 2015 in Illinois. As a result of
the Illinois rules, Genco, AERG and EEI will need to procure
allowances and install 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.
In October 2008, Genco, CILCO (AERG) and EEI
submitted a request for a variance from the MPS to the
Illinois Pollution Control Board. In preparing this request,
Genco, CILCO (AERG) and EEI worked with the Illinois EPA
and agreed to the installation of more stringent SO2 and NOx
controls at various stages between 2010 and 2020 in order
to make the variance proposal “environmentally neutral.” In
January 2009, the Illinois Pollution Control Board denied
the variance request on procedural grounds. Genco, CILCO
(AERG) and EEI filed a motion for reconsideration in
February 2009. With the Illinois EPA’s concurrence, they
now seek to amend the MPS within a pending rulemaking
pertaining to technical amendments of the underlying
mercury regulations. Revisions to the MPS within that
rulemaking will require Illinois Pollution Control Board
approval. If approved, this variance or rule amendment
would allow Genco to defer approximately $375 million of
environmental capital expenditures from the 2009-2012
timeframe to the 2013-2015 timeframe. This amount is
reduced from the $500 million disclosed in Genco’s
Quarterly Report on Form 10-Q for the period ended
September 30, 2008, because of revisions to the size and
timing of projected environmental capital expenditures if no
variance is granted. A decision is expected in 2009.
In March 2008, the EPA finalized regulations that will
lower the ambient standard for ozone. States must submit
their nonattainment plans in March 2009. A final action by
the EPA to designate areas as nonattainment 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 the
future state implementation plans. At this time, we are
unable to determine the impact such state actions would
have on our results of operations, financial position, or
liquidity.
The table below presents estimated capital costs that
are based on current technology, to comply with the federal
Clean Air Interstate Rule and related state implementation
plans through 2018, as well as federal ambient air quality
standards including ozone and fine particulates, and the
federal Clean Air Visibility rule. The estimates described
below could change depending upon additional federal or
state requirements, the requirements under a mercury
MACT standard, whether the variance or rule amendment
request with respect to the Illinois MPS discussed above is
granted, new technology, variations in costs of material or
labor, or alternative compliance strategies, among other
reasons. 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.
2009
2010 - 2013
2014 - 2018
Total
UE(a) . . . . . . $ 100 $
Genco . . . .
CILCO . . . .
EEI . . . . . . .
230
55
15
525- $
875-
365-
120-
655 $ 1,530- $ 1,885 $ 2,155- $ 2,640
1,440
125
590
80
830
660
1,200-
480-
665-
95-
60-
530-
1,085
455
155
Ameren . . . $ 400 $ 1,885- $ 2,350 $ 2,215- $ 2,750 $ 4,500- $ 5,500
(a) UE’s expenditures are expected to be recoverable in rates over
time.
Emission Allowances
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. If additional allowances are needed for
new generating facilities, they can be purchased from
facilities that have excess allowances or from allowance
banks. In addition, the Illinois rules to implement the federal
Clean Air Interstate Rule include an allowance set aside for
new generating facilities. 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 facilities are expected to comply with the NOx
limits through the use and purchase of allowances or
through the application of pollution control technology,
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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 carried as intangible assets as of December 31,
2008.
UE, Genco, CILCO and EEI expect to use a substantial
portion of the 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 that is 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, 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. Both sets of allowances for the years
2009 through 2014 were issued by the Missouri
Department of Natural Resources in December 2007.
Allocations for UE’s Missouri generating facilities 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. Both
sets of allowances for the years 2009 through 2011 were
issued by the Illinois EPA in April 2008. Allocations for
UE’s, Genco’s, AERG’s, and EEI’s Illinois generating
facilities were 90, 3,442, 1,368, and 1,758 tons per ozone
season, respectively, and 93, 8,300, 3,418, and 4,564 tons
annually.
Global Climate
Future initiatives regarding greenhouse gas emissions
and global warming are subject to active consideration in
the U.S. Congress. In October 2008, the U.S. House of
Representatives, Energy and Commerce Committee,
Subcommittee on Energy and Air Quality issued a
“discussion draft” of climate legislation, which proposed
establishing an economy-wide cap-and-trade program. The
overarching goal of such legislation is to reduce greenhouse
gas emissions to a level that is 6% below 2005 levels by
2020 and 80% below 2005 levels by the year 2050. In
addition, new leadership in the Energy and Commerce
Committee is considering aggressive climate legislation.
President Obama supports an economy-wide cap-and-
trade greenhouse gas reduction program that would reduce
emissions to 1990 levels by 2020 and to 80% below 1990
levels by 2050. President Obama has also indicated support
for auctioning 100% of the emission allowances to be
distributed under the legislation. Although we cannot
predict the date of enactment or the requirements of any
global warming legislation, it is likely that some form of
federal greenhouse gas legislation will become law during
President Obama’s administration.
Potential impacts from proposed legislation could vary,
depending upon proposed CO2 emission limits, the timing
of implementation of those limits, the method of allocating
allowances, and provisions for cost containment measures,
such as a “safety valve” that provides a ceiling price for
emission allowance purchases. As a result of our diverse
fuel portfolio, our contribution to greenhouse gases varies
among our generating facilities, but coal-fired power plants
are significant sources of CO2, a principal greenhouse gas.
Ameren’s current analysis shows that under some policy
scenarios being considered in the U.S. Congress,
household costs and rates for electricity could rise
significantly. The burden could fall particularly hard on
electricity consumers and the Midwest economy 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 electric generation also could affect the cost of
heating for our utility customers and many industrial
processes. Under some policy scenarios being considered
by Congress, 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.
Future initiatives regarding greenhouse gas emissions
and global warming may also be subject to the activities
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. It is expected that the advisory group to the
Midwest governors will provide recommendations on the
design of a greenhouse gas reduction program by the third
quarter of 2009. However, it is uncertain whether legislation
to implement the recommendations will be implemented or
passed by any of the states, including Illinois.
With regard to greenhouse gas regulation under
existing law, in April 2007, the U.S. Supreme Court issued a
decision that the EPA has the authority to regulate CO2 and
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other greenhouse gases from automobiles as “air pollutants”
under the Clean Air Act. This decision was a result of a Bush
Administration ruling denying a waiver request by the state of
California to implement such regulations. The Supreme Court
sent the case back to the EPA, which must conduct a
rulemaking process to determine whether greenhouse gas
emissions contribute to climate change “which may
reasonably be anticipated to endanger public health or
welfare.” In July 2008, the EPA issued an advance notice of
public rulemaking (ANPR) in response to the U.S. Supreme
Court’s directive. The ANPR solicited public comments on the
benefits and ramifications of regulating greenhouse gases
under the Clean Air Act, and that rulemaking has not been
completed. On February 12, 2009, the EPA announced its
intent to reconsider the decision under the Bush
Administration denying the waiver to the state of California
for regulating CO2 emissions from automobiles. On
February 17, 2009, the EPA also granted a petition for
reconsideration filed by the Sierra Club to reexamine a
December 2008 Bush Administration ruling that CO2 should
not be regulated under the Clean Air Act when issuing
construction permits for power plants. These EPA actions will
factor into the rulemaking process on the ANPR and could
ultimately lead to regulation of CO2 from power plants.
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. 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. 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, or liquidity.
Ameren has taken actions to address the global climate
issue. These include:
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seeking partners to develop wind energy for our
generation portfolio;
participating in DOE-sponsored research into the
feasibility of sequestering CO2 underground in the
Illinois basin, the Plains sequestration partnership, and
a Missouri sequestration project to be conducted in
Southwest Missouri;
increasing the operating efficiency and capacity of our
nuclear and hydroelectric plants to provide more
energy to offset fossil generation;
participating in the PowerTree Carbon Company, LLC,
whose purpose is to reforest acreage in the lower
Mississippi valley to sequester carbon;
using coal combustion byproducts as a direct
replacement for cement, thereby reducing carbon
emissions at cement kilns;
participating in a DOE and state of Missouri Department
of Natural Resources project evaluating Missouri wind
resources for the next generation of wind turbines;
funding a project investigating opportunities to reduce
nitrous oxide (N2O), a potent greenhouse gas from
agricultural usage, and tracking those reductions;
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participating in the Illinois Clean Energy Community
Foundation, a program that supports energy efficiency,
promotes renewable energy, and provides educational
opportunities;
establishing Pure Power, UE’s voluntary renewable
energy program that allows UE’s electric customers to
support development of wind farms and other
renewable energy facilities in the Midwest;
purchasing Renewable Energy Credits, as when the
Ameren Illinois Utilities purchased 415,000 renewable
energy credits in April 2008; and
participating in funding the new Consortium for Clean
Coal Utilization research center at Washington
University, which will investigate clean coal
technologies, such as oxy-fuel combustion and CO2
capture and storage.
The impact on us of future initiatives related to
greenhouse gas emissions and global warming is unknown.
Although compliance costs are unlikely in the near future, 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, or liquidity.
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
us to install additional intake screens or 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
facilities. In January 2007, the U.S. Court of Appeals for the
Second Circuit remanded many provisions of these rules to
the EPA for revision. In April 2008, the U.S. Supreme Court
agreed to hear an appeal of the lower court ruling. The U.S.
Supreme Court heard the case in December 2008. The EPA
is expected to reissue the rules early in 2009. Until a
decision is issued by the Supreme Court and the new rules
are adopted, and the studies on 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.
New Source Review
The EPA has been conducting an enforcement initiative
to determine whether modifications at a number of coal-
fired power plants owned by electric utilities in the
United States are subject to New Source Review (NSR)
requirements or New Source Performance Standards under
the Clean Air Act. The EPA’s inquiries focus on whether the
best available emission control technology was or should
have been used at such power plants when major
maintenance or capital improvements were performed.
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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 December 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. We are in the
process of responding to this request. We are also currently
in discussions with the EPA and the state of Illinois regarding
resolution of these matters, but we are unable to predict the
outcome of these discussions.
In March 2008, Ameren received a request from the
EPA for information pursuant to Section 114(a) of the Clean
Air Act seeking detailed operating and maintenance history
data with respect to UE’s Labadie, Meramec, Rush Island,
and Sioux facilities. All of these facilities are coal-fired
power plants. The information request required UE to
provide responses to specific EPA questions regarding
certain projects and maintenance activities in order to
determine UE’s compliance with state and federal regulatory
requirements. UE is complying with this information
request, but we are unable to predict the outcome of this
matter.
Resolution of these matters could have a material
adverse impact on the future results of operations, financial
position, or liquidity of Ameren, UE, Genco, AERG and EEI. A
resolution could result in increased capital expenditures for
the installation of control technology, increased operations
and maintenance expenses, and fines or penalties.
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 for remediation costs
associated with preexisting environmental contamination at
the transferred sites.
As of December 31, 2008, CIPS, CILCO and IP owned
or were otherwise responsible for several former MGP sites
in Illinois. CIPS has 14, CILCO 4, and IP 25. All of these
sites are in various stages of investigation, evaluation and
remediation. Under its current schedule, Ameren anticipates
that remediation at these sites should be completed by
2015. 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, and costs are subject to annual
reconciliation review by the ICC. As of December 31, 2008,
estimated obligations were: CIPS – $17 million to
$29 million, CILCO – $8 million to $13 million,
IP –$74 million to $143 million. CIPS, CILCO and IP
recorded liabilities of $17 million, $8 million, and
$74 million, respectively, to represent estimated minimum
obligations, as no other amount within the range was a
better estimate.
CIPS is also responsible for the cleanup of a former
landfill in Coffeen, Illinois. As of December 31, 2008, CIPS
estimated its 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, 2008,
IP recorded a liability of $1 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 in Iowa. UE does not
currently have in effect in Missouri a rate rider mechanism
that permits remediation costs associated with MGP sites to
be recovered from utility customers. See Note 2 – Rate and
Regulatory Matters for information on a Missouri law
enabling the MoPSC to put in place environmental cost
recovery mechanisms for Missouri utilities. 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, 2008, UE estimated its obligation at
$3 million to $4 million. UE recorded a liability of $3 million
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 electric sites in
Missouri that have corporate cleanup liability, most as a
result of federal agency mandates.
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.
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.
Sauget Area 2 investigations overseen by the EPA are
largely completed, and the results will be submitted to the
EPA in June 2009. Following this submission, the EPA will
ultimately select a remedy alternative and begin
negotiations with various PRPs to implement it. Over the
last several years, numerous other parties have joined the
PRP group and 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
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waste landfill in the Sauget Area 2, notwithstanding
Solutia’s filing for bankruptcy protection. As of
December 31, 2008, UE estimated its obligation at
$1 million to $10 million. UE recorded a liability of
$1 million to represent its estimated minimum obligation,
as no other amount within the range was a better estimate.
In March 2008, the EPA issued an administrative order
requesting that CIPS participate in a portion of an
environmental cleanup of a site within Sauget Area 2
previously occupied by Clayton Chemical Company. CIPS
was formerly a customer of Clayton Chemical Company,
which before its dissolution was a recycler of waste
solvents and oil. Other former customers of Clayton
Chemical Company were issued similar orders by the EPA.
Pursuant to that order, CIPS and three other PRPs agreed
to install an engineered barrier on portions of the Clayton
Chemical Company site. This work is expected to be
concluded in the first quarter of 2009. As of December 31,
2008, CIPS recorded a liability of $0.25 million to represent
its best estimate of its obligation for this site.
In July 2008, the EPA issued an administrative order to
UE pertaining to a former coal tar distillery operated by
Koppers Company or its predecessor and successor
companies. UE is the current owner of the site but did not
conduct any of the manufacturing operations involving coal
tar or its byproducts. UE is currently in negotiations with
other PRPs concerning the scope of future site
investigations. As of December 31, 2008, UE estimated its
obligation at $2 million to $5 million. UE recorded a liability
of $2 million to represent its estimated minimum obligation,
as no other amount within the range was a better estimate.
In December 2004, AERG submitted a comprehensive
package 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. CILCORP and CILCO both have a liability
of $1.9 million at December 31, 2008, on their Consolidated
Balance Sheets for the estimated cost of the remediation
effort, which involves treating and discharging recycle-
system water in order to address these groundwater and
surface water issues.
In addition, 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
the impact these actions may have on our results of
operations, financial position, or liquidity.
Ash Ponds
In December 2008, an ash pond dike failed at a
non-Ameren owned utility company releasing approximately
one billion gallons of coal ash slurry. The ash was deposited
primarily over 300 acres, destroying three homes. As a
result of this incident, there has been increased activity at
both the state and federal level to examine the need for
additional regulation of utility ash pond facilities and coal-
combustion wastes. It is anticipated that some form of
additional regulation concerning the integrity of ash ponds
and the handling and disposal of coal combustion waste
may be forthcoming within the next two years. At this time,
we are unable to predict the outcome any such regulations
might have on our results of operations, financial position,
or liquidity.
Polychlorinated Biphenyls Information Request
Polychlorinated biphenyls (PCBs) are a blend of
chemical compounds that were historically used in a variety
of industrial products because of their chemical and thermal
stability. In natural gas systems, PCBs were used as a
compressor lubricant and a valve sealant before their sale
for these applications was banned by the EPA in 1979.
During the third quarter of 2007, the Ameren Illinois Utilities
received requests from the Illinois attorney general and
from the EPA for information regarding their experiences
with PCBs in their gas distribution systems. The Ameren
Illinois Utilities responded to these information requests.
The Ameren Illinois Utilities have evaluated their gas
distribution systems for the presence of PCBs. They believe
that the presence of PCBs is limited to discrete areas and is
not widespread throughout their service territories. We
cannot predict whether any further actions will be required
on the part of the Ameren Illinois Utilities regarding this
matter or what the ultimate outcome will be.
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 has settled with FERC and the state of Missouri all
issues associated with the December 2005 Taum Sauk
incident. In addition, UE received approval from FERC to
rebuild the upper reservoir at its Taum Sauk plant and has
begun rebuilding the facility. The estimated cost to rebuild the
upper reservoir is in the range of $480 million. UE expects
the Taum Sauk plant to be out of service through early 2010.
In December 2006, 11 business owners filed a lawsuit
regarding the Taum Sauk breach. The suit, which was filed in
the Missouri Circuit Court of Reynolds County and remains
pending, contains allegations of negligence, violations of the
Missouri Clean Water Act, and various other statutory and
common law claims. It seeks damages relating to business
losses, lost profit, and unspecified punitive damages. UE has
filed a motion to dismiss the lawsuit, arguing that Missouri
law does not permit the plaintiffs to recover purely economic
losses under theories of negligence and strict liability. This
motion is currently pending.
In December 2008, the Department of the Army, Corps
of Engineers filed a lawsuit regarding the Taum Sauk
breach. The suit, which was filed in the U.S. District Court
in Cape Girardeau, Missouri, and remains pending, claims
that Clearwater Lake in southeast Missouri was damaged by
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sediment from the Taum Sauk breach. This litigation is in
its early stages, and we are evaluating the merits of the
allegations. We are unable to predict the timing or outcome
of this litigation, or its possible effect on UE’s results of
operations, financial position, or liquidity.
At this time, UE believes that substantially all damages
and liabilities caused by the breach, including costs related
to the settlement agreement with the state of Missouri, the
cost of rebuilding the plant, and the cost of replacement
power, up to $8 million annually, will be covered by
insurance. Insurance will 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 reservoir, will range from $200 million to $220 million.
As of December 31, 2008, UE had paid $181 million,
including costs resulting from the FERC-approved
stipulation and consent agreement. UE accrued a
$18 million liability while expensing $33 million and
recording a $166 million receivable due from insurance
companies. As of December 31, 2008, UE had received
$85 million from insurance companies, which reduced the
insurance receivable balance to $81 million.
As of December 31, 2008, UE had recorded a
$332 million receivable due from insurance companies
related to the rebuilding of the facility and the
reimbursement of replacement power costs. As of
December 31, 2008, UE had received $158 million from
insurance companies, which reduced the insurance
receivable balance as of December 31, 2008, to
$174 million.
Under UE’s insurance policies, all claims by or against
UE are subject to review by its insurance carriers.
Until litigation has been resolved and the insurance
review is completed, among other things, we are unable to
determine the total impact the breach may have on
Ameren’s and UE’s results of operations, financial position,
or liquidity beyond those amounts already recognized.
Mechanics’ Liens
In November 2007, the primary subcontractor on a
2007 maintenance outage at AERG’s Duck Creek facility
filed a complaint for foreclosure of its mechanic’s lien of
$19 million plus interest against AERG. That action was
filed in the Circuit Court of Fulton County, Illinois.
Subsequently, various second-tier subcontractors of the
primary subcontractor also filed for foreclosure of their
mechanics’ lien claims against AERG in the Circuit Court of
Fulton County, Illinois, in addition to filing their claims
against the primary subcontractor. Approximately
13 mechanics’ liens claiming $23 million plus interest in the
aggregate were filed as of December 31, 2008, against
AERG for labor or material for the 2007 maintenance
outage. These claims were primarily based on additional
work outside of the original contract scope. Effective as of
December 17, 2008, AERG entered into a Settlement and
Release Agreement with the primary contractor. It provides
that in exchange for AERG’s payment of $19 million to the
primary contractor, the primary contractor will, among
other things, release Ameren from any existing or future
claims they may have, pay off and obtain full releases of all
mechanics’ liens filed against AERG and dismiss all
mechanics’ lien claims against AERG in the Fulton County
litigation made by the primary subcontractor and all
second-tier subcontractors’, and indemnify, defend and
hold AERG harmless from all such claims by these parties.
The resolution of these liens and lawsuits did not have a
material impact on CILCO’s results of operations, financial
position, or liquidity.
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
161 parties are named in some pending cases and as few
as six in others. However, in the cases pending as of
December 31, 2008, the average number of parties was 68.
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, 2008:
Specifically Named as Defendant
Ameren
3
UE
25
CIPS
Genco
CILCO
31
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10
IP
36
Total(a)
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(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, 2008, six 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.
IP has a tariff rider to recover the costs of asbestos-
related litigation claims, subject to the following terms.
Beginning in 2007, 90% of cash expenditures in excess of
the amount included in base electric rates are recoverable
by IP from a trust fund established by IP. At December 31,
2008, the trust fund balance was $23 million, including
accumulated interest.
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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 is
not expected to have its permanent storage facility for spent
fuel available before 2020. 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.
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. UE intends to submit a
license extension application with the NRC to extend its
Callaway nuclear plant’s operating license to 2044. It is
assumed that the Callaway nuclear plant site will be
decommissioned based on the immediate dismantlement
method and removal 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. See Note
1 – Summary of Significant Accounting Policies for
additional information on asset retirement obligations.
Decommissioning costs are charged to the costs of service
used to establish electric rates for UE’s customers. These
costs amounted to $7 million in each of the years 2008,
2007 and 2006. 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 study
was filed in September 2008. The 2008 study included the
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 and UE’s
Consolidated Balance Sheets. This amount is legally
restricted. It 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 and to a regulatory asset or
regulatory liability, as appropriate.
See Note 2 – Rate and Regulatory Matters for
information on the COLA filed by UE with the NRC for a
potential new nuclear unit and Note 9 – Nuclear
Decommissioning Trust Fund Investments.
NOTE 17 – SEGMENT INFORMATION
Ameren has three reportable segments: Missouri
Regulated, Illinois Regulated, and Non-rate-regulated
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) and other non-rate-regulated activities,
which are in Other. 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. The Non-rate-regulated Generation
segment for Ameren consists primarily of the operations or
activities of Genco, the CILCORP parent company, AERG,
EEI, and Marketing Company. The category called Other
primarily includes Ameren parent company activities and
the leasing activities of CILCORP, AERG, Resources
Company, and CIPSCO Investment Company. CIPSCO
Investment Company was eliminated on March 31, 2008,
through an internal reorganization.
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 and other non-rate-
regulated activities, which are included in Other.
CILCORP and CILCO have two reportable segments:
Illinois Regulated and Non-rate-regulated Generation. The
Illinois Regulated segment for CILCORP and CILCO
consists of the regulated electric and gas transmission and
distribution businesses of CILCO. The Non-rate-regulated
Generation segment for CILCORP and CILCO consists of
the generation business of AERG. For CILCORP and CILCO,
Other comprises leveraged lease investments, parent
company activity, and minor activities not reported in the
Illinois Regulated or Non-rate-regulated Generation
segments for CILCORP.
172
The following tables present information about the reported revenues and specified items included in net income of
Ameren, UE, CILCORP, and CILCO for the years ended December 31, 2008, 2007 and 2006, and total assets as of
December 31, 2008, 2007 and 2006.
Ameren
Missouri
Regulated
Illinois
Regulated
Non-rate-
regulated
Generation
Other
Intersegment
Eliminations
Consolidated
2008
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . .
Interest and dividend income . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss)(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets(b)
2007
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . .
Interest and dividend income . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets(b)
2006
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . .
Interest and dividend income . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets(b)
$
$
$
2,922
38
329
33
193
134
234
874
11,524
2,915
46
333
34
194
143
281
625
10,852
2,584
227
335
33
171
184
267
782
10,254
$ 3,433
45
219
15
144
16
32
359
7,079
$ 3,318
62
217
26
132
25
47
321
6,385
$ 3,338
15
192
20
95
65
115
314
6,280
$ 1,482
455
109
3
99
217
352
611
4,622
$ 1,315
497
105
2
107
182
281
395
4,027
$
926
788
106
1
103
78
138
160
3,612
$
$
$
2
18
28
30
44
(40)
(13)
52
1,227
14
40
26
52
29
(20)
9
40
965
47
27
28
34
29
(43)
27
28
1,161
$
-
(556)
-
(38)
(40)
-
-
-
(1,795)
$
-
(645)
-
(59)
(39)
-
-
-
(1,501)
$
-
(1,057)
-
(50)
(48)
-
-
-
(1,672)
$
$
$
7,839
-
685
43
440
327
605
1,896
22,657
7,562
-
681
55
423
330
618
1,381
20,728
6,895
-
661
38
350
284
547
1,284
19,635
(a) Represents net income available to common stockholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated
segment.
(b) Total assets for Illinois Regulated included an allocation of goodwill and other purchase accounting amounts related to CILCO that are recorded
at CILCORP (parent company).
UE
Missouri
Regulated
Other(a)
Consolidated
UE
2008
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2,960
329
193
134
234
874
11,524
2,961
333
194
143
281
625
10,852
$ -
-
-
-
11
-
-
$ -
-
-
(3)
55
-
51
$
$
2,960
329
193
134
245
874
11,524
2,961
333
194
140
336
625
10,903
173
2006
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,811
335
171
184
267
782
10,254
$12
-
-
-
76
-
36
$ 2,823
335
171
184
343
782
10,290
Missouri
Regulated
Other(a)
Consolidated
UE
Included 40% interest in EEI through February 29, 2008.
(a)
(b) Represents net income available to the common stockholder (Ameren).
CILCORP
Illinois
Regulated
Non-rate-
regulated
Generation
Other
Intersegment
Eliminations
Consolidated
CILCORP
2008
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss)(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss)(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
805
3
50
16
5
16
61
1,402
732
-
54
18
-
9
64
1,202
713
-
53
15
12
25
53
1,217
$
$
$
342
-
31
39
14
27
258
1,680
279
4
24
46
21
38
190
1,455
34
181
22
37
(19)
(3)
66
1,246
$ -
-
-
-
-
(1)
-
2
$ -
-
-
-
-
-
-
1
$ -
-
-
-
(4)
(3)
-
4
$
-
(3)
-
-
-
-
-
(219)
$
-
(4)
-
-
-
-
-
(199)
$
-
(181)
-
-
-
-
-
(217)
$ 1,147
-
81
55
19
42
319
2,865
$ 1,011
-
78
64
21
47
254
2,459
$
747
-
75
52
(11)
19
119
2,250
(a) Represents net income available to the common stockholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois
Regulated segment.
(b) Total assets for Illinois Regulated and Non-rate-regulated Generation include an allocation of goodwill and other purchase accounting amounts
related to CILCO that are recorded at CILCORP (parent company).
174
CILCO
Illinois
Regulated
Non-rate-
regulated
Generation
Other
Intersegment
Eliminations
Consolidated
CILCO
2008
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006
External revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss)(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
805
3
50
16
5
16
61
1,212
732
-
54
18
-
9
64
1,012
713
-
53
15
12
25
53
1,029
$
$
$
342
-
27
5
34
52
258
1,081
279
4
19
8
39
65
190
859
34
181
17
3
2
23
66
642
$ -
-
-
-
-
-
-
-
$ -
-
-
1
-
-
-
-
$ -
-
-
-
(4)
(3)
-
1
$
$
-
(3)
-
-
-
-
-
1
-
(4)
-
-
-
-
-
(9)
$
-
(181)
-
-
-
-
-
(22)
$ 1,147
-
77
21
39
68
319
2,294
$ 1,011
-
73
27
39
74
254
1,862
$
747
-
70
18
10
45
119
1,650
(a) Represents net income available to the common stockholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois
Regulated segment.
175
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
Quarter Ended
Ameren
Operating
Revenues
Operating
Income
Net
Income
Earnings per Common
Share - Basic and
Diluted
March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,081
2,025
$ 321
294
$ 138
123
June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,790
1,728
2,060
1,997
1,908
1,812
444
326
428
481
169
258
206
143
204
244
57
108
$ 0.66
0.59
0.98
0.69
0.97
1.18
0.27
0.52
Quarter Ended
UE
Operating
Revenues
Operating
Income
(Loss)
Net
Income
(Loss)
Net Income (Loss)
Available to Common
Stockholder
March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS
March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco(a)
March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP(a)
March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
724
650
771
697
875
945
590
669
290
314
207
229
217
224
268
238
233
244
196
186
238
221
241
225
345
315
232
226
264
211
306
259
$ 111
68
232
144
195
317
(24)
61
$
8
23
3
15
14
8
17
3
$
83
83
133
41
$
46
55
68
79
47
44
19
36
40
17
14
37
$
$
$
$
64
33
124
81
99
193
(36)
35
3
12
(3)
5
7
1
8
(1)
46
43
74
17
20
25
35
40
20
21
4
12
18
1
-
13
$
$
$
$
63
32
122
79
98
192
(38)
33
2
11
(3)
5
6
-
7
(2)
46
43
74
17
20
25
35
40
20
21
4
12
18
1
-
13
176
Quarter Ended
CILCO
Operating
Revenues
Operating
Income
(Loss)
Net
Income
(Loss)
Net Income (Loss)
Available to Common
Stockholder
March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP
March 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
September 30, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$345
315
232
226
264
211
306
259
$503
515
360
365
353
356
480
410
(a) Genco and CILCORP had no preferred stock outstanding.
$48
47
22
39
43
23
19
34
$27
40
8
29
29
8
39
32
$ 26
27
12
21
24
10
7
18
$ 3
15
(10)
7
5
(4)
7
8
$
$
26
27
11
20
24
10
7
17
2
14
(10)
7
4
(5)
7
8
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 2008 fiscal year.
(a) Evaluation of Disclosure Controls and Procedures
As of December 31, 2008, 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 under the framework in Internal Control - Integrated Framework issued by the COSO,
management concluded that each of the Ameren Companies’ internal control over financial reporting was effective as of
December 31, 2008. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2008, 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, CILCORP’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.
177
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 may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may 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 2008 that has not previously been reported on an SEC Form 8-K.
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 2009 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 2009 annual
meetings 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’ 2009 annual
meeting of shareholders filed pursuant to SEC
Regulation 14C; it is incorporated herein by reference. With
respect to Genco and CILCORP, 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, CILCORP, 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 and Susan
S. Elliott serve as members. The board of directors of
Ameren has determined that Douglas R. Oberhelman qualifies
ITEM 11. EXECUTIVE COMPENSATION.
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, CILCORP, 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. These documents are also available free
in print upon written request to Ameren Corporation,
Attention: Secretary, P.O. Box 66149, St. Louis, Missouri
63166-6149. 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 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14A and 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 2009 annual meeting of shareholders filed pursuant to SEC
Regulation 14C and 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’ 2009 annual meeting of
shareholders filed pursuant to SEC Regulation 14C and is incorporated herein by reference. With respect to Genco and
CILCORP, this information is omitted in reliance on General Instruction I(2) of Form 10-K.
178
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, 2008, with respect to the shares of Ameren’s common stock
that may be issued under its existing equity compensation plans.
Plan
Category
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)
Equity compensation plans approved by security
holders(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,122,955
$
32.80(b)
Equity compensation plans not approved by
security holders . . . . . . . . . . . . . . . . . . . . . . . . . .
-
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,122,955
-
$
32.80(b)
3,046,330
-
3,046,330
(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, 116,877 of the securities represent PSUs that vested at December 31, 2008, (including accrued and
reinvested dividends) and 920,278 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.
(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 calculating the weighted-average exercise price.
UE, CIPS, Genco, CILCORP, CILCO and IP do not have separate equity compensation plans.
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 2009 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 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated
herein by reference. With respect to Genco and CILCORP, 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, 2009. To our knowledge, other than Ameren, which as noted above owns 73% of IP’s
outstanding preferred stock, there are no beneficial owners of 5% or more of IP’s outstanding shares of preferred stock as of
February 1, 2009, 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 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for
its 2009 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 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated
herein by reference. Information required by this SEC Regulation S-K item for IP is identical to the information that will be
contained in CIPS’ definitive information statement for CIPS’ 2009 annual meeting of shareholders filed pursuant to SEC
Regulation 14C; it is incorporated herein by reference. With respect to Genco and CILCORP, 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 2009 annual meetings of
shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference.
179
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)(1) Financial Statements
Page No.
PART IV
Ameren
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet - December 31, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . .
UE
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet - December 31, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . .
CIPS
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Income - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheet - December 31, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Common Stockholders’ Equity - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Genco
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet - December 31, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholder’s Equity - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . .
CILCORP
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet - December 31, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholder’s Equity - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . .
CILCO
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet - December 31, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . .
IP
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheet - December 31, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . .
(a)(2) Financial Statement Schedules
Schedule I - Condensed Financial Information of Parent - CILCORP:
Condensed Statement of Income - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Condensed Balance Sheet - December 31, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Condensed Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Schedule I - Condensed Financial Information of Parent - CILCO:
Condensed Statement of Income - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Condensed Balance Sheet - December 31, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Condensed Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . .
80
84
85
86
87
81
88
89
90
91
81
92
93
94
95
82
96
97
98
99
82
100
101
102
103
83
104
105
106
107
83
108
109
110
111
181
181
181
182
182
182
183
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.
(b)
Exhibits are listed in the Exhibit Index commencing on page 191.
180
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CILCORP INC.
CONDENSED STATEMENT OF INCOME
For the Years Ended December 31, 2008, 2007 and 2006
(In millions)
Operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity in earnings of subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and other charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
$
-
12
(12)
68
34
(20)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 42
2007
$
-
8
(8)
74
37
(18)
$ 47
2006
$
-
14
(14)
45
33
(21)
$ 19
(In millions)
Assets:
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CILCORP INC.
CONDENSED BALANCE SHEET
December 31, 2008
December 31, 2007
Cash and equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investments in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property and plant, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
-
21
21
674
123
542
35
$
-
16
16
606
130
542
40
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,395
$ 1,334
Liabilities and Stockholder’s Equity:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and other noncurrent liabilities . . . . . . . . . . . . . . . . . . . . . . . . .
Stockholder’s equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
342
343
257
40
755
$
1
190
191
389
42
712
Total liabilities and stockholder’s equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,395
$ 1,334
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CILCORP INC.
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2008, 2007 and 2006
(In millions)
Cash flows from operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
$ (25)
-
25
-
-
-
-
2007
$ (39)
-
39
-
-
-
-
2006
$ (11)
136
(125)
-
-
-
65
CILCORP (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2008
NOTE 1 – BASIS OF PRESENTATION
CILCORP (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
to our financial statements under Part II, Item 8, of this report.
NOTE 2 – LONG-TERM OBLIGATIONS
See Note 5 – Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a description and details
of long-term obligations of CILCORP (parent company only).
NOTE 3 – COMMITMENTS AND CONTINGENCIES
See Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a description of all material
contingencies and guarantees outstanding of CILCORP (parent company only).
181
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CENTRAL ILLINOIS LIGHT COMPANY
CONDENSED STATEMENT OF INCOME
For the Years Ended December 31, 2008, 2007 and 2006
(In millions)
Operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity in earnings of subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Miscellaneous income (expense) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and other charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
$ 793
751
42
53
(4)
18
5
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
68
$
2007
$ 732
704
28
65
1
20
-
74
2006
$ 713
653
60
20
1
24
12
$ 45
(In millions)
Assets:
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CENTRAL ILLINOIS LIGHT COMPANY
CONDENSED BALANCE SHEET
December 31, 2008
December 31, 2007
Cash and equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investments in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property and plant, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
-
248
248
438
754
209
$
4
190
194
385
737
72
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,649
$ 1,388
Liabilities and Stockholders’ Equity:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other deferred credits and other noncurrent liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86
95
181
279
501
688
$
52
158
210
148
409
621
Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,649
$ 1,388
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CENTRAL ILLINOIS LIGHT COMPANY
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2008, 2007 and 2006
(In millions)
Cash flows from operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
$ 42
(61)
15
(4)
4
-
-
2007
$ 28
(54)
30
4
-
4
10
2006
$ 84
(36)
(49)
(1)
1
-
19
CENTRAL ILLINOIS LIGHT COMPANY (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 2008
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 to our financial statements under Part II, Item 8, of this report.
NOTE 2 – LONG-TERM OBLIGATIONS
See Note 5 – Long-term Debt and Equity Financings to our financial statements 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 to our financial statements 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).
182
(In millions)
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006
Column A
Column B
Column C
Column D
Column E
Description
Balance at
Beginning
of Period
(1)
Charged to Costs
and Expenses
(2)
Charged to Other
Accounts
Deductions(a)
Balance at End
of Period
Ameren:
Deducted from assets - allowance for doubtful accounts:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 22
11
22
UE:
Deducted from assets - allowance for doubtful accounts:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CIPS:
Deducted from assets - allowance for doubtful accounts:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCORP:
Deducted from assets - allowance for doubtful accounts:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CILCO:
Deducted from assets - allowance for doubtful accounts:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IP:
Deducted from assets - allowance for doubtful accounts:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a) Uncollectible accounts charged off, less recoveries.
$
$
$
$
$
6
6
6
5
2
4
2
1
5
2
1
5
9
3
8
$ 63
53
28
$ 14
14
13
$ 13
10
3
$
$
9
7
2
9
7
2
$ 27
21
9
$ -
-
-
$ -
-
-
$ -
-
-
$ -
-
-
$ -
-
-
$ -
-
-
$ 57
42
39
$ 12
14
13
$ 12
7
5
$
$
8
6
6
8
6
6
$ 24
15
14
$ 28
22
11
$
$
$
$
8
6
6
6
5
2
3
2
1
3
2
1
$ 12
9
3
183
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: March 2, 2009
AMEREN CORPORATION (registrant)
By /s/ Gary L. Rainwater
Gary L. Rainwater
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/ Gary L. Rainwater
Gary L. Rainwater
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
Stephen F. Brauer
Susan S. Elliott
Walter J. Galvin
Gayle P.W. Jackson
James C. Johnson
*
*
*
*
*
*
Charles W. Mueller
*
Douglas R. Oberhelman
*
*
*
Harvey Saligman
Patrick T. Stokes
Jack D. Woodard
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
Chairman, President,
Chief Executive Officer, and Director
(Principal Executive Officer)
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
184
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
Date: March 2, 2009
UNION ELECTRIC COMPANY (registrant)
By /s/ Thomas R. Voss
Thomas R. Voss
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/ Thomas R. Voss
Thomas R. Voss
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
Daniel F. Cole
Adam C. Heflin
Richard J. Mark
Steven R. Sullivan
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
*
*
*
*
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
Executive Vice President,
Chief Financial Officer and Director
(Principal Financial Officer)
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
Director
Director
Director
Director
185
Date: March 2, 2009
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.
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
Executive Vice President,
Chief Financial Officer and Director
(Principal Financial Officer)
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
*
*
Director
Director
/s/ Scott A. Cisel
Scott A. Cisel
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
Daniel F. Cole
Steven R. Sullivan
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
186
Date: March 2, 2009
AMEREN ENERGY GENERATING COMPANY (registrant)
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/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
*
*
Daniel F. Cole
Steven R. Sullivan
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
Chairman, President and Director
(Principal Executive Officer)
Executive Vice President,
Chief Financial Officer and Director
(Principal Financial Officer)
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
Director
Director
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
187
Date: March 2, 2009
CILCORP INC. (registrant)
By /s/ Gary L. Rainwater
Gary L. Rainwater
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/ Gary L. Rainwater
Gary L. Rainwater
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
Daniel F. Cole
Patrick T. Stokes
Steven R. Sullivan
Thomas R. Voss
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
*
*
*
*
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
Executive Vice President,
Chief Financial Officer and Director
(Principal Financial Officer)
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
Director
Director
Director
Director
188
Date: March 2, 2009
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.
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
Executive Vice President,
Chief Financial Officer and Director
(Principal Financial Officer)
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
*
*
Director
Director
/s/ Scott A. Cisel
Scott A. Cisel
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
Daniel F. Cole
Steven R. Sullivan
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
189
Date: March 2, 2009
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.
Chairman, President,
Chief Executive Officer and Director
(Principal Executive Officer)
Executive Vice President,
Chief Financial Officer and Director
(Principal Financial Officer)
Senior Vice President and
Chief Accounting Officer
(Principal Accounting Officer)
*
*
Director
Director
/s/ Scott A. Cisel
Scott A. Cisel
/s/ Warner L. Baxter
Warner L. Baxter
/s/ Martin J. Lyons
Martin J. Lyons
Daniel F. Cole
Steven R. Sullivan
*By /s/ Warner L. Baxter
Warner L. Baxter
Attorney-in-Fact
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
March 2, 2009
190
EXHIBIT INDEX
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 Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
Articles of Incorporation/ By-Laws
3.1(i)
3.2(i)
3.3(i)
3.4(i)
3.5(i)
3.6(i)
Ameren
Ameren
UE
CIPS
Genco
Genco
3.7(i)
CILCORP
3.8(i)
CILCORP
Restated Articles of Incorporation
of Ameren
Certificate of Amendment to
Ameren’s Restated Articles of
Incorporation filed December 14,
1997
File No. 33-64165, Annex F
1998 Form 10-K, Exhibit 3(i), File
No. 1-14756
Restated Articles of Incorporation
of UE
1993 Form 10-K, Exhibit 3(i), File
No. 1-2967
Restated Articles of Incorporation
of CIPS
March 31, 1994 Form 10-Q,
Exhibit 3(b), File No. 1-3672
Articles of Incorporation of Genco
Amendment to Articles of
Incorporation of Genco filed
April 19, 2000
Articles of Incorporation of
CILCORP, as amended to May 2,
1991
Articles of Amendment to
CILCORP’s Articles of
Incorporation filed November 15,
1999
Exhibit 3.1, Form S-4, File
No. 333-56594
Exhibit 3.2, Form S-4, File
No. 333-56594
Exhibit 3.1, File No. 333-90373
1999 Form 10-K, Exhibit 3, File
No. 1-8946
3.9(i)
CILCO
Articles of Incorporation of CILCO
as amended May 29, 1998
1998 Form 10-K, Exhibit 3, File
No. 1-2732
3.10(i)
3.11(i)
IP
IP
3.12(ii)
Ameren
3.13(ii)
UE
3.14(ii)
CIPS
3.15(ii)
Genco
3.16(ii)
CILCORP
3.17(ii)
CILCO
3.18(ii)
IP
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
September 7, 1994 Form 8-K,
Exhibit 3(a), File No. 1-3004
Exhibit 4.1(ii), File No. 333-84008
By-Laws of Ameren as amended
effective October 10, 2008
October 14, 2008 Form 8-K,
Exhibit 3.1(ii), File No. 1-14756
By-Laws of UE as amended
July 28, 2008
By-Laws of CIPS as amended
July 28, 2008
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
By-Laws of Genco as amended to
October 8, 2004
September 30, 2004 Form 10-Q,
Exhibit 3.1, File No. 333-56594
By-Laws of CILCORP as amended
as of October 8, 2004
September 30, 2004 Form 10-Q,
Exhibit 3.2, File No. 1-8946
By-Laws of CILCO as amended
effective July 28, 2008
July 29, 2008 Form 8-K, Exhibit
3.3(ii), File No. 1-2732
By-Laws of IP as amended
July 28, 2008
July 29, 2008 Form 8-K, Exhibit
3.4(ii), File No. 1-3004
191
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
Instruments Defining Rights of Security Holders, Including Indentures
4.1
Ameren
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
Ameren
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
Exhibit 4.5, File No. 333-81774
June 30, 2008 Form 10-Q, Exhibit
4.1, File No. 1-14756
Exhibit B-1, File No. 2-4940
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
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
Supplemental Indenture to the UE
Mortgage dated as of April 1, 1971
April 1971 Form 8-K, Exhibit 6,
File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated as of February 1,
1974
Supplemental Indenture to the UE
Mortgage dated as of July 7, 1980
February 1974 Form 8-K, Exhibit
3, File No. 1-2967
Exhibit 4.6, File No. 2-69821
Supplemental Indenture to the UE
Mortgage dated as of May 1, 1993
1993 Form 10-K, Exhibit 4.6, File
No. 1-2967
Supplemental Indenture to the UE
Mortgage dated as of October 1,
1993
Supplemental Indenture to the UE
Mortgage dated as of February 1,
2000
1993 Form 10-K, Exhibit 4.8, File
No. 1-2967
2000 Form 10-K, Exhibit 4.1, File
No. 1-2967
Supplemental Indenture to the UE
Mortgage dated August 15, 2002
August 23, 2002 Form 8-K, Exhibit
4.3, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated March 5, 2003
March 11, 2003 Form 8-K, Exhibit
4.4, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated April 1, 2003
April 10, 2003 Form 8-K, Exhibit
4.4, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated July 15, 2003
August 4, 2003 Form 8-K, Exhibit
4.4, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated October 1, 2003
October 8, 2003 Form 8-K, Exhibit
4.4, File No. 1-2967
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
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
192
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
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
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
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
Supplemental Indenture to the UE
Mortgage dated May 1, 2004
May 18, 2004 Form 8-K, Exhibit
4.4, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated September 1,
2004
September 23, 2004 Form 8-K,
Exhibit 4.4, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated January 1, 2005
January 27, 2005 Form 8-K,
Exhibit 4.4, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated July 1, 2005
July 21, 2005 Form 8-K, Exhibit
4.4, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated December 1, 2005
December 9, 2005 Form 8-K,
Exhibit 4.4, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated June 1, 2007
June 15, 2007 Form 8-K, Exhibit
4.5, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated April 11, 2008
April 18, 2008 Form 8-K, Exhibit
4.7, File No. 1-2967
Supplemental Indenture to the UE
Mortgage dated June 1, 2008
June 19, 2008 Form 8-K, Exhibit
4.5, File No. 1-2967
1992 Form 10-K, Exhibit 4.37, File
No. 1-2967
Loan Agreement dated as of
December 1, 1991, between the
Missouri Environmental Authority
and UE, together with Indenture of
Trust dated as of December 1,
1991, between the Missouri
Environmental Authority and UMB
Bank N.A. as successor trustee to
Mercantile Bank of St. Louis, N. A.
193
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.32
4.33
4.34
4.35
4.36
4.37
4.38
4.39
4.40
4.41
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
Ameren
UE
March 31, 2004 Form 10-Q,
Exhibit 4.9, 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
First Amendment dated as of
February 1, 2004, to Loan
Agreement dated as of December 1,
1991, between the Missouri
Environmental Authority and UE
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 Trust Company, N.A.,
as successor trustee (relating to
senior secured debt securities)
194
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.42
4.43
4.44
4.45
4.46
4.47
4.48
4.49
4.50
4.51
4.52
4.53
4.54
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
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
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 18, 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
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)
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)
195
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.55
4.56
4.57
4.58
4.59
4.60
4.61
4.62
4.63
4.64
4.65
4.66
4.67
4.68
4.69
4.70
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Exhibit 2.01, File No. 2-60232
Indenture of Mortgage and 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
Amended Exhibit 7(b), File
No. 2-7341
Supplemental Indenture to the CIPS
Mortgage, dated January 1, 1949
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
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
September 8, 2006 Form 8-K,
Exhibit 4.4, File No. 1-3672
March 14, 2007 Form 8-K, Exhibit
4.2, File No. 1-3672
Exhibit 4.4, File No. 333-59438
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
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 August 1,
2006
Supplemental Indenture to the
CIPS Mortgage, dated March 1,
2007
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)
196
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.71
4.72
4.73
4.74
4.75
4.76
4.77
4.78
4.79
4.80
4.81
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
CIPS
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
Genco
Ameren
Genco
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
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
197
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.82
Ameren
CILCORP
4.83
Ameren
CILCO
4.84
4.85
4.86
4.87
4.88
4.89
4.90
4.91
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Exhibits 4.1 and 4.2, File
No. 333-90373
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
September 8, 2006 Form 8-K,
Exhibit 4.2, File No. 1-2732
March 14, 2007 Form 8-K, Exhibit
4.4, File No. 1-2732
Indenture, dated as of October 18,
1999, between Midwest Energy,
Inc., and The Bank of New York
Mellon Trust Company, N.A., as
successor trustee, and First
Supplemental Indenture, dated as
of October 18, 1999, between
CILCORP and The Bank of New
York Mellon Trust Company, N.A.,
as successor trustee
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 August 1,
2006
Supplemental Indenture to the
CILCO Mortgage, dated March 1,
2007
198
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.92
4.93
4.94
4.95
4.96
4.97
4.98
4.99
4.100
4.101
4.102
4.103
4.104
4.105
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
CILCO
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Supplemental Indenture to the
CILCO Mortgage, dated
December 1, 2008
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
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
199
December 9, 2008 Form 8-K,
Exhibit 4.5, 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
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
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
4.106
4.107
4.108
4.109
4.110
4.111
4.112
4.113
4.114
4.115
4.116
Material Contracts
10.1
10.2
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
IP
Ameren
CIPS
Genco
Ameren
Genco
Ameren
IP
September 8, 2006 Form 8-K,
Exhibit 4.6,
File No. 1-3004
March 14, 2007 Form 8-K, Exhibit
4.6, 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 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
March 28, 2008 Form 8-K, Exhibit
10.3, File No. 1-14756
October 1, 2004 Form 8-K, Exhibit
10.3, File No. 1-3004
Supplemental Indenture dated as
of August 1, 2006, to IP Mortgage
for the 2006 credit agreement
series bonds
Supplemental Indenture dated as
of March 1, 2007, to IP Mortgage
for the 2007 credit agreement
series 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
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
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
200
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.3
Ameren Companies
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
Ameren
Genco
CILCORP
Ameren
UE
Genco
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
Ameren
CIPS
CILCORP
CILCO
IP
Ameren
CIPS
CILCORP
CILCO
IP
Ameren
CIPS
CILCORP
CILCO
IP
Ameren
CIPS
CILCORP
CILCO
IP
Ameren
Ameren
CILCORP
CILCO
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
July 18, 2006 Form 8-K, Exhibit
10.6, File No. 2-95569
February 13, 2007 Form 8-K,
Exhibit 10.3, File No. 1-14756
July 18, 2006 Form 8-K, Exhibit
10.2, File No. 1-14756
March 28, 2008 Form 8-K, Exhibit
10.1, File No. 1-14756
February 13, 2007 Form 8-K,
Exhibit 10.1, File No. 1-14756
March 28, 2008 Form 8-K, Exhibit
10.2, File No. 1-14756
June 27, 2008 Form 8-K, Exhibit
10.1, File No. 1-14756
October 29, 1999 Form 8-K,
Exhibit 10.1, File No. 2-95569
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 Five-Year
Revolving Credit Agreement, dated
as of July 14, 2006, currently
among Ameren, UE, Genco and
JPMorgan Chase Bank, N.A., as
administrative agent
Collateral Agency Agreement, dated
as of July 14, 2006, between AERG
and The Bank of New York Mellon
Trust Company, N.A., as collateral
agent
Collateral Agency Agreement
Supplement, dated as of
February 9, 2007, between AERG
and The Bank of New York Mellon
Trust Company, N.A., as collateral
agent
Credit Agreement - Illinois Facility,
dated as of July 14, 2006, among
CIPS, CILCO, IP, AERG, CILCORP
and JPMorgan Chase Bank, N.A.,
as administrative agent
(2006 Illinois Credit Agreement)
Amendment dated as of March 26,
2008 to 2006 Illinois Credit
Agreement
Credit Agreement - Illinois Facility,
dated as of February 9, 2007,
among CIPS, CILCO, IP, AERG,
CILCORP and JPMorgan Chase
Bank, N.A., as administrative agent
(2007 Illinois Credit Agreement)
Amendment dated as of March 26,
2008 to 2007 Illinois Credit
Agreement
Credit Agreement dated as of
June 25, 2008, between Ameren
and JPMorgan Chase Bank, N.A.,
as agent
Pledge Agreement dated as of
October 18, 1999, between
CILCORP and The Bank of New
York Mellon, as collateral agent
201
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.14
10.15
10.16
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
10.17
Ameren
CILCORP
CILCO
10.18
Ameren
Pledge Agreement Supplement,
dated as of July 14, 2006, between
CILCORP and The Bank of New
York Mellon, as Collateral Agent
Pledge Agreement Supplement,
dated as of February 9, 2007,
between CILCORP and The Bank
of New York Mellon, as Collateral
Agent
Open-Ended Mortgage, Security
Agreement, Assignment of Rents
and Leases and Fixtures Filing
(Illinois) - E.D. Edwards plant,
dated as of July 14, 2006, by and
from AERG to The Bank of New
York Mellon Trust Company, N.A.,
as agent
Open-Ended Mortgage, Security
Agreement, Assignment of Rents
and Leases and Fixtures Filing
(Illinois) - Duck Creek plant, dated
as of July 14, 2006, by and from
AERG to The Bank of New York
Mellon Trust Company, N.A.,
as agent
*Summary Sheet of Ameren
Corporation Non-Management
Director Compensation revised on
August 8, 2008
July 18, 2006 Form 8-K, Exhibit
10.3, File No. 2-95569
February 13, 2007 Form 8-K,
Exhibit 10.2, File No. 1-14756
July 18, 2006 Form 8-K, Exhibit
10.4, File No. 2-95569
July 18, 2006 Form 8-K, Exhibit
10.5, File No. 2-95569
September 30, 2008 Form 10-Q,
Form 8-K, Exhibit 10.1, File
No. 1-14756
10.19
Ameren Companies
*Ameren’s Long-Term Incentive
Plan of 1998
1998 Form 10-K, Exhibit 10.1, File
No. 1-14756
10.20
Ameren Companies
*First Amendment to Ameren’s
Long-Term Incentive Plan of 1998
February 16, 2006 Form 8-K,
Exhibit 10.6, File No. 1-14756
10.21
Ameren Companies
10.22
Ameren
10.23
Ameren Companies
10.24
Ameren Companies
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
*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
*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
202
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.25
Ameren Companies
10.26
Ameren Companies
*Ameren 2007 Deferred
Compensation Plan
*Ameren 2008 Deferred
Compensation Plan
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
10.27
Ameren Companies
*2004 Ameren Executive Incentive
Plan
2003 Form 10-K, Exhibit 10.7, File
No. 1-14756
10.28
Ameren Companies
10.29
Ameren Companies
10.30
Ameren Companies
10.31
Ameren Companies
10.32
Ameren Companies
10.33
Ameren Companies
10.34
Ameren Companies
10.35
Ameren Companies
10.36
Ameren Companies
10.37
Ameren Companies
10.38
Ameren Companies
10.39
Ameren Companies
10.40
Ameren Companies
10.41
Ameren Companies
10.42
Ameren Companies
*2005 Ameren Executive Incentive
Plan
February 14, 2005 Form 8-K,
Exhibit 10.2, File No. 1-14756
*2006 Ameren Executive Incentive
Plan
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 15, 2005 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
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
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
*2007 Executive Incentive
Compensation Plan
*2008 Executive Incentive
Compensation Plan
*2009 Executive Incentive
Compensation Plan
*2005 and 2006 Base Salary Table
for Named Executive Officers and
2006 Executive Officer Bonus
Targets
*2007 Base Salary Table for
Named Executive Officers
*2008 Base Salary Table for
Named Executive Officers
*2009 Base Salary Table for
Named Executive Officers
*Second Amended and Restated
Ameren Corporation Change of
Control Severance Plan
*Table of 2005 Cash Bonus
Awards and 2006 Performance
Share Unit Awards Issued to
Named Executive Officers
*Table of Target 2007
Performance Share Unit Awards
Issued to Named Executive
Officers
*Table of Target 2008
Performance Share Unit Awards
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
203
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
10.43
Ameren Companies
10.44
Ameren Companies
10.45
10.46
10.47
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
Ameren
CILCORP
CILCO
Statement re: Computation of Ratios
12.1
Ameren
12.2
UE
12.3
CIPS
12.4
Genco
12.5
CILCORP
12.6
CILCO
12.7
IP
*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
June 30, 2008 Form 10-Q, Exhibit
10.1, File No. 1-14756
1999 Form 10-K, Exhibit 10, File
No. 1-2732
*CILCO Executive Deferral Plan II
as amended effective April 1, 1999
1999 Form 10-K, Exhibit 10(a),
File No. 1-2732
*CILCO Restructured Executive
Deferral Plan (approved August 15,
1999)
1999 Form 10-K, Exhibit 10(e),
File No. 1-2732
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
CILCORP’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
Code of Ethics
14.1
Ameren Companies
Code of Ethics amended as of
June 11, 2004
June 30, 2004 Form 10-Q, Exhibit
14.1, File No. 1-14756
204
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
Subsidiaries of the Registrant
21.1
Ameren Companies
Subsidiaries of Ameren
Consent of Experts and Counsel
23.1
Ameren
23.2
UE
23.3
CIPS
23.4
Genco
23.5
CILCO
23.6
IP
Power of Attorney
24.1
24.2
24.3
24.4
24.5
24.6
24.7
Ameren
UE
CIPS
Genco
CILCORP
CILCO
IP
Rule 13a-14(a)/15d-14(a) Certifications
31.1
Ameren
31.2
Ameren
31.3
31.4
UE
UE
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
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
CILCORP
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
205
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
31.5
CIPS
31.6
CIPS
31.7
Genco
31.8
Genco
31.9
CILCORP
31.10
CILCORP
31.11
CILCO
31.12
CILCO
31.13
31.14
IP
IP
Section 1350 Certifications
32.1
Ameren
32.2
UE
32.3
CIPS
32.4
Genco
32.5
CILCORP
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 CILCORP
Rule13a-14(a)/15d-14(a)
Certification of Principal Financial
Officer of CILCORP
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
CILCORP
206
Exhibit Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
32.6
CILCO
32.7
IP
Additional Exhibits
99.1
Ameren
CILCORP
CILCO
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
Amended and Restated Power
Supply Agreement, dated
March 28, 2008, between
Marketing Company and AERG
March 28, 2008 Form 8-K,
Exhibit 99.1, File No. 1-14756
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; CILCORP, 2-95569; CILCO, 1-2732; and IP, 1-3004.
*Management compensatory plan or arrangement.
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.
207
2009 BASE SALARY TABLE FOR NAMED EXECUTIVE OFFICERS
On December 12, 2008, the Human Resources Committee of the Board of Directors of Ameren Corporation (Committee)
approved the 2009 annual base salaries of the following Named Executive Officers of Ameren Corporation (Ameren), Union Electric
Company (UE), Central Illinois Public Service Company (CIPS), Ameren Energy Generating Company (Genco), CILCORP Inc.
(CILCORP), Central Illinois Light Company (CILCO) and Illinois Power Company (IP) (which officers were determined to the
extent applicable by reference to the Ameren Proxy Statement and the UE, CIPS and CILCO Information Statements, each dated
March 6, 2008, for the 2008 annual meetings of shareholders and by reference to the definition of “Named Executive Officer” in Item
402(a)(3) of SEC Regulation S-K).
EXHIBIT 10.36
Name and Position
Gary L. Rainwater
Chairman, President and Chief Executive
Officer - Ameren and CILCORP
Warner L. Baxter
Executive Vice President and Chief Financial
Officer – Ameren, UE, CIPS, Genco,
CILCORP, CILCO and IP
Thomas R. Voss
Executive Vice President and Chief Operating
Officer – Ameren; Chairman, President and
Chief Executive Officer of UE
Steven R. Sullivan
Senior Vice President, General Counsel and
Secretary – Ameren, UE, CIPS, Genco,
CILCORP, CILCO and IP
Charles D. Naslund
President (principal executive officer) – Genco;
and until 07/01/08, Senior Vice President and
Chief Nuclear Officer – UE
Daniel F. Cole
Senior Vice President – UE, CIPS, Genco,
CILCORP, CILCO and IP
Scott A. Cisel
Chairman, President and Chief Executive
Officer – CIPS, CILCO and IP
Jerre E. Birdsong
Vice President and Treasurer – Ameren, UE,
CIPS, Genco, CILCORP, CILCO and IP
2009 Base Salary
940,000*
$
$
552,933*
$
477,400*
$
417,133*
$
427,267*
$
$
$
350,800
387,000
297,200
* On February 12, 2009, the Committee, due to the current business environment, revised downward the annual base salary
payable to such Named Executive Officer, effective March 1, 2009, to the base salary level payable to such named Named
Executive Officer at the end of the 2008 fiscal year (2008 base salary). Consequently, the 2009 base salary payable to such
named Executive Officer is the same as such Named Executive Officer’s 2008 base salary, except that for the first two months
of fiscal 2009 such Named Executive Officer’s base salary was higher as approved by the Committee on December 12, 2008.
The 2009 base salaries for certain of the Ameren Named Executive Officers may be subject to adjustment as may be disclosed
by Ameren in its Current Report on Form 8-K dated March 2, 2009.
SECOND AMENDED AND RESTATED AMEREN CORPORATION
CHANGE OF CONTROL SEVERANCE PLAN
Introduction
Exhibit 10.37
The Board of Directors of Ameren Corporation recognizes that, as is the case with many publicly held corporations, there exists
the possibility of a Change of Control of the Company. This possibility and the uncertainty it creates may result in the loss or
distraction of senior executives of the Company, to the detriment of the Company and its shareholders.
The Board considers the avoidance of such loss and distraction to be essential to protecting and enhancing the best interests of
the Company and its shareholders. The Board also believes that when a Change of Control is perceived as imminent, or is occurring,
the Board should be able to receive and rely on impartial service from senior executives regarding the best interests of the Company
and its shareholders, without concern that senior executives might be distracted or concerned by the personal uncertainties and risks
created by the perception of an imminent or occurring Change of Control.
In addition, the Board believes that it is consistent with the Company’s employment practices and policies and in the best
interests of the Company and its shareholders to treat fairly its employees whose employment terminates in connection with or
following a Change of Control.
Accordingly, the Board has determined that appropriate steps should be taken to assure the Company of the continued
employment and attention and dedication to duty of its senior executives and to seek to ensure the availability of their continued
service, notwithstanding the possibility, threat or occurrence of a Change of Control.
Therefore, in order to fulfill the above purposes, the following plan has been developed and is hereby adopted.
As of the Effective Date, the Company hereby amends and restates the Ameren Corporation Change of Control Severance Plan,
as set forth in this document.
ARTICLE I
ESTABLISHMENT OF PLAN
ARTICLE II
DEFINITIONS
As used herein, the following words and phrases shall have the following respective meanings unless the context clearly
indicates otherwise.
(a) Annual Bonus Award. The target annual cash bonus that a Participant is eligible to earn for the year in which a Change in
Control occurs pursuant to the Company’s Executive Incentive Plan, the Ameren Corporation 2006 Omnibus Incentive Compensation
Plan, or any successor to either such plan.
(b) Annual Salary. The Participant’s regular annual base salary immediately prior to his or her termination of employment,
including compensation converted to other benefits under a flexible pay arrangement maintained by any Employer or deferred
pursuant to a written plan or agreement with any Employer.
(c) Board. The Board of Directors of the Company.
(d) Cause. The occurrence of any one or more of the following:
(i) The Participant’s willful failure to substantially perform his duties with the Company (other than any such failure
resulting from the Participant’s Disability), after a written demand for substantial performance is delivered to the Participant that
specifically identifies the manner in which the Committee believes that the Participant has not substantially performed his
duties, and the Participant has failed to remedy the situation within fifteen (15) business days of such written notice from the
Company;
(ii) Gross negligence in the performance of the Participant’s duties which results in material financial harm to the
Company;
(iii) The Participant’s conviction of, or plea of guilty or nolo contendere, to any felony or any other crime involving the
personal enrichment of the Participant at the expense of the Company or shareholders of the Company; or
(iv) The Participant’s willful engagement in conduct that is demonstrably and materially injurious to the Company,
monetarily or otherwise.
(e) Change of Control. The occurrence of any of the following events after the Effective Date of this Plan:
(i) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities
Exchange Act of 1934, as amended (the “Exchange Act”)) (a “Person”) of beneficial ownership (within the meaning of Rule
13d-3 promulgated under the Exchange Act) of 20% or more of either (x) the then outstanding shares of common stock of the
Company (the “Outstanding Company Common Stock”) or (y) the combined voting power of the then outstanding voting
securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”);
provided, however, that for purposes of this subsection (i), the following acquisitions shall not constitute a Change of Control:
(A) any acquisition directly from the Company, (B) any acquisition by the Company, (C) any acquisition by any employee
benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or
(D) any acquisition by any corporation pursuant to a transaction which complies with clauses (A), (B) and (C) of paragraph
(iii) below; or
(ii) Individuals who, as of the Effective Date of this Plan, constitute the Board (the “Incumbent Board”) cease for any
reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to
the Effective Date whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at least
a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member
of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result
of (A) an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened
solicitation of proxies or consents by or on behalf of a Person other than the Board or (B) any agreement intended to avoid or
settle any election contest; or
2
(iii) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the
assets of the Company or the acquisition of assets of another corporation (a “Business Combination”), in each case, unless,
following such Business Combination, (A) all or substantially all of the individuals and entities who were the beneficial owners,
respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to
such Business Combination beneficially own, directly or indirectly, more than 60% of, respectively, the then outstanding shares
of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the
election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without
limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company’s
assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately
prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities,
as the case may be, (B) no Person (excluding any corporation resulting from such Business Combination or any employee
benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns,
directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of the corporation resulting
from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation
except to the extent that such ownership existed prior to the Business Combination and (C) at least a majority of the members of
the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at
the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or
(iv) Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.
Notwithstanding the foregoing, a Change of Control shall not be deemed to occur solely because any Person (the “Subject
Person”) acquired beneficial ownership of more than the permitted amount of the then Outstanding Company Common Stock or
the Outstanding Company Voting Securities as a result of the acquisition of shares of common stock or voting securities by the
Company which, by reducing the number of shares of Outstanding Company Common Stock or the Outstanding Company
Voting Securities, increases the proportional number of shares beneficially owned by the Subject Persons, provided that if a
Change of Control would occur (but for the operation of this sentence) as a result of the acquisition of shares of Outstanding
Company Common Stock or the Outstanding Company Voting Securities by the Company, and after such share acquisition by
the Company, the Subject Person becomes the beneficial owner of any additional shares of Outstanding Company Common
Stock or the Outstanding Company Voting Securities which increases the percentage of the then Outstanding Company
Common Stock or the Outstanding Company Voting Securities beneficially owned by the Subject Person, then a Change of
Control shall occur.
3
(f) Code. The Internal Revenue Code of 1986, as amended from time to time.
(g) Committee. The Human Resources Committee of the Board.
(h) Company. Ameren Corporation and any successors thereto.
(i) Date of the Change of Control. The date on which a Change of Control occurs.
(j) Date of Termination. The date on which a Participant ceases to be an Employee.
(k) Disability. A termination of a Participant’s Employment for Disability shall have occurred if the Termination occurs because
of a disability which qualifies the Participant for benefits under the Company’s long-term disability plan.
(l) Effective Date. October 1, 2008.
(m) Employee. Any full-time, regular-benefit, non-bargaining employee of the Company or any other Employer.
(n) Employer. The Company or any subsidiary of the Company.
(o) Employment. The state of being an Employee.
(p) ERISA. The Employee Retirement Income Security Act of 1974, as amended, and the regulations thereunder.
(q) Good Reason. The occurrence after a Change in Control of the Company of any one or more of the following without the
Participant’s express written consent:
(i) A net reduction of the Participant’s authorities, duties, or responsibilities as an executive and/or officer of the Company
from those in effect prior to the Change in Control, other than an insubstantial and inadvertent reduction that is remedied by the
Company promptly after receipt of notice thereof given by the Participant;
(ii) The Company’s requiring the Participant to be based at a location in excess of fifty (50) miles from the location of the
Participant’s principal job location or office immediately prior to the Change of Control; except for required travel on the
Company’s business to an extent substantially consistent with the Participant’s then present business travel obligations;
(iii) Any material reduction by the Company of the Participant’s Base Salary or targeted Annual Bonus Awards, in effect
on the Date of the Change of Control, or as the same shall be increased from time to time;
(iv) The failure to provide the Participant with an annualized long-term incentive opportunity which is either essentially
equivalent in value to or greater in value than the Participant’s regular annualized long-term incentive opportunity in effect on
4
the Date of the Change of Control (for this purpose, the permissible floor value is intended to reference normal long-term
incentive awards made as a part of the regular annual pay package, and not special awards that are not made on a regular basis)
when calculated on a grant date basis using widely recognized valuation methodologies (e.g., Black-Scholes for options);
(v) The failure of the Company to continue in effect the aggregate value in any of the employee benefit or retirement plans
in which the Participant participates prior to the Change in Control of the Company;
(vi) The failure of the Company to obtain a satisfactory agreement from any successor to the Company to assume and
agree to perform the Company’s obligations under this Plan, as contemplated in Article V herein; and
(vii) A material breach of this Plan by the Company which is not remedied by the Company within ten (10) business days
of receipt of written notice of such breach delivered by the Participant to the Company.
In the event it is necessary to determine the value of a long-term incentive opportunity under Section q(iv) above or the
aggregate value of employee benefit or retirement plans under Section q(v) above, an outside independent benefit consulting
firm shall be engaged by the Company to make such determination.
(r) Multiple. With respect to any Participant, the number set forth opposite the Participant’s name under the heading “Benefit
Level” on Schedule I hereto.
(s) Participant. An individual who is designated as such pursuant to Section 3.1.
(t) Plan. The Ameren Corporation Change of Control Severance Plan.
(u) Retirement. A termination by Retirement shall have occurred where a Participant’s termination is due to his or her late,
normal or early retirement under a pension plan sponsored by the Company or any of its affiliates, as defined in such plan.
(v) Separation Benefits. The benefits described in Section 4.2 that are provided to qualifying Participants under the Plan.
(w) Separation Period. With respect to any Participant, the period beginning on a Participant’s Date of Termination and ending
after the expiration of a number of years equal to the Multiple for such Participant.
ARTICLE III
ELIGIBILITY
3.1 Participants. Each of the individuals named on Schedule I hereto shall be a Participant in the Plan.
3.2 Duration of Participation. A Participant shall only cease to be a Participant in the Plan as a result of an amendment or
termination of the Plan complying with Article VI of the Plan, or when he ceases to be an Employee, unless, at the time he ceases to
5
be an Employee, such Participant is entitled to payment of a Separation Benefit as provided in the Plan or there has been an event or
occurrence that constitutes Good Reason which would enable the Participant to terminate his employment and receive a Separation
Benefit. A Participant entitled to payment of a Separation Benefit or any other amounts under the Plan shall remain a Participant in
the Plan until the full amount of the Separation Benefit and any other amounts payable under the Plan have been paid to the
Participant.
ARTICLE IV
SEPARATION BENEFITS
4.1 Terminations of Employment Which Give Rise to Separation Benefits Under Plan. A Participant shall be entitled to
Separation Benefits as set forth in Section 4.2 below if, at any time before the second anniversary of the Date of the Change of
Control, the Participant’s Employment is terminated (i) by the Employer for any reason other than Cause or (ii) by the Participant
within 90 days after the occurrence of Good Reason. A Participant shall not be entitled to Separation Benefits if the Participant’s
Employment is terminated (i) voluntarily by the Participant without Good Reason (or more than 90 days after any event which
constitutes the occurrence of Good Reason) or (ii) by reason of death or Disability or (iii) by the Employer for Cause. In addition, if a
Participant’s employment is terminated by the Company without Cause prior to the date of a Change of Control, either (i) at the
request of a third party who has indicated an intention or taken steps reasonably calculated to effect such Change of Control, or
(ii) otherwise in connection with, or in anticipation of, such a Change of Control which has been threatened or proposed, such
termination shall be deemed to have occurred after a Change of Control for purposes of this Plan provided a Change of Control shall
actually occur.
4.2 Separation Benefits.
(a) If a Participant’s employment is terminated under circumstances entitling him to Separation Benefits as provided in
Section 4.1, the Company shall pay such Participant, within 30 days of the Date of Termination, a cash lump sum as set forth in
subsection (b) below and the continued benefits set forth in subsection (c) below. For purposes of determining the benefits set forth in
subsections (b) and (c), if the termination of the Participant’s employment is for Good Reason after there has been a reduction of the
Participant’s Annual Salary, opportunity to earn Annual Bonuses, or other compensation or employee benefits, such reduction shall
be ignored.
(b) The cash lump sum referred to in Section 4.2(a) is the aggregate of the following amounts:
(i) the sum of (1) the Participant’s Annual Salary through the Date of Termination to the extent not theretofore paid, (2) the
product of (x) the Annual Bonus Award and (y) a fraction, the numerator of which is the number of days in such year through
the Date of Termination, and the denominator of which is 365, and (3) any accrued vacation pay, to the extent not theretofore
paid and in full satisfaction of the rights of the Participant thereto;
6
(ii) an amount equal to the product of (1) the Participant’s Multiple times (2) the sum of (x) the Participant’s Annual Salary
plus (y) the Participant’s Annual Bonus Award; and
(iii) an amount equal to the difference between (a) the actuarial equivalent of the benefit under the qualified defined benefit
retirement plans of the Employer in which the Participant participates (collectively, the “Retirement Plan”) and any excess or
supplemental retirement plans in which the Participant participates (collectively, the “SERP”) which the Participant would
receive if his or her employment continued during the Separation Period, assuming that the Participant’s compensation during
the Separation Period would have been equal to his or her compensation as in effect immediately before the termination or, if
higher, on the Effective Date, and (b) the actuarial equivalent of the Participant’s actual benefit (paid or payable), if any, under
the Retirement Plan and the SERP as of the Date of Termination. The actuarial assumptions used for purposes of determining
actuarial equivalence shall be no less favorable to the Participant than the more favorable of those in effect under the Retirement
Plan and the SERP on the Date of Termination or the Date of the Change of Control.
(c) The continued benefits referred to above are as follows:
(i) during the Separation Period, the Participant and his or her family shall be provided with medical, dental and life
insurance benefits as if the Participant’s employment had not been terminated; provided, however, that if the Participant
becomes reemployed with another employer and is eligible to receive medical or other welfare benefits under another employer-
provided plan, the medical and other welfare benefits described herein shall be secondary to those provided under such other
plan during such applicable period of eligibility. For purposes of determining eligibility (but not the time of commencement of
benefits) of the Participant for retiree medical, dental and life insurance benefits under the Employer’s plans, practices, programs
and policies, the Participant shall be considered to have remained employed during the Separation Period and to have retired on
the last day of such period; and
(ii) if the Participant’s employment is terminated by the Company other than for Cause, the Company shall, at its sole
expense as incurred, provide the Participant with outplacement services the scope and provider of which shall be selected by the
Participant in his or her sole discretion (but at a cost to the Company of not more than $30,000), provided that no such
outplacement services shall be provided beyond the end of the second calendar year following the calendar year in which the
Date of Termination occurs;
To the extent any benefits described in this Section 4.2(c) cannot be provided pursuant to the appropriate plan or program maintained
for Employees, the Company shall provide such benefits outside such plan or program at no additional cost (including without
limitation tax cost) to the Participant.
4.3 Other Benefits Payable. The cash lump sum and continuing benefits described in Section 4.2 above shall be payable in
addition to, and not in lieu of, all other accrued or vested or earned but deferred compensation, rights, options or other benefits which
may be owed to a Participant upon or following termination, including but not limited to accrued vacation or sick pay, amounts
7
or benefits payable under any bonus or other compensation plans, stock option plan, stock ownership plan, stock purchase plan, life
insurance plan, health plan, disability plan or similar or successor plan, but excluding any severance pay or pay in lieu of notice
required to be paid to such Participant under applicable law.
4.4 Certain Additional Payments by the Company.
(a) Anything in this Plan to the contrary notwithstanding and except as set forth below, in the event it shall be determined that
any payment or distribution by the Company to or for the benefit of any Participant (whether paid or payable or distributed or
distributable pursuant to the terms of this Plan or otherwise, but determined without regard to any additional payments required under
this Section 4.4) (a “Payment”) would be subject to the excise tax imposed by Section 4999 of the Code or any interest or penalties
are incurred by the Participant with respect to such excise tax (such excise tax, together with any such interest and penalties, are
hereinafter collectively referred to as the “Excise Tax”), then the Participant shall be entitled to receive an additional payment (a
“Gross-Up Payment”) in an amount such that after payment by the Participant of all taxes (including any interest or penalties imposed
with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect
thereto) and Excise Tax imposed upon the Gross-Up Payment, the Participant retains an amount of the Gross-Up Payment equal to
the Excise Tax imposed upon the Payments. Notwithstanding the foregoing provisions of this Section 4, if it shall be determined that
the Participant is entitled to a Gross-Up Payment, but that the Payments do not exceed 110% of the greatest amount (the “Reduced
Amount”) that could be paid to the Participant such that the receipt of Payments will not give rise to any Excise Tax, then no Gross-
Up Payment shall be made to the Participant and the Payments, in the aggregate, shall be reduced to the Reduced Amount. In the
event that the preceding sentence applies, the Payments shall be reduced first out of Payments which are not subject to Code
Section 409A and, if necessary, then Payments which are subject to Code Section 409A shall be reduced, starting with the Payments
which are to be paid on the latest future date, until the Payments have been reduced to the Reduced Amount.
(b) Subject to the provisions of Section 4.4(c), all determinations required to be made under this Section 4.4, including whether
and when a Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at
such determination, shall be made by such certified public accounting firm, human resources consulting firm, or other consulting firm
in the business of performing such calculations as may be designated by the Company (the “Consulting Firm”), which shall provide
detailed supporting calculations both to the Company and the Participant. All fees and expenses of the Consulting Firm shall be borne
solely by the Company. Any Gross-Up Payment, as determined pursuant to this Section 4.4, due upon a Change of Control or due
upon the Participant’s termination of employment shall be paid by the Company to the Participant no later than the last day of the
calendar year following the calendar year in which the related taxes are remitted to the taxing authorities. Any determination by the
Consulting Firm shall be binding upon the Company and the Participant. As a result of the uncertainty in the application of
Section 4999 of the Code at the time of the initial determination by the Consulting Firm hereunder, it is possible that Gross-Up
Payments which will not have been made by the Company should have been made (“Underpayment”), consistent with the
calculations required to be made hereunder. In the event that the Company exhausts its remedies pursuant to Section 4.4(c) and the
Participant thereafter is required to make a payment of any Excise Tax, the Consulting Firm shall determine the amount of the
Underpayment that has occurred and any such Underpayment shall be paid by the Company to or for the benefit of the Participant by
the last day of the calendar year following the calendar year in which the taxes that are the subject of audit, litigation, or any claim by
the Internal Revenue Service are remitted to the taxing authorities.
8
(c) The Participant shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would
require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later
than ten business days after the Participant is informed in writing of such claim and shall apprise the Company of the nature of such
claim and the date on which such claim is requested to be paid. The Participant shall not pay such claim prior to the expiration of the
30-day period following the date on which it gives such notice to the Company (or such shorter period ending on the date that any
payment of taxes with respect to such claim is due). If the Company notifies the Participant in writing prior to the expiration of such
period that it desires to contest such claim, the Participant shall:
(i) give the Company any information reasonably requested by the Company relating to such claim,
(ii) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time
to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably
selected by the Company,
(iii) cooperate with the Company in good faith in order effectively to contest such claim, and
(iv) permit the Company to participate in any proceedings relating to such claim;
provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties)
incurred in connection with such contest and shall indemnify and hold the Participant harmless, on an after-tax basis, for any Excise
Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of
costs and expenses. Without limitation on the foregoing provisions of this Section 4.4(c), the Company shall control all proceedings
taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings,
hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Participant to
pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and the Participant agrees to prosecute such
contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as
the Company shall determine; provided, however, that if the Company directs the Participant to pay such claim and sue for a refund,
to the extent permitted by law the Company shall advance the amount of such payment to the Participant, on an interest-free basis and
shall indemnify and hold the Participant harmless, on an after-tax basis, from any Excise Tax or income tax (including interest or
penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such
advance; and further provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of
9
the Participant with respect to which such contested amount is claimed to be due is limited solely to such contested amount.
Furthermore, the Company’s control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be
payable hereunder and the Participant shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal
Revenue Service or any other taxing authority.
(d) If, after the receipt by the Participant of an amount advanced by the Company pursuant to Section 4.4(c), the Participant
becomes entitled to receive any refund with respect to such claim, the Participant shall (subject to the Company’s complying with the
requirements of Section 4.4(c)) promptly pay to the Company the amount of such refund (together with any interest paid or credited
thereon after taxes applicable thereto). If, after the receipt by the Participant of an amount advanced by the Company pursuant to
Section 4.4(c), a determination is made that the Participant shall not be entitled to any refund with respect to such claim and the
Company does not notify the Participant in writing of its intent to contest such denial of refund prior to the expiration of 30 days after
such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall
offset, to the extent thereof, the amount of Gross-Up Payment required to be paid.
4.5 Payment Obligations Absolute. The obligations of the Company and the other Employers to pay the separation benefits
described in Section 4.2 and any additional payments described in Section 4.4 shall be absolute and unconditional and shall not be
affected by any circumstances, including, without limitation, any set-off, counterclaim, recoupment, defense or other right which the
Company or any of the other Employers may have against any Participant. In no event shall a Participant be obligated to seek other
employment or take any other action by way of mitigation of the amounts payable to a Participant under any of the provisions of this
Plan, nor shall the amount of any payment hereunder be reduced by any compensation earned by a Participant as a result of
employment by another employer, except as specifically provided in Section 4.2(c)(i).
ARTICLE V
SUCCESSOR TO COMPANY
This Plan shall bind any successor of the Company, its assets or its businesses (whether direct or indirect, by purchase, merger,
consolidation or otherwise), in the same manner and to the same extent that the Company would be obligated under this Plan if no
succession had taken place.
In the case of any transaction in which a successor would not by the foregoing provision or by operation of law be bound by this
Plan, the Company shall require such successor expressly and unconditionally to assume and agree to perform the Company’s
obligations under this Plan, in the same manner and to the same extent that the Company would be required to perform if no such
succession had taken place. The term “Company,” as used in this Plan, shall mean the Company as hereinbefore defined and any
successor or assignee to the business or assets which by reason hereof becomes bound by this Plan.
ARTICLE VI
DURATION, AMENDMENT AND TERMINATION
6.1 Amendment or Termination. The Board may amend or terminate this Plan (including Schedule I) at any time; provided, that
this Plan (including Schedule I) may not be terminated or amended (i) following a Change of Control, (ii) at the request of a
10
third party who has taken steps reasonably calculated to effect a Change of Control, or (iii) otherwise in connection with or in
anticipation of a Change of Control, in any manner that could adversely affect the rights of any Participant. If a Change of Control
occurs while this Plan is in effect, this Plan shall continue in full force and effect and shall not terminate or expire until after all
Participants who become entitled to any payments hereunder shall have received such payments in full and all adjustments required to
be made pursuant to Section 4.4 have been made.
6.2 Procedure for Amendment or Termination. Any Amendment or termination of this Plan by the Board in accordance with the
foregoing shall be made by action of the Board in accordance with the Company’s charter and by-laws and applicable law, and shall
be evidenced by a written instrument signed by a duly authorized officer of the Company, certifying that the Board has taken such
action.
ARTICLE VII
MISCELLANEOUS
7.1 Legal Fees and Expenses. The Company shall pay as incurred all legal fees, costs of litigation, costs of arbitration,
prejudgment interest, and other expenses which are incurred in good faith by the Participant as a result of the Company’s refusal to
provide the benefits to which the Participant becomes entitled under this Agreement, or as a result of the Company’s (or any third
party’s) contesting the validity, enforceability, or interpretation of the Agreement, or as a result of any conflict between the parties
pertaining to this Agreement; provided, however, that if the court (or arbitration panel, as applicable) determines that the Participant’s
claims were arbitrary and capricious, the Company shall have no obligation hereunder. This reimbursement provision shall apply for
the lifetime of the Participant. Any reimbursement under this section must be made on or before the last day of the calendar year
following the calendar year in which the expense was incurred, and the right to reimbursement shall not be subject to liquidation or
exchange for another benefit; provided, however, that if the court (or arbitration panel, as applicable) determines that the Participant’s
claims were arbitrary and capricious, the Participant shall be obligated to repay to the Company all expenses previously reimbursed
under this Section 7.1 immediately at the time such determination has been made final and unappealable.
7.2 Employment Status. This Plan does not constitute a contract of employment, nor does it impose on the Participant or the
Employers any obligation for the Participant to remain an Employee or change the status of the Participant’s employment or the
Employers’ policies regarding termination of employment.
7.3 Named Fiduciary; Administration. The Company is the named fiduciary of the Plan, with full authority to control and
manage the operation and administration of the Plan, acting through the Benefits Administration Committee.
7.4 Claim Procedure. If an Employee, former Employee or other person who believes that he or she is being denied a benefit to
which he or she is entitled (“claimant”), or his or her duly authorized representative, makes a written request alleging a right to
receive benefits under this Plan or alleging a right to receive an adjustment in benefits being paid under the Plan, the Company shall
treat it as a claim for benefit. All claims for benefit under the Plan shall be sent to the Chief Executive Officer of the Company at
Ameren Corporation, 1901 Chouteau Avenue, P.O. Box 66149, St. Louis, MO 63166, and must be received within 30 days after
termination of employment.
11
(a) Claim Decision. Upon receipt of a claim, the Chief Executive Officer shall advise the claimant that a reply will be
forthcoming within a reasonable period of time, but ordinarily not later than 90 days, and shall, in fact, deliver such reply within such
period. However, the Chief Executive Officer may extend the reply period for an additional ninety days for reasonable cause. If the
reply period will be extended, the Chief Executive Officer shall advise the claimant in writing during the initial 90-day period
indicating the special circumstances requiring an extension and the date by which the Chief Executive Officer expects to render the
benefit determination. If the Chief Executive Officer denies the claim, in whole or in part, the Chief Executive Officer will inform the
claimant in writing of his or her determination and the reasons therefor in terms calculated to be understood by the claimant. The
notice shall set forth the specific reasons for the denial, make specific reference to the pertinent Plan provisions on which the denial is
based, and describe any additional material or information necessary for the claimant to perfect the claim and explain why such
material or such information is necessary. Such notice shall, in addition, inform the claimant what procedure the claimant should
follow to take advantage of the review procedures set forth below in the event the claimant desires to contest the denial of the claim,
including a statement of the claimant’s right to bring a civil action under Section 502(a) of ERISA following an adverse benefit
determination on review and the time limits for requesting a review and for the actual review.
(b) Request for Review. The claimant may within 60 days thereafter request in writing that the Committee of the Board review
the Chief Executive Officer’s prior determination. Such request must be addressed to the Committee of the Board at Ameren
Corporation, 1901 Chouteau Avenue, P.O. Box 66149, St. Louis, MO 63166. The claimant or his or her authorized representative
may submit written comments, documents, records or other information relating to the denied claim, which shall be considered in the
review without regard to whether such information was submitted or considered in the initial benefit determination. The claimant or
his or her authorized representative shall be provided, upon request and free of charge, reasonable access to, and copies of, all
documents, records and other information which (i) was relied upon by the Chief Executive Officer in making his or her initial claims
decision, (ii) was submitted, considered or generated in the course of the Chief Executive Officer making his or her initial claims
decision, without regard to whether such instrument was actually relied upon by the Chief Executive Officer in making his or her
decision or (iii) demonstrates compliance by the Chief Executive Officer with the administrative processes and safeguards designed to
ensure and to verify that benefit claims determinations are made in accordance with governing Plan documents and that, where
appropriate, the Plan provisions have been applied consistently with respect to similarly situated claimants. If the claimant does not
request a review of the Chief Executive Officer’s determination within such 60-day period, he or she shall be barred and estopped
from challenging such determination.
(c) Review of Decision. The Committee shall, within a reasonable period of time, ordinarily not later than 60 days, after the
Committee’s receipt of a request for review, review the Chief Executive Officer’s prior determination. If special circumstances
require that the 60-day time period be extended, the Committee will so notify the claimant within the initial 60-day period indicating
the special circumstances requiring an extension and the date by which the Committee expects to render its decision on review, which
shall be as soon as possible but not later than 120 days after receipt of the request for review. In the event that the Committee extends
12
the determination period on review due to a claimant’s failure to submit information necessary to decide a claim, the period for
making the benefit determination on review shall not take into account the period beginning on the date on which notification of
extension is sent to the claimant and ending on the date on which the claimant responds to the request for additional information. The
Committee has discretionary authority to determine a claimant’s eligibility for benefits and to interpret the terms of the Plan. Benefits
under the Plan will be paid only if the Committee decides in its discretion that the claimant is entitled to such benefits. The decision
of the Committee shall be final and non-reviewable, unless found to be arbitrary and capricious by a court of competent review. Such
decision will be binding upon the Company and the claimant. If the Committee makes an adverse benefit determination on review, the
Committee will render a written opinion, using language calculated to be understood by the claimant, that sets forth the specific
reasons for the denial, makes specific references to pertinent Plan provisions on which the denial is based and includes a statement of
the claimant’s right to bring a civil action under Section 502(a) of ERISA following the adverse benefit determination on such review.
The opinion shall also include a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access
to, and copies of, all documents, records and other information which (i) was relied upon by the Committee in making its decision,
(ii) was submitted, considered or generated in the course of the Committee making its decision, without regard to whether such
instrument was actually relied upon by the Committee in making its decision, or (iii) demonstrates compliance by the Committee with
its administrative processes and safeguards designed to ensure and to verify that benefit claims determinations are made in accordance
with governing Plan documents, and that, where appropriate, the Plan provisions have been applied consistently with respect to
similarly situated claimants.
7.5 Unfunded Plan Status. This Plan is intended to be an unfunded plan maintained primarily for the purpose of providing
deferred compensation for a select group of management or highly compensated employees, within the meaning of Section 401 of
ERISA. All payments pursuant to the Plan shall be made from the general funds of the Company and no special or separate fund shall
be established or other segregation of assets made to assure payment. No Participant or other person shall have under any
circumstances any interest in any particular property or assets of the Company as a result of participating in the Plan. Notwithstanding
the foregoing, one or more of the Employers may (but shall not be obligated to) create one or more grantor trusts, the assets of which
are subject to the claims of the Employers’ creditors, to assist them in accumulating funds to pay their obligations under the Plan.
7.6 Validity and Severability. The invalidity or unenforceability of any provision of the Plan shall not affect the validity or
enforceability of any other provision of the Plan, which shall remain in full force and effect, and any prohibition or unenforceability
in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.
7.7 Governing Law. The validity, interpretation, construction and performance of the Plan shall in all respects be governed by
the laws of Missouri, without reference to principles of conflict of law, except to the extent pre-empted by ERISA.
7.8 Specified Employees; Section 409A Compliance. To the extent necessary to comply with Code Section 409A, any payments
due to a “specified employee” hereunder as a result of a separation from service will, to the extent required by Code Section 409A,
13
be payable no earlier than six months following such specified employee’s separation from service. The terms “specified employee”
and “separation from service” shall be interpreted in accordance with the resolution of the Board defining such terms. This Plan shall
be interpreted in a manner so as to be consistent with Code Section 409A and the regulations thereunder to the extent applicable to
payments and benefits provided hereunder.
14
SCHEDULE I
CHANGE OF CONTROL
SEVERANCE PLAN PARTICIPANTS
Benefit Level - 3
Baxter, Warner L.
Cisel, Scott A.
Cole, Daniel F.
Heflin, Adam C.
Lyons, Martin J.
Mark, Richard J.
Martin, Donna K.
Barnes, Lynn M.
Birdsong, Jerre E.
Birk, Mark C.
Borkowski, Maureen A.
Brawley, Mark
Bremer, Charles A.
Cissell, Richard C.
Diya, Fadi M.
Evans, Ronald K.
Fey, John R.
Foss, Karen C.
Glaeser, Scott A.
Herrmann, Timothy E.
Iselin, Christopher A.
Kidwell, Stephen M.
Lindgren, Mark C.
Menne, Michael L.
Moehn, Michael
Naslund, Charles D.
Nelson, Gregory L.
Rainwater, Gary L
Sullivan, Steven R.
Voss, Thomas R.
Benefit Level - 2
Mosier, Don M.
Mueller, Michael G.
Neff, Robert K.
Nelson, Craig D.
Ogden, Stan E.
Pate, Ron D.
Power, Joseph M.
Prebil, William J.
Schepers, David J.
Schukar, Shawn E.
Serri, Andrew M.
Simpson, Jerry L.
Sobule, James A.
Steinke, Bruce A.
Weisenborn, Dennis W.
Zdellar, Ronald C.
FIRST AMENDMENT TO THE
AMEREN SUPPLEMENTAL RETIREMENT PLAN
Exhibit 10.44
WHEREAS, Ameren Corporation (“Ameren”) previously adopted the Ameren Supplemental Retirement Plan (“Plan”); and
WHEREAS, Ameren previously acquired Central Illinois Light Company (“CILCO”) and became the sponsor of the CILCO
Benefit Replacement Plan (“BRP”); and
WHEREAS, Ameren reserved the right to amend the Plan and the BRP; and
WHEREAS, Ameren desires to merge the BRP into the Plan effective November 1, 2008;
NOW THEREFORE, effective November 1, 2008, the BRP is merged into the Plan, and the Plan is amended by adding a new
Schedule B as attached hereto; and
RESOLVED FURTHER, the terms of the BRP in effect prior to the merger shall continue to apply with respect to a participant
who terminated employment prior to January 1, 2005, and the benefits of such participants shall be “grandfathered” for purposes of
Section 409A of the Internal Revenue Code of 1986, as amended.
IN WITNESS WHEREOF, this Amendment is executed as of the date below.
AMEREN CORPORATION
By:
/s/ Donna K. Martin
Title: SVP & CHRO
Date: 10-24-08
SCHEDULE B
CILCO BENEFIT REPLACEMENT PLAN BENEFITS
Effective November 1, 2008, the CILCO BRP is merged into the Plan. An individual who is a Participant under the CILCO BRP on
such date (“CILCO Participant”) shall become a Participant in the Plan on such date, and his or her benefits under the Plan shall be
determined in accordance with the terms of the Plan, subject to the following provisions:
•
In lieu of the death benefits described in Section 3.3, upon the death of a CILCO Participant before termination of
employment, if he or she leaves a surviving spouse to whom he or she had been continuously married for the one-year
period ending on the date of his or her death, his or her spouse shall be entitled to a death benefit equal to (a) the monthly
benefit which would have been payable to the surviving spouse as a pre-retirement death benefit under the CILCO Salaried
Supplement without regard to any limitations described in Section 2.1(a) of the Plan, minus (b) the monthly pre-retirement
death benefit actually payable to the surviving spouse under the CILCO Salaried Supplement. Such benefit shall be paid at
the time and in the form described in Section 3.3 of the Plan.
•
In addition to the forms of payment described in Section 3.4B, a CILCO Participant may elect, in accordance with the terms
of Section 3.4, to receive his or her benefit upon termination of employment in the form of an annuity option available under
the CILCO Salaried Supplement (or its successor document) under the Retirement Plan.
Ameren Corporation
Computation of Ratio of Earnings to Fixed Charges
(Thousands of Dollars, Except Ratios)
2004
Year Ended December 31,
2006
2007
2005
Exhibit 12.1
Net income from continuing operations
Less- Change in accounting principle
Less- Minority interest
Add- Taxes based on income
Net income before income taxes, change in accounting
principle and minority interest
Add- fixed charges:
Interest on long term debt
Estimated interest cost within rental expense
Amortization of net debt premium, discount, and
expenses
Subsidiary preferred stock dividends
Adjust preferred stock dividends to pre-tax basis
Total fixed charges
Less: Adjustment of preferred stock dividends to pre-tax
basis
Earnings available for fixed charges
Ratio of earnings to fixed charges
(1) Includes FIN 48 interest expense
$ 529,884 $ 605,725 $ 546,738 $ 617,804
—
(27,266)
330,141
—
(4,201)
282,558
(22,135)
(3,231)
356,016
—
(27,135)
283,825
2008
$ 605,189
—
(28,422)
326,736
816,643
987,107
857,698
975,211
960,347
269,868
3,185
297,822
4,208
345,410
4,081
421,406 (1)
5,020
440,507(1)
6,510
12,983
11,089
5,913
303,038
14,687
12,745
7,227
336,689
15,341
10,936
5,565
381,333
18,638
10,871
5,709
461,644
19,716
10,357
5,497
482,587
5,913
5,709
$1,113,768 $1,316,569 $1,233,466 $1,431,146
3.10
5,565
7,227
3.91
3.23
3.67
5,497
$1,437,437
2.97
Union Electric Company
Computation of Ratios of Earnings to Fixed Charges and Combined
Fixed Charges and Preferred Stock Dividend Requirements
(Thousands of Dollars, Except Ratios)
Year Ended December 31,
Exhibit 12.2
Net income from continuing operations
Less- Income from equity investee
Add- Taxes based on income
Net income before income taxes, change in Accounting principle and
income from equity investee
Add- fixed charges:
Interest on long term debt
Estimated interest cost within rental expense
Amortization of net debt premium, discount, and expenses
Total fixed charges
Earnings available for fixed charges
Ratio of earnings to fixed charges
Earnings required for combined fixed charges and preferred stock
dividends:
Preferred stock dividends
Adjustment to pre-tax basis
Combined fixed charges and preferred stock dividend requirements
Ratio of earnings to combined fixed charges and preferred stock
dividend requirements
(1) Includes FIN 48 interest expense
2004
2005
2006
$378,670 $351,770 $348,806 $341,966 $250,998
10,948
133,514
54,545
139,782
6,463
193,156
54,285
183,867
5,098
207,641
2008
2007
581,213
538,463
478,388
427,203
373,564
103,338
2,790
5,168
111,296
692,509
6.22
120,899
2,528
5,278
128,705
667,168
5.18
176,088
2,754
5,468
184,310
662,698
3.59
203,456(1)
2,540
5,634
211,630
638,833
3.01
205,314(1)
3,533
6,226
215,073
588,637
2.73
5,941
2,891
8,832
5,941
3,160
9,101
$120,128 $137,542 $193,495 $220,000 $224,174
5,941
2,429
8,370
5,941
2,896
8,837
5,941
3,244
9,185
5.76
4.85
3.42
2.90
2.62
Exhibit 12.3
2008
$14,739
5,199
19,938
Central Illinois Public Service Company
Computation of Ratios of Earnings to Fixed Charges and Combined
Fixed Charges and Preferred Stock Dividend Requirements
(Thousands of Dollars, Except Ratios)
Net income from continuing operations
Add- Taxes based on income
Net income before income taxes
Add- fixed charges:
Interest on long term debt
Estimated interest cost within rental expense
Amortization of net debt premium, discount, and expenses
Total fixed charges
Earnings available for fixed charges
Ratio of earnings to fixed charges
Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends
Adjustment to pre-tax basis
Combined fixed charges and preferred stock dividend requirements
Ratio of earnings to combined fixed charges and preferred stock dividend
requirements
(1) Includes FIN 48 interest expense
2004
Year Ended December 31,
2006
2007
2005
$32,463 $42,998 $37,372 $16,535
9,322
25,857
15,539
52,911
24,596
67,594
16,135
48,598
31,372
—
903
32,275
80,873
2.50
28,969
—
953
29,922
97,516
3.25
29,932
726
1,025
31,683
84,594
2.67
36,670(1)
899
1,105
38,674
64,531
1.66
29,422(1)
760
1,024
31,206
51,144
1.63
2,512
1,248
3,760
2,512
1,416
3,928
$36,035 $33,871 $35,240 $42,602
2,512
1,045
3,557
2,512
1,437
3,949
2,512
886
3,398
$34,604
2.24
2.87
2.40
1.51
1.47
Ameren Energy Generating Company
Computation of Ratio of Earnings to Fixed Charges
(Thousands of Dollars, Except Ratios)
2004
Year Ended December 31,
2006
2007
2005
Net income from continuing operations
Less- Change in accounting principle
Add- Taxes based on income
Net income before income taxes and change in accounting principle
Add- fixed charges:
Interest on long term debt
Estimated interest cost within rental expense
Amortization of net debt premium, discount, and expenses
Total fixed charges
Earnings available for fixed charges
Ratio of earnings to fixed charges
(1) Includes FIN 48 interest expense
$107,292 $ 96,732 $ 48,929 $124,894
—
77,799
202,693
(15,600)
72,433
184,765
—
64,245
171,537
—
21,955
70,884
93,118
—
1,497
94,615
71,720
—
1,345
73,065
54,783(1)
164
586
55,533
$266,152 $257,830 $130,647 $258,226
4.64
59,070
107
586
59,763
3.52
2.81
2.18
Exhibit 12.4
2008
$175,450
—
100,005
275,455
54,153(1)
228
760
55,141
$330,596
5.99
CILCORP INC.
Computation of Ratio of Earnings to Fixed Charges
(Thousands of Dollars, Except Ratios)
2004
2005
2006
2007
Year Ended December 31,
Net income from continuing operations
Less- Change in accounting principle
Add- Taxes based on income (benefit)
Net income before income taxes and change in accounting principle
Add- fixed charges:
Interest on long term debt
Estimated interest cost within rental expense
Amortization of net debt premium, discount, and expenses
Subsidiary preferred stock dividends
Adjust preferred stock dividends to pre-tax basis
Total fixed charges
Less: Adjustment of preferred stock dividends to pre-tax basis
Earnings available for fixed charges
Ratio of earnings to fixed charges
(1) Includes FIN 48 interest expense
$10,367 $ 3,222 $ 21,004 $ 49,402
—
21,018
70,420
—
(10,944)
10,060
—
(8,526)
1,841
(2,497)
(3,164)
2,555
50,562
390
693
1,988
1,293
54,926
1,293
51,992
395
767
2,062
346
55,562
346
62,824(1)
343
1,322
1,869
812
67,170
812
$57,057 $56,188 $ 64,657 $136,778
2.03
51,574
289
801
1,933
(1,007)
53,590
(1,007)
1.20
1.02
1.02
Exhibit 12.5
2008
$ 43,542
—
19,411
62,953
53,592(1)
430
1,428
1,354
604
57,408
604
$119,757
2.08
Central Illinois Light Company
Computation of Ratios of Earnings to Fixed Charges and Combined
Fixed Charges and Preferred Stock Dividend Requirements
(Thousands of Dollars, Except Ratios)
Exhibit 12.6
Net income from continuing operations
Less- Change in accounting principle
Add- Taxes based on income
Net income before income taxes and change in accounting principle
Add- fixed charges:
Interest on long term debt
Estimated interest cost within rental expense
Amortization of net debt premium, discount, and expenses
Total fixed charges
Earnings available for fixed charges
Ratio of earnings to fixed charges
Earnings required for combined fixed charges and preferred stock
dividends:
Preferred stock dividends
Adjustment to pre-tax basis
Combined fixed charges and preferred stock dividend requirements
Ratio of earnings to combined fixed charges and preferred stock dividend
requirements
(1) Includes FIN 48 interest expense
Year Ended December 31,
2007
2004
2005
2006
$32,384 $25,296 $47,012 $ 75,984 $ 69,638
—
38,673
108,311
—
9,966 39,195
56,978 115,179
(2,497)
16,357
44,150
—
5,450
37,834
—
2008
15,179
395
611
16,185
54,019
3.33
13,918
390
473
14,781
58,931
3.98
289
705
18,044 26,071(1)
343
1,065
19,038 27,479
76,016 142,658
5.19
3.99
19,724(1)
429
1,112
21,265
129,576
6.09
2,062
346
2,408
1,354
752
2,106
$18,593 $18,072 $21,381 $ 30,325 $ 23,371
1,933
410
2,343
1,998
1,293
3,291
1,869
977
2,846
2.90
3.26
3.55
4.70
5.54
Illinois Power Company
Computation of Ratios of Earnings to Fixed Charges and Combined
Fixed Charges and Preferred Stock Dividend Requirements
(Thousands of Dollars, Except Ratios)
Exhibit 12.7
Net income from continuing operations
Add- Taxes based on income
Net income before income taxes
Add- fixed charges:
Interest on long term debt
Estimated interest cost within rental expense
Amortization of net debt premium, discount, expenses and losses
Total fixed charges
Earnings available for fixed charges
Ratio of earnings to fixed charges
Earnings required for combined fixed charges and preferred stock
dividends:
Preferred stock dividends
Adjustment to pre-tax basis
Combined fixed charges and preferred stock dividend requirements
Ratio of earnings to combined fixed charges and preferred stock
dividend requirements
Year Ended December 31,
2004 (1)
2005
2006
2007
$137,538 $ 97,039 $ 56,659 $ 25,780 $
87,591
225,129
65,171
162,210
37,246
93,905
15,341
41,121
2008
4,970
4,746
9,716
112,616
1,696
18,772
133,084
358,213
2.69
41,028
1,290
2,315
44,633
206,843
4.63
46,167
205
3,537
49,909
143,814
2.88
69,085(2)
234
8,454
77,773
118,894
1.52
91,143(2)
701
8,922
100,766
110,482
1.09
2,294
1,461
3,755
2,294
2,191
4,485
$136,839 $ 48,469 $ 53,711 $ 81,432 $105,251
2,294
1,365
3,659
2,294
1,542
3,836
2,294
1,508
3,802
2.61
4.26
2.67
1.46
1.04
(1) Ameren Corporation purchased Illinois Power Company on September 30, 2004, amounts include combined predecessor and
successor financial information.
(2) Includes FIN 48 interest expense
SUBSIDIARIES OF AMEREN CORPORATION
AT DECEMBER 31, 2008
Name
Ameren Corporation
Ameren Development Company
Enporion, Inc. (21% interest)
Missouri Central Railroad Company
CIPSCO Leasing Company
Gateway Energy Systems, L.C. (89.1% interest)
Gateway Energy WGK Project, L.L.C.
Ameren Energy Resources Company, LLC
Ameren Energy Generating Company
Coffeen and Western Railroad Company
Ameren Energy Marketing Company
Illinois Materials Supply Co.
Electric Energy, Inc. (80% interest)
Midwest Electric Power Inc.
Joppa and Eastern Railroad Company
Met South, Inc.
Massac Enterprises LLC
AmerenEnergy Medina Valley Cogen, L.L.C.
Ameren Energy Fuels and Services Company
Ameren Illinois Transmission Company
Ameren Services Company
Central Illinois Public Service Company, d/b/a AmerenCIPS
CILCORP Inc.
Central Illinois Light Company, d/b/a AmerenCILCO
AmerenEnergy Resources Generating Company
CLC Aircraft Leasing LLC
QST Enterprises Inc.
ESE Land Corporation
California/Nevada Development L.L.C. (15% interest)
Energy Risk Assurance Company
Missouri Energy Risk Assurance Company LLC
Illinois Power Company, d/b/a AmerenIP
Illinois Power Securitization Limited Liability Company*
Illinois Power Special Purpose Trust*
Union Electric Company, d/b/a AmerenUE
Fuelco LLC (33.33% interest)
Exhibit 21.1
State or Jurisdiction
of Organization
Missouri
Missouri
Delaware
Delaware
Illinois
Missouri
Illinois
Delaware
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Illinois
Missouri
Illinois
Illinois
Illinois
Illinois
Delaware
Illinois
Illinois
Delaware
Vermont
Missouri
Illinois
Delaware
Delaware
Missouri
Delaware
Subsidiaries not included on this list, considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary
as of December 31, 2008.
* Dissolved February 2009
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-152046, 333-155416,
333-155416-04 and 333-155416-05) and the Registration Statements on Form S-8 (Nos. 333-50793, 333-133998 and 333-136971) of
Ameren Corporation of our report dated March 2, 2009 relating to the financial statements, financial statement schedule and the
effectiveness of internal control over financial reporting, which appears in this Form 10-K.
Exhibit 23.1
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-151432 and 333-151432-
01) of Union Electric Company of our report dated March 2, 2009 relating to the financial statements and financial statement
schedule, which appears in this Form 10-K.
Exhibit 23.2
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-155416-03) of Central
Illinois Public Service Company of our report dated March 2, 2009 relating to the financial statements and financial statement
schedule, which appears in this Form 10-K.
Exhibit 23.3
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-155416-02) and the
Registration Statement on Form S-4 (No. 333-151014) of Ameren Energy Generating Company of our report dated March 2, 2009
relating to the financial statements, which appears in this Form 10-K.
Exhibit 23.4
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-155416-01) of Central
Illinois Light Company of our report dated March 2, 2009 relating to the financial statements and financial statement schedule, which
appears in this Form 10-K.
Exhibit 23.5
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-155416-06) and the
Registration Statements on Form S-4 (Nos. 333-149502, 333-150973 and 333-156606) of Illinois Power Company of our report dated
March 2, 2009 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
Exhibit 23.6
PricewaterhouseCoopers LLP
St. Louis, Missouri
March 2, 2009
POWER OF ATTORNEY
Exhibit 24.1
WHEREAS, AMEREN CORPORATION, a Missouri corporation (herein referred to as the “Company”), is required to file with
the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report
on Form 10-K for the year ended December 31, 2008; and
WHEREAS, each of the below undersigned is a director of the Company.
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Gary L. Rainwater and/or Warner L. Baxter
and/or Thomas R. Voss and/or Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-
fact of the undersigned, for and in the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-
K and any amendments thereto, and, for the performance of the same acts, each with power to appoint in their place and stead and as
their substitute, one or more attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all
that said attorneys-in-fact may do by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:
Stephen F. Brauer, Director
/s/ Stephen F. Brauer
Susan S. Elliott, Director
/s/ Susan S. Elliott
Walter J. Galvin, Director
/s/ Walter J. Galvin
Gayle P. W. Jackson, Director
/s/ Gayle P. W. Jackson
James C. Johnson, Director
/s/ James C. Johnson
Charles W. Mueller, Director
/s/ C. W. Mueller
Douglas R. Oberhelman, Director
/s/ Douglas R. Oberhelman
Harvey Saligman, Director
/s/ Harvey Saligman
Patrick T. Stokes, Director
/s/ Patrick T. Stokes
Jack D. Woodard, Director
/s/ Jack D. Woodard
STATE OF MISSOURI )
CITY OF ST. LOUIS
) SS.
)
On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the
above-named directors of Ameren Corporation, known to me to be the persons described in and who executed the foregoing power of
attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.
IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.
/s/ Carolyn J. Shannon
CAROLYN J. SHANNON
Notary Public- Notary Seal
STATE OF MISSOURI- ST. LOUIS COUNTY
Commission #08383284
My Commission Expires 03/02/2012
POWER OF ATTORNEY
Exhibit 24.2
WHEREAS, UNION ELECTRIC COMPANY, a Missouri corporation (herein referred to as the “Company”), is required to file
with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual
report on Form 10-K for the year ended December 31, 2008; and
WHEREAS, each of the below undersigned is a director of the Company.
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Thomas R. Voss and/or Warner L. Baxter and/or
Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for and in
the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto,
and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more
attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact
may do by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:
Daniel F. Cole, Director
Adam C. Heflin
Richard J. Mark, Director
/s/ Daniel F. Cole
/s/ Adam C. Heflin
/s/ Richard J. Mark
Steven R. Sullivan, Director
/s/ Steven R. Sullivan
STATE OF MISSOURI )
CITY OF ST. LOUIS
) SS.
)
On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the
above-named directors of Union Electric Company, known to me to be the persons described in and who executed the foregoing
power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.
IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.
/s/ Carolyn J. Shannon
CAROLYN J. SHANNON
Notary Public – Notary Seal
STATE OF MISSOURI – ST. LOUIS COUNTY
Commission #08383284
My Commission Expires 03/02/2012
POWER OF ATTORNEY
Exhibit 24.3
WHEREAS, CENTRAL ILLINOIS PUBLIC SERVICE COMPANY, an Illinois corporation (herein referred to as the
“Company”), is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of
1934, as amended, its annual report on Form 10-K for the year ended December 31, 2008; and
WHEREAS, each of the below undersigned is a director of the Company.
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Scott A. Cisel and/or Warner L. Baxter and/or
Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for and in
the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto,
and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more
attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact
may do by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:
Daniel F. Cole, Director
/s/ Daniel F. Cole
Steven R. Sullivan, Director
/s/ Steven R. Sullivan
STATE OF MISSOURI )
CITY OF ST. LOUIS
) SS.
)
On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the
above-named directors of Central Illinois Public Service Company, known to me to be the persons described in and who executed the
foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein
stated.
IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.
/s/ Carolyn J. Shannon
CAROLYN J. SHANNON
Notary Public – Notary Seal
STATE OF MISSOURI – ST. LOUIS COUNTY
Commission #08383284
My Commission Expires 03/02/2012
POWER OF ATTORNEY
Exhibit 24.4
WHEREAS, AMEREN ENERGY GENERATING COMPANY, an Illinois corporation (herein referred to as the “Company”),
is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as
amended, its annual report on Form 10-K for the year ended December 31, 2008; and
WHEREAS, each of the below undersigned is a director of the Company.
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Charles D. Naslund and/or Warner L. Baxter
and/or Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for
and in the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments
thereto, and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or
more attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-
fact may do by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:
Daniel F. Cole, Director
/s/ Daniel F. Cole
Steven R. Sullivan, Director
/s/ Steven R. Sullivan
STATE OF MISSOURI )
CITY OF ST. LOUIS
) SS.
)
On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the
above-named directors of Ameren Energy Generating Company, known to me to be the persons described in and who executed the
foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein
stated.
IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.
/s/ Carolyn J. Shannon
CAROLYN J. SHANNON
Notary Public – Notary Seal
STATE OF MISSOURI – ST. LOUIS COUNTY
Commission #08383284
My Commission Expires 03/02/2012
POWER OF ATTORNEY
Exhibit 24.5
WHEREAS, CILCORP Inc., an Illinois corporation (herein referred to as the “Company”), is required to file with the Securities
and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K
for the year ended December 31, 2008; and
WHEREAS, each of the below undersigned is a director of the Company.
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Gary L. Rainwater and/or Warner L. Baxter
and/or Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for
and in the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments
thereto, and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or
more attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-
fact may do by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:
Daniel F. Cole, Director
Patrick T. Stokes, Director
/s/ Daniel F. Cole
/s/ Patrick T. Stokes
Steven R. Sullivan, Director
/s/ Steven R. Sullivan
STATE OF MISSOURI )
CITY OF ST. LOUIS
) SS.
)
On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the
above-named directors of CILCORP Inc., known to me to be the persons described in and who executed the foregoing power of
attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.
IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.
/s/ Carolyn J. Shannon
CAROLYN J. SHANNON
Notary Public – Notary Seal
STATE OF MISSOURI – ST. LOUIS COUNTY
Commission #08383284
My Commission Expires 03/02/2012
POWER OF ATTORNEY
Exhibit 24.6
WHEREAS, CENTRAL ILLINOIS LIGHT COMPANY, an Illinois corporation (herein referred to as the “Company”), is
required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as
amended, its annual report on Form 10-K for the year ended December 31, 2008; and
WHEREAS, each of the below undersigned is a director of the Company.
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Scott A. Cisel and/or Warner L. Baxter and/or
Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for and in
the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto,
and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more
attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact
may do by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:
Daniel F. Cole, Director
/s/ Daniel F. Cole
Steven R. Sullivan, Director
/s/ Steven R. Sullivan
STATE OF MISSOURI )
CITY OF ST. LOUIS
) SS.
)
On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the
above-named directors of Central Illinois Light Company, known to me to be the persons described in and who executed the
foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein
stated.
IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.
/s/ Carolyn J. Shannon
CAROLYN J. SHANNON
Notary Public – Notary Seal
STATE OF MISSOURI – ST. LOUIS COUNTY
Commission #08383284
My Commission Expires 03/02/2012
POWER OF ATTORNEY
Exhibit 24.7
WHEREAS, ILLINOIS POWER COMPANY, an Illinois corporation (herein referred to as the “Company”), is required to file
with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual
report on Form 10-K for the year ended December 31, 2008; and
WHEREAS, each of the below undersigned is a director of the Company.
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Scott A. Cisel and/or Warner L. Baxter and/or
Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for and in
the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto,
and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more
attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact
may do by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:
Daniel F. Cole, Director
/s/ Daniel F. Cole
Steven R. Sullivan, Director
/s/ Steven R. Sullivan
STATE OF MISSOURI )
D
CITY OF ST. LOUIS
) SS.
)
On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the
above-named directors of Illinois Power Company, known to me to be the persons described in and who executed the foregoing
power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.
IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.
/s/ Carolyn J. Shannon
CAROLYN J. SHANNON
Notary Public – Notary Seal
STATE OF MISSOURI – ST. LOUIS COUNTY
Commission #08383284
My Commission Expires 03/02/2012
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN CORPORATION
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
Exhibit 31.1
I, Gary L. Rainwater, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 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: March 2, 2009
/s/ Gary L. Rainwater
Gary L. Rainwater
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
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, Warner L. Baxter, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 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: March 2, 2009
/S/ WARNER L. BAXTER
Warner L. Baxter
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
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)
Exhibit 31.3
I, Thomas R. Voss, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 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: March 2, 2009
/S/
THOMAS R. VOSS
Thomas R. Voss
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
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)
Exhibit 31.4
I, Warner L. Baxter, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 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: March 2, 2009
/s/ Warner L. Baxter
Warner L. Baxter
Executive 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.
Company;
I have reviewed this report Form 10-K for the fiscal year ended December 31, 2008 of Central Illinois Public Service
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: March 2, 2009
/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, Warner L. Baxter, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 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: March 2, 2009
/s/ Warner L. Baxter
Warner L. Baxter
Executive 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.
Company;
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Ameren Energy Generating
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: March 2, 2009
/s/ Charles D. Naslund
Charles D. Naslund
Chairman and President
(Principal Executive Officer)
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)
Exhibit 31.8
I, Warner L. Baxter, certify that:
1.
Company;
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Ameren Energy Generating
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: March 2, 2009
/s/ Warner L. Baxter
Warner L. Baxter
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL EXECUTIVE OFFICER OF CILCORP INC.
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
Exhibit 31.9
I, Gary L. Rainwater, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of CILCORP Inc.;
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: March 2, 2009
/s/ Gary L. Rainwater
Gary L. Rainwater
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
RULE 13a-14(a)/15d-14(a) CERTIFICATION
OF PRINCIPAL FINANCIAL OFFICER OF CILCORP INC.
(required by Section 302 of the Sarbanes-Oxley Act of 2002)
Exhibit 31.10
I, Warner L. Baxter, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of CILCORP Inc.;
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: March 2, 2009
/s/ Warner L. Baxter
Warner L. Baxter
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
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)
Exhibit 31.11
I, Scott A. Cisel, certify that:
1.
Company;
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Central Illinois Light
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: March 2, 2009
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
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)
Exhibit 31.12
I, Warner L. Baxter, certify that:
1.
Company;
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Central Illinois Light
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: March 2, 2009
/s/ Warner L. Baxter
Warner L. Baxter
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
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)
Exhibit 31.13
I, Scott A. Cisel, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 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: March 2, 2009
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
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)
Exhibit 31.14
I, Warner L. Baxter, certify that:
1.
I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 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: March 2, 2009
/s/ Warner L. Baxter
Warner L. Baxter
Executive 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, 2008 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: March 2, 2009
/s/ Gary L. Rainwater
Gary L. Rainwater
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
/s/ Warner L. Baxter
Warner L. Baxter
Executive 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, 2008 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: March 2, 2009
/s/
Thomas R. Voss
Thomas R. Voss
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
/s/ Warner L. Baxter
Warner L. Baxter
Executive 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, 2008 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: March 2, 2009
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
/s/ Warner L. Baxter
Warner L. Baxter
Executive 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, 2008 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: March 2, 2009
/s/ Charles D. Naslund
Charles D. Naslund
Chairman and President
(Principal Executive Officer)
/s/ Warner L. Baxter
Warner L. Baxter
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
SECTION 1350 CERTIFICATION OF
CILCORP INC.
(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, 2008 of CILCORP Inc.
(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: March 2, 2009
/s/ Gary L. Rainwater
Gary L. Rainwater
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
/s/ Warner L. Baxter
Warner L. Baxter
Executive 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 32.6
In connection with the report on Form 10-K for the fiscal year ended December 31, 2008 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: March 2, 2009
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
/s/ Warner L. Baxter
Warner L. Baxter
Executive 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 32.7
In connection with the report on Form 10-K for the fiscal year ended December 31, 2008 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: March 2, 2009
/s/ Scott A. Cisel
Scott A. Cisel
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
/s/ Warner L. Baxter
Warner L. Baxter
Executive 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 72,518 on December 31, 2008.
The following table provides the closing price ranges and
dividends paid per Ameren common share for each quarter
during 2008 and 2007.
aee 2008
Quarter Ended
High
Low Close
Dividends
Paid
March 31
June 30
September 30
December 31
aee 2007
$54.29 $40.92 $44.04
41.34
38.49
39.03
43.16
48.39
42.23
39.15 25.51
33.26
63 1⁄2 ¢
63 1⁄2
63 1⁄2
63 1⁄2
Quarter Ended
High
Low Close
Dividends
Paid
March 31
June 30
September 30
December 31
$55.00 $48.56 $50.30
48.23
47.10
52.50
53.89
55.00
49.01
54.74
51.81
54.21
63 1⁄2 ¢
63 1⁄2
63 1⁄2
63 1⁄2
annual MeetIng
The annual meeting of Ameren Corporation shareholders will
convene at 9 a.m. (Central Time), Tuesday, April 28, 2009,
at the Chase Park Plaza Hotel, Khorassan Ballroom,
212 N. Kingshighway Blvd., St. Louis, Missouri. 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:
n make cash investments by check or automatic direct debit
to their bank accounts to purchase Ameren common stock,
totaling up to $120,000 annually,
n reinvest their dividends in Ameren common stock or receive
Ameren dividends in cash, and
n 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 SEC Form 10-K, quarterly reports
on SEC Form 10-Q and its current reports on SEC Form 8-K,
filed with the Securities and Exchange Commission, including
any chief executive officer and chief financial officer certifications
required to be filed therewith.
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.
oFFICe
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. B o x 6 6 1 4 9 | st . lo uIs , Mo | 6 3 1 6 6 - 6 1 4 9 | W W W. aMe r e n .CoM